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Xcel Energy 10-Q 2008
UNITED STATES Washington, D.C. 20549
FORM 10-Q
For the quarterly period ended June 30, 2008
OR
For the transition period from to
Commission File Number: 1-3034
Xcel Energy Inc. (Exact name of registrant as specified in its charter)
Registrant’s telephone number, including area code (612) 330-5500
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. x Yes o No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one): x Large accelerated filer o Accelerated filer o Non-accelerated filer (Do not check if a smaller reporting company) o Smaller reporting company
Indicate by check mark
whether the registrant is a shell company (as defined in Rule 12b-2 of the
Exchange Act).
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.
This Form 10-Q is filed by Xcel Energy, Inc. Xcel Energy, Inc. wholly owns the following subsidiaries: Northern States Power Company, a Minnesota corporation (NSP-Minnesota); Northern States Power Company, a Wisconsin corporation (NSP-Wisconsin); Public Service Company of Colorado, a Colorado corporation (PSCo); and Southwestern Public Service Company, a New Mexico corporation (SPS). Additional information on the wholly owned subsidiaries is available on various filings with the Securities and Exchange Commission (SEC).
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PART I — FINANCIAL INFORMATION
XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
See Notes to Consolidated Financial Statements
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XCEL ENERGY INC. AND SUBSIDIARIES (Thousands of Dollars)
See Notes to Consolidated Financial Statements
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XCEL ENERGY INC. AND SUBSIDIARIES (Thousands of Dollars)
See Notes to Consolidated Financial Statements
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XCEL ENERGY INC. AND SUBSIDIARIES (UNAUDITED)
See Notes to Consolidated Financial Statements
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XCEL ENERGY INC. AND SUBSIDIARIES (UNAUDITED)
See Notes to Consolidated Financial Statements
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XCEL ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly the financial position of Xcel Energy Inc. and its subsidiaries (collectively, Xcel Energy) as of June 30, 2008, and Dec. 31, 2007; the results of its operations and changes in stockholders’ equity for the three and six months ended June 30, 2008 and 2007; and its cash flows for the six months ended June 30, 2008 and 2007. Due to the seasonality of Xcel Energy’s electric and natural gas sales, such interim results are not necessarily an appropriate base from which to project annual results.
1. Significant Accounting Policies
Except to the extent updated or described below, the significant accounting policies set forth in Note 1 to the consolidated financial statements in Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2007, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.
Fair Value Measurements — Xcel Energy presents interest rate derivatives, commodity derivatives, and nuclear decommissioning fund assets at estimated fair values in its consolidated financial statements. For interest rate derivatives, broker quotes are used to establish fair value. For commodity derivatives, the most observable inputs available are used to determine the fair value of each contract. In the absence of a quoted price for an identical contract in an active market, Xcel Energy may use broker quotes for identical or similar contracts, or internally prepared valuation models to determine fair value. For the nuclear decommissioning fund, published trading data, broker quotes and market inputs are utilized to estimate fair value for each class of security.
2. Recently Issued Accounting Pronouncements
Statement of Financial Accounting Standards (SFAS) No. 157 Fair Value Measurements (SFAS No. 157) — In September 2006, the Financial Accounting Standards Board (FASB) issued SFAS No. 157, which provides a single definition of fair value, together with a framework for measuring it, and requires additional disclosure about the use of fair value to measure assets and liabilities. SFAS No. 157 also emphasizes that fair value is a market-based measurement, and sets out a fair value hierarchy with the highest priority being quoted prices in active markets. Fair value measurements are disclosed by level within that hierarchy. SFAS No. 157 was effective for financial statements issued for fiscal years beginning after Nov. 15, 2007.
As of Jan. 1, 2008, Xcel Energy adopted SFAS No. 157 for all assets and liabilities measured at fair value except for non-financial assets and non-financial liabilities measured at fair value on a non-recurring basis, as permitted by FASB Staff Position No. 157-2. The adoption did not have a material impact on its consolidated financial statements. For additional discussion and SFAS No. 157 required disclosures see Note 11 to the consolidated financial statements.
The Fair Value Option for Financial Assets and Financial Liabilities — Including an Amendment of FASB Statement No. 115 (SFAS No. 159) — In February 2007, the FASB issued SFAS No. 159, which provides companies with an option to measure, at specified election dates, many financial instruments and certain other items at fair value that are not currently measured at fair value. A company that adopts SFAS No. 159 will report unrealized gains and losses on items, for which the fair value option has been elected, in earnings at each subsequent reporting date. This statement also establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. This statement was effective for fiscal years beginning after Nov. 15, 2007. Effective Jan. 1, 2008, Xcel Energy adopted SFAS No. 159 and the adoption did not have a material impact on its consolidated financial statements.
Business Combinations (SFAS No. 141 (revised 2007)) — In December 2007, the FASB issued SFAS No. 141R, which establishes principles and requirements for how an acquirer in a business combination recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest; recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase; and determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. SFAS No. 141R is to be applied prospectively to business combinations for which the acquisition date is on or after the beginning of an entity’s fiscal year that begins on or after Dec. 15, 2008. Xcel Energy will evaluate the impact of SFAS No. 141R on its consolidated financial statements for any potential business combinations subsequent to Jan. 1, 2009.
Noncontrolling Interests in Consolidated Financial Statements, an Amendment of Accounting Research Bulletin (ARB) No. 51 (SFAS No. 160) — In December 2007, the FASB issued SFAS No. 160, which establishes accounting and reporting standards that require the ownership interest in subsidiaries held by parties other than the parent be clearly identified and presented in the consolidated balance sheets within equity, but separate from the parent’s equity; the amount of consolidated net income attributable to
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the parent and the noncontrolling interest be clearly identified and presented on the face of the consolidated statement of earnings; and changes in a parent’s ownership interest while the parent retains its controlling financial interest in its subsidiary be accounted for consistently. This statement is effective for fiscal years beginning on or after Dec. 15, 2008. Xcel Energy is currently evaluating the impact of SFAS No. 160 on its consolidated financial statements.
Disclosures about Derivative Instruments and Hedging Activities (SFAS No. 161) — In March 2008, the FASB issued SFAS No. 161, which is intended to enhance disclosures to help users of the financial statements better understand how derivative instruments and hedging activities affect an entity’s financial position, financial performance and cash flows. SFAS No. 161 amends and expands the disclosure requirements of SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, to require disclosures of objectives and strategies for using derivatives, gains and losses on derivative instruments, and credit-risk-related contingent features in derivative agreements. SFAS No. 161 is effective for financial statements issued for fiscal years and interim periods beginning after Nov. 15, 2008, with early application encouraged. Xcel Energy is currently evaluating the impact of adoption of SFAS No. 161 on its consolidated financial statements.
The Hierarchy of Generally Accepted Accounting Principles (GAAP) (SFAS No. 162) — In May 2008, the FASB issued SFAS No. 162, which establishes the GAAP hierarchy, identifying the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements. SFAS No. 162 is effective 60 days following the SEC approval of the Public Company Accounting Oversight Board amendments to AU Section 411, The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles. Xcel Energy does not believe that implementation of SFAS No. 162 will have any impact on its consolidated financial statements.
Accounting for Deferred Compensation and Postretirement Benefit Aspects of Endorsement Split-Dollar Life Insurance Arrangements (Emerging Issues Task Force (EITF) Issue No. 06-4) — In June 2006, the EITF reached a consensus on EITF No. 06-4, which provides guidance on the recognition of a liability and related compensation costs for endorsement split-dollar life insurance policies that provide a benefit to an employee that extends to postretirement periods. Therefore, this EITF would not apply to a split-dollar life insurance arrangement that provides a specified benefit to an employee that is limited to the employee’s active service period with an employer. EITF No. 06-4 was effective for fiscal years beginning after Dec. 15, 2007, with earlier application permitted. Upon adoption of EITF No. 06-4 on Jan. 1, 2008, Xcel Energy recorded a liability of $1.6 million, net of tax, as a reduction of retained earnings. Thereafter, changes in the liability are reflected in operating results.
Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards (EITF No. 06-11) — In June 2007, the EITF reached a consensus on EITF No. 06-11, which states that an entity should recognize a realized tax benefit associated with dividends on nonvested equity shares and nonvested equity share units charged to retained earnings as an increase in additional paid in capital. The amount recognized in additional paid in capital should be included in the pool of excess tax benefits available to absorb potential future tax deficiencies on share-based payment awards. EITF No. 06-11 should be applied prospectively to income tax benefits of dividends on equity-classified share-based payment awards that are declared in fiscal years beginning after Dec. 15, 2007. The adoption of EITF No. 06-11 did not have a material impact on Xcel Energy’s consolidated financial statements.
3. Selected Balance Sheet Data
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4. Discontinued Operations
A summary of the subsidiaries presented as discontinued operations is discussed below. Results of operations for divested businesses are reported, for all periods presented, as discontinued operations. In addition, the remaining assets and liabilities related to the businesses divested or discontinued have been reclassified to assets and liabilities held for sale and related to discontinued operations in the consolidated balance sheets. The majority of current and noncurrent assets related to discontinued operations are deferred tax assets and net operating loss (NOL) and tax credit carryforwards, originally from discontinued operations, that will be deductible in future years.
Nonregulated Subsidiaries
Seren Innovations Inc., NRG Energy, Inc., e prime, Xcel Energy International, Utility Engineering, and Quixx, which were all divested or sold in 2006 or earlier, continue to have activity and balances reflected on Xcel Energy’s financial statements as reported in the tables below.
Summarized Financial Results of Discontinued Operations
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The major classes of assets and liabilities held for sale and related to discontinued operations are as follows:
5. Income Taxes
Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109 (FIN 48) — Xcel Energy files a consolidated federal income tax return and state tax returns based on income in its major operating jurisdictions of Colorado, Minnesota, Texas, and Wisconsin, and various other state income-based tax returns.
In the first quarter of 2008, the Internal Revenue Service (IRS) completed an examination of Xcel Energy’s federal income tax returns for 2004 and 2005 (and research credits for 2003). The IRS did not propose any material adjustments for those tax years. Tax year 2004 is the earliest open year and the statute of limitations applicable to Xcel Energy’s 2004 federal income tax return remains open until Dec. 31, 2009. Xcel Energy expects the IRS to commence their examination of tax years 2006 and 2007 in the third quarter of 2008.
In the first quarter of 2008, the state of Minnesota concluded an income tax audit through tax year 2001 and the state of Texas concluded an audit through tax year 2005. No material adjustments were proposed for these state audits. As of June 30, 2008, Xcel Energy’s earliest open tax years in which an audit can be initiated by state taxing authorities in its major operating jurisdictions are as follows: Colorado-2003, Minnesota-2004, Texas-2004 and Wisconsin-2003. There currently are no state income tax audits in progress.
The amount of unrecognized tax benefits reported in continuing operations was $26.3 million on Dec. 31, 2007, and $28.0 million on June 30, 2008. The amount of unrecognized tax benefits reported in discontinued operations was $4.3 million on Dec. 31, 2007 and $4.3 million on June 30, 2008. These unrecognized tax benefit amounts were reduced by the tax benefits associated with NOL and tax credit carryovers reported in continuing operations of $7.8 million on Dec. 31, 2007 and $9.3 million on June 30, 2008 and NOL and tax credit carryovers reported in discontinued operations of $17.8 million on Dec. 31, 2007 and $19.6 million on June 30, 2008.
The unrecognized tax benefit balance reported in continuing operations included $9.8 million and $8.0 million of tax positions on Dec. 31, 2007 and June 30, 2008, respectively, which if recognized would affect the annual effective tax rate. In addition, the unrecognized tax benefit balance reported in continuing operations included $16.5 million and $20.0 million of tax positions on Dec. 31, 2007 and June 30, 2008, respectively, for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the effective tax rate but would accelerate the payment of cash to the taxing authority to an earlier period.
The increase in the unrecognized tax benefit balance reported in continuing operations of $1.9 million from April 1, 2008 to June 30, 2008, was due to the addition of similar uncertain tax positions related to ongoing activity. Xcel Energy’s amount of unrecognized tax benefits for continuing operations could significantly change in the next 12 months when the IRS and state audits resume. However, at this time, it is not reasonably possible to estimate an overall range of possible change.
The liability for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryovers. The amount of interest expense related to unrecognized tax benefits reported within interest charges in continuing operations in the second quarter of 2008 was $0.4 million. The liability for interest related to unrecognized tax benefits reported in continuing operations was $5.8 million on Dec. 31, 2007 and $5.0 million on June 30, 2008. The amount of interest income related to unrecognized tax benefits reported within interest charges in discontinued operations in the second quarter of 2008 was $0.3 million.
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The receivable for interest related to unrecognized tax benefits reported in discontinued operations was $0.5 million on Dec. 31, 2007 and $1.0 million on June 30, 2008.
No amounts were accrued for penalties in the second quarter of 2008. The liability for penalties related to unrecognized tax benefits reported in continuing operations was $1.0 million on Dec. 31, 2007 and June 30, 2008.
Other Income Tax Matters — The effective tax rate for continuing operations was 34.3 percent for the second quarter of 2008, compared with 51.2 percent for the same period in 2007. The higher effective tax rate for second quarter 2007 was primarily due to the corporate-owned life insurance (COLI) settlement in that quarter. This was partially offset by an increase in the forecasted annual effective tax rate for 2008, which was largely a result of PSR Investments, Inc. (PSRI) terminating the COLI program in 2007. Without these charges and benefits, the effective tax rate for the second quarters of 2008 and 2007 would have been 35.2 percent and 37.8 percent, respectively.
The effective tax rate for continuing operations was 33.7 percent for the first six months of 2008, compared with 39.0 percent for the same period in 2007. The higher effective tax rate for the first six months of 2007 was primarily due to the COLI settlement. This was partially offset by an increase in the forecasted annual effective tax rate for 2008, which was largely a result of PSRI terminating the COLI program in 2007. Without these charges and benefits, the effective tax rate for the first six months of 2008 and 2007 would have been 33.8 percent and 35.6 percent, respectively.
COLI — On June 19, 2007, a settlement in principle was reached between Xcel Energy and representatives of the United States Government regarding Public Service Company of Colorado’s (PSCo) right to deduct interest expense on policy loans related to its COLI program that insured lives of certain PSCo employees. These COLI policies were owned and managed by PSRI, a wholly owned subsidiary of PSCo.
In September 2007, Xcel Energy and the United States finalized a settlement, which terminated the tax litigation pending between the parties. As a result of the settlement, the lawsuit filed by Xcel Energy in the United States District Court has been dismissed and the Tax Court proceedings are in the process of being dismissed. Xcel Energy paid the government a total of $64.4 million in full settlement of the government’s claims for tax, penalty, and interest for tax years 1993-2007.
6. Rate Matters
Except to the extent noted below, the circumstances set forth in Note 14 to the consolidated financial statements included in Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2007 appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference. The following include unresolved proceedings that are material to Xcel Energy’s financial position.
NSP-Minnesota
Pending and Recently Concluded Regulatory Proceedings — Minnesota Public Utilities Commission (MPUC)
Electric, Purchased Gas and Resource Adjustment Clauses
Transmission Cost Recovery (TCR) Rider — In November 2006, the MPUC approved a TCR rider pursuant to legislation, which allows annual adjustments to retail electric rates to provide recovery of incremental transmission investments between rate cases. In December 2007, NSP-Minnesota filed adjustments to the TCR rate factors and implemented a rider to recover $18.5 million beginning Jan. 1, 2008. In March 2008, the MPUC approved the 2008 cost recovery, but requiring certain procedural changes for future TCR filings if costs are disputed. NSP-Minnesota filed the required compliance filing in April 2008.
Renewable Energy Standard (RES) Rider — In March 2008, the MPUC approved a RES Rider to recover the costs associated with utility-owned projects implemented in compliance with the RES adopted by the 2007 Minnesota legislature, and it was implemented on April 1, 2008. Under the rider, NSP-Minnesota could recover up to approximately $14.5 million in 2008 attributable to the Grand Meadow wind farm, a 100-megawatt (MW) wind project, subject to true-up.
Annual Automatic Adjustment Report for 2007 — In September 2007, NSP-Minnesota filed its annual automatic adjustment reports for July 1, 2006 through June 30, 2007, which is the basis for the MPUC review of charges that flow through the fuel clause adjustment (FCA) and purchased gas adjustment (PGA) mechanisms. During that time period, $1.2 billion in fuel and purchased energy costs, including $384 million of Midwest Independent Transmission System Operator, Inc. (MISO) charges were recovered from electric customers through the FCA. In addition, approximately $590 million of purchased natural gas and transportation costs were recovered through the PGA. The 2007 annual automatic adjustment reports are pending comments and MPUC action. The
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Minnesota Office of Energy Security (OES) submitted its comments in this proceeding on June 30, 2008. While the OES made several recommendations regarding assignment of wholesale and retail costs for the recovery period and future periods, none of these recommendations have a material financial impact, as NSP-Minnesota currently returns all margins to ratepayers.
Other
Nuclear Refueling Outage Costs — In November 2007, NSP-Minnesota filed a request asking for a change in the recovery method for costs associated with refueling outages at its nuclear plants. The request seeks approval to amortize refueling outage costs over the period between refueling outages to better match revenues and expenses. This request, if approved, would reduce 2008 expenses for NSP-Minnesota jurisdiction by approximately $25 million due to deferral and amortization over an 18-month period versus expensed as incurred. In March 2008, the OES issued comments indicating it did not object to adoption of the proposal, subject to conditions. The Minnesota Office of Attorney General filed comments opposing implementation of this change outside of a rate case. NSP-Minnesota filed reply comments in support of its proposal, and MPUC action is pending.
Pending Regulatory Proceedings — North Dakota Public Service Commission (NDPSC) and South Dakota Public Utilities Commission (SDPUC)
NSP-Minnesota North Dakota Electric Rate Case — In December 2007, NSP-Minnesota filed a request with the NDPSC to increase North Dakota retail electric rates by $20.5 million, which is an $18.2 million impact to NSP-Minnesota due to the transfer of certain costs and revenues between base rates and the fuel cost recovery mechanism. The request was based on an 11.50 percent return on equity (ROE), an equity ratio of 51.77 percent, and a rate base of approximately $242 million. Interim rates of $17.2 million became effective in February 2008.
NSP-Minnesota and the NDPSC staff reached a stipulation settlement in the rate case in which both parties recommended an ROE of 10.75 percent, with a sharing mechanism for earnings above 10.75 percent. This stipulation settlement is subject to approval by the NDPSC. In June 2008, NSP-Minnesota filed rebuttal testimony and reduced its requested rate increase to $17.9 million, a net impact of $15.7 million to NSP-Minnesota, which reflects a 10.75 percent ROE and other adjustments.
Evidentiary hearings were held June 23-25, 2008 in the pending electric rate case application in North Dakota. The updated NDPSC staff’s overall recommendation following the hearing is a base rate increase of $4.9 million, a net impact of $2.5 million to NSP-Minnesota, with recommended disallowances for costs associated with NSP-Minnesota’s compliance with Minnesota renewable energy requirements, investments in environmental improvements and power plant life extensions through NSP-Minnesota’s Metropolitan Emissions Reduction Program (MERP), and recommended changes in treatment of depreciation costs. Briefs are expected to be filed on Aug. 22, 2008, with reply briefs due Sept. 12, 2008. Final rates are expected to be effective in the fall of 2008.
Nuclear Refueling Outage Costs — In late 2007, NSP-Minnesota filed with both the NDPSC and SDPUC a request asking for a change in the recovery method for costs associated with refueling outages at its nuclear plants. The request is comparable to that filed with the MPUC. In February 2008, the NDPSC approved the request, indicating that appropriate cost recovery levels would be determined in the pending electric rate case. The SDPUC has not acted on the petition.
Pending and Recently Concluded Regulatory Proceedings — Federal Energy Regulatory Commission (FERC)
MISO Long-Term Transmission Pricing — In October 2005, MISO filed a proposed change to its Transmission and Energy Markets Tariff of MISO (TEMT) to regionalize future cost recovery of certain high voltage transmission projects to be constructed for reliability improvements. The tariff, called the Regional Expansion Criteria Benefits phase I (RECB I) and a subsequent proposal based on regional economic benefits (RECB II), would recover varying percentages of eligible reliability transmission costs from all transmission service customers in the MISO 15 state region. In November 2006, the FERC issued an order accepting the RECB I tariff, including the 20 percent limitation, which is the cap on the portion of transmission expansion costs that would be regionalized and recovered from all loads in the MISO region, with 80 percent allocated to the pricing zone where the transmission facilities are constructed. In December 2006, the Public Service Commission of Wisconsin (PSCW) and other parties filed an appeal of the RECB I order to the U.S. federal Court of Appeals for the District of Columbia. The appeal is pending.
In March 2007, the FERC issued an order approving most aspects of the RECB II proposal. Transmission service rates in the MISO region presently use a rate design in which the transmission cost depends on the location of the load being served (referred to as “license plate” rates). Costs of existing transmission facilities are thus not regionalized. MISO and its transmission owners filed a successor rate methodology in August 2007, to be effective February 2008. Other entities sought to regionalize some of these costs. The impact of the regionalization of future facilities would depend on the specific facilities placed in service. In January 2008, the FERC issued an order accepting the MISO filing to continue use of license plate rates for existing facilities and RECB (limited regionalization) pricing for certain new facilities. The requests for rehearing are pending FERC action.
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NSP-Wisconsin
Pending and Recently Concluded Regulatory Proceedings — PSCW
Base Rate
Electric and Gas Rate Case — In January 2008, the PSCW issued the final written order in NSP-Wisconsin’s 2008 test year rate case, approving an electric rate increase of approximately $39.4 million, or 8.1 percent, and a natural gas rate increase of $5.3 million, or 3.3 percent. The rate increase was based on a 10.75 percent ROE and a 52.5 percent common equity ratio. New rates went into effect Jan. 9, 2008.
On Aug. 1, 2008, NSP-Wisconsin filed an application with the PSCW requesting authority to increase retail electric rates by $47.1 million, which represents an overall increase of 8.6 percent. In the application, NSP-Wisconsin requested the PSCW to reopen the 2008 base rate case for the limited purpose of adjusting 2009 base electric rates to reflect forecast increases in production and transmission costs, as authorized by the PSCW.
The requested increase in electric rates is related to investments in cleaner sources of energy and transmission lines to reliably meet customers’ electric demand and increasing costs for fuel and purchased power. No changes are being requested to the capital structure or authorized ROE authorized by the PSCW in the 2008 base rate case.
Public hearings to address NSP-Wisconsin’s rate request will be held later this fall at the PSCW. No specific dates for hearings or prehearing conferences have been scheduled as of this time.
Other
2008 Electric Fuel Cost Recovery — On May 2, 2008, the PSCW approved NSP-Wisconsin’s request to increase Wisconsin retail electric rates on an interim basis. The PSCW approved $19.7 million, or 3.8 percent, on an annual basis, to recover increases in fuel and purchased power costs. NSP-Wisconsin expects that the surcharge will generate approximately $13 million in additional revenue in 2008. The increase in fuel costs is primarily driven by fuel and purchased power costs, including replacement power costs associated with unplanned plant outages. Fuel costs for the remainder of 2008 are expected to be significantly higher than approved by the PSCW in NSP-Wisconsin’s 2008 rate case. The increased rates went into effect May 6, 2008. The revenues that NSP-Wisconsin collects are subject to refund with interest at a rate of 10.75 percent, pending PSCW review and final approval.
Fuel Cost Recovery Rulemaking — In June 2006, the PSCW opened a rulemaking docket to address potential revisions to the electric fuel cost recovery rules. Wisconsin statutes prohibit the use of automatic adjustment clauses by large investor-owned electric public utilities. The statutes authorize the PSCW to approve a rate increase for these utilities to allow for the recovery of costs caused by an emergency or extraordinary increase in the cost of fuel.
In August 2007, the PSCW staff issued its draft revisions to the fuel rules and requested comments. The proposed rules incorporate a plan year fuel cost forecast, deferred accounting for differences between actual and forecast costs (if the difference is greater than 2 percent), and an after the fact reconciliation proceeding to allow the opportunity to recover or refund the deferred balance.
On July 3, 2008, the PSCW officially issued its proposed revisions to the fuel rules for public comment, and set a hearing date of August 4, 2008. The proposed revisions to the rules are substantively the same as the version issued in August 2007, described above. If approved as proposed, the new rules would be effective with rate requests filed after January 1, 2009.
Bay Front Emission Controls Certificate of Authority — In March 2008, the PSCW issued a certificate of authority and order approving NSP-Wisconsin’s application to install equipment relating to combustion improvement and nitrogen oxide (NOx) emission controls in boilers 1 and 2 at the Bay Front power plant in Ashland County, Wisconsin. Construction began in May and is expected to be completed in the fall of 2008.
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PSCo
Pending and Recently Concluded Regulatory Proceedings — Colorado Public Utilities Commission (CPUC)
Electric, Purchased Gas and Resource Adjustment Clauses
Transmission Cost Adjustment Rider — In September 2007, PSCo filed with the CPUC a request to implement a transmission cost adjustment rider (TCA), which would recover approximately $18.2 million in 2008. This filing was pursuant to recently enacted legislation, which entitled public utilities to recover, through a separate rate adjustment clause, the costs that they prudently incur in planning, developing and completing the construction or expansion of transmission.
In December 2007, the CPUC approved PSCo’s application to implement the TCA. The CPUC limited the scope of the costs that could be recovered through the rider during 2008 to only those costs associated with transmission investment made after the new legislation authorizing the rider became effective on March 26, 2007. The CPUC also will require PSCo to base its revenue requirement calculation on a thirteen-month average net transmission plant balance. As a result of the CPUC’s decision, PSCo implemented a rider on Jan. 1, 2008, expected to recover approximately $4.5 million in 2008.
Enhanced Demand Side Management (DSM) Program — In October 2007, PSCo filed an application with the CPUC for approval to implement an expanded DSM program and to revise its DSM cost adjustment mechanism to include current cost recovery and incentives designed to reward PSCo for successfully implementing cost-effective DSM programs and measures. In July 2008, the CPUC issued an order approving PSCo’s proposal to expand the DSM program and recover 100 percent of its forecasted expenses associated with the DSM program during the year in which the rider is in effect, beginning in 2009. An incentive mechanism was also approved to reward PSCo for meeting and exceeding program goals.
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 an active participant in the hearings. In September 2001, the presiding administrative law judge (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 regarding the use of certain strategies and how they may have impacted the markets in the Pacific Northwest markets. For the referenced period, parties have claimed that the total amount of transactions with PSCo subject to refund are $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 Ninth Circuit remanded the proceeding back to the FERC. The court of appeals preliminarily determined that it had jurisdiction to review the FERC’s decision not to order refunds and remanded the case back to the FERC, directing that the FERC consider evidence that had been presented regarding intentional market manipulation in the California markets and its potential ties to transactions in the Pacific Northwest. The court of appeals also indicated that the FERC should consider other rulings addressing overcharges in the California organized markets. The FERC has yet to act on this order on remand.
PSCo Wholesale Rate Case — In February 2008, PSCo requested a $12.5 million, or 5.88 percent, increase in wholesale rates, based on 11.5 percent requested ROE. The $12.5 million total increase was composed of $8.8 million of traditional base rate recovery and $3.7 million of construction work in progress recovery for the Comanche 3 and Fort St. Vrain projects. The increase is applicable to all wholesale firm service customers with the exception of Intermountain Rural Electric Cooperative, which would be under a rate moratorium until January 2009.
In March 2008, PSCo reached an agreement with Rural Electric Association (REA) customers Holy Cross, Yampa Valley and Grand Valley, which resolved all issues based on a “black box” settlement with an implied ROE of 10.4 percent. Parties filed the settlement with the FERC on April 17, 2008, with rates effective May 1, 2008. PSCo has reached an agreement with the cities of Burlington, Center and Aquila under the same substantive terms and conditions as the REA settlement. This settlement was filed with the FERC on April 25, 2008. The settlements provide for:
· A traditional annual rate base rate increase of $6.6 million with allowance for funds used during construction continuing for Comanche and Fort St. Vrain. · Implementation of new rates several months earlier than is typical in a disputed filing.
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· The ability to implement rates in PSCo’s next general rate case that will involve Comanche 3 costs upon a nominal suspension.
The FERC approved the settlement agreements on June 19, 2008.
SPS
Pending and Recently Concluded Regulatory Proceedings — Public Utility Commission of Texas (PUCT)
Base Rate
Texas Retail Base Rate Case — On June 12, 2008, SPS filed with the PUCT, and the 80 cities in SPS’ Texas service territory with original rate jurisdiction, a request for a Texas system retail electric general rate increase.
The filing requests an overall increase in annual revenues of approximately $61.3 million, or an increase of 5.9 percent. Base revenues are proposed to increase by $94.4 million, while fuel and purchased power revenue will decline by $33.1 million, primarily due to the fuel savings from SPS’ power purchases from the Hobbs generating facility, which is owned by Lea Power Partners, LLC (LPP). Hobbs is a natural gas combined cycle 604 MW plant currently being constructed in New Mexico. The LPP project had been expected to come on line in the summer of 2008.
The rate filing is based on a 2007 calendar year test year adjusted for known and measurable changes and includes a requested rate of ROE of 11.25 percent, net rate base of approximately $989.4 million allocated to the Texas retail jurisdiction, and an equity ratio of 51.0 percent.
In SPS’ last Texas rate case, the parties agreed that SPS seek, in this rate filing, interim rate relief of $18 million per year for the LPP purchase agreement. The interim rates are proposed to go into effect when the LPP plant comes on line. The deadline for the PUCT to act on SPS’ request is March 31, 2009.
The filing with the PUCT also includes a request to reconcile (i.e. seek final approval for) $1.0 billion of SPS’ fuel and purchased power costs for calendar years 2006 and 2007.
The following procedural schedule has been established:
· Intervenor direct testimony will be filed on Oct. 13, 2008; · PUCT staff testimony will be filed on Oct. 21, 2008; · PUCT staff and intervenors cross-rebuttal testimony will be filed on Oct. 28, 2008; · SPS rebuttal testimony will be filed on Nov. 4, 2008; · The hearing on the merits will begin on Nov. 12, 2008; and · Final order by March 31, 2009.
Electric and Resource Adjustment Clauses
TCR Factor Rulemaking — In November 2007, the PUCT adopted new rules relating to TCR factor outside of a base rate case. The rule establishes the mechanism by which SPS can request annual recovery of its reasonable and necessary expenditures for transmission infrastructure improvement costs and changes in wholesale transmission charges that are not included in existing rates. This new rule allows SPS more timely recovery of transmission cost increases in-between base rate cases.
Pending and Recently Concluded Regulatory Proceedings — New Mexico Public Regulation Commission (NMPRC)
Base Rate
New Mexico Electric Rate Case — In July 2007, SPS filed with the NMPRC requesting a New Mexico retail electric general rate increase of $17.3 million annually, or 6.6 percent. The rate filing is based on a 2006 test year adjusted for known and measurable changes and includes a requested rate of ROE of 11.0 percent, an electric rate base of approximately $307.3 million and an equity ratio of 51.2 percent. In addition to the base rate costs described above, SPS sought to implement a rate rider to recover costs for the LPP project, which had been expected to come on line on June 1, 2008. In March 2008, SPS filed rebuttal testimony reducing the rate increase request to $16.6 million, based on a 10.7 percent ROE.
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In April 2008, hearings on SPS’ application were held, in which the parties agreed to move consideration of the LPP power purchase agreement costs to a future rate proceeding to be initiated by SPS this fall. SPS is expected to start taking energy beginning in late summer of 2008 when LPP reaches commercial operations.
On July 3, 2008, the hearing examiner recommended a $12.6 million electric rate increase, including a 10.14 percent ROE on a rate base of approximately $300.9 million. In addition, the hearing examiner recommended the exclusion of approximately $3.5 million of historical demand-side management costs from the New Mexico retail rate base and a reduction in certain test year expenses for preparing the rate case, for power plant outage, maintenance work and for annual incentive compensation. The parties’ exceptions to the recommendation were filed on July 16, 2008 and the responses to exceptions were filed on July 24, 2008. The deadline for the NMPRC to issue its order is Aug. 29, 2008.
Electric and Resource Adjustment Clauses
New Mexico Fuel Factor Continuation Filing — In August 2005, SPS filed with the NMPRC requesting continuation of the use of SPS’ fuel and purchased power cost adjustment clause (FPPCAC) and current monthly factor cost recovery methodology. This filing was required by NMPRC rule.
Testimony was filed in the case by staff and intervenors objecting to SPS’ assignment of system average fuel costs to certain wholesale sales and the inclusion of certain purchased power capacity and energy payments in the FPPCAC. The testimony also proposed limits on SPS’ future use of the FPPCAC. Related to these issues, some intervenors requested disallowances for past periods, which in the aggregate total approximately $45 million. This claim was for the period from Oct. 1, 2001 through May 31, 2005 and does not include the value of incremental cost assigned for wholesale transactions from that date forward. Other issues in the case include the treatment of renewable energy certificates and sulfur dioxide (SO2) allowance credit proceeds in relation to SPS’ New Mexico retail fuel and purchased power recovery clause.
In December 2007, SPS, the NMPRC, Occidental Permian Ltd. and the New Mexico Industrial Energy Consumers filed an uncontested settlement of this matter with the NMPRC.
A hearing on the merits of the settlement was held in April 2008. On June 3, 2008, the hearing examiner certified the unanimous stipulation to the NMPRC. The unanimous stipulation is pending final review and approval by the NMPRC. The NMPRC has scheduled a hearing for Aug. 14, 2008 to enable the commissioners to directly question the witnesses who supported the unanimous stipulation.
Investigation of SPS Participation in Southwest Power Pool, Inc. (SPP) — In October 2007, the NMPRC issued an order initiating an investigation to consider the prudence and reasonableness of SPS’ participation in the SPP Regional Transmission Organization (RTO). The investigation will consider the costs and benefits of RTO participation to SPS customers in New Mexico. The order required SPS to file direct testimony no later than 75 days after the completion of the hearing in the New Mexico electric rate case. SPS has been granted an extension and filed its direct testimony on July 31, 2008 with the NMPRC.
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 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.
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In May 2006, a FERC ALJ issued an initial decision in the proceeding. The ALJ found that SPS should recalculate its wholesale fuel and purchased economic energy cost adjustment clause (FCAC) billings for the period beginning Jan. 1, 1999, to reduce the fuel and purchased power costs recovered from the complaining customers by deducting from such costs the incremental fuel costs attributed to SPS’ sales of system firm capacity and associated energy to other wholesale customers served under market-based rates during this period based on the view that such sales should be treated as opportunity sales made out of temporarily excess capacity. In addition, the ALJ made recommendations on a number of base rate issues including a 9.64 percent ROE and the use of a 3-month coincident peak (3CP) demand allocator.
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 December 2007, this comprehensive offer of settlement (the Settlement) was filed with the FERC. On April 21, 2008, the FERC approved the Settlement with a minor modification to the formula rate proposed by the FERC and accepted by the parties. The Settlement provides for:
· A $1.25 million payment by SPS to Golden Spread related to resolve a dispute concerning the quantities Golden Spread was entitled to take under its existing partial requirements agreement for the years 2006 and 2007. The Settlement caps those quantities for the period 2008 through 2011. SPS is not required to make any fuel refunds to Golden Spread that were the subject of the Complaint under the terms of the Settlement.
· An extended partial requirements contract at system average cost, with a capacity amount that ramps down over the period 2012 through 2019 from 500 MW to 200 MW. The extended agreement requires that the cost assignment treatment receive Texas and New Mexico state approvals and provides for alternative pricing terms and quantities to hold SPS harmless from cost disallowances in the event that adverse regulatory treatment occurs or state approvals are not obtained. 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.
· Resolution of base rates in the Complaint without any adjustment to the existing rates for the period January 2005 through June 30, 2006. The Settlement also resolves all base rate issues in SPS’ subsequent proceeding related to the period July 1, 2006 through June 30, 2008, other than the method to be used to allocate demand related costs and provided for two sets of agreed on rates that are dependent on the ultimate resolution of that issue. If SPS prevails in its support of the 12-month coincident peak (12 CP) demand allocation method, there would be no impact to earnings for this period. If Golden Spread prevails, SPS would be required to refund Golden Spread and PNM approximately $4 million for the period through the end of 2007.
· For July 1, 2008 and beyond, Golden Spread will be under a formula rate for power supply service. The rate will be based on actual data the most recent historic year adjusted for known and measurable changes and trued up to the actual performance in the subsequent calendar year. Initially, the formula will be based on a 10.25 percent ROE and either party will have a right to seek changes to the ROE beginning with the 2009 formula rate filing. SPS and Golden Spread will share margins from its sales to West Texas Municipal Power Agency and El Paso Electric in that year but will assign system average fuel and energy costs to those agreements for purposes of calculating Golden Spread’s monthly fuel cost.
Order on Wholesale Rate Complaints — On April 21, 2008, the FERC issued its Order on the Complaint (the Order) 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.
Base Rates: The FERC determined: (1) the ROE should be 9.33 percent; (2) rates should be based on a 12 CP allocator; and (3) the treatment of market based rate contracts in the test year should be to credit revenues to the cost of service rather than allocating costs to the agreements. The revenue requirement established by the FERC results in proposed revenues that are estimated to be approximately $25 million, or approximately $6.9 million below the level charged these customers during this 18-month period. Rates for full requirements customers, the New Mexico Cooperatives and Cap Rock, as well as an interruptible contract with PNM for the period beginning in July 1, 2006, are the subject of settlements that have either been approved or are pending before FERC. These settlements are described in Wholesale 2005 Power Base Rate Application below.
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