NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly the financial position of NSP-Minnesota and its subsidiaries as of June 30, 2006, and Dec. 31, 2005; the results of its operations for the three and six months ended June 30, 2006 and 2005; and its cash flows for the six months ended June 30, 2006 and 2005. Due to the seasonality of electric and natural gas sales of NSP-Minnesota, quarterly 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 NSP-Minnesota’s Annual Report on Form 10-K for the year ended Dec. 31, 2005 appropriately represent, in all material respects, the current status of accounting policies, and are incorporated herein by reference.
Metro Emissions Reduction Project (MERP) Accounting - Allowance for funds used during construction (AFDC) is an amount capitalized as a part of construction costs representing the cost of financing the construction. Generally these costs are recovered from customers as the related property is depreciated. The Minnesota Public Utilities Commission (MPUC) has approved a more current recovery of the financing costs related to the MERP. The in-service plant costs, including the financing costs during construction, are recovered from customers through a MERP rider resulting in a lower recognition of AFDC.
FASB Interpretation No. 48 (FIN 48) — In July 2006, the FASB issued FIN 48, “Accounting for Uncertainty in Income Taxes —an interpretation of FASB Statement No. 109”. FIN 48 prescribes a comprehensive financial statement model of how a company should recognize, measure, present, and disclose uncertain tax positions that the company has taken or expects to take in its income tax returns. FIN 48 requires that only income tax benefits that meet the “more likely than not” recognition threshold be recognized or continue to be recognized on the effective date. Initial derecognition amounts would be reported as a cumulative effect of a change in accounting principle.
FIN 48 is effective for fiscal years beginning after Dec. 15, 2006. NSP-Minnesota is assessing the impact of the new guidance on all of its open tax positions.
Reclassifications — Certain items in the statements of cash flows related to nuclear decommissioning investments have been reclassified for the six months ended June 30, 2005 to conform to the 2006 gross investment activity presentation.
2. Regulation
Midwest Independent Transmission System Operator, Inc. (MISO) Operations —NSP-Minnesota and Northern States Power Company, a Wisconsin corporation (NSP-Wisconsin), an affiliate of NSP-Minnesota, are members of the MISO. The MISO is a regional transmission organization (RTO) that provides transmission tariff administration services for electric transmission systems, including those of NSP-Minnesota and NSP-Wisconsin. In 2002, NSP-Minnesota and NSP-Wisconsin received all required regulatory approvals to transfer functional control of their high voltage (100 kilovolts and greater) transmission systems to the MISO. The MISO exercises functional control over the operations of these facilities and the facilities of certain neighboring electric utilities. On April 1, 2005, MISO initiated a regional Day 2 wholesale energy market pursuant to its transmission and energy markets tariff .
MISO Cost Recovery
While the Day 2 market is designed to provide efficiencies through region-wide generation dispatch and increased reliability, there are costs associated with the Day 2 market. NSP-Minnesota has requested recovery of these costs within their respective jurisdictions as outlined below.
On Feb. 24, 2006, the MPUC ordered jurisdictional investor-owned utilities in the state, including NSP-Minnesota, to participate with the Minnesota Department of Commerce and other parties in a proceeding to evaluate suitability of recovery of some of the MISO Day 2 energy market costs in the variable Fuel Cost Adjustment (FCA). The Minnesota utilities and other parties filed a joint report with the MPUC on June 22, 2006 recommending pass-through of MISO energy market costs in the FCA, with the exception of two components which would be included in base retail electric rates in a future rate case upon a showing of MISO regional market benefits. The two components are MISO Schedule 16, which recoups MISO costs for administration of financial transmission rights; and Schedule 17, which recoups the cost of MISO’s market computer systems and staff. The MPUC has requested written comments on the joint report, and action by the MPUC in response to the recommendations in this report is anticipated sometime later in 2006.
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An adverse MPUC ruling on cost recovery of MISO Day 2 market costs could have a material financial impact on NSP-Minnesota.
Revenue Sufficiency Guarantee Charges
On April 25, 2006, the Federal Energy Regulatory Commission (FERC) issued an order determining that MISO had incorrectly applied its energy markets tariff regarding the application of the revenue sufficiency guarantee (RSG) charge to certain transactions. The FERC ordered MISO to resettle all affected transactions retroactive to April 1, 2005. The RSG charges are collected from certain MISO customers and paid to others. Based on the FERC order, Xcel Energy could be required to make net payments to MISO. The FERC granted a rehearing on the issue for purposes of further consideration on June 23, 2006, and is expected to issue a final order later in 2006. NSP-Minnesota has reserved $5.7 million in the event the FERC order is upheld on rehearing and appeal.
Joint and Common Wholesale Energy Market
On March 16, 2006, the FERC dismissed complaints filed by Wisconsin Public Service Corp. et al. (WPS) asking the FERC to order MISO and the PJM Interconnection, Inc. (PJM) to establish a joint and common wholesale energy market (JCM) for the two neighboring RTOs. Xcel Energy opposed the WPS complaints, arguing that MISO and PJM are completing projects shown to be cost beneficial to market participants, and a full JCM could substantially increase market operations costs with limited benefits in terms of energy savings. In dismissing the complaints, the FERC ruled that the progress by MISO and PJM toward the JCM was satisfactory.
Ancillary Service Markets
MISO and its stakeholders are developing proposals to establish ancillary service markets within its footprint. The proposals would increase market efficiency by providing a reduced allocation of generation contingency reserves for market participants and by creating economic market opportunities to obtain alternative sources of generating reserves. The proposed implementation of these market design improvements is scheduled for phase-in over the course of 2007, subject to project actions by MISO. NSP-Minnesota signed a memoranda of understanding with MISO that permit NSP-Minnesota to participate in the development of agreements relating to regional generation reserve sharing. The MISO generation reserve sharing pool agreement was executed by numerous parties on July 31, 2006; however, the agreement provides an “opt out” in the event participation is lower than anticipated. Final participation will be determined by Aug. 4, 2006. NSP-Minnesota and NSP-Wisconsin will participate through a collective of participants in the existing Mid-Continent Area Power Pool generation reserve sharing agreement, which would be replaced by the MISO arrangement for contingency reserves.
Electric Rate Case — In November 2005, NSP-Minnesota requested an electric rate increase of $168 million or 8.05 percent. This increase was based on a requested 11 percent return on common equity, a projected common equity to total capitalization ratio of 51.7 percent and a projected electric rate base of $3.2 billion. On Dec. 15, 2005, the MPUC authorized an interim rate increase of $147 million, subject to refund, which became effective on Jan. 1, 2006. In March 2006, the MPUC approved a new depreciation order, which lowered decommissioning accruals for 2006 from anticipated levels. As a result, interim rates are being recorded at an annual level of approximately $119 million. Due to the seasonality of sales, the rate increase will not be recognized ratably throughout 2006. The nuclear decommissioning recovery was reduced by $10.2 million and $21.1 million for the second quarter and first six months of 2006, respectively. The annual recovery decreased from $80.8 million to $42.5 million. The decrease was attributed to a change in cost estimate and recovery parameters.
On April 13, 2006, intervenors filed testimony regarding the Minnesota electric rate case. In its testimony, the Minnesota Department of Commerce proposed an increase in annual revenues of approximately $90 million, a return on equity of 10.64 percent and a proposed equity ratio of 51.37 percent, resulting in an overall return on rate base of 8.81 percent. The primary adjustments related to return on equity, nuclear decommissioning expense, ratemaking treatment of wholesale margins, adjustments to fuel expense and an increase in sales volumes. On the latter two issues the Department of Commerce indicated that the recommendations might change if NSP-Minnesota is able to supply additional information in its rebuttal testimony.
The Office of Attorney General also filed testimony. It proposed two adjustments related to income taxes and wholesale margins that would result in a decrease in 2006 annual revenues of approximately $20 million. On March 30, 2006, NSP-Minnesota filed rebuttal testimony reducing the requested rate increase to $156 million. Evidentiary hearings concluded on April 27, 2006.
On April 24, 2006, NSP-Minnesota reached a settlement agreement regarding the treatment of wholesale electric sales margins. The settlement is with five intervenor groups, including the Office of Attorney General and a large industrial customer group.
The settlement resolves recommendations of most parties regarding the treatment of wholesale electric sales margins. Significant components of the settlement agreement are as follows:
· No credit to base electric rates for wholesale electric sales margins;
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· Wholesale electric sales margins derived from excess generation capacity will be flowed through the FCA as an offset to fuel and energy costs;
· 80 percent of wholesale margins derived from the sales from NSP-Minnesota’s ancillary services obligations (e.g. spinning reserves) will be flowed through the FCA as an offset to fuel and energy costs and NSP-Minnesota will retain 20 percent; and
· 25 percent of proprietary margins, sales that do not arise from the use of NSP-Minnesota generating assets, will be flowed through the FCA as an offset to fuel and energy costs, and 75 percent will be retained by NSP-Minnesota.
The settlement agreement is pending approval by the MPUC and will be considered in the MPUC’s determination of NSP-Minnesota’s overall requested increase.
On July 6, 2006, the administrative law judge (ALJ) recommended an overall increase in revenues for the 2006 test year of approximately $135 million. For 2007, the ALJ recommended the increase be revised downward to $119 million to reflect the increased revenues expected due to the return of Flint Hills, an oil refinery, as a full-requirements customer. The MPUC is expected to hold oral arguments in August 2006 and issue its final order in September 2006.
Excelsior Energy — In December 2005, Excelsior Energy Inc., an independent energy developer, filed for approval of a proposed power purchase agreement with NSP-Minnesota for its proposed integrated gas combined cycle (IGCC) plant to be located in northern Minnesota. Excelsior Energy filed this petition pursuant to Minnesota law, which provides certain considerations for a qualifying Innovative Energy Project, subject to MPUC public interest determinations. Excelsior Energy asked the MPUC to open a contested case proceeding to:
· approve, disapprove, amend, or modify the terms and conditions of Excelsior Energy’s proposed power purchase agreement;
· determine that Excelsior Energy’s coal-fueled IGCC plant is, or is likely to be, a least-cost resource, obligating NSP-Minnesota to use the plant’s generation for at least 2 percent of the energy supplied to its retail customers; and
· determine that at least 13 percent of the energy supplied to NSP-Minnesota retail customers should come from the IGCC plant by 2013.
The MPUC referred this matter to a contested case hearing to develop the facts and issues that must be resolved to act on Excelsior’s petition, including development of as much contract price information as possible. The contested case proceeding is scheduled to consider a 603 megawatt unit in phase I of the proceedings, which are currently underway, and consider a second 603 megawatt unit in phase II of the proceedings, which are scheduled to begin in 2007. A report from the administrative law judges (ALJs) on phase I is expected in early 2007 and a report from the ALJs on phase II is expected in summer 2007. NSP-Minnesota anticipates opposing or seeking significant modification of Excelsior Energy’s petition and power purchase agreement. NSP-Minnesota will request that all costs associated with the proposed power purchase agreement, if approved, will be recoverable in customer rates.
NSP 2004 Resource Plan - On Nov. 1, 2004, NSP-Minnesota filed its proposed resource plan for the period 2005 through 2019. The proposed plan identified needed resources and proposed processes for acquiring resources to meet those needs, which included the need for base load capacity beginning 2013. A series of comments and replies occurred on both the proposed plan and the proposed resource acquisition processes. On July 28, 2006, the MPUC issued an order that, among other things:
· Approves NSP-Minnesota’s proposal to proceed with a request for proposal for 136 megawatts of peaking resources with an intended in service date of 2011;
· Identifies a base load resource need of 375 megawatts beginning in 2015 and requires NSP-Minnesota to file a certificate of need application for a proposed base load resource to begin the acquisition process by Nov. 1, 2006;
· Requires NSP-Minnesota to file for any mandatory Commission review or approvals of proposed upgrades to existing base load and nuclear power plants (Sherco, Prairie Island and Monticello) by Dec. 31, 2006;
· Approves an acquisition of 1,680 megawatts of wind generation resource over the planning period; and
· Accepts the proposed increases in demand-side management and energy-savings goals.
3. Commitments and Contingent Liabilities
Environmental Contingencies
NSP-Minnesota has been or is currently involved with the cleanup of contamination from certain hazardous substances at several sites. In many situations, NSP-Minnesota is pursuing, or intends to pursue, insurance claims and believes it will recover some portion of these costs through such claims. Additionally, where applicable, NSP-Minnesota is pursuing, or intends to pursue, recovery from other potentially responsible parties and through the rate regulatory process. New and changing federal and state environmental mandates can also create added financial liabilities for NSP-Minnesota, which are normally recovered through the rate regulatory process.
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To the extent any costs are not recovered through the options listed above, NSP-Minnesota would be required to recognize an expense for such unrecoverable amounts in its Consolidated Financial Statements.
Regional Haze Rules in Minnesota - The U.S. Environmental Protection Agency (EPA) requires states to develop implementation plans to comply with regional haze rules that require emission controls, known as best available retrofit technology (BART), by December 2007. States are required to identify the facilities that will have to reduce emissions under BART and then set BART emissions limits for those facilities. Minnesota has begun implementing its BART strategy as the first step toward the December 2007 deadline. By Sept. 10, 2006, each BART-eligible source in Minnesota must perform and submit an analysis of the need for additional emission controls for sulfur dioxide (SO2) and/or nitrogen oxide (NOx). The Sherburne County (Sherco) generating plant is the only NSP-Minnesota facility that is required to perform such an analysis and may eventually be required to install additional emission controls. If required, controls must be installed by 2013.
Clean Air Interstate Rule — In March 2005, the EPA issued the Clean Air Interstate Rule (CAIR), which further regulates SO2 and NOx emissions. Under CAIR’s cap-and-trade structure, utilities can comply through capital investments in emission controls or purchase of emission “allowances” from other utilities making reductions on their systems. There is uncertainty concerning implementation of CAIR. States are required to develop implementation plans within 18 months of the issuance of the new rules and have a significant amount of discretion in the implementation details. Legal challenges to CAIR rules could alter their requirements and/or schedule. The uncertainty associated with the final CAIR rules makes it difficult to predict the ultimate amount and timing of capital expenditures and operating expenses.
On June 13, 2006, the Minnesota Pollution Control Agency (MPCA) issued a draft rule for implementing the CAIR in Minnesota, which further regulates SO2 and NOx emissions. This proposal would require more stringent emission reductions than the federal CAIR program, resulting in additional implementation costs. A stakeholder process is ongoing, and a proposed rule is expected in September 2006.
While NSP-Minnesota expects to comply with the new rules through a combination of additional capital investments in emission controls at various facilities and purchases of emission allowances, it is continuing to review the alternatives. NSP-Minnesota believes the cost of any required capital investment or allowance purchases will be recoverable from customers.
Clean Air Mercury Rule — In March 2005, the EPA issued the Clean Air Mercury Rule (CAMR), which regulates mercury emissions from power plants for the first time. NSP-Minnesota continues to evaluate the strategy for complying with CAMR. Compliance may be achieved by either adding mercury controls or purchasing allowances or a combination of both. The capital cost is estimated at $9.0 million for the mercury control equipment.
Minnesota Mercury Legislation — The Governor of Minnesota signed mercury reduction legislation in 2006. This legislation requires the installation of mercury monitoring equipment by July 1, 2007; submittal of mercury emission reduction plans for dry scrubbed units by Dec. 31, 2007 and for wet scrubbed units by Dec. 31, 2009; and installation of mercury emission control equipment at NSP-Minnesota’s Allen S. King and Sherco generating facilities in Minnesota. Mercury emission control equipment must be installed on unit 3 of Sherco and at Allen S. King by Dec. 31, 2009 and Dec. 31, 2010. Sherco units 1 and 2 modifications are required by Dec. 31, 2014. The cost of controls will be determined as part of the engineering analysis portion of the mercury reduction plans and is not currently estimable. The legislation includes full and timely cost recovery provisions for both the costs of complying with this statute and any federal and state environmental regulations effective after Dec. 31, 2004.
Legal Contingencies
Lawsuits and claims arise in the normal course of business. Management, after consultation with legal counsel, has recorded an estimate of the probable cost of settlement or other disposition of them. The ultimate outcome of these matters cannot presently be determined. Accordingly, the ultimate resolution of these matters could have a material adverse effect on NSP-Minnesota’s financial position and results of operations.
Metropolitan Airports Commission vs. Northern States Power Company — On Dec. 30, 2004, the Metropolitan Airports Commission (MAC) filed a complaint in Minnesota state district court in Hennepin County asserting that NSP-Minnesota is required to relocate facilities on MAC property at the expense of NSP-Minnesota. MAC claims that approximately $7.1 million charged by NSP-Minnesota over the past five years for relocation costs should be repaid. Both parties asserted cross motions for partial summary judgment on a separate and less significant claim concerning legal obligations associated with rent payments allegedly due and owing by NSP-Minnesota to MAC for the use of its property for a substation that serves the MAC. A hearing regarding these cross motions was held in January 2006. In February 2006, the court granted MAC’s motion on this issue, finding that there was a valid lease and that the past course of action between the parties required NSP-Minnesota to continue such payments. NSP-Minnesota had made rent payments for 45 years. Depositions of key witnesses took place in February, March, and April of 2006. The parties entered into
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meaningful settlement negotiations in May 2006, and such negotiations are ongoing. Trial remains set for August 2006, but is likely to be continued due to ongoing negotiations. If settlement discussions are not productive, additional summary judgment motions are likely prior to trial.
Hoffman vs. Northern States Power Company — On March 15, 2006, a purported class action complaint was filed in Minnesota state district court Hennepin County on behalf of NSP-Minnesota’s residential customers in Minnesota, North Dakota and South Dakota for alleged breach of a contractual obligation to maintain and inspect the points of connection between NSP-Minnesota’s wires and customers’ homes within the meter box. Plaintiffs claim NSP-Minnesota’s breach results in an increased risk of fire and is in violation of tariffs on file with the MPUC. Plaintiffs seek injunctive relief and damages in an amount equal to the value of inspections plaintiffs claim NSP-Minnesota was required to perform over the past six years. NSP-Minnesota has filed a motion for dismissal on the pleadings, scheduled to be heard on August 16, 2006.
Comer vs. Xcel Energy Inc. et al. — On April 25, 2006, Xcel Energy received notice of a purported class action lawsuit filed in United States District Court for the Southern District of Mississippi. Although NSP-Minnesota is not named as a party to this litigation, if the litigation ultimately results in an unfavorable outcome for Xcel Energy, it could have a material adverse effect on NSP-Minnesota. The lawsuit names more than 45 oil, chemical and utility companies, including Xcel Energy, as defendants and alleges that defendants’ carbon dioxide emissions “were a proximate and direct cause of the increase in the destructive capacity of Hurricane Katrina.” Plaintiffs allege in support of their claim, several legal theories, including negligence, and public and private nuisance and seek damages related to the hurricane. Xcel Energy believes this lawsuit is without merit and intends to vigorously defend itself against these claims. On July 19, 2006, Xcel Energy filed a motion to dismiss the lawsuit in its entirety.
NewMech vs. Northern States Power Company --- On May 16, 2006, NewMech served and filed a complaint against NSP-Minnesota, Southern Minnesota Municipal Power Agency (SMMPA), and Benson Engineering in the Minnesota State District Court, Sherburne County, alleging entitlement to payment in the amount of approximately $4.2 million for unpaid costs allegedly associated with construction work done by NewMech at NSP-Minnesota and SMMPA’s jointly owned Sherco 3 generating plant in 2005. NewMech had previously served a mechanic’s lien, and seeks, through this action, foreclosure of the lien and sale of the property. NewMech additionally seeks the claimed damages as a result of an alleged breach of contract by NSP-Minnesota. NSP-Minnesota, SMMPA and Benson have filed answers denying NewMech’s allegations. Additionally, NSP-Minnesota and SMMPA have counterclaimed for damages in excess of $7 million for breach of contract, delay in contract performance, misrepresentation and fraudulent inducement to enter into the contract, and slander of title.
Carbon Dioxide Emissions Lawsuit — On July 21, 2004, the attorneys general of eight states and New York City, as well as several environmental groups, filed lawsuits in U.S. District Court for the Southern District of New York against five utilities, including Xcel Energy, to force reductions in carbon dioxide (CO2) emissions. Although NSP-Minnesota is not named as a party to this litigation, the requested relief that Xcel Energy cap and reduce its CO2 emissions could have a material adverse effect on NSP-Minnesota. The other utilities include American Electric Power Co., Southern Co., Cinergy Corp. and Tennessee Valley Authority. CO2 is emitted whenever fossil fuel is combusted, such as in automobiles, industrial operations and coal- or gas-fired power plants. The lawsuits allege that CO2 emitted by each company is a public nuisance as defined under state and federal common law because it has contributed to global warming. The lawsuits do not demand monetary damages. Instead, the lawsuits ask the court to order each utility to cap and reduce its CO2 emissions. In October 2004, Xcel Energy and four other utility companies filed a motion to dismiss the lawsuit, contending, among other reasons, that the lawsuit is an attempt to usurp the policy-setting role of the U.S. Congress and the president. On Sept. 19, 2005, the judge granted the defendants’ motion to dismiss on constitutional grounds. Plaintiffs filed an appeal to the Second Circuit. Oral arguments were presented on June 7, 2006 and a decision on the appeal is pending.
Other Contingencies
Except as set forth above, the circumstances in Notes 10, 11 and 12 to the Consolidated Financial Statements in NSP-Minnesota’s Annual Report on Form 10-K for the year ended Dec. 31, 2005 and Note 2 of this Quarterly Report on Form 10-Q appropriately represent, in all material respects, the current status of commitments and contingent liabilities, including those regarding public liability for claims resulting from any nuclear incident and are incorporated herein by reference.
4. Long-term Debt
On May 25, 2006, NSP-Minnesota issued $400 million of 6.25 percent first mortgage bonds, series due June 1, 2036. NSP-Minnesota added the net proceeds from the sale of the first mortgage bonds to its general funds and applied a portion of the proceeds to the repayment at maturity of $200 million aggregate principal amount of its 2.875 percent first mortgage bonds, Series due Aug. 1, 2006. It plans to apply additional proceeds to the repayment at maturity of $2,420,000 aggregate principal amount of the Ramsey County, Minnesota and the County of Washington, Minnesota 4.10 percent Resource Recovery Refunding Revenue Bonds (Northern States Power Company Project), Collateralized Series 1999 due Dec. 1, 2006 issued for NSP-Minnesota’s benefit and secured by a series of
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its first mortgage bonds; and $2,365,000 aggregate principal amount of the County of Anoka, Minnesota 5.0 percent Resource Recovery Refunding Revenue Bonds (Northern States Power Company Project), Collateralized Series 1999 due Dec. 1, 2006 issued for NSP-Minnesota’s benefit and secured by a series of its first mortgage bonds.
5. Derivative Valuation and Financial Impacts
NSP-Minnesota uses a number of different derivative instruments in connection with its utility commodity price, interest rate, short-term wholesale and commodity trading activities, including forward contracts, futures, swaps and options.
All derivative instruments not qualifying for the normal purchases and normal sales exception, as defined by SFAS No. 133 -”Accounting for Derivative Instruments and Hedging Activities,” as amended (SFAS No. 133), are recorded at fair value. The presentation of these derivative instruments is dependent on the designation of a qualifying hedging relationship. The adjustment to fair value of derivative instruments not designated in a qualifying hedging relationship is reflected in current earnings or as a regulatory balance. This classification is dependent on the applicability of any regulatory mechanism in place. This includes certain instruments used to mitigate market risk for NSP-Minnesota and all instruments related to the commodity trading operations. The designation of a cash flow hedge permits the classification of fair value to be recorded within Other Comprehensive Income, to the extent effective. The designation of a fair value hedge permits a derivative instrument’s gains or losses to offset the related results of the hedged item in the Consolidated Statements of Income.
NSP-Minnesota records the fair value of its derivative instruments in its Consolidated Balance Sheets as separate line items identified as Derivative Instruments Valuation in both current and noncurrent assets and liabilities.
The fair value of all interest rate swaps is determined through counterparty valuations, internal valuations and broker quotes. There have been no material changes in the techniques or models used in the valuation of interest rate swaps during the periods presented.
Qualifying hedging relationships are designated as either a hedge of a forecasted transaction or future cash flow (cash flow hedge), or a hedge of a recognized asset, liability or firm commitment (fair value hedge). The types of qualifying hedging transactions that NSP-Minnesota is currently engaged in are discussed below.
Cash Flow Hedges
NSP-Minnesota enters into derivative instruments to manage variability of future cash flows from changes in commodity prices and interest rates. These derivative instruments are designated as cash flow hedges for accounting purposes, and the changes in the fair value of these instruments are recorded as a component of Other Comprehensive Income.
At June 30, 2006, NSP-Minnesota had various commodity-related contracts designated as cash flow hedges extending through March 2007. The fair value of these cash flow hedges is recorded in either Other Comprehensive Income or deferred as a regulatory asset or liability. This classification is based on the regulatory recovery mechanisms in place. Amounts deferred in these accounts are recorded in earnings as the hedged purchase or sales transaction is settled. This could include the purchase or sale of energy or energy-related products, the use of natural gas to generate electric energy or gas purchased for resale. As of June 30, 2006, NSP-Minnesota had no amounts in Accumulated Other Comprehensive Income related to commodity cash flow hedge contracts that are expected to be recognized in earnings during the next 12 months as the hedged transactions settle.
NSP-Minnesota enters into various instruments that effectively fix the interest payments on certain floating rate debt obligations or effectively fix the yield or price on a specified benchmark interest rate for a specific period. These derivative instruments are designated as cash flow hedges for accounting purposes and the change in the fair value of these instruments is recorded as a component of Other Comprehensive Income. As of June 30, 2006, NSP-Minnesota had net gains of $0.3 million in Accumulated Other Comprehensive Income that it expects to recognize in earnings during the next 12 months.
Gains or losses on hedging transactions for the sales of energy or energy-related products are primarily recorded as a component of revenue, hedging transactions for fuel used in energy generation are recorded as a component of fuel costs, hedging transactions for gas purchased for resale are recorded as a component of gas costs and interest rate hedging transactions are recorded as a component of interest expense. NSP-Minnesota is allowed to recover in electric and natural gas rates the costs of certain financial instruments acquired to reduce commodity cost volatility. There was no hedge ineffectiveness in the second quarter of 2006.
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The impact of the qualifying cash flow hedges on NSP-Minnesota’s Other Comprehensive Income, included as a component of stockholder’s equity, are detailed in the following table:
| | Six months ended June 30, | |
(Millions of dollars) | | 2006 | | 2005 | |
| | | | | |
Accumulated other comprehensive income related to cash flow hedges at Jan. 1 | | $ | — | | $ | — | |
After-tax net unrealized gains related to derivatives accounted for as hedges | | 9.7 | | — | |
After-tax net realized losses on derivative transactions reclassified into earnings | | — | | — | |
Accumulated other comprehensive income related to cash flow hedges at June 30 | | $ | 9.7 | | $ | — | |
Fair Value Hedges
The effective portion of the change in the fair value of a derivative instrument qualifying as a fair value hedge is offset against the change in the fair value of the underlying asset, liability or firm commitment being hedged. That is, fair value hedge accounting allows the gains or losses of the derivative instrument to offset, in the same period, the gains and losses of the hedged item.
Derivatives Not Qualifying for Hedge Accounting
NSP-Minnesota has commodity trading operations that enter into derivative instruments. These derivative instruments are accounted for on a mark-to-market basis in the Consolidated Statements of Income. The results of these transactions are recorded on a net basis within Operating Revenues on the Consolidated Statements of Income.
NSP-Minnesota may also enter into certain commodity-based derivative transactions not included in trading operations, which do not qualify for hedge accounting treatment. These derivative instruments are accounted for on a mark-to-market basis in accordance with SFAS No. 133.
Normal Purchases or Normal Sales Contracts
NSP-Minnesota enters into contracts for the purchase and sale of various commodities for use in its business operations. SFAS No. 133 requires a company to evaluate these contracts to determine whether the contracts are derivatives. Certain contracts that literally meet the definition of a derivative may be exempted from SFAS No. 133 as normal purchases or normal sales. Normal purchases and normal sales are contracts that provide for the purchase or sale of something other than a financial or derivative instrument that will be delivered in quantities expected to be used or sold over a reasonable period in the normal course of business. In addition, normal purchases and normal sales contracts must have a price based on an underlying that is clearly and closely related to the asset being purchased or sold. An underlying is a specified interest rate, security price, commodity price, foreign exchange rate, index of prices or rates, or other variable, including the occurrence or nonoccurrence of a specified event, such as a scheduled payment under a contract.
NSP-Minnesota evaluates all of its contracts when such contracts are entered to determine if they are derivatives and, if so, if they qualify to meet the normal designation requirements under SFAS No. 133. None of the contracts entered into within the commodity trading operations qualify for a normal designation.
In 2003, as a result of FASB Statement 133 Implementation Issue No. C20, NSP-Minnesota began recording several long-term power purchase agreements at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During the first quarter of 2006, NSP-Minnesota qualified these contracts under the normal purchase exception. Based on this qualification, the contracts will no longer be adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory balances.
Normal purchases and normal sales contracts are accounted for as executory contracts as required under other generally accepted accounting principles.
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6. Detail of Interest and Other Income - - Net
Interest and other income, net of nonoperating expenses, for the three and six months ended June 30 consisted of the following:
| | Three months ended June 30, | | Six months ended June 30, | |
(Thousands of dollars) | | 2006 | | 2005 | | 2006 | | 2005 | |
Interest income | | $ | 3,921 | | $ | 1,908 | | $ | 5,808 | | $ | 3,403 | |
Equity income in unconsolidated affiliates | | 294 | | 75 | | 559 | | 164 | |
Other nonoperating income | | 59 | | 857 | | 146 | | 886 | |
Loss on disposal of investments | | (109 | ) | — | | (218 | ) | — | |
Other nonoperating loss | | — | | (146 | ) | — | | (292 | ) |
Employee-related insurance policy expenses | | (1,335 | ) | (1,344 | ) | (2,588 | ) | (2,674 | ) |
Total interest and other income — net | | $ | 2,830 | | $ | 1,350 | | $ | 3,707 | | $ | 1,487 | |
7. Segment Information
NSP-Minnesota has two reportable segments, Regulated Electric Utility and Regulated Natural Gas Utility. Commodity trading operations are not a reportable segment and are included in the Regulated Electric Utility segment.
(Thousands of dollars) | | Regulated
Electric Utility | | Regulated
Natural Gas
Utility | | All Other | | Reconciling
Eliminations | | Consolidated
Total | |
Three months ended June 30, 2006 | | | | | | | | | | | |
Revenues from: | | | | | | | | | | | |
External customers | | $ | 732,723 | | $ | 92,179 | | $ | 4,443 | | $ | — | | $ | 829,345 | |
Internal customers | | 137 | | 631 | | — | | (768 | ) | — | |
Total revenue | | $ | 732,860 | | $ | 92,810 | | $ | 4,443 | | $ | (768 | ) | $ | 829,345 | |
Segment net income (loss) | | $ | 34,301 | | $ | (4,695 | ) | $ | 514 | | $ | — | | $ | 30,120 | |
| | | | | | | | | | | |
Three months ended June 30, 2005 | | | | | | | | | | | |
Revenues from: | | | | | | | | | | | |
External customers | | $ | 741,305 | | $ | 107,757 | | $ | 5,503 | | $ | — | | $ | 854,565 | |
Internal customers | | (103 | ) | 3,499 | | — | | (3,396 | ) | — | |
Total revenue | | $ | 741,202 | | $ | 111,256 | | $ | 5,503 | | $ | (3,396 | ) | $ | 854,565 | |
Segment net income (loss) | | $ | 32,244 | | $ | (2,674 | ) | $ | 163 | | $ | — | | $ | 29,733 | |
(Thousands of dollars) | | Regulated
Electric Utility | | Regulated
Natural Gas
Utility | | All Other | | Reconciling
Eliminations | | Consolidated
Total | |
Six months ended June 30, 2006 | | | | | | | | | | | |
Revenues from: | | | | | | | | | | | |
External customers | | $ | 1,453,127 | | $ | 454,143 | | $ | 9,788 | | $ | — | | $ | 1,917,058 | |
Internal customers | | 206 | | 1,552 | | — | | (1,758 | ) | — | |
Total revenue | | $ | 1,453,333 | | $ | 455,695 | | $ | 9,788 | | $ | (1,758 | ) | $ | 1,917,058 | |
Segment net income | | $ | 74,265 | | $ | 10,986 | | $ | 3,811 | | $ | — | | $ | 89,062 | |
| | | | | | | | | | | |
Six months ended June 30, 2005 | | | | | | | | | | | |
Revenues from: | | | | | | | | | | | |
External customers | | $ | 1,359,882 | | $ | 427,325 | | $ | 10,829 | | $ | — | | $ | 1,798,036 | |
Internal customers | | 175 | | 4,507 | | — | | (4,682 | ) | — | |
Total revenue | | $ | 1,360,057 | | $ | 431,832 | | $ | 10,829 | | $ | (4,682 | ) | $ | 1,798,036 | |
Segment net income | | $ | 48,376 | | $ | 20,529 | | $ | 2,455 | | $ | — | | $ | 71,360 | |
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8. Comprehensive Income
The components of total comprehensive income are shown below:
| | Three months ended
June 30, | | Six months ended
June 30, | |
(Millions of dollars) | | 2006 | | 2005 | | 2006 | | 2005 | |
| | | | | | | | | |
Net income | | $ | 30.1 | | $ | 29.7 | | $ | 89.1 | | $ | 71.4 | |
Other comprehensive income: | | | | | | | | | |
After-tax net unrealized gains related to derivatives accounted for as hedges (see Note 5) | | 9.7 | | — | | 9.7 | | — | |
After-tax net realized losses (gains) on derivative transactions reclassified into earnings (see Note 5) | | — | | — | | — | | — | |
Other comprehensive income | | 9.7 | | — | | 9.7 | | — | |
Comprehensive income | | $ | 39.8 | | $ | 29.7 | | $ | 98.8 | | $ | 71.4 | |
The accumulated comprehensive income in stockholder’s equity at June 30, 2006 and Dec. 31, 2005, relates to valuation adjustments on NSP-Minnesota’s derivative financial instruments and hedging activities.
9. Benefit Plans and Other Postretirement Benefits
Pension and other postretirement benefit disclosures below generally represent Xcel Energy consolidated information unless specifically identified as being attributable to NSP-Minnesota.
Components of Net Periodic Benefit Cost
| | Three months ended June 30, | |
| | 2006 | | 2005 | | 2006 | | 2005 | |
(Thousands of dollars) | | Pension Benefits | | Postretirement Health
Care Benefits | |
Xcel Energy Inc. | | | | | | | | | |
Service cost | | $ | 14,380 | | $ | 12,980 | | $ | 1,479 | | $ | 1,599 | |
Interest cost | | 38,197 | | 39,496 | | 13,287 | | 13,663 | |
Expected return on plan assets | | (67,551 | ) | (69,484 | ) | (7,110 | ) | (6,267 | ) |
Amortization of transition obligation | | — | | — | | 3,577 | | 3,644 | |
Amortization of prior service cost (credit) | | 7,421 | | 7,496 | | (545 | ) | (544 | ) |
Amortization of net (gain) loss | | 4,165 | | (39 | ) | 5,875 | | 6,460 | |
Net periodic benefit cost (credit) | | (3,388 | ) | (9,551 | ) | 16,563 | | 18,555 | |
Credits not recognized due to the effects of regulation | | 3,893 | | 6,500 | | — | | — | |
Additional cost recognized due to the effects of regulation | | — | | — | | 973 | | 973 | |
Net benefit cost (credit) recognized for financial reporting | | $ | 505 | | $ | (3,051 | ) | $ | 17,536 | | $ | 19,528 | |
| | | | | | | | | |
NSP-Minnesota | | | | | | | | | |
Net periodic benefit cost (credit) | | $ | (3,564 | ) | $ | (6,281 | ) | $ | 4,415 | | $ | 4,378 | |
Additional cost recognized due to the effects of regulation | | 3,894 | | 6,500 | | — | | — | |
Net benefit cost recognized for financial reporting | | $ | 330 | | $ | 219 | | $ | 4,415 | | $ | 4,378 | |
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| | Six months ended June 30, | |
| | 2006 | | 2005 | | 2006 | | 2005 | |
(Thousands of dollars) | | Pension Benefits | | Postretirement Health
Care Benefits | |
Xcel Energy Inc. | | | | | | | | | |
Service cost | | $ | 30,814 | | $ | 30,230 | | $ | 3,316 | | $ | 3,342 | |
Interest cost | | 77,706 | | 80,492 | | 26,470 | | 27,530 | |
Expected return on plan assets | | (134,032 | ) | (139,758 | ) | (13,378 | ) | (12,850 | ) |
Amortization of transition obligation | | — | | — | | 7,222 | | 7,289 | |
Amortization of prior service cost (credit) | | 14,848 | | 15,018 | | (1,090 | ) | (1,089 | ) |
Amortization of net loss | | 8,676 | | 3,410 | | 12,398 | | 13,123 | |
Net periodic benefit cost (credit) | | (1,988 | ) | (10,608 | ) | 34,938 | | 37,345 | |
Credits not recognized due to the effects of regulation | | 6,318 | | 9,684 | | — | | — | |
Additional cost recognized due to the effects of regulation | | — | | — | | 1,946 | | 1,946 | |
Net benefit cost (credit) recognized for financial reporting | | $ | 4,330 | | $ | (924 | ) | $ | 36,884 | | $ | 39,291 | |
| | | | | | | | | |
NSP-Minnesota | | | | | | | | | |
Net periodic benefit cost (credit) | | $ | (5,687 | ) | $ | (9,181 | ) | $ | 8,577 | | $ | 8,785 | |
Additional cost recognized due to the effects of regulation | | 6,319 | | 9,684 | | — | | — | |
Net benefit cost recognized for financial reporting | | $ | 632 | | $ | 503 | | $ | 8,577 | | $ | 8,785 | |
Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Discussion of financial condition and liquidity for NSP-Minnesota is omitted per conditions set forth in general instructions H (1) (a) and (b) of Form 10-Q for wholly owned subsidiaries. It is replaced with management’s narrative analysis and the results of operations set forth in general instructions H (2) (a) of Form 10-Q for wholly owned subsidiaries (reduced disclosure format).
Forward-Looking Information
The following discussion and analysis by management focuses on those factors that had a material effect on the financial condition and results of operations of NSP-Minnesota during the periods presented, or are expected to have a material impact in the future. It should be read in conjunction with the accompanying unaudited financial statements and notes.
Except for the historical statements contained in this report, the matters discussed in the following discussion and analysis are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words “anticipate,” “estimate,” “expect,” “objective,” “outlook,” “possible,” “potential” and similar expressions. Actual results may vary materially. Factors that could cause actual results to differ materially include, but are not limited to:
· Economic conditions, including their impact on capital expenditures and the ability of NSP-Minnesota to obtain financing on favorable terms, inflation rates and monetary fluctuations;
· Business conditions in the energy business;
· Trade, monetary, fiscal, taxation and environmental policies of governments, agencies and similar organizations in geographic areas where NSP-Minnesota has a financial interest;
· Customer business conditions, including demand for their products or services and supply of labor and materials used in creating their products and services;
· Financial or regulatory accounting principles or policies imposed by the Financial Accounting Standards Board, the Securities and Exchange Commission, the Federal Energy Regulatory Commission and similar entities with regulatory oversight;
· Availability or cost of capital such as changes in: interest rates; market perceptions of the utility industry, NSP-Minnesota, Xcel Energy or any of its other subsidiaries; or security ratings;
· Factors affecting utility operations such as unusual weather conditions; catastrophic weather-related damage; unscheduled generation outages, maintenance or repairs; unanticipated changes to fossil fuel, nuclear fuel or natural gas supply costs or availability due to higher demand, shortages, transportation problems or other developments; nuclear or environmental incidents; or electric transmission or natural gas pipeline constraints;
· Employee workforce factors, including loss or retirement of key executives, collective bargaining agreements with union employees, or work stoppages;
· Increased competition in the utility industry;
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· State and federal legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rate structures and affect the speed and degree to which competition enters the electric and natural gas markets; industry restructuring initiatives; transmission system operation and/or administration initiatives; recovery of investments made under traditional regulation; nature of competitors entering the industry; retail wheeling; a new pricing structure; and former customers entering the generation market;
· Rate-setting policies or procedures of regulatory entities, including environmental externalities, which are values established by regulators assigning environmental costs to each method of electricity generation when evaluating generation resource options;
· Nuclear regulatory policies and procedures, including operating regulations and spent nuclear fuel storage;
· Social attitudes regarding the utility and power industries;
· Cost and other effects of legal and administrative proceedings, settlements, investigations and claims;
· Technological developments that result in competitive disadvantages and create the potential for impairment of existing assets;
· Significant slowdown in growth or decline in the U.S. economy, delay in growth or recovery of the U.S. economy or increased cost for insurance premiums, security and other items;
· Other business or investment considerations that may be disclosed from time to time in NSP-Minnesota’s SEC filings, including “Risk Factors” in Item 1A of NSP-Minnesota’s Annual Report on Form 10-K for the year ended Dec. 31, 2005 and Exhibit 99.01 to this report on Form 10-Q for the quarter ended June 30, 2006.
Market Risks
NSP-Minnesota is exposed to market risks, including changes in commodity prices and interest rates, as disclosed in Item 7A — Quantitative and Qualitative Disclosures About Market Risk in its Annual Report on Form 10-K for the year ended Dec. 31, 2005. Commodity price and interest rate risks for NSP-Minnesota are mitigated in most jurisdictions due to cost-based rate regulation. At June 30, 2006, there were no material changes to the financial market risks that affect the quantitative and qualitative disclosures presented as of Dec. 31, 2005.
NSP-Minnesota maintains trust funds, as required by the Nuclear Regulatory Commission, to fund certain costs of nuclear decommissioning. Those investments are exposed to price fluctuations in equity markets and changes in interest rates. However, because the costs of nuclear decommissioning are recovered through NSP-Minnesota rates, fluctuations in investment fair value do not affect NSP-Minnesota’s consolidated results of operations.
RESULTS OF OPERATIONS
NSP-Minnesota’s net income was approximately $89.1 million for the first six months of 2006, compared with approximately $71.4 million for the first six months of 2005.
Electric Utility, Short-term Wholesale and Commodity Trading Margins — Electric fuel and purchased power expense tend to vary with changing retail and wholesale sales requirements and unit cost changes in fuel and purchased power. Due to fuel cost recovery mechanisms for retail customers, most fluctuations in energy costs do not significantly affect electric utility margin.
NSP-Minnesota has two distinct forms of wholesale sales: short-term wholesale and commodity trading. Short-term wholesale refers to energy related purchase and sales activity, and the use of certain financial instruments associated with the fuel required for, and energy produced from, NSP-Minnesota’s generation assets and energy and capacity purchased to serve native load. Commodity trading is not associated with NSP-Minnesota’s generation assets or the energy or capacity purchased to serve native load. Short-term wholesale and commodity trading activities are considered part of the electric utility segment.
Margins from commodity trading activity conducted at NSP-Minnesota are partially redistributed to Public Service Company of Colorado and Southwestern Public Service Company, both wholly owned subsidiaries of Xcel Energy, pursuant to the joint operating agreement (JOA) approved by the FERC. Margins received pursuant to the JOA are reflected as part of Base Electric Utility Revenue. Trading revenues are reported net of related costs in the Consolidated Statements of Income. Commodity trading costs include purchased power, transmission, broker fees and other related costs. Short-term wholesale and commodity trading margins reflect the estimated impact of regulatory sharing of realized margins, if applicable.
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The following table details base electric utility, short-term wholesale and commodity trading revenue and margin:
(Millions of dollars) | | Base
Electric
Utility | | Short-term
Wholesale | | Commodity
Trading | | Consolidated
Total | |
Six months ended June 30, 2006 | | | | | | | | | |
Electric utility revenue (excluding commodity trading) | | $ | 1,393 | | $ | 59 | | $ | — | | $ | 1,452 | |
Electric fuel and purchased power | | (552 | ) | (53 | ) | — | | (605 | ) |
Commodity trading revenue | | — | | — | | 53 | | 53 | |
Commodity trading costs | | — | | — | | (52 | ) | (52 | ) |
Gross margin before operating expenses | | $ | 841 | | $ | 6 | | $ | 1 | | $ | 848 | |
Margin as a percentage of revenue | | 60.4 | % | 10.2 | % | 1.9 | % | 56.3 | % |
| | | | | | | | | |
Six months ended June 30, 2005 | | | | | | | | | |
Electric utility revenue (excluding commodity trading) | | $ | 1,274 | | $ | 85 | | $ | — | | $ | 1,359 | |
Electric fuel and purchased power | | (532 | ) | (46 | ) | — | | (578 | ) |
Commodity trading revenue | | — | | — | | 85 | | 85 | |
Commodity trading costs | | — | | — | | (84 | ) | (84 | ) |
Gross margin before operating expenses | | $ | 742 | | $ | 39 | | $ | 1 | | $ | 782 | |
Margin as a percentage of revenue | | 58.2 | % | 45.9 | % | 1.2 | % | 54.2 | % |
The following summarizes the components of the changes in base electric revenue and base electric margin for the six months ended June 30:
Base Electric Revenue
(Millions of dollars) | | 2006 vs. 2005 | |
| | | |
Conservation and non-fuel rider revenues | | $ | 6 | |
Interim base rate changes | | 65 | |
Sales growth (excluding weather impact) | | 12 | |
Interchange agreement billing with NSP-Wisconsin | | 8 | |
MERP rider | | 18 | |
Estimated impact of weather | | (7 | ) |
Firm wholesale | | 13 | |
Transmission and other | | 4 | |
Total base electric revenue increase | | $ | 119 | |
Base Electric Margin
(Millions of dollars) | | 2006 vs. 2005 | |
| | | |
Interim base rate changes | | $ | 65 | |
Sales growth (excluding weather impact) | | 9 | |
MERP rider | | 18 | |
Conservation and non-fuel rider revenues | | 6 | |
Estimated impact of weather | | (6 | ) |
Interchange agreement billing with NSP-Wisconsin | | 7 | |
Interchange agreement billing — obligation load true-up | | (5 | ) |
Firm wholesale | | 8 | |
Transmission and other | | (3 | ) |
Total base electric margin increase | | $ | 99 | |
On Jan. 1, 2006, an interim rate increase for NSP-Minnesota of $147 million, subject to refund, in Minnesota went into effect. In March 2006, the MPUC approved a new depreciation order, which lowered decommissioning accruals for 2006 from anticipated levels. Due to the seasonality of sales, the rate increase will not be recognized ratably throughout 2006.
Short-term wholesale margins decreased approximately $33 million for the first six months of 2006, compared with the same period in 2005. As expected, short-term margins declined due to retail sales growth, which reduced surplus generation available for sale in the wholesale market, and decreased opportunities to sell due to the MISO centralized dispatch market. In addition, during the second
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quarter of 2006 a $5.7 million charge was recorded to commodity trading margins for the estimated impact of a Federal Energy Regulatory Commission (FERC) order regarding the allocation of MISO charges to certain trading activities.
In addition, NSP-Minnesota entered into a wholesale electric sales margin settlement agreement in the second quarter of 2006 as part of the Minnesota rate case proceeding. The agreement is pending MPUC approval. The settlement agreement provides for a sharing of certain short-term wholesale and commodity trading margins with retail electric customers beginning Jan. 1, 2006. The financial impact of this agreement is reflected in the financial statements as of and for the period ended June 30, 2006.
Natural Gas Utility Margins — The following table details the change in natural gas revenue and margin. The cost of natural gas tends to vary with changing sales requirements and unit cost of natural gas purchases. However, due to purchased natural gas cost recovery mechanisms for retail customers, fluctuations in the cost of natural gas have little effect on natural gas margin.
| | Six months ended
June 30, | |
(Millions of dollars) | | 2006 | | 2005 | |
| | | | | |
Natural gas utility revenue | | $ | 454 | | $ | 427 | |
Cost of natural gas sold and transported | | (369 | ) | (340 | ) |
Natural gas utility margin | | $ | 85 | | $ | 87 | |
The following summarizes the components of the changes in natural gas revenue and margin for the six months ended June 30:
Natural Gas Revenue
(Millions of dollars) | | 2006 vs. 2005 | |
| | | |
Purchased gas adjustment clause recovery | | $ | 55 | |
Estimated impact of weather on firm sales volume | | (25 | ) |
Off-system sales | | (5 | ) |
Sales decline (excluding weather impact) | | (1 | ) |
Sales mix | | 2 | |
Transportation and other | | 1 | |
Total natural gas revenue increase | | $ | 27 | |
Natural Gas Margin
(Millions of dollars) | | 2006 vs. 2005 | |
| | | |
Sales mix | | $ | 1 | |
Estimated impact of weather on firm sales volume | | (4 | ) |
Off-system sales | | (1 | ) |
Transportation and other | | 2 | |
Total natural gas margin decrease | | $ | (2 | ) |
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Non-Fuel Operating Expense and Other Costs — The following summarizes the components of the changes in other utility operating and maintenance expense for the six months ended June 30:
(Millions of dollars) | | 2006 vs. 2005 | |
| | | |
Higher vegetation line clearance costs | | $ | 4 | |
Higher conservation incentive program costs | | 4 | |
Higher field operations labor costs | | 2 | |
Higher uncollectible receivable costs | | 1 | |
Higher information technology costs | | 1 | |
Higher severance costs | | 1 | |
Higher plant maintenance costs | | 1 | |
Higher brand sponsorship costs | | 1 | |
Lower nuclear plant costs | | (9 | ) |
Lower employee benefit costs | | (2 | ) |
Other | | 3 | |
Total other utility operating and maintenance expense increase | | $ | 7 | |
Depreciation and amortization expense increased by approximately $19.0 million, or 10.0 percent, for the first six months of 2006, compared with the first six months of 2005. The increase is due to normal plant additions and a recently approved change in decommissioning accruals resulting in an additional depreciation expense of $9.7 million year-to-date.
Income tax expense increased by approximately $ 14.5 million for the first six months of 2006 compared with the first six months of 2005. The effective tax rate was 34.8 percent for the first six months of 2006, compared with 31.6 percent for the same period in 2005. The increase in tax expense and the effective tax rate was primarily due to an increase in pretax income.
Item 4. CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
NSP-Minnesota maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms. In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the chief executive officer (CEO) and chief financial officer (CFO), allowing timely decisions regarding required disclosure. As of the end of the period covered by this report, based on an evaluation carried out under the supervision and with the participation of NSP-Minnesota’s management, including the CEO and CFO, of the effectiveness of our disclosure controls and procedures, the CEO and CFO have concluded that NSP-Minnesota’s disclosure controls and procedures are effective.
Internal Control Over Financial Reporting
No change in NSP-Minnesota’s internal control over financial reporting has occurred during the most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, NSP-Minnesota’s internal control over financial reporting.
Part II. OTHER INFORMATION
Item 1. LEGAL PROCEEDINGS
In the normal course of business, various lawsuits and claims have arisen against NSP-Minnesota. After consultation with legal counsel, NSP-Minnesota has recorded an estimate of the probable cost of settlement or other disposition for such matters. See Notes 2 and 3 of the Financial Statements in this Quarterly Report on Form 10-Q for further discussion of legal proceedings, including Regulatory Matters and Commitments and Contingent Liabilities, which are hereby incorporated by reference. Reference also is made to Item 3 and Note 11 of NSP-Minnesota’s Annual Report on Form 10-K for the year ended Dec. 31, 2005 for a description of certain legal proceedings presently pending. Except as discussed herein, there are no new significant cases to report against NSP-Minnesota and there have been no notable changes in the previously reported proceedings.
Item 1A. Risk Factors
NSP-Minnesota’s risk factors are documented in Item 1A of Part I of its 2005 Annual Report on Form 10-K, which is incorporated herein by reference. There have been no material changes to the risk factors.
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Item 6. EXHIBITS
The following Exhibits are filed with this report:
4.02 | | Supplemental Indenture, dated May 1, 2006, between Northern States Power Co. (a Minnesota corporation) and BNY Midwest Trust Company, as successor Trustee. (Exhibit 4.01 to NSP-Minnesota Form 8-K (file no. 001-31387) dated May 18, 2006). |
| | |
31.01 | | Principal Executive Officer’s and Principal Financial Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
| | |
32.01 | | Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
| | |
99.01 | | Statement pursuant to Private Securities Litigation Reform Act of 1995. |
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized on Aug. 4, 2006.
Northern States Power Co. (a Minnesota corporation)
(Registrant)
| | /s/ TERESA S. MADDEN | |
| | Teresa S. Madden |
| | Vice President and Controller |
| |
| | /s/ BENJAMIN G.S. FOWKE III | |
| | Benjamin G.S. Fowke III |
| | Vice President and Chief Financial Officer |
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