Income Taxes — Xcel Energy accounts for income taxes using the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. Xcel Energy defers income taxes for all temporary differences between pretax financial and taxable income, and between the book and tax bases of assets and liabilities. Xcel Energy uses the tax rates that are scheduled to be in effect when the temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date.
Deferred tax assets are reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of the deferred tax asset will not be realized. In making such a determination, all available positive and negative evidence, including scheduled reversals of deferred tax liabilities, projected future taxable income, tax planning strategies and recent financial operations, is considered.
Due to the effects of past regulatory practices, when deferred taxes were not required to be recorded, the reversal of some temporary differences are accounted for as current income tax expense. Investment tax credits are deferred and their benefits amortized over the book depreciable lives of the related property. Utility rate regulation also has resulted in the recognition of certain regulatory assets and liabilities related to income taxes, which are summarized in Note 15.
Xcel Energy follows the applicable accounting guidance to measure and disclose uncertain tax positions that it has taken or expects to take in its income tax returns. Xcel Energy recognizes a tax position in its consolidated financial statements when it is more likely than not that the position will be sustained upon examination based on the technical merits of the position. Recognition of changes in uncertain tax positions are reflected as a component of income tax.
Xcel Energy reports interest and penalties related to income taxes within the other income and interest charges sections in the consolidated statements of income.
Xcel Energy Inc. and its subsidiaries file consolidated federal income tax returns as well as combined or separate state income tax returns. Federal income taxes paid by Xcel Energy Inc., as parent of the Xcel Energy consolidated group, are allocated to Xcel Energy Inc.’s subsidiaries based on separate company computations of tax. A similar allocation is made for state income taxes paid by Xcel Energy Inc. in connection with combined state filings. Xcel Energy Inc. also allocates its own income tax benefits to its direct subsidiaries based on the relative positive tax liabilities of the subsidiaries.
See Note 6 for further discussion of income taxes.
Types of and Accounting for Derivative Instruments — Xcel Energy uses derivative instruments in connection with its interest rate, utility commodity price, vehicle fuel price, short-term wholesale and commodity trading activities, including forward contracts, futures, swaps and options. All derivative instruments not designated and qualifying for the normal purchases and normal sales exception, as defined by the accounting guidance for derivatives and hedging, are recorded on the consolidated balance sheets at fair value as derivative instruments. This includes certain instruments used to mitigate market risk for the utility operations and all instruments related to the commodity trading operations. The classification of changes in fair value for those derivative instruments is dependent on the designation of a qualifying hedging relationship. Changes in fair value of derivative instruments not designated in a qualifying hedging relationship are reflected in current earnings or as a regulatory asset or liability. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms.
Gains or losses on hedging transactions for the sale 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 natural gas purchased for resale are recorded as a component of natural gas costs; hedging transactions for vehicle fuel costs are recorded as a component of capital projects or O&M costs; and interest rate hedging transactions are recorded as a component of interest expense. Certain utility subsidiaries are allowed to recover in electric or natural gas rates the costs of certain financial instruments purchased to reduce commodity cost volatility.
Cash Flow Hedges — Certain qualifying hedging relationships are designated as a hedge of a forecasted transaction, or future cash flow (cash flow hedge). Changes in the fair value of a derivative designated as a cash flow hedge, to the extent effective, are included in OCI, or deferred as a regulatory asset or liability based on recovery mechanisms until earnings are affected by the hedged transaction.
Normal Purchases and Normal Sales — Xcel Energy enters into contracts for the purchase and sale of commodities for use in its business operations. Derivatives and hedging accounting guidance requires a company to evaluate these contracts to determine whether the contracts are derivatives. Certain contracts that meet the definition of a derivative may be exempted from derivative accounting as normal purchases or normal sales.
Xcel Energy evaluates all of its contracts at inception to determine if they are derivatives and if they meet the normal purchases and normal sales designation requirements. None of the contracts entered into within the commodity trading operations qualify for a normal purchases and normal sales designation.
See Note 11 for further discussion of Xcel Energy’s risk management and derivative activities.
Commodity Trading Operations — All applicable gains and losses related to commodity trading activities, whether or not settled physically, are shown on a net basis in electric operating revenues in the consolidated statements of income.
Xcel Energy’s commodity trading operations are conducted by NSP-Minnesota, PSCo and SPS. Commodity trading activities are not associated with energy produced from Xcel Energy’s generation assets or energy and capacity purchased to serve native load. Commodity trading contracts are recorded at fair market value and commodity trading results include the impact of all margin-sharing mechanisms. See Note 11 for further discussion.
Fair Value Measurements — Xcel Energy presents cash equivalents, interest rate derivatives, commodity derivatives and nuclear decommissioning fund assets at estimated fair values in its consolidated financial statements. Cash equivalents are recorded at cost plus accrued interest; money market funds are measured using quoted net asset values. For interest rate derivatives, quoted prices based primarily on observable market interest rate curves are used as a primary input to establish fair value. For commodity derivatives, the most observable inputs available are generally 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 quoted prices for similar contracts or internally prepared valuation models to determine fair value. For the nuclear decommissioning fund, published trading data and pricing models, generally using the most observable inputs available, are utilized to estimate fair value for each class of security. See Note 11 for further discussion.
Cash and Cash Equivalents — Xcel Energy considers investments in certain instruments, including commercial paper and money market funds, with a remaining maturity of three months or less at the time of purchase, to be cash equivalents.
Accounts Receivable and Allowance for Bad Debts — Accounts receivable are stated at the actual billed amount net of an allowance for bad debts. Xcel Energy establishes an allowance for uncollectible receivables based on a policy that reflects its expected exposure to the credit risk of customers.
Inventory — All inventory is recorded at average cost.
Renewable Energy Credits — RECs are marketable environmental commodities that represent proof that energy was generated from eligible renewable energy sources. RECs are awarded upon delivery of the associated energy and can be bought and sold. RECs are typically used as a form of measurement of compliance to RPS enacted by those states that are encouraging construction and consumption from renewable energy sources, but can also be sold separately from the energy produced. Currently, utility subsidiaries acquire RECs from the generation or purchase of renewable power.
When RECs are acquired in the course of generation or purchased as a result of meeting load obligations, they are recorded as inventory at cost. The cost of RECs that are utilized for compliance purposes is recorded as electric fuel and purchased power expense. As a result of state regulatory orders, Xcel Energy reduces recoverable fuel costs for the value of certain RECs and records the cost of future compliance requirements that are recoverable in future rates as regulatory assets.
Sales of RECs that are acquired in the course of generation or purchased as a result of meeting load obligations are recorded in electric utility operating revenues on a gross basis. The cost of these RECs, related transaction costs, and amounts credited to customers under margin-sharing mechanisms are recorded in electric fuel and purchased power expense. RECs acquired for trading purposes are recorded as other investments and are also recorded at cost. The sales of RECs for trading purposes are recorded in electric utility operating revenues, net of the cost of the RECs, transaction costs, and amounts credited to customers under margin-sharing mechanisms.
Emission Allowances — Emission allowances, including the annual SO2 and NOx emission allowance entitlement received at no cost from the EPA, are recorded at cost plus associated broker commission fees. Xcel Energy follows the inventory accounting model for all emission allowances. The sales of emission allowances are included in electric utility operating revenues and the operating activities section of the consolidated statements of cash flows.
Environmental Costs — Environmental costs are recorded when it is probable Xcel Energy is liable for the costs and the liability can be reasonably estimated. Costs are deferred as a regulatory asset if it is probable that the costs will be recovered from customers in future rates. Otherwise, the costs are expensed. If an environmental expense is related to facilities currently in use, such as emission-control equipment, the cost is capitalized and depreciated over the life of the plant.
Estimated remediation costs, excluding inflationary increases, are recorded. The estimates are based on experience, an assessment of the current situation and the technology currently available for use in the remediation. The recorded costs are regularly adjusted as estimates are revised and remediation proceeds. If other participating PRPs exist and acknowledge their potential involvement with a site, costs are estimated and recorded only for Xcel Energy’s expected share of the cost. Any future costs of restoring sites where operation may extend indefinitely are treated as a capitalized cost of plant retirement. The depreciation expense levels recoverable in rates include a provision for removal expenses, which may include final remediation costs. Removal costs recovered in rates are classified as a regulatory liability.
See Note 13 for further discussion of environmental costs.
Benefit Plans and Other Postretirement Benefits — Xcel Energy maintains pension and postretirement benefit plans for eligible employees. Recognizing the cost of providing benefits and measuring the projected benefit obligation of these plans under applicable accounting guidance requires management to make various assumptions and estimates.
Based on the regulatory recovery mechanisms of Xcel Energy Inc.’s utility subsidiaries, certain unrecognized actuarial gains and losses and unrecognized prior service costs or credits are recorded as regulatory assets and liabilities, rather than OCI.
See Note 9 for further discussion of benefit plans and other postretirement benefits.
Guarantees — Xcel Energy recognizes, upon issuance or modification of a guarantee, a liability for the fair market value of the obligation that has been assumed in issuing the guarantee. This liability includes consideration of specific triggering events and other conditions which may modify the ongoing obligation to perform under the guarantee.
The obligation recognized is reduced over the term of the guarantee as Xcel Energy is released from risk under the guarantee. See Note 13 for specific details of issued guarantees.
Subsequent Events — Management has evaluated the impact of events occurring after Dec. 31, 2011 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation.
2. Accounting Pronouncements
Recently Adopted
Multiemployer Plans — In September 2011, the FASB issued Multiemployer Plans (Subtopic 715-80) — Disclosures about an Employer’s Participation in a Multiemployer Plan (ASU No. 2011-09), which updates the Codification to require certain disclosures about an entity’s involvement with multiemployer pension and other postretirement benefit plans. These updates do not affect recognition and measurement guidance for an employer’s participation in multiemployer plans, but rather require additional disclosure such as the nature of multiemployer plans and the employer’s participation, contributions to the plans and details regarding any significant plans. These updates to the Codification are effective for annual periods ending after Dec. 15, 2011. Xcel Energy implemented the annual disclosure guidance effective Jan. 1, 2011, and the implementation did not have a material impact on its consolidated financial statements. For further information and required disclosures, see Note 9.
Recently Issued
Fair Value Measurement — In May 2011, the FASB issued Fair Value Measurement (Topic 820) — Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS (ASU No. 2011-04), which provides additional guidance for fair value measurements. These updates to the Codification include clarifications regarding existing fair value measurement principles and disclosure requirements, and also specific new guidance for items such as measurement of instruments classified within stockholders’ equity. These updates to the Codification are effective for interim and annual periods beginning after Dec. 15, 2011. Xcel Energy does not expect the implementation of this guidance to have a material impact on its consolidated financial statements.
Comprehensive Income — In June 2011, the FASB issued Comprehensive Income (Topic 220) — Presentation of Comprehensive Income (ASU No. 2011-05), which updates the Codification to require the presentation of the components of net income, the components of OCI and total comprehensive income in either a single continuous statement of comprehensive income or in two separate, but consecutive statements of net income and comprehensive income. These updates do not affect the items reported in OCI or the guidance for reclassifying such items to net income. These updates to the Codification are effective for interim and annual periods beginning after Dec. 15, 2011. Xcel Energy does not expect the implementation of this presentation guidance to have a material impact on its consolidated financial statements.
Balance Sheet Offsetting — In December 2011, the FASB issued Balance Sheet (Topic 210) — Disclosures about Offsetting Assets and Liabilities (ASU No. 2011-11), which updates the Codification to require disclosures regarding netting arrangements in agreements underlying derivatives, certain financial instruments and related collateral amounts, and the extent to which an entity’s financial statement presentation policies related to netting arrangements impact amounts recorded to the financial statements. These updates to the disclosure requirements of the Codification do not affect the presentation of amounts in the consolidated balance sheets, and are effective for annual reporting periods beginning on or after Jan. 1, 2013, and interim periods within those periods. Xcel Energy does not expect the implementation of this disclosure guidance to have a material impact on its consolidated financial statements.
3. Selected Balance Sheet Data
| (Thousands of Dollars) | | Dec. 31, 2011 | | | Dec. 31, 2010 | |
| Accounts receivable, net | | | | | | |
| Accounts receivable | | $ | 811,685 | | | $ | 773,037 | |
| Less allowance for bad debts | | | (58,565 | ) | | | (54,563 | ) |
| | | $ | 753,120 | | | $ | 718,474 | |
| Inventories | | | | | | | | |
| Materials and supplies | | $ | 202,699 | | | $ | 196,081 | |
| Fuel | | | 236,023 | | | | 188,566 | |
| Natural gas | | | 179,510 | | | | 176,153 | |
| | | $ | 618,232 | | | $ | 560,800 | |
| Property, plant and equipment, net | | | | | | | | |
| Electric plant | | $ | 27,254,541 | | | $ | 24,993,582 | |
| Natural gas plant | | | 3,676,754 | | | | 3,463,343 | |
| Common and other property | | | 1,546,643 | | | | 1,555,287 | |
Plant to be retired (a) | | | 151,184 | | | | 236,606 | |
| Construction work in progress | | | 1,085,245 | | | | 1,186,433 | |
| Total property, plant and equipment | | | 33,714,367 | | | | 31,435,251 | |
| Less accumulated depreciation | | | (11,658,351 | ) | | | (11,068,820 | ) |
| Nuclear fuel | | | 1,939,299 | | | | 1,837,697 | |
| Less accumulated amortization | | | (1,641,948 | ) | | | (1,541,046 | ) |
| | | $ | 22,353,367 | | | $ | 20,663,082 | |
| (a) | In 2010, in response to the CACJA, the CPUC approved the early retirement of Cherokee Units 1, 2 and 3, Arapahoe Unit 3 and Valmont Unit 5 between 2011 and 2017. Amounts are presented net of accumulated depreciation. See Item 1 – Public Utility Regulation for further discussion. |
4. Borrowings and Other Financing Instruments
Short-Term Borrowings
Money Pool — Xcel Energy Inc. and its utility subsidiaries have established a money pool arrangement that allows for short-term investments in and borrowings between the utility subsidiaries. NSP-Wisconsin does not participate in the money pool. Xcel Energy Inc. may make investments in the utility subsidiaries at market-based interest rates; however, the money pool arrangement does not allow the utility subsidiaries to make investments in Xcel Energy Inc. The money pool balances are eliminated upon consolidation.
Commercial Paper — Xcel Energy Inc. and its utility subsidiaries meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under their credit facilities. Commercial paper outstanding for Xcel Energy was as follows:
| | | Three Months Ended | |
| (Amounts in Millions, Except Interest Rates) | | Dec. 31, 2011 | |
| Borrowing limit | | $ | 2,450 | |
| Amount outstanding at period end | | | 219 | |
| Average amount outstanding | | | 165 | |
| Maximum amount outstanding | | | 241 | |
| Weighted average interest rate, computed on a daily basis | | | 0.35 | % |
| Weighted average interest rate at end of period | | | 0.40 | |
| | | Twelve Months Ended | | | Twelve Months Ended | | | Twelve Months Ended | |
| (Amounts in Millions, Except Interest Rates) | | Dec. 31, 2011 | | | Dec. 31, 2010 | | | Dec. 31, 2009 | |
| Borrowing limit | | $ | 2,450 | | | $ | 2,177 | | | $ | 2,177 | |
| Amount outstanding at period end | | | 219 | | | | 466 | | | | 459 | |
| Average amount outstanding | | | 430 | | | | 263 | | | | 406 | |
| Maximum amount outstanding | | | 824 | | | | 653 | | | | 675 | |
| Weighted average interest rate, computed on a daily basis | | | 0.36 | % | | | 0.36 | % | | | 0.95 | % |
| Weighted average interest rate at end of period | | | 0.40 | | | | 0.40 | | | | 0.36 | |
Credit Facilities — In order to use their commercial paper programs to fulfill short-term funding needs, Xcel Energy Inc. and its utility subsidiaries must have revolving credit facilities in place at least equal to the amount of their respective commercial paper borrowing limits and cannot issue commercial paper in an aggregate amount exceeding available capacity under these credit agreements.
During 2011, NSP-Minnesota, NSP-Wisconsin, PSCo, SPS and Xcel Energy Inc. executed new four-year credit agreements. The total size of the credit facilities is $2.45 billion and each credit facility terminates in March 2015. Xcel Energy Inc. and its utility subsidiaries have the right to request an extension of the revolving termination date for two additional one-year periods, subject to majority bank group approval.
The credit facilities provide short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings. Other features of the credit facilities include:
| | · | Each of the credit facilities, other than NSP-Wisconsin’s, may be increased by up to $200 million for Xcel Energy Inc., $100 million each for NSP-Minnesota and PSCo, and $50 million for SPS. |
| | · | Each credit facility has a financial covenant requiring that the debt-to-total capitalization ratio of each entity be less than or equal to 65 percent. Each entity was in compliance at Dec. 31, 2011 as evidenced by the table below: |
| | | Debt-to-Total Capitalization Ratio | |
| Xcel Energy | | | 55 | % |
| NSP-Wisconsin | | | 50 | |
| NSP-Minnesota | | | 48 | |
| SPS | | | 48 | |
| PSCo | | | 45 | |
If Xcel Energy Inc. or any of its utility subsidiaries do not comply with the covenant, an event of default may be declared, and if not remedied, any outstanding amounts due under the facility can be declared due by the lender.
| | · | The Xcel Energy Inc. credit facility has a cross-default provision that provides Xcel Energy Inc. will be in default on its borrowings under the facility if it or any of its subsidiaries, except NSP-Wisconsin as long as its total assets do not comprise more than 15 percent of Xcel Energy’s consolidated total assets, default on certain indebtedness in an aggregate principal amount exceeding $75 million. |
| | · | The interest rates under these lines of credit are based on the Eurodollar rate or an alternate base rate, plus a borrowing margin of 0 to 200 basis points per year based on the applicable credit ratings. |
| | · | The commitment fees, also based on applicable long-term credit ratings, are calculated on the unused portion of the lines of credit at a range of 10 to 35 basis points per year. |
| | · | NSP-Wisconsin’s intercompany borrowing arrangement with NSP-Minnesota was subsequently terminated. |
At Dec. 31, 2011, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available:
| (Millions of Dollars) | | Facility | | | Drawn (a) | | | Available | |
| Xcel Energy Inc. | | $ | 800.0 | | | $ | 127.1 | | | $ | 672.9 | |
| PSCo | | | 700.0 | | | | 4.9 | | | | 695.1 | |
| NSP-Minnesota | | | 500.0 | | | | 33.7 | | | | 466.3 | |
| SPS | | | 300.0 | | | | - | | | | 300.0 | |
| NSP-Wisconsin | | | 150.0 | | | | 66.0 | | | | 84.0 | |
| Total | | $ | 2,450.0 | | | $ | 231.7 | | | $ | 2,218.3 | |
| (a) | Includes outstanding commercial paper and letters of credit. |
All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the respective credit facilities. Xcel Energy Inc. and its subsidiaries had no direct advances on the credit facilities outstanding at Dec. 31, 2011 and 2010.
Letters of Credit — Xcel Energy Inc. and its subsidiaries use letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations. At Dec. 31, 2011 and 2010, there were $12.7 million and $10.1 million of letters of credit outstanding, respectively, under the credit facilities. An additional $1.1 million of letters of credit not issued under the credit facilities were outstanding at Dec. 31, 2011 and 2010, respectively. The contract amounts of these letters of credit approximate their fair value and are subject to fees determined in the marketplace.
Long-Term Borrowings and Other Financing Instruments
Generally, all real and personal property of NSP-Minnesota and NSP-Wisconsin and all real and personal property used in or in connection with the electric utility business of PSCo and SPS are subject to the liens of their first mortgage indentures. Additionally, debt premiums, discounts and expenses are amortized over the life of the related debt. The premiums, discounts and expenses associated with refinanced debt are deferred and amortized over the life of the related new issuance, in accordance with regulatory guidelines.
Maturities of long-term debt are as follows:
| (Millions of Dollars) | | | |
| 2012 | | $ | 1,060 | |
| 2013 | | | 257 | |
| 2014 | | | 282 | |
| 2015 | | | 256 | |
| 2016 | | | 207 | |
Xcel Energy has entered into a Replacement Capital Covenant (RCC). Under the terms of the RCC, Xcel Energy has agreed not to redeem or repurchase all or part of the $400 million of 7.6 percent junior subordinated notes due 2068 (Junior Subordinated Notes) prior to 2038 unless qualifying securities are issued to non-affiliates in a replacement offering in the 180 days prior to the redemption or repurchase date. Qualifying securities include those that have equity-like characteristics that are the same as, or more equity-like than, the applicable characteristics of the Junior Subordinated Notes at the time of redemption or repurchase.
During 2011, Xcel Energy Inc. and its utility subsidiaries completed the following financings:
| | · | In September 2011, Xcel Energy Inc. issued $250 million of 4.80 percent senior unsecured notes due Sept. 15, 2041. |
| | · | In August 2011, PSCo issued $250 million of 4.75 percent first mortgage bonds due Aug. 15, 2041. |
| | · | In August 2011, SPS issued $200 million of 4.50 percent first mortgage bonds due Aug. 15, 2041. |
During 2010, Xcel Energy Inc. and its utility subsidiaries completed the following financings:
| | · | In May 2010, Xcel Energy Inc. issued $550 million of 4.70 percent unsecured senior notes, due May 15, 2020. |
| | · | In August 2010, NSP-Minnesota issued $250 million of 1.95 percent first mortgage bonds, due Aug. 15, 2015 and $250 million of 4.85 percent first mortgage bonds, due Aug. 15, 2040. |
| | · | In November 2010, PSCo issued $400 million of 3.2 percent first mortgage bonds, due Nov. 15, 2020. |
Deferred Financing Costs — Other assets included deferred financing costs of approximately $75 million and $74 million, net of amortization, at Dec. 31, 2011 and 2010, respectively. Xcel Energy is amortizing these financing costs over the remaining maturity periods of the related debt.
Capital Stock — Xcel Energy Inc. has authorized 7,000,000 shares of preferred stock with a $100 par value. At Dec. 31, 2011, there were no shares of preferred stock outstanding and at Dec. 31, 2010, Xcel Energy Inc. had six series of preferred stock outstanding, redeemable at its option at prices ranging from $102 to $103.75 per share plus accrued dividends. Xcel Energy Inc. redeemed all series of its preferred stock on Oct. 31, 2011, at an aggregate purchase price of $108 million, plus accrued dividends. As such, the redemption premium of $3.3 million and accrued dividends are reflected as reductions of Xcel Energy’s earnings available to common shareholders in the consolidated statements of income.
The charters of some of Xcel Energy Inc.’s subsidiaries also authorize the issuance of preferred stock. However, at Dec. 31, 2011 and 2010, there were no preferred shares of subsidiaries outstanding. The following table lists preferred shares by subsidiary at Dec. 31, 2011 and 2010:
| | | Preferred Shares Authorized | | | Par Value | |
| SPS | | | 10,000,000 | | | $ | 1.00 | |
| PSCo | | | 10,000,000 | | | | 0.01 | |
Xcel Energy Inc. has authorized 1,000,000,000 shares of common stock. Outstanding shares at Dec. 31, 2011 and 2010 were 486,493,933 and 482,333,750, respectively.
Dividend and Other Capital-Related Restrictions — Xcel Energy Inc.’s Articles of Incorporation place restrictions on the amount of common stock dividends it can pay when preferred stock is outstanding. As there was no preferred stock outstanding at Dec. 31, 2011, the restrictions did not place any effective limit on Xcel Energy Inc.’s ability to pay dividends at Dec. 31, 2011.
All of Xcel Energy’s utility subsidiaries’ dividends are subject to the FERC’s jurisdiction under the Federal Power Act, which prohibits the payment of dividends out of capital accounts; payment of dividends is allowed out of retained earnings only.
NSP-Minnesota’s first mortgage indenture places certain restrictions on the amount of cash dividends it can pay to Xcel Energy Inc., the holder of its common stock. Even with these restrictions, NSP-Minnesota could have paid more than $1.1 billion in additional cash dividends on common stock at Dec. 31, 2010, or $1.2 billion at Dec. 31, 2011.
NSP-Minnesota’s state regulatory commissions indirectly limit the amount of dividends NSP-Minnesota can pay to Xcel Energy Inc. by requiring an equity-to-total capitalization ratio between 47.07 percent and 57.53 percent. NSP-Minnesota’s equity-to-total capitalization ratio was 52.1 percent at Dec. 31, 2011. Total capitalization for NSP-Minnesota cannot exceed $8.25 billion.
NSP-Wisconsin shall not pay dividends if its calendar year average equity-to-total capitalization ratio is or falls below the state commission authorized level of 52.5 percent. NSP-Wisconsin’s calendar year average equity-to-total capitalization ratio was 55.1 percent at Dec. 31, 2011.
SPS’ state regulatory commissions indirectly limit the amount of dividends that SPS can pay Xcel Energy Inc. by requiring an equity-to-total capitalization ratio (excluding short-term debt) between 45.0 percent and 55.0 percent. In addition, SPS may not pay a dividend that would cause it to lose its investment grade bond rating. SPS’ equity-to-total capitalization ratio (excluding short-term debt) was 52.0 percent at Dec. 31, 2011.
The issuance of securities by Xcel Energy Inc. generally is not subject to regulatory approval. However, utility financings and certain intra-system financings are subject to the jurisdiction of the applicable state regulatory commissions and/or the FERC under the Federal Power Act.
| | · | PSCo currently has authorization to issue up to $1.15 billion of long-term debt and up to $800 million of short-term debt. |
| | · | SPS currently has authorization to issue up $400 million of short-term debt. |
| | · | NSP-Wisconsin currently has authorization to issue up to $150 million of long-term debt and up to $150 million of short-term debt. |
| | · | NSP-Minnesota has authorization to issue long-term securities provided the equity-to-total capitalization ratio remains between 47.07 percent and 57.53 percent and to issue short-term debt provided it does not exceed 15 percent of total capitalization. Total capitalization for NSP-Minnesota cannot exceed $8.25 billion. |
Xcel Energy believes these authorizations are adequate and will seek additional authorization when necessary; however, there can be no assurance that additional authorization will be granted on the timeframe or in the amounts requested.
5. Joint Ownership of Generation, Transmission and Gas Facilities
Following are the investments by Xcel Energy Inc.’s utility subsidiaries in jointly owned generation, transmission and gas facilities and the related ownership percentages as of Dec. 31, 2011:
| | | | | | | | | Construction | | | | |
| | | Plant in | | | Accumulated | | | Work in | | | | |
| (Thousands of Dollars) | | Service | | | Depreciation | | | Progress | | | Ownership % | |
| NSP-Minnesota | | | | | | | | | | | | |
| Electric Generation: | | | | | | | | | | | | |
| Sherco Unit 3 | | $ | 565,832 | | | $ | 358,907 | | | $ | 3,731 | | | | 59.0 | % |
| Sherco Common Facilities Units 1, 2 and 3 | | | 138,790 | | | | 82,229 | | | | 531 | | | | 80.0 | |
| Sherco Substation | | | 4,790 | | | | 2,621 | | | | - | | | | 59.0 | |
| Electric Transmission: | | | | | | | | | | | | | | | | |
| Grand Meadow Line and Substation | | | 11,204 | | | | 855 | | | | - | | | | 50.0 | |
| CapX2020 Transmission | | | 57,856 | | | | 8,899 | | | | 74,404 | | | | 49.6 | |
| Total NSP-Minnesota | | $ | 778,472 | | | $ | 453,511 | | | $ | 78,666 | | | | | |
| | | | | | | | | Construction | | | | |
| | | Plant in | | | Accumulated | | | Work in | | | | |
| (Thousands of Dollars) | | Service | | | Depreciation | | | Progress | | | Ownership % | |
| PSCo | | | | | | | | | | | | |
| Electric Generation: | | | | | | | | | | | | |
| Hayden Unit 1 | | $ | 88,337 | | | $ | 60,549 | | | $ | 830 | | | | 75.5 | % |
| Hayden Unit 2 | | | 119,621 | | | | 55,126 | | | | 722 | | | | 37.4 | |
| Hayden Common Facilities | | | 34,558 | | | | 14,155 | | | | 1 | | | | 53.1 | |
| Craig Units 1 and 2 | | | 54,058 | | | | 33,225 | | | | 193 | | | | 9.7 | |
| Craig Common Facilities 1, 2 and 3 | | | 35,241 | | | | 15,896 | | | | 2,863 | | | | 6.5 - 9.7 | |
| Comanche Unit 3 | | | 867,976 | | | | 28,973 | | | | 1,014 | | | | 66.7 | |
| Comanche Common Facilities | | | 12,628 | | | | 219 | | | | 169 | | | | 82.0 | |
| Electric Transmission: | | | | | | | | | | | | | | | | |
| Transmission and other facilities, including substations | | | 150,420 | | | | 56,654 | | | | 449 | | | Various | |
| Gas Transportation: | | | | | | | | | | | | | | | | |
| Rifle to Avon | | | 16,278 | | | | 6,333 | | | | - | | | | 60.0 | |
| Total PSCo | | $ | 1,379,117 | | | $ | 271,130 | | | $ | 6,241 | | | | | |
NSP-Minnesota and PSCo have approximately 500 MW and 820 MW of jointly owned generating capacity, respectively. NSP-Minnesota’s and PSCo’s share of operating expenses and construction expenditures are included in the applicable utility accounts. Each of the respective owners is responsible for providing its own financing.
NSP-Minnesota is part owner of Sherco Unit 3, an 860 MW, coal-fueled electric generating unit. NSP-Minnesota is the operating agent under the joint ownership agreement. In November 2011, Sherco Unit 3 experienced a significant failure of its turbine, generator, and exciter systems. The facility was immediately shut down and isolated for investigation of the cause of the failure, which is still uncertain. It is unknown when Sherco Unit 3 will recommence operations. NSP-Minnesota maintains insurance policies for the entire unit, inclusive of the other joint owner’s proportionate share. Replacement and repair of damaged systems, and other significant costs of the failure in excess of a $1.5 million deductible are expected to be recovered through these insurance policies. For its proportionate share of possible expenditures in excess of insurance recoveries for components of the jointly owned facility, NSP-Minnesota will recognize additions to property, plant and equipment and O&M. Sherco Units 1 and 2, wholly owned by NSP-Minnesota, continue to operate.
6. Income Taxes
COLI — In 2007, Xcel Energy Inc., PSCo and the U.S. government settled an ongoing dispute regarding PSCo’s 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. Xcel Energy Inc. and PSCo paid the U.S. government a total of $64.4 million in settlement of the U.S. government’s claims for tax, penalty and interest for tax years 1993 through 2007. Xcel Energy Inc. and PSCo surrendered the policies to its insurer on Oct. 31, 2007, without recognizing a taxable gain. As a result of the settlement, the lawsuit filed by Xcel Energy Inc. and PSCo in the U.S. District Court was dismissed and the Tax Court proceedings were dismissed in December 2010 and January 2011.
As part of the Tax Court proceedings, during 2010, an agreement in principle of Xcel Energy Inc.’s and PSCo’s statements of account was reached, dating back to tax year 1993. Upon completion of this review, PSRI recorded a net non-recurring tax and interest charge of approximately $9.4 million. Upon final cash settlement in 2011, Xcel Energy received $0.7 million and recognized a further reduction of expense of $0.3 million. A closing agreement covering tax years 2003 through 2007 was finalized with the IRS in January 2012.
In 2010, Xcel Energy Inc., PSCo and PSRI entered into a settlement agreement with Provident related to all claims asserted by Xcel Energy Inc., PSCo and PSRI against Provident in a lawsuit associated with the discontinued COLI program. Under the terms of the settlement, Xcel Energy Inc., PSCo and PSRI were paid $25 million by Provident and Reassure America Life Insurance Company in 2010. The $25 million proceeds were not subject to income taxes.
Medicare Part D Subsidy Reimbursements — In March 2010, the Patient Protection and Affordable Care Act was signed into law. The law includes provisions to generate tax revenue to help offset the cost of the new legislation. One of these provisions reduces the deductibility of retiree health care costs to the extent of federal subsidies received by plan sponsors that provide retiree prescription drug benefits equivalent to Medicare Part D coverage, beginning in 2013. Based on this provision, Xcel Energy became subject to additional taxes and was required to reverse previously recorded tax benefits in the period of enactment. Xcel Energy expensed approximately $17 million of previously recognized tax benefits relating to Medicare Part D subsidies during the first quarter of 2010. Xcel Energy does not expect the $17 million of additional tax expense to recur in future periods.
Federal Audit — Xcel Energy files a consolidated federal income tax return. The statute of limitations applicable to Xcel Energy’s 2007 federal income tax return expired in September 2011. The statute of limitations applicable to Xcel Energy’s 2008 federal income tax return expires in September 2012. The IRS commenced an examination of tax years 2008 and 2009 in the third quarter of 2010. In December 2011, Xcel Energy finalized the Revenue Agent Report and signed the Waiver of Assessment for tax years 2008 and 2009. The total assessment for these tax years was $1.4 million, including tax and interest.
State Audits — Xcel Energy files consolidated 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. As of Dec. 31, 2011, Xcel Energy’s earliest open tax years that are subject to examination by state taxing authorities in its major operating jurisdictions were as follows:
| State | | Year | |
| Colorado | | 2006 | |
| Minnesota | | 2007 | |
| Texas | | 2007 | |
| Wisconsin | | 2007 | |
As of Dec. 31, 2011, there were no state income tax audits in progress.
Unrecognized Tax Benefits —The unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual ETR. In addition, the unrecognized tax benefit balance includes temporary tax positions 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 ETR but would accelerate the payment of cash to the taxing authority to an earlier period.
A reconciliation of the amount of unrecognized tax benefit is as follows:
| (Millions of Dollars) | | Dec. 31, 2011 | | | Dec. 31, 2010 | |
| Unrecognized tax benefit - Permanent tax positions | | $ | 4.3 | | | $ | 5.9 | |
| Unrecognized tax benefit - Temporary tax positions | | | 30.4 | | | | 34.6 | |
| Unrecognized tax benefit balance | | $ | 34.7 | | | $ | 40.5 | |
A reconciliation of the beginning and ending amount of unrecognized tax benefit is as follows:
| (Millions of Dollars) | | 2011 | | | 2010 | | | 2009 | |
| Balance at Jan. 1 | | $ | 40.5 | | | $ | 30.3 | | | $ | 42.1 | |
| Additions based on tax positions related to the current year - continuing operations | | | 11.9 | | | | 13.4 | | | | 12.6 | |
| Reductions based on tax positions related to the current year - continuing operations | | | (1.9 | ) | | | (0.6 | ) | | | (1.8 | ) |
| Additions for tax positions of prior years - continuing operations | | | 14.0 | | | | 5.5 | | | | 6.8 | |
| Reductions for tax positions of prior years - continuing operations | | | (2.4 | ) | | | (1.8 | ) | | | (2.3 | ) |
| Reductions for tax positions of prior years - discontinued operations | | | - | | | | (6.3 | ) | | | - | |
| Settlements with taxing authorities - continuing operations | | | (27.3 | ) | | | - | | | | (27.1 | ) |
| Lapse of applicable statutes of limitations - continuing operations | | | (0.1 | ) | | | - | | | | - | |
| Balance at Dec. 31 | | $ | 34.7 | | | $ | 40.5 | | | $ | 30.3 | |
The unrecognized tax benefit amounts were reduced by the tax benefits associated with NOL and tax credit carryforwards. The amounts of tax benefits associated with NOL and tax credit carryfowards are as follows:
| (Millions of Dollars) | | Dec. 31, 2011 | | | Dec. 31, 2010 | |
| NOL and tax credit carryforwards | | $ | (33.6 | ) | | $ | (38.0 | ) |
The decrease in the unrecognized tax benefit balance of $5.8 million in 2011 was due to the resolution of certain federal audit matters, partially offset by an increase due to the addition of uncertain tax positions related to current and prior years’ activity. Xcel Energy’s amount of unrecognized tax benefits could change in the next 12 months as the IRS and state audits resume. At this time, due to the uncertain nature of the audit process, it is not reasonably possible to estimate an overall range of possible change. However, Xcel Energy does not anticipate total unrecognized tax benefits will significantly change within the next 12 months.
The payable for interest related to unrecognized tax benefits is substantially offset by the interest benefit associated with NOL and tax credit carryforwards. A reconciliation of the beginning and ending amount of the payable for interest related to unrecognized tax benefits reported is as follows:
| (Millions of Dollars) | | 2011 | | | 2010 | | | 2009 | |
| Payable for interest related to unrecognized tax benefits at Jan. 1 | | $ | (0.3 | ) | | $ | (0.2 | ) | | $ | (0.4 | ) |
| Interest income (expense) related to unrecognized tax benefits - continuing operations | | | 0.9 | | | | (0.6 | ) | | | 1.5 | |
| Interest (expense) income related to unrecognized tax benefits - discontinued operations | | | (0.8 | ) | | | 0.5 | | | | (1.3 | ) |
| Payable for interest related to unrecognized tax benefits at Dec. 31 | | $ | (0.2 | ) | | $ | (0.3 | ) | | $ | (0.2 | ) |
No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2011, 2010 or 2009.
Other Income Tax Matters — NOL amounts represent the amount of the tax loss that is carried forward and tax credits represent the deferred tax asset. NOL and tax credit carryforwards as of Dec. 31 were as follows:
| (Millions of Dollars) | | 2011 | | | 2010 | |
| Federal NOL carryforward | | $ | 1,710 | | | $ | 989 | |
| Federal tax credit carryforwards | | | 232 | | | | 205 | |
| State NOL carryforwards | | | 1,707 | | | | 1,363 | |
| Valuation allowances for state NOL carryforwards | | | (51 | ) | | | (32 | ) |
State tax credit carryforwards, net of federal detriment (a) | | | 22 | | | | 21 | |
| Valuation allowances for state tax credit carryforwards, net of federal benefit | | | (2 | ) | | | - | |
| (a) | State tax credit carryforwards are net of federal detriment of $12 million and $11 million as of Dec. 31, 2011 and 2010, respectively. |
The federal carryforward periods expire between 2021 and 2031. The state carryforward periods expire between 2012 and 2031.
Total income tax expense from continuing operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense. The following reconciles such differences for the years ending Dec. 31:
| | | 2011 | | | 2010 | | | 2009 | |
| Federal statutory rate | | | 35.0 | % | | | 35.0 | % | | | 35.0 | % |
| Increases (decreases) in tax from: | | | | | | | | | | | | |
| State income taxes, net of federal income tax benefit | | | 4.2 | | | | 3.9 | | | | 4.0 | |
| Resolution of income tax audits and other | | | 0.3 | | | | 0.6 | | | | 0.8 | |
| Tax credits recognized, net of federal income tax expense | | | (2.6 | ) | | | (1.8 | ) | | | (2.0 | ) |
| Regulatory differences — utility plant items | | | (0.8 | ) | | | (1.1 | ) | | | (2.0 | ) |
| Change in unrecognized tax benefits | | | (0.1 | ) | | | 0.1 | | | | (0.5 | ) |
| Life insurance policies | | | (0.1 | ) | | | (0.8 | ) | | | (0.2 | ) |
| Previously recognized Medicare Part D subsidies | | | - | | | | 1.4 | | | | - | |
| Other, net | | | (0.1 | ) | | | (0.6 | ) | | | - | |
| Effective income tax rate from continuing operations | | | 35.8 | % | | | 36.7 | % | | | 35.1 | % |
The components of Xcel Energy’s income tax expense for the years ending Dec. 31 were:
| (Thousands of Dollars) | | 2011 | | | 2010 | | | 2009 | |
| Current federal tax expense (benefit) | | $ | 3,399 | | | $ | 16,657 | | | $ | (39,886 | ) |
| Current state tax expense | | | 9,971 | | | | 12,580 | | | | 8,672 | |
| Current change in unrecognized tax benefit | | | (8,266 | ) | | | (2,982 | ) | | | (7,627 | ) |
| Current tax credits | | | - | | | | (944 | ) | | | - | |
| Deferred federal tax expense | | | 410,794 | | | | 376,073 | | | | 360,252 | |
| Deferred state tax expense | | | 80,670 | | | | 52,543 | | | | 69,947 | |
| Deferred change in unrecognized tax expense | | | 6,705 | | | | 4,641 | | | | 2,387 | |
| Deferred tax credits | | | (28,763 | ) | | | (15,580 | ) | | | (16,005 | ) |
| Deferred investment tax credits | | | (6,194 | ) | | | (6,353 | ) | | | (6,426 | ) |
| Total income tax expense from continuing operations | | $ | 468,316 | | | $ | 436,635 | | | $ | 371,314 | |
The components of Xcel Energy’s net deferred tax liability (current and noncurrent) at Dec. 31 were as follows:
| (Thousands of Dollars) | | 2011 | | | 2010 | |
| Deferred tax liabilities: | | | | | | |
| Differences between book and tax bases of property | | $ | 4,558,951 | | | $ | 3,853,425 | |
| Regulatory assets | | | 253,162 | | | | 242,760 | |
| Other | | | 279,162 | | | | 219,035 | |
| Total deferred tax liabilities | | $ | 5,091,275 | | | $ | 4,315,220 | |
| | | | | | | | | |
| Deferred tax assets: | | | | | | | | |
| NOL carryforward | | $ | 696,435 | | | $ | 425,620 | |
| Tax credit carryforward | | | 254,157 | | | | 226,057 | |
| Unbilled revenue - fuel costs | | | 73,912 | | | | 69,358 | |
| Environmental remediation | | | 45,551 | | | | 41,696 | |
| Rate refund | | | 37,443 | | | | 8,971 | |
| Deferred investment tax credits | | | 37,425 | | | | 39,916 | |
| Regulatory liabilities | | | 37,012 | | | | 51,600 | |
| Accrued liabilities and other | | | 73,092 | | | | 58,891 | |
| NOL and tax credit valuation allowances | | | (5,683 | ) | | | (1,927 | ) |
| Total deferred tax assets | | $ | 1,249,344 | | | $ | 920,182 | |
| Net deferred tax liability | | $ | 3,841,931 | | | $ | 3,395,038 | |
7. Earnings Per Share
Basic EPS was computed by dividing the earnings available to Xcel Energy Inc.’s common shareholders by the weighted average number of common shares outstanding during the period. Diluted EPS was computed by dividing the earnings available to Xcel Energy Inc.’s common shareholders by the diluted weighted average number of common shares outstanding during the period. Diluted EPS reflects the potential dilution that could occur if securities or other agreements to issue common stock (i.e., common stock equivalents), such as equity forward agreements or stock options and other share-based compensation awards were settled.
Common Stock Equivalents — Xcel Energy Inc. currently has common stock equivalents consisting of 401(k) equity awards and stock options, and in 2010, also had equity forward instruments. The weighted average number of potentially dilutive shares outstanding used to calculate Xcel Energy Inc.’s diluted EPS is calculated based on the treasury stock method.
Equity Forward Agreements
In August 2010, Xcel Energy Inc. entered into equity forward agreements in connection with a public offering of 21.85 million shares of its common stock. Under the equity forward agreements (Forward Agreements), Xcel Energy Inc. agreed to issue to the banking counterparty 21.85 million shares of its common stock.
The equity forward instruments were accounted for as equity and recorded at fair value at the execution of the Forward Agreements, and were not subsequently adjusted for changes in fair value until settlement. Based upon the market terms of the equity forward instruments, including initial pricing of $20.855 per share determined based on the August 2010 offering price of Xcel Energy Inc.’s common stock of $21.50 per share less underwriting fees of $0.645 per share, and as no premium on the transaction was owed either party to the Forward Agreements at execution, no fair value was recorded to equity for the instruments when the Forward Agreements were entered. The Forward Agreements settled on Nov. 29, 2010 and the proceeds of $449.8 million were recorded to common stock and additional paid in capital.
Share-Based Compensation
Common stock equivalents related to share-based compensation causing dilutive impact to EPS historically have included 401(k) equity awards and stock options. Stock equivalent units granted to Xcel Energy Inc.’s Board of Directors are included in common shares outstanding upon grant date as there is no further service, performance or market condition associated with these awards. Restricted stock, granted to settle amounts due certain employees under the Xcel Energy Inc. Executive Annual Incentive Award Plan, is included in common shares outstanding when granted, pending remaining service conditions.
Share-based compensation arrangements for which there is currently no dilutive impact to EPS include the following:
| | · | RSU equity awards subject to a performance condition; included in common shares outstanding when all necessary conditions for settlement have been satisfied by the end of the reporting period. |
| | · | PSP liability awards subject to a performance condition; any portions settled in shares are included in common shares outstanding upon settlement. |
The dilutive impact of common stock equivalents affecting EPS was as follows for the years ending Dec. 31:
| | | 2011 | | | 2010 | | | 2009 | |
| (Amounts in thousands, except per share data) | | Income | | | Share | | | Per Share Amount | | | Income | | | Share | | | Per Share Amount | | | Income | | | Share | | | Per Share Amount | |
| Net income | | $ | 841,172 | | | | | | | | | | | $ | 755,834 | | | | | | | | | | | $ | 680,887 | | | | | | | | | |
| Less: Dividend requirements on preferred stock | | | (3,534 | ) | | | | | | | | | (4,241 | ) | | | | | | | | | (4,241 | ) | | | | | | |
| Less: Premium on redemption of preferred stock | | | (3,260 | ) | | | | | | | | | - | | | | | | | | | | - | | | | | | | |
| Basic earnings per share: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Earnings available to common shareholders | | | 834,378 | | | 485,039 | | | $ | 1.72 | | | | 751,593 | | | 462,052 | | | $ | 1.63 | | | | 676,646 | | | 456,433 | | | $ | 1.48 | |
| Effect of dilutive securities: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Equity forward instruments | | | - | | | - | | | | | | | | - | | | 700 | | | | | | | | - | | | - | | | | | |
| 401(k) equity awards | | | - | | | 576 | | | | | | | | - | | | 639 | | | | | | | | - | | | 705 | | | | | |
| Stock options | | | - | | | - | | | | | | | | - | | | - | | | | | | | | - | | | 1 | | | | | |
| Diluted earnings per share: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Earnings available to common shareholders | | $ | 834,378 | | | 485,615 | | | $ | 1.72 | | | $ | 751,593 | | | 463,391 | | | $ | 1.62 | | | $ | 676,646 | | | 457,139 | | | $ | 1.48 | |
In 2011, 2010 and 2009, Xcel Energy Inc. had approximately 2.1 million, 5.4 million and 7.6 million weighted average options outstanding, respectively, that were antidilutive, and therefore, excluded from the earnings per share calculation.
8. Share-Based Compensation
Stock Options — Xcel Energy Inc. has incentive compensation plans under which stock options and other performance incentives are awarded to key employees. Xcel Energy Inc. has not granted stock options since December 2001.
Activity in stock options was as follows:
| | | 2011 | | | 2010 | | | 2009 | |
| | | | | | Average | | | | | | Average | | | | | | Average | |
| | | | | | Exercise | | | | | | Exercise | | | | | | Exercise | |
| (Awards in Thousands) | | Awards | | | Price | | | Awards | | | Price | | | Awards | | | Price | |
| Outstanding and exercisable at Jan. 1 | | | 2,498 | | | $ | 30.42 | | | | 6,657 | | | $ | 28.17 | | | | 8,460 | | | $ | 27.05 | |
| Exercised | | | (1,173 | ) | | | 25.90 | | | | (51 | ) | | | 19.31 | | | (794 | ) | | | 19.84 | |
| Forfeited | | | - | | | | - | | | | - | | | | - | | | (11 | ) | | | 20.04 | |
| Expired | | | (1,325 | ) | | | 34.42 | | | | (4,108 | ) | | | 26.91 | | | (998 | ) | | | 25.40 | |
| Outstanding and exercisable at Dec. 31 | | | - | | | | - | | | | 2,498 | | | | 30.42 | | | 6,657 | | | | 28.17 | |
The total market value and the total intrinsic value of stock options exercised were as follows for the years ended Dec. 31:
| (Thousands of Dollars) | | 2011 | | | 2010 | | | 2009 | |
| Market value of exercises | | $ | 30,761 | | | $ | 1,087 | | | $ | 16,429 | |
Intrinsic value of options exercised (a) | | | 380 | | | | 93 | | | | 670 | |
| (a) | Intrinsic value is calculated as market price at exercise date less the option exercise price. |
Cash received from stock options exercised and the actual tax benefit realized for the tax deductions from stock options exercised during the years ended Dec. 31 were as follows:
| (Thousands of Dollars) | | 2011 | | | 2010 | | | 2009 | |
| Cash received from stock options exercised | | $ | 30,381 | | | $ | 1,033 | | | $ | 15,759 | |
| Tax benefit realized for the tax deductions from stock options exercised | | | 157 | | | | 40 | | | | 277 | |
Restricted Stock — Certain employees may elect to receive shares of common or restricted stock under the Xcel Energy Inc. Executive Annual Incentive Award Plan. Restricted stock vests and settles in equal annual installments over a three-year period. Xcel Energy Inc. reinvests dividends on the restricted stock it holds while restrictions are in place. Restrictions also apply to the additional shares of restricted stock acquired through dividend reinvestment. If the restricted shares are forfeited, the employee is not entitled to the dividends on those shares. Restricted stock has a fair value equal to the market trading price of Xcel Energy Inc.’s stock at the grant date.
Xcel Energy Inc. granted shares of restricted stock for the years ended Dec. 31 as follows:
| (Shares in Thousands) | | 2011 | | 2010 | | 2009 | |
| Granted shares | | | 15 | | | | 44 | | | | - | |
| Grant date fair value | | $ | 23.62 | | | $ | 20.47 | | | $ | - | |
A summary of the changes of nonvested restricted stock for the year ended Dec. 31, 2011 were as follows:
| (Shares in Thousands) | | Shares | | | Weighted Average Grant Date Fair Value | |
| Nonvested restricted stock at Jan. 1 | | | 55 | | | $ | 20.28 | |
| Granted | | | 15 | | | | 23.62 | |
| Vested | | | (25 | ) | | | 20.53 | |
| Dividend equivalents | | | 2 | | | | 24.37 | |
| Nonvested restricted stock at Dec. 31 | | | 47 | | | | 21.36 | |
Restricted Stock Units (RSUs) — Xcel Energy Inc.’s Board of Directors has granted RSUs under the Xcel Energy Inc. 2005 Long-term Incentive Plan (as amended and restated in 2010). The plan allows the attachment of various performance goals to the RSUs granted. The performance goals may vary by plan year. At the end of the restricted performance period, the grants will be awarded if the performance goals are met. If the goals are not achieved by the end of the restricted performance period, all associated restricted stock units and dividend equivalents are forfeited.
For RSUs issued in 2009 and 2010, if the performance criteria have not been met within four years of the grant date, all RSUs, plus associated dividend equivalents, shall be forfeited. The performance conditions for RSUs granted in 2011 will be measured three years after the grant date, at which time the RSUs, plus associated dividend equivalents, will either be settled or forfeited. Payout of the RSUs and the lapsing of restrictions on the transfer of units are based on one of two separate performance criteria.
The performance conditions for a portion of the awarded units are based on EPS growth, with an additional condition that Xcel Energy Inc.’s annual dividend paid on its common stock remains at a specified amount per share or greater. RSUs issued in 2009 and 2010, plus associated dividend equivalents, will be settled and the restricted period will lapse after Xcel Energy Inc. achieves a specified level of EPS growth. RSUs issued in 2011, plus associated dividend equivalents, will be settled or forfeited and the restricted period will lapse after three years, with potential payouts ranging from 0 percent to 150 percent, depending on the level of EPS growth.
The performance conditions for the remaining awarded units are based on environmental performance. RSUs issued in 2009 and 2010, plus associated dividend equivalents, will be settled and the restricted period will lapse after Xcel Energy Inc. achieves a specified level of environmental performance, based on established indicators. RSUs issued in 2011, plus associated dividend equivalents, will be settled or forfeited and the restricted period will lapse after three years with potential payouts ranging from 0 percent to 150 percent, depending on the level of environmental performance, based on established indicators.
The 2007 environmental RSUs met their target as of Dec. 31, 2009 and were settled in shares in February 2010. The 2007 RSUs measured on EPS growth and all 2008 RSUs met their targets as of Dec. 31, 2010 and were settled in shares in February 2011. The 2010 RSUs measured on EPS growth and all 2009 RSUs met their targets as of Dec. 31, 2011, and will be settled in shares in February 2012.
The RSUs granted for the years ended Dec. 31 were as follows:
| (Units in Thousands) | | 2011 | | | 2010 | | | 2009 | |
| Granted units | | | 828 | | | | 601 | | | | 597 | |
| Weighted average grant date fair value | | $ | 23.63 | | | $ | 21.26 | | | $ | 18.88 | |
A summary of the changes of nonvested RSUs for the year ended Dec. 31, 2011, were as follows:
| (Units in Thousands) | | Units | | | Weighted Average Grant Date Fair Value | |
| Nonvested restricted stock units at Jan. 1 | | | 1,138 | | | $ | 20.12 | |
| Granted | | | 828 | | | | 23.63 | |
| Forfeited | | | (270 | ) | | | 21.50 | |
| Vested | | | (1,091 | ) | | | 20.45 | |
| Dividend equivalents | | | 68 | | | | 21.18 | |
| Nonvested restricted stock units at Dec. 31 | | | 673 | | | | 23.46 | |
The total fair value of nonvested RSUs as of Dec. 31, 2011 was $18.6 million and the weighted average remaining contractual life was 2.0 years.
Approximately 1.1 million RSUs vested during 2011 at a total fair value of $30.1 million. Approximately 0.6 million RSUs vested during 2010 at a total fair value of $14.8 million. Approximately 0.04 million RSUs vested during 2009 at a total fair value of $0.8 million.
Stock Equivalent Unit Plan — Non-employee members of the Xcel Energy Inc. Board of Directors receive annual awards of stock equivalent units, with each unit having a value equal to one share of Xcel Energy Inc. common stock. The annual grants are vested as of the date of each member’s election to the board of directors; there is no further service or other condition attached to the annual grants after the member has been elected to the board. Additionally, directors may elect to receive their fees in stock equivalent units in lieu of cash, and similarly have no further service or other conditions attached. Dividends on Xcel Energy Inc.’s common stock are converted to stock equivalent units and granted based on the number of stock equivalent units held by each participant as of the dividend date. The stock equivalent units are payable as a distribution of Xcel Energy Inc.’s common stock upon a director’s termination of service.
The stock equivalent units granted for the years ended Dec. 31 were as follows:
| (Units in Thousands) | | 2011 | | | 2010 | | | 2009 | |
| Granted units | | | 60 | | | | 66 | | | | 72 | |
| Grant date fair value | | $ | 25.12 | | | $ | 21.14 | | | $ | 17.87 | |
A summary of the stock equivalent unit changes for the year ended Dec. 31, 2011 are as follows:
| (Units in Thousands) | | Units | | | Weighted Average Grant Date Fair Value | |
| Stock equivalent units at Jan. 1 | | | 471 | | | $ | 19.90 | |
| Granted | | | 60 | | | | 25.12 | |
| Units distributed | | | (29 | ) | | | 20.31 | |
| Dividend equivalents | | | 20 | | | | 24.38 | |
| Stock equivalent units at Dec. 31 | | | 522 | | | | 20.65 | |
PSP Awards — Xcel Energy Inc.’s Board of Directors has granted PSP awards under the Xcel Energy Inc. 2005 Long-term Incentive Plan (as amended and restated effective in 2010). The plan allows Xcel Energy to attach various performance goals to the PSP awards granted. The PSP awards have been historically dependent on a single measure of performance, Xcel Energy Inc.’s TSR measured over a three-year period. Xcel Energy Inc.’s TSR is compared to the TSR of other companies in the EEI Investor-Owned Electrics index. At the end of the three-year period, potential payouts of the PSP awards range from 0 percent to 200 percent, depending on Xcel Energy Inc.’s TSR compared to the peer group.
The PSP awards granted for the years ended Dec. 31 were as follows:
| (In Thousands) | | 2011 | | | 2010 | | | 2009 | |
| Awards granted | | | 311 | | | | 225 | | | | 207 | |
The total amounts of performance awards settled during the years ended Dec. 31 were as follows:
| (In Thousands) | | 2011 | | | 2010 | | | 2009 | |
| Awards settled | | | 305 | | | | 267 | | | | 293 | |
| Settlement amount (cash and common stock) | | $ | 7,200 | | | $ | 5,460 | | | $ | 5,195 | |
The amount of cash used to settle Xcel Energy’s PSP awards was $3.6 million and $2.7 million in 2011 and 2010, respectively.
Share-Based Compensation Expense — The vesting of the RSUs is predicated on the achievement of a performance condition, which is the achievement of an earnings per share or environmental measures target. RSU awards and restricted stock are considered to be equity awards, since the plan settlement determination (shares or cash) resides with Xcel Energy and not the participants. In addition, these awards have not been previously settled in cash and Xcel Energy plans to continue electing share settlement. The grant date fair value of RSUs and restricted stock is expensed as employees vest in their rights to those awards.
The PSP awards have been historically settled partially in cash, and therefore, do not qualify as an equity award, but rather are accounted for as a liability award. As liability awards, the fair value on which ratable expense is based, as employees vest in their rights to those awards, is remeasured each period based on the current stock price and performance conditions, and final expense is based on the market value of the shares on the date the award is settled.
The compensation costs related to share-based awards for the years ended Dec. 31 were as follows:
| (Thousands of Dollars) | | 2011 | | | 2010 | | | 2009 | |
Compensation cost for share-based awards (a) (b) | | $ | 45,006 | | | $ | 35,807 | | | $ | 29,672 | |
| Tax benefit recognized in income | | | 17,559 | | | | 13,964 | | | | 11,471 | |
| Total compensation cost capitalized | | | 3,857 | | | | 3,646 | | | | 3,636 | |
| (a) | Compensation costs for share-based payment arrangements is included in other O&M expense in the consolidated statements of income. |
| (b) | Included in compensation cost for share-based awards are matching contributions related to the Xcel Energy 401(k) plan, which totaled $21.6 million, $20.7 million and $19.3 million for the years ended 2011, 2010 and 2009, respectively. |
The maximum aggregate number of shares of common stock available for issuance under the Xcel Energy Inc. 2005 Long-term Incentive Plan (as amended and restated effective Feb. 17, 2010) is 8.3 million shares. Under the Xcel Energy Inc. Executive Annual Incentive Award Plan (as amended and restated effective Feb. 17, 2010), the total number of shares approved for issuance is 1.2 million shares.
As of Dec. 31, 2011 and 2010, there was approximately $15.4 million and $18.6 million, respectively, of total unrecognized compensation cost related to nonvested share-based compensation awards. Xcel Energy expects to recognize that cost over a weighted average period of 1.9 years.
9. Benefit Plans and Other Postretirement Benefits
Xcel Energy offers various benefit plans to its employees. Approximately 50 percent of employees that receive benefits are represented by several local labor unions under several collective-bargaining agreements. At Dec. 31, 2011:
| | · | NSP-Minnesota had 2,033 and NSP-Wisconsin had 405 bargaining employees covered under a collective-bargaining agreement, which expires at the end of 2013. NSP-Minnesota also had an additional 228 nuclear operation bargaining employees covered under several collective-bargaining agreements, which expire at various dates in 2012 and 2013. |
| | · | PSCo had 2,122 bargaining employees covered under a collective-bargaining agreement, which expires in May 2014. |
| | · | SPS had 804 bargaining employees covered under a collective-bargaining agreement, which expires in October 2014. |
The plans invest in various instruments which are disclosed under the accounting guidance for fair value measurements which establishes a hierarchal framework for disclosing the observability of the inputs utilized in measuring fair value. The three levels in the hierarchy and examples of each level are as follows:
Level 1 — Quoted prices are available in active markets for identical assets as of the reporting date. The types of assets included in Level 1 are highly liquid and actively traded instruments with quoted prices, such as common stocks listed by the New York Stock Exchange.
Level 2 — Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reporting date. The types of assets included in Level 2 are typically either comparable to actively traded securities or contracts or priced with models using highly observable inputs, such as corporate bonds with pricing based on market interest rate curves and recent trades of similarly rated securities.
Level 3 — Significant inputs to pricing have little or no observability as of the reporting date. The types of assets included in Level 3 are those with inputs requiring significant management judgment or estimation, such as private equity investments and real estate investments, for which the measurement of net asset value requires significant use of unobservable inputs when determining the fair value of the underlying fund investments, including equity in non-publicly traded entities and real estate properties.
Pension Benefits
Xcel Energy has several noncontributory, defined benefit pension plans that cover almost all employees. Benefits are based on a combination of years of service, the employee’s average pay and social security benefits. Xcel Energy’s policy is to fully fund into an external trust the actuarially determined pension costs recognized for ratemaking and financial reporting purposes, subject to the limitations of applicable employee benefit and tax laws.
Xcel Energy bases the investment-return assumption on expected long-term performance for each of the investment types included in its pension asset portfolio. Xcel Energy considers the actual historical returns achieved by its asset portfolio over the past 20-year or longer period, as well as the long-term return levels projected and recommended by investment experts. The historical weighted average annual return for the past 20 years for the Xcel Energy portfolio of pension investments is 8.73 percent, which is greater than the current assumption level. The pension cost determination assumes a forecasted mix of investment types over the long term. Investment returns were above the assumed levels of 7.50, 7.79 and 8.50 percent in 2011, 2010 and 2009, respectively. Xcel Energy continually reviews its pension assumptions. In 2012, Xcel Energy’s expected investment return assumption is 7.10 percent.
The assets are invested in a portfolio according to Xcel Energy’s return, liquidity and diversification objectives to provide a source of funding for plan obligations and minimize the necessity of contributions to the plan, within appropriate levels of risk. The principal mechanism for achieving these objectives is the projected allocation of assets to selected asset classes, given the long-term risk, return, and liquidity characteristics of each particular asset class. There were no significant concentrations of risk in any particular industry, index, or entity; however, as Xcel Energy has experienced in recent years, unusual market volatility can impact even well-diversified portfolios and significantly affect the return levels achieved by pension assets in any year.
The following table presents the target pension asset allocations for Xcel Energy:
| | | 2011 | | | 2010 | |
| Domestic and international equity securities | | | 27 | % | | | 24 | % |
| Long-duration fixed income securities | | | 31 | | | | 41 | |
| Short-to-intermediate fixed income securities | | | 12 | | | | 11 | |
| Alternative investments | | | 27 | | | | 17 | |
| Cash | | | 3 | | | | 7 | |
| Total | | | 100 | % | | | 100 | % |
Xcel Energy’s ongoing investment strategy is based on plan-specific investment recommendations that seek to minimize potential investment and interest rate risk as a plan’s funded status increases over time. The investment recommendations result in a greater percentage of long-duration fixed income securities being allocated to specific plans having relatively higher funded status ratios, and a greater percentage of growth assets being allocated to plans having relatively lower funded status ratios. The aggregate projected asset allocation presented in the table above for the master pension trust results from the plan-specific strategies.
Pension Plan Assets
The following tables present, for each of the fair value hierarchy levels, Xcel Energy’s pension plan assets that are measured at fair value as of Dec. 31, 2011 and 2010:
| | | Dec. 31, 2011 | |
| (Thousands of Dollars) | | Level 1 | | | Level 2 | | | Level 3 | | | Total | |
| Cash equivalents | | $ | 147,590 | | | $ | - | | | $ | - | | | $ | 147,590 | |
| Derivatives | | | - | | | | 8,011 | | | | - | | | | 8,011 | |
| Government securities | | | - | | | | 301,999 | | | | - | | | | 301,999 | |
| Corporate bonds | | | - | | | | 606,001 | | | | - | | | | 606,001 | |
| Asset-backed securities | | | - | | | | - | | | | 31,368 | | | | 31,368 | |
| Mortgage-backed securities | | | - | | | | - | | | | 73,522 | | | | 73,522 | |
| Common stock | | | 68,553 | | | | - | | | | - | | | | 68,553 | |
| Private equity investments | | | - | | | | - | | | | 159,363 | | | | 159,363 | |
| Commingled funds | | | - | | | | 1,292,569 | | | | - | | | | 1,292,569 | |
| Real estate | | | - | | | | - | | | | 37,106 | | | | 37,106 | |
| Securities lending collateral obligation and other | | | - | | | | (55,802 | ) | | | - | | | | (55,802 | ) |
| Total | | $ | 216,143 | | | $ | 2,152,778 | | | $ | 301,359 | | | $ | 2,670,280 | |
| | | Dec. 31, 2010 | |
| (Thousands of Dollars) | | Level 1 | | | Level 2 | | | Level 3 | | | Total | |
| Cash equivalents | | $ | 122,643 | | | $ | 135,710 | | | $ | - | | | $ | 258,353 | |
| Derivatives | | | - | | | | 8,140 | | | | - | | | | 8,140 | |
| Government securities | | | - | | | | 117,522 | | | | - | | | | 117,522 | |
| Corporate bonds | | | - | | | | 641,807 | | | | - | | | | 641,807 | |
| Asset-backed securities | | | - | | | | - | | | | 26,986 | | | | 26,986 | |
| Mortgage-backed securities | | | - | | | | - | | | | 113,418 | | | | 113,418 | |
| Common stock | | | 117,899 | | | | - | | | | - | | | | 117,899 | |
| Private equity investments | | | - | | | | - | | | | 122,223 | | | | 122,223 | |
| Commingled funds | | | - | | | | 1,152,386 | | | | - | | | | 1,152,386 | |
| Real estate | | | - | | | | - | | | | 73,701 | | | | 73,701 | |
| Securities lending collateral obligation and other | | | - | | | | (91,727 | ) | | | - | | | | (91,727 | ) |
| Total | | $ | 240,542 | | | $ | 1,963,838 | | | $ | 336,328 | | | $ | 2,540,708 | |
The following tables present the changes in Xcel Energy’s Level 3 pension plan assets for the years ended Dec. 31, 2011, 2010 and 2009:
| | | | | | | | | | | | Purchases, | | | | |
| | | | | | Net Realized | | | Net Unrealized | | | Issuances, and | | | | |
| (Thousands of Dollars) | | Jan. 1, 2011 | | | Gains (Losses) | | | Gains (Losses) | | | Settlements, Net | | | Dec. 31, 2011 | |
| Asset-backed securities | | $ | 26,986 | | | $ | 2,391 | | | $ | (2,504 | ) | | $ | 4,495 | | | $ | 31,368 | |
| Mortgage-backed securities | | | 113,418 | | | | 1,103 | | | | (5,926 | ) | | | (35,073 | ) | | | 73,522 | |
| Real estate | | | 73,701 | | | | (629 | ) | | | 20,271 | | | | (56,237 | ) | | | 37,106 | |
| Private equity investments | | | 122,223 | | | | 3,971 | | | | 12,412 | | | | 20,757 | | | | 159,363 | |
| Total | | $ | 336,328 | | | $ | 6,836 | | | $ | 24,253 | | | $ | (66,058 | ) | | $ | 301,359 | |
| | | | | | | | | | | | Purchases, | | | | |
| | | | | | Net Realized | | | Net Unrealized | | | Issuances, and | | | | |
| (Thousands of Dollars) | | Jan. 1, 2010 | | | Gains (Losses) | | | Gains (Losses) | | | Settlements, Net | | | Dec. 31, 2010 | |
| Asset-backed securities | | $ | 47,825 | | | $ | 3,400 | | | $ | (7,078 | ) | | $ | (17,161 | ) | | $ | 26,986 | |
| Mortgage-backed securities | | | 144,006 | | | | 13,719 | | | | (19,095 | ) | | | (25,212 | ) | | | 113,418 | |
| Real estate | | | 66,704 | | | | (1,135 | ) | | | 8,235 | | | | (103 | ) | | | 73,701 | |
| Private equity investments | | | 82,098 | | | | (1,008 | ) | | | (24 | ) | | | 41,157 | | | | 122,223 | |
| Total | | $ | 340,633 | | | $ | 14,976 | | | $ | (17,962 | ) | | $ | (1,319 | ) | | $ | 336,328 | |
| | | | | | | | | | | | Purchases, | | | | |
| | | | | | Net Realized | | | Net Unrealized | | | Issuances, and | | | | |
| (Thousands of Dollars) | | Jan. 1, 2009 | | | Gains (Losses) | | | Gains (Losses) | | | Settlements, Net | | | Dec. 31, 2009 | |
| Asset-backed securities | | $ | 77,398 | | | $ | 2,365 | | | $ | 45,920 | | | $ | (77,858 | ) | | $ | 47,825 | |
| Mortgage-backed securities | | | 166,610 | | | | 5,531 | | | | 97,939 | | | | (126,074 | ) | | | 144,006 | |
| Real estate | | | 109,289 | | | | (569 | ) | | | (42,638 | ) | | | 622 | | | | 66,704 | |
| Private equity investments | | | 81,034 | | | | - | | | | (5,682 | ) | | | 6,746 | | | | 82,098 | |
| Total | | $ | 434,331 | | | $ | 7,327 | | | $ | 95,539 | | | $ | (196,564 | ) | | $ | 340,633 | |
Benefit Obligations — A comparison of the actuarially computed pension benefit obligation and plan assets for Xcel Energy is presented in the following table:
| (Thousands of Dollars) | | 2011 | | | 2010 | |
| Accumulated Benefit Obligation at Dec. 31 | | $ | 3,073,637 | | | $ | 2,865,845 | |
| | | | | | | | | |
| Change in Projected Benefit Obligation: | | | | | | | | |
| Obligation at Jan. 1 | | $ | 3,030,292 | | | $ | 2,829,631 | |
| Service cost | | | 77,319 | | | | 73,147 | |
| Interest cost | | | 161,412 | | | | 165,010 | |
| Plan amendments | | | - | | | | 18,739 | |
| Actuarial loss | | | 195,369 | | | | 169,203 | |
| Benefit payments | | | (238,173 | ) | | | (225,438 | ) |
| Obligation at Dec. 31 | | $ | 3,226,219 | | | $ | 3,030,292 | |
| (Thousands of Dollars) | | 2011 | | | 2010 | |
| Change in Fair Value of Plan Assets: | | | | | | |
| Fair value of plan assets at Jan. 1 | | $ | 2,540,708 | | | $ | 2,449,326 | |
| Actual return on plan assets | | | 230,401 | | | | 282,688 | |
| Employer contributions | | | 137,344 | | | | 34,132 | |
| Benefit payments | | | (238,173 | ) | | | (225,438 | ) |
| Fair value of plan assets at Dec. 31 | | $ | 2,670,280 | | | $ | 2,540,708 | |
| | | | | | | | | |
| Funded Status of Plans at Dec. 31: | | | | | | | | |
Funded status (a) | | $ | (555,939 | ) | | $ | (489,584 | ) |
| | | | | | | | | |
| Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost: | | | | | | |
| Net loss | | $ | 1,610,946 | | | $ | 1,502,888 | |
| Prior service cost | | | 18,432 | | | | 40,965 | |
| Total | | $ | 1,629,378 | | | $ | 1,543,853 | |
| | | | | | | | | |
Amounts Related to the Funded Status of the Plans Have Been Recorded as Follows Based Upon Expected Recovery in Rates: | | | | | | | | |
| Current regulatory assets | | $ | 123,814 | | | $ | 92,765 | |
| Noncurrent regulatory assets | | | 1,435,372 | | | | 1,386,125 | |
| Deferred income taxes | | | 28,759 | | | | 26,592 | |
| Net-of-tax accumulated other comprehensive income | | | 41,433 | | | | 38,371 | |
| Total | | $ | 1,629,378 | | | $ | 1,543,853 | |
| | | | | | | | | |
| Measurement date | | Dec. 31, 2011 | | | Dec. 31, 2010 | |
| | | | | | | | | |
| Significant Assumptions Used to Measure Benefit Obligations: | | | | | | | | |
| Discount rate for year-end valuation | | | 5.00 | % | | | 5.50 | % |
| Expected average long-term increase in compensation level | | | 4.00 | | | | 4.00 | |
| Mortality table | | RP 2000 | | | RP 2000 | |
(a) | Amounts are recognized in noncurrent liabilities on Xcel Energy’s consolidated balance sheet. |
Cash Flows — Cash funding requirements can be impacted by changes to actuarial assumptions, actual asset levels and other calculations prescribed by the funding requirements of income tax and other pension-related regulations. These regulations did not require cash funding for 2008 through 2010 for Xcel Energy’s pension plans. Required contributions were made in 2011 and 2012 to meet minimum funding requirements.
The Pension Protection Act changed the minimum funding requirements for defined benefit pension plans beginning in 2008. The following are the pension funding contributions, both voluntary and required, made by Xcel Energy for 2010 through 2012:
| | · | In January 2012, contributions of $190.5 million were made across four of Xcel Energy’s pension plans; |
| | · | In 2011, contributions of $137.3 million were made across three of Xcel Energy’s pension plans; |
| | · | In 2010, contributions of $34 million were made to the Xcel Energy Pension Plan. |
| | · | For future years, we anticipate contributions will be made as necessary. |
Plan Amendments — No amendments occurred during 2011 to the Xcel Energy pension plans.
Benefit Costs — The components of Xcel Energy’s net periodic pension cost were:
| | | | | | | | | | |
| (Thousands of Dollars) | | 2011 | | | 2010 | | | 2009 | |
| Service cost | | $ | 77,319 | | | $ | 73,147 | | | $ | 65,461 | |
| Interest cost | | | 161,412 | | | | 165,010 | | | | 169,790 | |
| Expected return on plan assets | | | (221,600 | ) | | | (232,318 | ) | | | (256,538 | ) |
| Amortization of prior service cost | | | 22,533 | | | | 20,657 | | | | 24,618 | |
| Amortization of net loss | | | 78,510 | | | | 48,315 | | | | 12,455 | |
| Net periodic pension cost | | | 118,174 | | | | 74,811 | | | | 15,786 | |
| Costs not recognized due to effects of regulation | | | (37,198 | ) | | | (27,027 | ) | | | (2,891 | ) |
| Net benefit cost recognized for financial reporting | | $ | 80,976 | | | $ | 47,784 | | | $ | 12,895 | |
| | | | | | | | | | |
| Significant Assumptions Used to Measure Costs: | | | | | | | | | |
| Discount rate | | | 5.50 | % | | | 6.00 | % | | | 6.75 | % |
| Expected average long-term increase in compensation level | | | 4.00 | | | | 4.00 | | | | 4.00 | |
| Expected average long-term rate of return on assets | | | 7.50 | | | | 7.79 | | | | 8.50 | |
Pension costs include an expected return impact for the current year that may differ from actual investment performance in the plan. The return assumption used for 2012 pension cost calculations will be 7.10 percent.
Xcel Energy also maintains noncontributory, defined benefit supplemental retirement income plans for certain qualifying executive personnel. Benefits for these unfunded plans are paid out of Xcel Energy’s consolidated operating cash flows.
Defined Contribution Plans
Xcel Energy maintains 401(k) and other defined contribution plans that cover substantially all employees. Total contributions to these plans were approximately $27.1 million in 2011, $27.3 million in 2010 and $21.9 million in 2009.
Postretirement Health Care Benefits
Xcel Energy has a contributory health and welfare benefit plan that provides health care and death benefits to certain Xcel Energy retirees.
| | · | The former NSP discontinued contributing toward health care benefits for nonbargaining employees retiring after 1998 and for bargaining employees of NSP-Minnesota and NSP-Wisconsin who retired after 1999. |
| | · | Xcel Energy discontinued contributing toward health care benefits for former NCE nonbargaining employees retiring after June 30, 2003. |
| | · | Employees of NCE who retired in 2002 continue to receive employer-subsidized health care benefits. |
| | · | Nonbargaining employees of the former NCE who retired after 1998, bargaining employees of the former NCE who retired after 1999 and nonbargaining employees of NCE who retired after June 30, 2003, are eligible to participate in the Xcel Energy health care program with no employer subsidy. |
In 1993, Xcel Energy adopted accounting guidance regarding other non-pension postretirement benefits and elected to amortize the unrecognized APBO on a straight-line basis over 20 years.
Regulatory agencies for nearly all of Xcel Energy’s retail and wholesale utility customers have allowed rate recovery of accrued postretirement benefit costs. The Colorado jurisdictional postretirement benefit costs deferred during the transition period are being amortized to expense on a straight-line basis over the 15-year period from 1998 to 2012. PSCo transitioned to full accrual accounting for postretirement benefit costs between 1993 and 1997.
Plan Assets — Certain state agencies that regulate Xcel Energy Inc.’s utility subsidiaries also have issued guidelines related to the funding of postretirement benefit costs. SPS is required to fund postretirement benefit costs for Texas and New Mexico jurisdictional amounts collected in rates and PSCo is required to fund postretirement benefit costs in irrevocable external trusts that are dedicated to the payment of these postretirement benefits. Also, a portion of the assets contributed on behalf of nonbargaining retirees has been funded into a sub-account of the Xcel Energy pension plans. These assets are invested in a manner consistent with the investment strategy for the pension plan.
Xcel Energy bases its investment-return assumption for the postretirement health care fund assets on expected long-term performance for each of the investment types included in its asset portfolio. The assets are invested in a portfolio according to Xcel Energy’s return, liquidity and diversification objectives to provide a source of funding for plan obligations and minimize the necessity of contributions to the plan, within appropriate levels of risk. The principal mechanism for achieving these objectives is the projected allocation of assets to selected asset classes, given the long-term risk, return, correlation, and liquidity characteristics of each particular asset class. There were no significant concentrations of risk in any particular industry, index, or entity. Investment-return volatility is not considered to be a material factor in postretirement health care costs.
The following tables present, for each of the fair value hierarchy levels, Xcel Energy’s postretirement benefit plan assets that are measured at fair value as of Dec. 31, 2011 and 2010:
| | | Dec. 31, 2011 | |
| (Thousands of Dollars) | | Level 1 | | | Level 2 | | | Level 3 | | | Total | |
| Cash equivalents | | $ | 58,037 | | | $ | - | | | $ | - | | | $ | 58,037 | |
| Derivatives | | | - | | | | 13,178 | | | | - | | | | 13,178 | |
| Government securities | | | - | | | | 65,746 | | | | - | | | | 65,746 | |
| Corporate bonds | | | - | | | | 61,524 | | | | - | | | | 61,524 | |
| Asset-backed securities | | | - | | | | - | | | | 7,867 | | | | 7,867 | |
| Mortgage-backed securities | | | - | | | | - | | | | 27,253 | | | | 27,253 | |
| Preferred stock | | | - | | | | 423 | | | | - | | | | 423 | |
| Common stock | | | 351 | | | | - | | | | - | | | | 351 | |
| Private equity investments | | | - | | | | - | | | | 479 | | | | 479 | |
| Commingled funds | | | - | | | | 202,912 | | | | - | | | | 202,912 | |
| Real estate | | | - | | | | - | | | | 144 | | | | 144 | |
| Securities lending collateral obligation and other | | | - | | | | (11,079 | ) | | | - | | | | (11,079 | ) |
| Total | | $ | 58,388 | | | $ | 332,704 | | | $ | 35,743 | | | $ | 426,835 | |
| | | Dec. 31, 2010 | |
| (Thousands of Dollars) | | Level 1 | | | Level 2 | | | Level 3 | | | Total | |
| Cash equivalents | | $ | 72,573 | | | $ | 76,352 | | | $ | - | | | $ | 148,925 | |
| Derivatives | | | - | | | | 13,632 | | | | - | | | | 13,632 | |
| Government securities | | | - | | | | 3,402 | | | | - | | | | 3,402 | |
| Corporate bonds | | | - | | | | 70,752 | | | | - | | | | 70,752 | |
| Asset-backed securities | | | - | | | | - | | | | 2,585 | | | | 2,585 | |
| Mortgage-backed securities | | | - | | | | - | | | | 19,212 | | | | 19,212 | |
| Preferred stock | | | - | | | | 507 | | | | - | | | | 507 | |
| Commingled funds | | | - | | | | 102,962 | | | | - | | | | 102,962 | |
| Securities lending collateral obligation and other | | | - | | | | 70,253 | | | | - | | | | 70,253 | |
| Total | | $ | 72,573 | | | $ | 337,860 | | | $ | 21,797 | | | $ | 432,230 | |
The following tables present the changes in Xcel Energy’s Level 3 postretirement benefit plan assets for the years ended Dec. 31, 2011, 2010 and 2009:
| | | | | | | | | | | | Purchases, | | | | |
| | | | | | Net Realized | | | Net Unrealized | | | Issuances, and | | | | |
| (Thousands of Dollars) | | Jan. 1, 2011 | | | Gains (Losses) | | | Gains (Losses) | | | Settlements, Net | | | Dec. 31, 2011 | |
| Asset-backed securities | | $ | 2,585 | | | $ | (10 | ) | | $ | (664 | ) | | $ | 5,956 | | | $ | 7,867 | |
| Mortgage-backed securities | | | 19,212 | | | | (1,669 | ) | | | 2,623 | | | | 7,087 | | | | 27,253 | |
| Real estate | | | - | | | | (2 | ) | | | (34 | ) | | | 180 | | | | 144 | |
| Private equity investments | | | - | | | | 12 | | | | 53 | | | | 414 | | | | 479 | |
| Total | | $ | 21,797 | | | $ | (1,669 | ) | | $ | 1,978 | | | $ | 13,637 | | | $ | 35,743 | |
| | | | | | | | | | | | Purchases, | | | | |
| | | | | | Net Realized | | | Net Unrealized | | | Issuances, and | | | | |
| (Thousands of Dollars) | | Jan. 1, 2010 | | | Gains (Losses) | | | Gains (Losses) | | | Settlements, Net | | | Dec. 31, 2010 | |
| Asset-backed securities | | $ | 8,293 | | | $ | (259 | ) | | $ | 2,073 | | | $ | (7,522 | ) | | $ | 2,585 | |
| Mortgage-backed securities | | | 47,078 | | | | (927 | ) | | | 15,642 | | | | (42,581 | ) | | | 19,212 | |
| Total | | $ | 55,371 | | | $ | (1,186 | ) | | $ | 17,715 | | | $ | (50,103 | ) | | $ | 21,797 | |
| | | | | | | | | | | | Purchases, | | | | |
| | | | | | Net Realized | | | Net Unrealized | | | Issuances, and | | | | |
| (Thousands of Dollars) | | Jan. 1, 2009 | | | Gains (Losses) | | | Gains (Losses) | | | Settlements, Net | | | Dec. 31, 2009 | |
| Asset-backed securities | | $ | 8,705 | | | $ | 4 | | | $ | 1,025 | | | $ | (1,441 | ) | | $ | 8,293 | |
| Mortgage-backed securities | | | 69,988 | | | | 733 | | | | 2,289 | | | | (25,932 | ) | | | 47,078 | |
| Total | | $ | 78,693 | | | $ | 737 | | | $ | 3,314 | | | $ | (27,373 | ) | | $ | 55,371 | |
Benefit Obligations — A comparison of the actuarially computed benefit obligation and plan assets for Xcel Energy is presented in the following table:
| (Thousands of Dollars) | | 2011 | | | 2010 | |
| Change in Projected Benefit Obligation: | | | | | | |
| Obligation at Jan. 1 | | $ | 794,905 | | | $ | 728,902 | |
| Service cost | | | 4,824 | | | | 4,006 | |
| Interest cost | | | 42,086 | | | | 42,780 | |
| Medicare subsidy reimbursements | | | 3,518 | | | | 5,423 | |
| ERRP proceeds shared with retirees | | | 4,269 | | | | - | |
| Plan amendments | | | (26,630 | ) | | | - | |
| Plan participants’ contributions | | | 15,690 | | | | 14,315 | |
| Actuarial loss | | | 8,823 | | | | 68,126 | |
| Benefit payments | | | (70,638 | ) | | | (68,647 | ) |
| Obligation at Dec. 31 | | $ | 776,847 | | | $ | 794,905 | |
| | | | | | | | | |
| Change in Fair Value of Plan Assets: | | | | | | | | |
| Fair value of plan assets at Jan. 1 | | $ | 432,230 | | | $ | 384,689 | |
| Actual return on plan assets | | | 535 | | | | 53,430 | |
| Plan participants’ contributions | | | 15,690 | | | | 14,315 | |
| Employer contributions | | | 49,018 | | | | 48,443 | |
| Benefit payments | | | (70,638 | ) | | | (68,647 | ) |
| Fair value of plan assets at Dec. 31 | | $ | 426,835 | | | $ | 432,230 | |
| (Thousands of Dollars) | | 2011 | | | 2010 | |
| Funded Status of Plans at Dec. 31: | | | | | | |
| Funded status | | $ | (350,012 | ) | | $ | (362,675 | ) |
| Current assets | | | 332 | | | | - | |
| Current liabilities | | | (7,594 | ) | | | (5,392 | ) |
| Noncurrent liabilities | | | (342,750 | ) | | | (357,283 | ) |
| Net postretirement amounts recognized on consolidated balance sheets | | $ | (350,012 | ) | | $ | (362,675 | ) |
| | | | | | | | | |
| Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost: | | | | | | | | |
| Net loss | | $ | 246,846 | | | $ | 221,335 | |
| Prior service credit | | | (50,652 | ) | | | (28,954 | ) |
| Transition obligation | | | 15,147 | | | | 29,591 | |
| Total | | $ | 211,341 | | | $ | 221,972 | |
| | | | | | | | | |
Amounts Related to the Funded Status of the Plans Have Been Recorded as Follows Based Upon Expected Recovery in Rates: | | | | | | | | |
| Current regulatory assets | | $ | 26,139 | | | $ | 20,225 | |
| Noncurrent regulatory assets | | | 176,730 | | | | 197,952 | |
| Current regulatory liabilities | | | (1,866 | ) | | | - | |
| Noncurrent regulatory liabilities | | | - | | | | (6,423 | ) |
| Deferred income taxes | | | 4,207 | | | | 4,159 | |
| Net-of-tax accumulated other comprehensive income | | | 6,131 | | | | 6,059 | |
| Total | | $ | 211,341 | | | $ | 221,972 | |
| | | | | | | | | |
| Measurement date | | Dec. 31, 2011 | | | Dec. 31, 2010 | |
| | | | | | | | | |
| Significant Assumptions Used to Measure Benefit Obligations: | | | | | | | | |
| Discount rate for year-end valuation | | | 5.00 | % | | | 5.50 | % |
| Mortality table | | RP 2000 | | | RP 2000 | |
| Health care costs trend rate - initial | | | 6.31 | % | | | 6.50 | % |
Effective Dec. 31, 2011, the ultimate trend assumption remained unchanged at 5.0 percent. The period until the ultimate rate is reached remained unchanged at eight years. Xcel Energy bases its medical trend assumption on the long-term cost inflation expected in the health care market, considering the levels projected and recommended by industry experts, as well as recent actual medical cost increases experienced by Xcel Energy’s retiree medical plan.
A 1-percent change in the assumed health care cost trend rate would have the following effects on Xcel Energy:
| | | One Percentage Point | |
| (Thousands of Dollars) | | Increase | | | Decrease | |
| APBO | | $ | 79,710 | | | $ | (65,195 | ) |
| Service and interest components | | | 5,598 | | | | (4,456 | ) |
Cash Flows — The postretirement health care plans have no funding requirements under income tax and other retirement-related regulations other than fulfilling benefit payment obligations, when claims are presented and approved under the plans. Additional cash funding requirements are prescribed by certain state and federal rate regulatory authorities, as discussed previously. Xcel Energy contributed $49.0 million during 2011 and $48.4 million during 2010 and expects to contribute approximately $39.1 million during 2012.
Plan Amendments — The 2011 decrease of the projected Xcel Energy postretirement health and welfare benefit obligation for plan amendments is due to changes in the participant co-pay structure for certain retiree groups and the elimination of dental and vision benefits for some non-bargaining retirees.
Benefit Costs — The components of Xcel Energy’s net periodic postretirement benefit costs were:
| (Thousands of Dollars) | | 2011 | | | 2010 | | | 2009 | |
| Service cost | | $ | 4,824 | | | $ | 4,006 | | | $ | 4,665 | |
| Interest cost | | | 42,086 | | | | 42,780 | | | | 50,412 | |
| Expected return on plan assets | | | (31,962 | ) | | | (28,529 | ) | | | (22,775 | ) |
| Amortization of transition obligation | | | 14,444 | | | | 14,444 | | | | 14,444 | |
| Amortization of prior service cost | | | (4,932 | ) | | | (4,932 | ) | | | (2,726 | ) |
| Amortization of net loss | | | 13,294 | | | | 11,643 | | | | 19,329 | |
| Net periodic postretirement benefit cost | | | 37,754 | | | | 39,412 | | | | 63,349 | |
| Additional cost recognized due to effects of regulation | | | 3,891 | | | | 3,891 | | | | 3,891 | |
| Net benefit cost recognized for financial reporting | | $ | 41,645 | | | $ | 43,303 | | | $ | 67,240 | |
| | | | | | | | | | | | | |
| Significant Assumptions Used to Measure Costs: | | | | | | | | | | | | |
| Discount rate | | | 5.50 | % | | | 6.00 | % | | | 6.75 | % |
| Expected average long-term rate of return on assets (before tax) | | | 7.50 | | | | 7.50 | | | | 7.50 | |
Projected Benefit Payments
The following table lists Xcel Energy’s projected benefit payments for the pension and postretirement benefit plans:
| (Thousands of Dollars) | | Projected Pension Benefit Payments | | | Gross Projected Postretirement Health Care Benefit Payments | | | Expected Medicare Part D Subsidies | | | Net Projected Postretirement Health Care Benefit Payments | |
| 2012 | | $ | 270,101 | | | $ | 57,461 | | | $ | 4,523 | | | $ | 52,938 | |
| 2013 | | | 253,333 | | | | 57,318 | | | | 4,871 | | | | 52,447 | |
| 2014 | | | 261,854 | | | | 58,396 | | | | 5,175 | | | | 53,221 | |
| 2015 | | | 263,129 | | | | 59,880 | | | | 5,471 | | | | 54,409 | |
| 2016 | | | 264,885 | | | | 61,375 | | | | 5,751 | | | | 55,624 | |
| 2017-2021 | | | 1,328,001 | | | | 315,139 | | | | 32,659 | | | | 282,480 | |
Multiemployer Plans
NSP-Minnesota and NSP-Wisconsin each contribute to several union multiemployer pension and other postretirement benefit plans, none of which are individually significant. These plans provide pension and postretirement health care benefits to certain union employees, including electrical workers, boilermakers, and other construction and facilities workers who may perform services for more than one employer during a given period and do not participate in the NSP-Minnesota and NSP-Wisconsin sponsored pension and postretirement health care plans. Contributing to these types of plans creates risk that differs from providing benefits under NSP-Minnesota and NSP-Wisconsin sponsored plans, in that if another participating employer ceases to contribute to a multiemployer plan, additional unfunded obligations may need to be funded over time by remaining participating employers.
Contributions to multiemployer plans were as follows for the years ended Dec. 31, 2011, 2010 and 2009. There were no significant changes to the nature or magnitude of the participation of NSP-Minnesota and NSP-Wisconsin in multiemployer plans for the years presented:
| (Thousands of Dollars) | | 2011 | | | 2010 | | | 2009 | |
| Multiemployer pension contributions: | | | | | | | | | |
| NSP-Minnesota | | $ | 17,811 | | | $ | 13,461 | | | $ | 11,348 | |
| NSP-Wisconsin | | | 169 | | | | 170 | | | | 116 | |
| Total | | $ | 17,980 | | | $ | 13,631 | | | $ | 11,464 | |
| | | | | | | | | | | | | |
| Multiemployer other postretirement benefit contributions: | | | | | | | | | | | | |
| NSP-Minnesota | | $ | 336 | | | $ | 153 | | | $ | 140 | |
| Total | | $ | 336 | | | $ | 153 | | | $ | 140 | |
10. Other Income, Net
Other income (expense), net for the years ended Dec. 31 consisted of the following:
| (Thousands of Dollars) | | 2011 | | | 2010 | | | 2009 | |
| Interest income | | $ | 10,639 | | | $ | 11,023 | | | $ | 14,928 | |
| COLI settlement (See Note 6) | | | - | | | | 25,000 | | | | - | |
| Other nonoperating income | | | 3,722 | | | | 1,689 | | | | 3,650 | |
| Life insurance policy expense | | | (4,785 | ) | | | (6,529 | ) | | | (8,646 | ) |
| Other nonoperating expense | | | (321 | ) | | | (40 | ) | | | (161 | ) |
| Other income, net | | $ | 9,255 | | | $ | 31,143 | | | $ | 9,771 | |
11. Fair Value of Financial Assets and Liabilities
Fair Value Measurements
The accounting guidance for fair value measurements and disclosures provides a single definition of fair value and requires certain disclosures about assets and liabilities measured at fair value. A hierarchal framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value is established by this guidance. The three levels in the hierarchy are as follows:
Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices.
Level 2 — Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reporting date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, or priced with discounted cash flow or option pricing models using highly observable inputs.
Level 3 — Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those valued with models requiring significant management judgment or estimation.
Specific valuation methods include the following:
Cash equivalents — The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted net asset values.
Investments in equity securities and other funds — Equity securities are valued using quoted prices in active markets. The fair values for commingled funds, international equity funds, private equity investments and real estate investments are measured using net asset values, which take into consideration the value of underlying fund investments, as well as the other accrued assets and liabilities of a fund, in order to determine a per share market value. The investments in commingled funds and international equity funds may be redeemed for net asset value. Private equity investments require approval of the fund for any unscheduled redemption, and such redemptions may be approved or denied by the fund at its sole discretion. Unscheduled distributions from real estate investments may be redeemed with proper notice; however, withdrawals from real estate investments may be delayed or discounted as a result of fund illiquidity. Given the limited observability of inputs to the valuation of the underlying fund investments of the private equity and real estate investments, fair value measurements for private equity and real estate investments have been assigned a Level 3.
Investments in debt securities — Debt securities are primarily priced using recent trades and observable spreads from benchmark interest rates for similar securities, except for asset-backed and mortgage-backed securities, which also require significant, subjective risk-based adjustments to the interest rate used to discount expected future cash flows, which include estimated principal prepayments. Therefore, fair value measurements for asset-backed and mortgage-backed securities have been assigned a Level 3.
Interest rate derivatives — The fair values of interest rate derivatives are based on broker quotes utilizing current market interest rate forecasts.
Commodity derivatives — The methods utilized to measure the fair value of commodity derivatives include the use of forward prices and volatilities to value commodity forwards and options. Levels are assigned to these fair value measurements based on the significance of the use of subjective forward price and volatility forecasts for commodities and delivery locations with limited observability, or the significance of contractual settlements that extend to periods beyond those readily observable on active exchanges or quoted by brokers. Electric commodity derivatives include FTRs, for which fair value is determined using complex predictive models and inputs including forward commodity prices as well as subjective forecasts of retail and wholesale demand, generation and resulting transmission system congestion. Given the limited observability of management’s forecasts for several of these inputs, fair value measurements for FTRs have been assigned a Level 3.
Xcel Energy continuously monitors the creditworthiness of the counterparties to its commodity derivative contracts and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. Given this assessment, as well as an assessment of the impact of Xcel Energy’s own credit risk when determining the fair value of commodity derivative liabilities, the impact of considering credit risk was immaterial to the fair value of commodity derivative assets and liabilities presented in the consolidated balance sheets.
Non-Derivative Instruments Fair Value Measurements
The NRC requires NSP-Minnesota to maintain a portfolio of investments to fund the costs of decommissioning its nuclear generating plants. Together with all accumulated earnings or losses, the assets of the nuclear decommissioning fund are legally restricted for the purpose of decommissioning the Monticello and Prairie Island nuclear generating plants. The fund contains cash equivalents, debt securities, equity securities and other investments – all classified as available-for-sale. NSP-Minnesota plans to reinvest matured securities until decommissioning begins.
NSP-Minnesota recognizes the costs of funding the decommissioning of its nuclear generating plants over the lives of the plants, assuming rate recovery of all costs. Given the purpose and legal restrictions on the use of nuclear decommissioning fund assets, realized and unrealized gains on fund investments over the life of the fund are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs. Consequently, any realized and unrealized gains and losses on securities in the nuclear decommissioning fund, including any other-than-temporary impairments, are deferred as a component of the regulatory asset for nuclear decommissioning.
Unrealized gains for the decommissioning fund were $79.8 million and $82.5 million at Dec. 31, 2011 and Dec. 31, 2010, respectively, and unrealized losses and amounts recorded as other-than-temporary impairments were $87.5 million and $65.2 million at Dec. 31, 2011 and Dec. 31, 2010, respectively.
The following tables present the cost and fair value of Xcel Energy’s non-derivative instruments with recurring fair value measurements in the nuclear decommissioning fund at Dec. 31, 2011 and 2010:
| | | Dec. 31, 2011 | |
| | | | | | Fair Value | | | | |
| | | | | | | | | | | | | | | | |
| (Thousands of Dollars) | | Cost | | | Level 1 | | | Level 2 | | | Level 3 | | | Total | |
Nuclear decommissioning fund (a) | | | | | | | | | | | | | | | |
| Cash equivalents | | $ | 26,123 | | | $ | 7,103 | | | $ | 19,020 | | | $ | - | | | $ | 26,123 | |
| Commingled funds | | | 320,798 | | | | - | | | | 311,105 | | | | - | | | | 311,105 | |
| International equity funds | | | 63,781 | | | | - | | | | 58,508 | | | | - | | | | 58,508 | |
| Private equity investments | | | 9,203 | | | | - | | | | - | | | | 9,203 | | | | 9,203 | |
| Real estate | | | 24,768 | | | | - | | | | - | | | | 26,395 | | | | 26,395 | |
| Debt securities: | | | | | | | | | | | | | | | | | | | | |
| Government securities | | | 116,490 | | | | - | | | | 117,256 | | | | - | | | | 117,256 | |
| U.S. corporate bonds | | | 187,083 | | | | - | | | | 193,516 | | | | - | | | | 193,516 | |
| International corporate bonds | | | 35,198 | | | | - | | | | 35,804 | | | | - | | | | 35,804 | |
| Municipal bonds | | | 60,469 | | | | - | | | | 64,731 | | | | - | | | | 64,731 | |
| Asset-backed securities | | | 16,516 | | | | - | | | | - | | | | 16,501 | | | | 16,501 | |
| Mortgage-backed securities | | | 75,627 | | | | - | | | | - | | | | 78,664 | | | | 78,664 | |
| Equity securities: | | | | | | | | | | | | | | | | | | | | |
| Common stock | | | 408,122 | | | | 398,625 | | | | - | | | | - | | | | 398,625 | |
| Total | | $ | 1,344,178 | | | $ | 405,728 | | | $ | 799,940 | | | $ | 130,763 | | | $ | 1,336,431 | |
| (a) | Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $92.7 million of equity investments in unconsolidated subsidiaries and $34.3 million of miscellaneous investments. |
| | | Dec. 31, 2010 | |
| | | | | | Fair Value | | | | |
| | | | | | | | | | | | | | | | |
| (Thousands of Dollars) | | Cost | | | Level 1 | | | Level 2 | | | Level 3 | | | Total | |
Nuclear decommissioning fund (a) | | | | | | | | | | | | | | | |
| Cash equivalents | | $ | 83,837 | | | $ | 76,281 | | | $ | 7,556 | | | $ | - | | | $ | 83,837 | |
| Commingled funds | | | 131,000 | | | | - | | | | 133,080 | | | | - | | | | 133,080 | |
| International equity funds | | | 54,561 | | | | - | | | | 58,584 | | | | - | | | | 58,584 | |
| Debt securities: | | | | | | | | | | | | | | | | | | | | |
| Government securities | | | 146,473 | | | | - | | | | 146,654 | | | | - | | | | 146,654 | |
| U.S. corporate bonds | | | 279,028 | | | | - | | | | 288,304 | | | | - | | | | 288,304 | |
| International corporate bonds | | | 1,233 | | | | - | | | | 1,581 | | | | - | | | | 1,581 | |
| Municipal bonds | | | 100,277 | | | | - | | | | 97,557 | | | | - | | | | 97,557 | |
| Asset-backed securities | | | 32,558 | | | | - | | | | - | | | | 33,174 | | | | 33,174 | |
| Mortgage-backed securities | | | 68,072 | | | | - | | | | - | | | | 72,589 | | | | 72,589 | |
| Equity securities: | | | | | | | | | | | | | | | | | | | | |
| Common stock | | | 436,334 | | | | 435,270 | | | | - | | | | - | | | | 435,270 | |
| Total | | $ | 1,333,373 | | | $ | 511,551 | | | $ | 733,316 | | | $ | 105,763 | | | $ | 1,350,630 | |
| (a) | Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $97.6 million of equity investments in unconsolidated subsidiaries and $28.2 million of miscellaneous investments. |
The following tables present the changes in Level 3 nuclear decommissioning fund investments:
| (Thousands of Dollars) | | Jan. 1, 2011 | | | Purchases | | | Settlements | | | Gains (Losses) Recognized as Regulatory Assets and Liabilities | | | Dec. 31, 2011 | |
| Asset-backed securities | | $ | 33,174 | | | $ | 16,518 | | | $ | (32,560 | ) | | $ | (631 | ) | | $ | 16,501 | |
| Mortgage-backed securities | | | 72,589 | | | | 168,688 | | | | (161,134 | ) | | | (1,479 | ) | | | 78,664 | |
| Real estate | | | - | | | | 24,768 | | | | - | | | | 1,627 | | | | 26,395 | |
| Private equity investments | | | - | | | | 9,203 | | | | - | | | | - | | | | 9,203 | |
| Total | | $ | 105,763 | | | $ | 219,177 | | | | (193,694 | ) | | $ | (483 | ) | | $ | 130,763 | |
| (Thousands of Dollars) | | Jan. 1, 2010 | | | Purchases | | | Settlements | | | Gains Recognized as Regulatory Assets and Liabilities | | | Dec. 31, 2010 | |
| Asset-backed securities | | $ | 11,918 | | | $ | 38,871 | | | $ | (17,878 | ) | | $ | 263 | | | $ | 33,174 | |
| Mortgage-backed securities | | | 81,189 | | | | 63,497 | | | | (75,701 | ) | | | 3,604 | | | | 72,589 | |
| Total | | $ | 93,107 | | | $ | 102,368 | | | | (93,579 | ) | | $ | 3,867 | | | $ | 105,763 | |
| (Thousands of Dollars) | | Jan. 1, 2009 | | | Purchases | | | Settlements | | | Gains Recognized as Regulatory Assets and Liabilities | | | Dec. 31, 2009 | |
| Asset-backed securities | | $ | 10,962 | | | $ | 7,271 | | | $ | (7,755 | ) | | $ | 1,440 | | | $ | 11,918 | |
| Mortgage-backed securities | | | 98,461 | | | | 17,943 | | | | (45,815 | ) | | | 10,600 | | | | 81,189 | |
| Total | | $ | 109,423 | | | $ | 25,214 | | | | (53,570 | ) | | $ | 12,040 | | | $ | 93,107 | |
The following table summarizes the final contractual maturity dates of the debt securities in the nuclear decommissioning fund, by asset class, at Dec. 31, 2011:
| | | Final Contractual Maturity | |
| (Thousands of Dollars) | | Due in 1 Year or Less | | | Due in 1 to 5 Years | | | Due in 5 to 10 Years | | | Due after 10 Years | | | Total | |
| Government securities | | $ | 113,179 | | | $ | - | | | $ | 4,077 | | | $ | - | | | $ | 117,256 | |
| U.S. corporate bonds | | | 304 | | | | 35,437 | | | | 139,880 | | | | 17,895 | | | | 193,516 | |
| International corporate bonds | | | - | | | | 8,454 | | | | 23,501 | | | | 3,849 | | | | 35,804 | |
| Municipal bonds | | | - | | | | - | | | | 40,585 | | | | 24,146 | | | | 64,731 | |
| Asset-backed securities | | | - | | | | 9,907 | | | | 6,594 | | | | - | | | | 16,501 | |
| Mortgage-backed securities | | | - | | | | 1,731 | | | �� | 1,041 | | | | 75,892 | | | | 78,664 | |
| Debt securities | | $ | 113,483 | | | $ | 55,529 | | | $ | 215,678 | | | $ | 121,782 | | | $ | 506,472 | |
Derivative Instruments Fair Value Measurements
Xcel Energy enters into derivative instruments, including forward contracts, futures, swaps and options, for trading purposes and to reduce risk in connection with changes in interest rates, utility commodity prices and vehicle fuel prices, as well as variances in forecasted weather.
Interest Rate Derivatives — Xcel Energy 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 an anticipated debt issuance for a specific period. These derivative instruments are generally designated as cash flow hedges for accounting purposes.
At Dec. 31, 2011, accumulated OCI related to interest rate derivatives included $0.9 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings.
At Dec. 31, 2011, Xcel Energy had unsettled interest rate swaps outstanding with a notional amount of $475 million. These interest rate swaps were designated as hedges, and as such, changes in fair value are recorded to OCI. In addition, Xcel Energy entered into interest rate swaps with a notional amount of $175 million during the year which were settled in conjunction with the Xcel Energy Inc. debt issuance in September 2011. See Note 4 to for further discussions of long-term borrowings.
Short-Term Wholesale and Commodity Trading Risk — Xcel Energy conducts various short-term wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and energy-related instruments. Xcel Energy’s risk management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management committee, which is made up of management personnel not directly involved in the activities governed by this policy.
Commodity Derivatives — Xcel Energy enters into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric and natural gas operations, as well as for trading purposes. This could include the purchase or sale of energy or energy-related products, natural gas to generate electric energy, gas for resale and vehicle fuel.
At Dec. 31, 2011, Xcel Energy had various vehicle fuel related contracts designated as cash flow hedges extending through December 2014. Xcel Energy also enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers but are not designated as qualifying hedging transactions. Changes in the fair value of non-trading commodity derivative instruments are recorded in OCI or deferred as a regulatory asset or liability. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. Xcel Energy recorded immaterial amounts to income related to the ineffectiveness of cash flow hedges for the years ended Dec. 31, 2011 and 2010.
At Dec. 31, 2011, accumulated OCI related to commodity derivative cash flow hedges included $0.2 million of net gains expected to be reclassified into earnings during the next 12 months as the hedged transactions occur.
Additionally, Xcel Energy enters into commodity derivative instruments for trading purposes not directly related to commodity price risks associated with serving its electric and natural gas customers. Changes in the fair value of these commodity derivatives are recorded in electric operating revenues, net of amounts credited to customers under margin-sharing mechanisms.
The following table details the gross notional amounts of commodity forwards, options and FTRs at Dec. 31, 2011 and Dec. 31, 2010:
(Amounts in Thousands) (a)(b) | | Dec. 31, 2011 | | | Dec. 31, 2010 | |
| MWh of electricity | | | 38,822 | | | | 46,794 | |
| MMBtu of natural gas | | | 40,736 | | | | 75,806 | |
| Gallons of vehicle fuel | | | 600 | | | | 800 | |
| (a) | Amounts are not reflective of net positions in the underlying commodities. |
| (b) | Notional amounts for options are included on a gross basis, but are weighted for the probability of exercise. |
Financial Impact of Qualifying Cash Flow Hedges — The impact of qualifying interest rate and vehicle fuel cash flow hedges on Xcel Energy’s accumulated OCI, included in the consolidated statements of common stockholders’ equity and comprehensive income, is detailed in the following table:
| (Thousands of Dollars) | | 2011 | | | 2010 | | | 2009 | |
| Accumulated other comprehensive loss related to cash flow hedges at Jan. 1 | | $ | (8,094 | ) | | $ | (6,435 | ) | | $ | (13,113 | ) |
| After-tax net unrealized losses related to derivatives accounted for as hedges | | | (38,292 | ) | | | (4,289 | ) | | | (710 | ) |
| After-tax net realized losses on derivative transactions reclassified into earnings | | | 648 | | | | 2,630 | | | | 7,388 | |
| Accumulated other comprehensive loss related to cash flow hedges at Dec. 31 | | $ | (45,738 | ) | | $ | (8,094 | ) | | $ | (6,435 | ) |
Xcel Energy had no derivative instruments designated as fair value hedges during the years ended Dec. 31, 2011 and Dec. 31, 2010.
The following tables detail the impact of derivative activity during the years ended Dec. 31, 2011 and Dec. 31, 2010, on OCI, regulatory assets and liabilities, and income:
| | | Dec. 31, 2011 | | |
| | | | | | | | | | | | | | | | | | | |
| | | Fair Value | | | Pre-Tax Amounts | | | | | | |
| | | Changes Recognized | | | Reclassified into Income | | | | Pre-Tax Gains (Losses) | | |
| | | During the Period in: | | | During the Period from: | | | | | |
| | | Accumulated | | | | | | Accumulated | | | | | | | | | |
| | | Other | | | Regulatory | | | Other | | | | Regulatory | | | | Recognized | | |
| | | Comprehensive | | | (Assets) and | | | Comprehensive | | | | Assets and | | | | During the Period | | |
| (Thousands of Dollars) | | Loss | | | Liabilities | | | Loss | | | | (Liabilities) | | | | in Income | | |
| Derivatives designated as cash flow hedges | | | | | | | | | | | | | | | | | | |
| Interest rate | | $ | (63,573 | ) | | $ | - | | | $ | 1,424 | | (a) | | $ | - | | | | $ | - | | |
| Vehicle fuel and other commodity | | | 195 | | | | - | | | | (178 | ) | (e) | | | - | | | | | - | | |
| Total | | $ | (63,378 | ) | | $ | - | | | $ | 1,246 | | | | $ | - | | | | $ | - | | |
| | | | | | | | | | | | | | | | | | | | | | | | |
| Other derivative instruments | | | | | | | | | | | | | | | | | | | | | | | |
| Trading commodity | | $ | - | | | $ | - | | | $ | - | | | | $ | - | | | | $ | 6,418 | | (b) |
| Electric commodity | | | - | | | | 49,818 | | | | - | | | | | (40,492 | ) | (c) | | | - | | |
| Natural gas commodity | | | - | | | | (111,574 | ) | | | - | | | | | 91,743 | | (d) | | | (382 | ) | (b) |
| Total | | $ | - | | | $ | (61,756 | ) | | $ | - | | | | $ | 51,251 | | | | $ | 6,036 | | |
| | | Dec. 31, 2010 | | |
| | | Fair Value | | | Pre-Tax Amounts | | | | | | |
| | | Changes Recognized | | | Reclassified into Income | | | | | | |
| | | During the Period in: | | | During the Period from: | | | | Pre-Tax Gains | | |
| | | Accumulated | | | | | | Accumulated | | | | | | | | | |
| | | Other | | | Regulatory | | | Other | | | | Regulatory | | | | Recognized | | |
| | | Comprehensive | | | (Assets) and | | | Comprehensive | | | | Assets and | | | | During the Period | | |
| (Thousands of Dollars) | | Loss | | | Liabilities | | | | | | | (Liabilities) | | | | in Income | | |
| Derivatives designated as cash flow hedges | | | | | | | | | | | | | | | | | | |
| Interest rate | | $ | (7,210 | ) | | $ | - | | | $ | 1,107 | | (a) | | $ | - | | | | $ | - | | |
| Vehicle fuel and other commodity | | | (238 | ) | | | - | | | | 3,474 | | (e) | | | - | | | | | - | | |
| Total | | $ | (7,448 | ) | | $ | - | | | $ | 4,581 | | | | $ | - | | | | $ | - | | |
| | | | | | | | | | | | | | | | | | | | | | | | |
| Other derivative instruments | | | | | | | | | | | | | | | | | | | | | | | |
| Trading commodity | | $ | - | | | $ | - | | | $ | - | | | | $ | - | | | | $ | 11,004 | | (b) |
| Electric commodity | | | - | | | | 3,969 | | | | - | | | | | (21,840 | ) | (c) | | | - | | |
| Natural gas commodity | | | - | | | | (105,396 | ) | | | - | | | | | 51,034 | | (d) | | | - | | |
| Other | | | - | | | | - | | | | - | | | | | - | | | | | 135 | | (b) |
| Total | | $ | - | | | $ | (101,427 | ) | | $ | - | | | | $ | 29,194 | | | | $ | 11,139 | | |
| (a) | Recorded to interest charges. |
(b) | Recorded to electric operating revenues. Portions of these total gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate. |
(c) | Recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate. |
| (d) | Recorded to cost of natural gas sold and transported. These derivative settlement gains and losses are shared with natural gas customers through purchased natural gas cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate. |
(e) | Recorded to O&M expenses. |
Credit Related Contingent Features — Contract provisions of the derivative instruments that the utility subsidiaries enter into may require the posting of collateral or settlement of the contracts for various reasons, including if the applicable utility subsidiary is unable to maintain its credit ratings. If the credit ratings of Xcel Energy Inc.’s subsidiaries were downgraded below investment grade, contracts underlying $8.3 million and $5.6 million of derivative instruments in a gross liability position at Dec. 31, 2011 and Dec. 31, 2010, respectively, would have required Xcel Energy Inc.’s subsidiaries to post collateral or settle applicable contracts, which would have resulted in payments to counterparties of $9.3 million and $9.8 million, respectively. At Dec. 31, 2011 and Dec. 31, 2010, there was no collateral posted on these specific contracts.
Certain derivative instruments are also subject to contract provisions that contain adequate assurance clauses. These provisions allow counterparties to seek performance assurance, including cash collateral, in the event that a given utility subsidiary’s ability to fulfill its contractual obligations is reasonably expected to be impaired. Xcel Energy had no collateral posted related to adequate assurance clauses in derivative contracts as of Dec. 31, 2011 and Dec. 31, 2010.
Recurring Fair Value Measurements — The following table presents for each of the hierarchy levels, Xcel Energy’s derivative assets and liabilities that are measured at fair value on a recurring basis at Dec. 31, 2011:
| | | Dec. 31, 2011 | |
| | | Fair Value | | | | | | | | | | |
| | | | | | | | | | | | Fair Value | | | Counterparty | | | | |
| (Thousands of Dollars) | | Level 1 | | | Level 2 | | | Level 3 | | | Total | | | Netting (b) | | | Total | |
| Current derivative assets | | | | | | | | | | | | | | | | | | |
| Derivatives designated as cash flow hedges: | | | | | | | | | | | | | | | | | | |
| Vehicle fuel and other commodity | | $ | - | | | $ | 169 | | | $ | - | | | $ | 169 | | | $ | (76 | ) | | $ | 93 | |
| Other derivative instruments: | | | | | | | | | | | | | | | | | | | | | | | | |
| Trading commodity | | | - | | | | 32,682 | | | | - | | | | 32,682 | | | | (13,391 | ) | | | 19,291 | |
| Electric commodity | | | - | | | | - | | | | 13,333 | | | | 13,333 | | | | (1,471 | ) | | | 11,862 | |
| Total current derivative assets | | $ | - | | | $ | 32,851 | | | $ | 13,333 | | | $ | 46,184 | | | $ | (14,938 | ) | | | 31,246 | |
Purchased power agreements (a) | | | | | | | | | | | | | | | | | | | | | | | 33,094 | |
| Current derivative instruments | | | | | | | | | | | | | | | | | | | | | | $ | 64,340 | |
| Noncurrent derivative assets | | | | | | | | | | | | | | | | | | | | | | | | |
| Derivatives designated as cash flow hedges: | | | | | | | | | | | | | | | | | | | | | | | | |
| Vehicle fuel and other commodity | | $ | - | | | $ | 107 | | | $ | - | | | $ | 107 | | | $ | (59 | ) | | $ | 48 | |
| Other derivative instruments: | | | | | | | | | | | | | | | | | | | | | | | | |
| Trading commodity | | | - | | | | 36,599 | | | | - | | | | 36,599 | | | | (5,540 | ) | | | 31,059 | |
| Total noncurrent derivative assets | | $ | - | | | $ | 36,706 | | | $ | - | | | $ | 36,706 | | | $ | (5,599 | ) | | | 31,107 | |
Purchased power agreements (a) | | | | | | | | | | | | | | | | | | | | | | | 121,780 | |
| Noncurrent derivative instruments | | | | | | | | | | | | | | | | | | | | | | $ | 152,887 | |
| | | Dec. 31, 2011 | |
| | | Fair Value | | | | | | | | | | |
| | | | | | | | | | | | Fair Value | | | Counterparty | | | | |
| (Thousands of Dollars) | | Level 1 | | | Level 2 | | | Level 3 | | | Total | | | Netting (b) | | | Total | |
| Current derivative liabilities | | | | | | | | | | | | | | | | | | |
| Derivatives designated as cash flow hedges: | | | | | | | | | | | | | | | | | | |
| Interest rate | | $ | - | | | $ | 57,749 | | | $ | - | | | $ | 57,749 | | | $ | - | | | $ | 57,749 | |
| Other derivative instruments: | | | | | | | | | | | | | | | | | | | | | | | | |
| Trading commodity | | | - | | | | 27,891 | | | | - | | | | 27,891 | | | | (14,417 | ) | | | 13,474 | |
| Electric commodity | | | - | | | | 698 | | | | 916 | | | | 1,614 | | | | (1,471 | ) | | | 143 | |
| Natural gas commodity | | | 418 | | | | 70,119 | | | | - | | | | 70,537 | | | | (7,486 | ) | | | 63,051 | |
| Total current derivative liabilities | | $ | 418 | | | $ | 156,457 | | | $ | 916 | | | $ | 157,791 | | | $ | (23,374 | ) | | | 134,417 | |
Purchased power agreements (a) | | | | | | | | | | | | | | | | | | | | | | | 22,997 | |
| Current derivative instruments | | | | | | | | | | | | | | | | | | | | | | $ | 157,414 | |
| Noncurrent derivative liabilities | | | | | | | | | | | | | | | | | | | | | | | | |
| Other derivative instruments: | | | | | | | | | | | | | | | | | | | | | | | | |
| Trading commodity | | $ | - | | | $ | 20,966 | | | $ | - | | | $ | 20,966 | | | $ | (5,599 | ) | | $ | 15,367 | |
| Total noncurrent derivative liabilities | | $ | - | | | $ | 20,966 | | | $ | - | | | $ | 20,966 | | | $ | (5,599 | ) | | | 15,367 | |
Purchased power agreements (a) | | | | | | | | | | | | | | | | | | | | | | | 248,539 | |
| Noncurrent derivative instruments | | | | | | | | | | | | | | | | | | | | | | $ | 263,906 | |
| (a) | In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, Xcel Energy began recording several long-term purchased power 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 2006, Xcel Energy qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer 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 assets and liabilities. |
| (b) | The accounting guidance for derivatives and hedging permits the netting of receivables and payables for derivatives and related collateral amounts when a legally enforceable master netting agreement exists between Xcel Energy and a counterparty. A master netting agreement is an agreement between two parties who have multiple contracts with each other that provides for the net settlement of all contracts in the event of default on or termination of any one contract. |
The following table presents for each of the hierarchy levels, Xcel Energy’s derivative assets and liabilities that are measured at fair value on a recurring basis at Dec. 31, 2010:
| | | Dec. 31, 2010 | |
| | | Fair Value | | | | | | | | | | |
| | | | | | | | | | | | Fair Value | | | Counterparty | | | | |
| (Thousands of Dollars) | | Level 1 | | | Level 2 | | | Level 3 | | | Total | | | Netting (b) | | | Total | |
| Current derivative assets | | | | | | | | | | | | | | | | | | |
| Derivatives designated as cash flow hedges: | | | | | | | | | | | | | | | | | | |
| Vehicle fuel and other commodity | | $ | - | | | $ | 126 | | | $ | - | | | $ | 126 | | | $ | - | | | $ | 126 | |
| Other derivative instruments: | | | | | | | | | | | | | | | | | | | | | | | | |
| Trading commodity | | | 487 | | | | 37,019 | | | | - | | | | 37,506 | | | | (21,352 | ) | | | 16,154 | |
| Electric commodity | | | - | | | | - | | | | 3,619 | | | | 3,619 | | | | (1,226 | ) | | | 2,393 | |
| Natural gas commodity | | | - | | | | 1,595 | | | | - | | | | 1,595 | | | | (1,219 | ) | | | 376 | |
| Total current derivative assets | | $ | 487 | | | $ | 38,740 | | | $ | 3,619 | | | $ | 42,846 | | | $ | (23,797 | ) | | | 19,049 | |
Purchased power agreements (a) | | | | | | | | | | | | | | | | | | | | | | | 35,030 | |
| Current derivative instruments | | | | | | | | | | | | | | | | | | | | | | $ | 54,079 | |
| Noncurrent derivative assets | | | | | | | | | | | | | | | | | | | | | | | | |
| Derivatives designated as cash flow hedges: | | | | | | | | | | | | | | | | | | | | | | | | |
| Vehicle fuel and other commodity | | $ | - | | | $ | 150 | | | $ | - | | | $ | 150 | | | $ | - | | | $ | 150 | |
| Other derivative instruments: | | | | | | | | | | | | | | | | | | | | | | | | |
| Trading commodity | | | - | | | | 32,621 | | | | - | | | | 32,621 | | | | (4,595 | ) | | | 28,026 | |
| Natural gas commodity | | | - | | | | 1,246 | | | | - | | | | 1,246 | | | | (269 | ) | | | 977 | |
| Total noncurrent derivative assets | | $ | - | | | $ | 34,017 | | | $ | - | | | $ | 34,017 | | | $ | (4,864 | ) | | | 29,153 | |
Purchased power agreements (a) | | | | | | | | | | | | | | | | | | | | | | | 154,873 | |
| Noncurrent derivative instruments | | | | | | | | | | | | | | | | | | | | | | $ | 184,026 | |
| | | Dec. 31, 2010 | |
| | | Fair Value | | | | | | | | | | |
| | | | | | | | | | | | Fair Value | | | Counterparty | | | | |
| (Thousands of Dollars) | | Level 1 | | | Level 2 | | | Level 3 | | | Total | | | Netting (b) | | | Total | |
| Current derivative liabilities | | | | | | | | | | | | | | | | | | |
| Other derivative instruments: | | | | | | | | | | | | | | | | | | |
| Trading commodity | | $ | 392 | | | $ | 30,608 | | | $ | - | | | $ | 31,000 | | | $ | (24,007 | ) | | $ | 6,993 | |
| Electric commodity | | | - | | | | - | | | | 1,227 | | | | 1,227 | | | | (1,227 | ) | | | - | |
| Natural gas commodity | | | 20 | | | | 52,709 | | | | - | | | | 52,729 | | | | (21,169 | ) | | | 31,560 | |
| Total current derivative liabilities | | $ | 412 | | | $ | 83,317 | | | $ | 1,227 | | | $ | 84,956 | | | $ | (46,403 | ) | | | 38,553 | |
Purchased power agreements (a) | | | | | | | | | | | | | | | | | | | | | | | 23,192 | |
| Current derivative instruments | | | | | | | | | | | | | | | | | | | | | | $ | 61,745 | |
| Noncurrent derivative liabilities | | | | | | | | | | | | | | | | | | | | | | | | |
| Other derivative instruments: | | | | | | | | | | | | | | | | | | | | | | | | |
| Trading commodity | | $ | - | | | $ | 18,878 | | | $ | - | | | $ | 18,878 | | | $ | (4,596 | ) | | $ | 14,282 | |
| Natural gas commodity | | | - | | | | 438 | | | | - | | | | 438 | | | | (269 | ) | | | 169 | |
| Total noncurrent derivative liabilities | | $ | - | | | $ | 19,316 | | | $ | - | | | $ | 19,316 | | | $ | (4,865 | ) | | | 14,451 | |
Purchased power agreements (a) | | | | | | | | | | | | | | | | | | | �� | | | | 271,535 | |
| Noncurrent derivative instruments | | | | | | | | | | | | | | | | | | | | | | $ | 285,986 | |
| (a) | In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, Xcel Energy began recording several long-term purchased power 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 2006, Xcel Energy qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer 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 assets and liabilities. |
| (b) | The accounting guidance for derivatives and hedging permits the netting of receivables and payables for derivatives and related collateral amounts when a legally enforceable master netting agreement exists between Xcel Energy and a counterparty. A master netting agreement is an agreement between two parties who have multiple contracts with each other that provides for the net settlement of all contracts in the event of default on or termination of any one contract. |
The following table presents the changes in Level 3 commodity derivatives for the years ended Dec. 31, 2011, 2010 and 2009:
| | | Year Ended Dec. 31 | |
| (Thousands of Dollars) | | 2011 | | | 2010 | | | 2009 | |
| Balance at Jan. 1 | | $ | 2,392 | | | $ | 28,042 | | | $ | 23,221 | |
| Purchases | | | 33,609 | | | | 10,813 | | | | 9,077 | |
| Settlements | | | (36,555 | ) | | | (25,261 | ) | | | (18,316 | ) |
| Transfers (out of) into Level 3 | | | - | | | | (13,525 | ) | | | 1,280 | |
| Net transactions recorded during the period: | | | | | | | | | | | | |
Gains recognized in earnings (a) | | | 69 | | | | 6,237 | | | | 8,228 | |
| Gains (losses) recognized as regulatory assets and liabilities | | | 12,902 | | | | (3,914 | ) | | | 4,552 | |
| Balance at Dec. 31 | | $ | 12,417 | | | $ | 2,392 | | | $ | 28,042 | |
| (a) | These unrealized amounts relate to commodity derivatives held at the end of the period. |
Xcel Energy recognizes transfers between levels as of the beginning of each period. There were no transfers of amounts between levels for the year ended Dec. 31, 2011. The following table presents the transfers that occurred from Level 3 to Level 2 during the year ended Dec. 31, 2010.
| | | Year Ended | |
| (Thousands of Dollars) | | Dec. 31, 2010 | |
| Trading commodity derivatives not designated as cash flow hedges: | | | |
| Current assets | | $ | 7,271 | |
| Noncurrent assets | | | 26,438 | |
| Current liabilities | | | (4,115 | ) |
| Noncurrent liabilities | | | (16,069 | ) |
| Total | | $ | 13,525 | |
There were no transfers of amounts from Level 2 to Level 3, or any transfers to or from Level 1 for the year ended Dec. 31, 2010. The transfer of amounts from Level 3 to Level 2 in the year ended Dec. 31, 2010 was due to the valuation of certain long-term derivative contracts for which observable commodity pricing forecasts became a more significant input during the period.
Fair Value of Long-Term Debt
As of Dec. 31, 2011 and 2010, other financial instruments for which the carrying amount did not equal fair value were as follows:
| | | 2011 | | | 2010 | |
| (Thousands of Dollars) | | Carrying Amount | | | Fair Value | | | Carrying Amount | | | Fair Value | |
| Long-term debt, including current portion | | $ | 9,908,435 | | | $ | 11,734,798 | | | $ | 9,318,559 | | | $ | 10,224,845 | |
The fair value of Xcel Energy’s long-term debt is estimated based on the quoted market prices for the same or similar issues, or the current rates for debt of the same remaining maturities and credit quality. The fair value estimates presented are based on information available to management as of Dec. 31, 2011 and 2010. These fair value estimates have not been comprehensively revalued for purposes of these consolidated financial statements since that date and current estimates of fair values may differ significantly.
12. Rate Matters
NSP-Minnesota
Pending Regulatory Proceedings — MPUC
Base Rate
NSP-Minnesota - Minnesota Electric Rate Case — In November 2010, NSP-Minnesota filed a request with the MPUC to increase electric rates in Minnesota for 2011 by approximately $150 million, or an increase of 5.62 percent and an additional increase of $48.3 million, or 1.81 percent in 2012. The rate filing was based on a 2011 forecast test year and included a requested ROE of 11.25 percent, an electric rate base of approximately $5.6 billion and an equity ratio of 52.56 percent. The MPUC approved an interim rate increase of $123 million, subject to refund, effective Jan. 2, 2011.
In June 2011, NSP-Minnesota revised its requested rate increase to $122.8 million, reflecting a revised ROE of 10.85 percent and other adjustments. The DOER revised its recommended rate increase to approximately $84.7 million in 2011 and an additional rate increase of $34 million in 2012, reflecting an ROE of 10.37 percent. The primary differences between the NSP-Minnesota requested rate increase and the DOER updated recommendation were associated with ROE and compensation related issues.
In August 2011, NSP-Minnesota submitted supplemental testimony, revising its requested rate increase to approximately $122 million for 2011 and a 2012 step increase of approximately $29 million. The revisions were due to delays in the Monticello nuclear plant extended power uprate.
In November 2011, NSP-Minnesota reached a settlement agreement with the Xcel Large Industrials, the Minnesota Chamber of Commerce, the Commercial Group and Verso Paper Corp., which settled all financial issues and several rate design issues between the signing parties. The settlement includes a rate increase of approximately $58.0 million in 2011 and an incremental rate increase of $14.8 million in 2012 based on an ROE of 10.37 percent. The settlement agreement reflects a reduction to depreciation expense and NSP-Minnesota’s rate request by $30 million with an additional adjustment of $7.5 million related to employee compensation. The settlement also provides NSP-Minnesota the ability to seek deferred accounting for incremental property tax increases associated with electric and natural gas businesses in 2012, which is currently projected to increase by approximately $28 million. NSP-Minnesota also agreed to not file an electric rate case prior to Nov. 1, 2012, provided that both the settlement and the property tax filing are approved by the MPUC. NSP-Minnesota has recorded a provision for revenue subject to refund of approximately $67.4 million for 2011 and has reduced depreciation expense by $30 million.
In February 2012, the ALJ recommended MPUC approval of the settlement agreement. In addition, NSP-Minnesota filed to reduce the interim rate request to $72.8 million to align with the settlement agreement. A decision is expected by the MPUC in the first half of 2012.
Pending Regulatory Proceedings — NDPSC
NSP-Minnesota – North Dakota Electric Rate Case — In December 2010, NSP-Minnesota filed a request with the NDPSC to increase 2011 electric rates in North Dakota by approximately $19.8 million, or an increase of 12 percent in 2011 and a step increase of $4.2 million, or 2.6 percent in 2012. The rate filing is based on a 2011 forecast test year and includes a requested ROE of 11.25 percent, an electric rate base of approximately $328 million and an equity ratio of 52.56 percent.
The NDPSC approved an interim rate increase of approximately $17.4 million, subject to refund, effective Feb. 18, 2011. NSP-Minnesota has recorded a provision for revenue subject to refund of approximately $2.4 million for 2011. The interim rates will remain in effect until the NDPSC makes its final decision on the case.
In May 2011, NSP-Minnesota revised its rate request to approximately $18.0 million, or an increase of 11 percent, for 2011 and $2.4 million, or 1.4 percent, for the additional step increase in 2012, due to the termination of the Merricourt wind project.
In September 2011, NSP-Minnesota reached a settlement with the NDPSC Advocacy Staff. If approved by the NDPSC, the settlement would result in a rate increase of $13.7 million in 2011 and an additional step increase of $2.0 million in 2012, based on a 10.4 percent ROE and black box settlement for all other issues. To address 2011 sales coming in below test year projections, the settlement includes a true-up to 2012 non-fuel revenues plus the settlement rate increase.
An NDPSC decision is expected in March 2012.
Pending Regulatory Proceedings — SDPUC
NSP-Minnesota – South Dakota Electric Rate Case — In June 2011, NSP-Minnesota filed a request with the SDPUC to increase South Dakota electric rates by $14.6 million annually, effective in 2012. The proposed increase included $0.7 million in revenues currently recovered through automatic recovery mechanisms. The request is based on a 2010 historic test year adjusted for known and measurable changes, a requested ROE of 11 percent, a rate base of $323.4 million and an equity ratio of 52.48 percent. NSP-Minnesota also requested approval of a nuclear cost recovery rider to recover the actual investment cost of the Monticello nuclear plant life cycle management and extended power uprate project that is not reflected in the test year.
As a result of delays in the rate case process, interim rates of $12.7 million were implemented Jan. 2, 2012. A final decision is expected in the first half of 2012.
Electric, Purchased Gas and Resource Adjustment Incentive Clauses
NSP-Minnesota has several retail adjustment clauses that recover fuel, purchased energy, other resource costs, lost margins and/or performance incentives, which are generally recovered concurrently through riders and base rates. At Dec. 31, 2011, pending adjustment clauses, which contain amounts related to incentive programs were as follows:
CIP Rider — CIP expenses are recovered through base rates and a rider that is adjusted annually. Under the 2010 electric CIP rider request approved by the MPUC in October 2010, NSP-Minnesota recovered $84.4 million through the rider during November 2010 to December 2011. This is in addition to $60.9 million recovered through base rates. During December 2010 to December 2011, NSP-Minnesota recovered $27.4 million through the natural gas CIP rider approved in November 2010. This is in addition to $4.4 million recovered in base rates.
In January 2012, the MPUC approved NSP-Minnesota’s annual electric rider petition requesting recovery of $74.7 million of electric CIP expenses and financial incentives to be recovered during February 2012 through December 2012. In December 2011, the MPUC approved NSP-Minnesota’s annual gas rider petition requesting $10.6 million of natural gas CIP expenses and financial incentives to be recovered during January 2012 through December 2012. This proposed recovery through the riders is in addition to an estimated $48.3 million and $3.8 million through electric and gas base rates, respectively.
NSP-Wisconsin
Recently Concluded Regulatory Proceedings — PSCW
Base Rate
NSP-Wisconsin 2011 Electric and Gas Rate Case — In June 2011, NSP-Wisconsin filed a request with the PSCW to increase electric rates approximately $29.2 million, or 5.1 percent and natural gas rates approximately $8.0 million, or 6.6 percent effective Jan. 1, 2012. The rate filing is based on a 2012 forecast test year and includes a requested ROE of 10.75 percent, an equity ratio of 52.54 percent, an electric rate base of approximately $718 million and a natural gas rate base of $84 million.
In December 2011, the PSCW approved an electric rate increase of approximately $12.2 million or 2.1 percent, and a natural gas rate increase of $2.9 million or 2.4 percent, with new rates effective Jan. 1, 2012. The primary reason for the natural gas rate reduction from the original request was the PSCW decision to deny NSP-Wisconsin’s proposal to pre-collect certain manufactured gas plant remediation costs. The primary reasons for the electric rate reduction were updated 2012 electric fuel costs and the delays in the Monticello nuclear plant extended life cycle management and power uprate project. The rate increases were based on a 10.4 percent ROE and an equity ratio of 52.59 percent.
PSCo
Pending and Recently Concluded Regulatory Proceedings — CPUC
Base Rate
PSCo 2010 Gas Rate Case — In December 2010, PSCo filed a request with the CPUC to increase Colorado retail gas rates by $27.5 million on an annual basis. In March 2011, PSCo revised its requested rate increase to $25.6 million. The revised request was based on a 2011 forecast test year, a 10.9 percent ROE, a rate base of $1.1 billion and an equity ratio of 57.1 percent. PSCo proposed recovering $23.2 million of test year capital and O&M expenses associated with several pipeline integrity costs plus an amortization of similar costs that have been accumulated and deferred since the last rate case in 2006. PSCo also proposed removing the earnings on gas in underground storage from base rates.
In August 2011, the CPUC approved a comprehensive settlement that PSCo reached with the CPUC Staff and the OCC to increase rates by $12.8 million, to institute the PSIA rider, and to remove gas in underground storage from base rates and recover those costs in the GCA. The GCA is expected to recover another $10 million of annual incremental revenue, subject to adjustment to actual costs. Rates were set on a test year ending June 30, 2011 with an equity ratio of 56 percent and an ROE of 10.1 percent.
New base rates and the GCA recovery went into effect in September 2011. The PSIA rider and new rate designs went into effect on Jan. 1, 2012.
PSCo 2011 Electric Rate Case — In November 2011, PSCo filed a request with the CPUC to increase Colorado retail electric rates by $141.9 million. The request was based on a 2012 forecast test year, a 10.75 percent ROE, a rate base of $5.4 billion and an equity ratio of 56 percent. Final rates are expected to be effective in the summer of 2012. The CPUC is expected to rule on the electric rate case in July 2012.
In November 2011, PSCo filed a petition to implement interim rates, subject to refund, of $100 million to be effective in January 2012. On Jan. 11, 2012, the CPUC denied PSCo’s request to implement an interim electric rate increase of $100 million on the basis that it had not demonstrated adverse financial impacts. On Jan. 12, 2012, PSCo filed for reconsideration of the CPUC’s decision to deny interim rates, and requested that the CPUC authorize interim rates of approximately $42 million, specifically related to the impacts resulting from the expiration of the Black Hills contract. On Jan. 17, 2012, the CPUC denied the request for reconsideration. However, on Jan. 27, 2012, the CPUC approved PSCo’s request for deferred accounting of the $42 million annual revenue requirement associated with the Black Hills contract.
Pending Regulatory Proceedings — FERC
Base Rate
PSCo Wholesale Electric Rate Case — In February 2011, PSCo filed with the FERC to change Colorado wholesale electric rates to formula based rates with an expected annual increase of $16.1 million for 2011. The request was based on a 2011 forecast test year, a 10.9 percent ROE, a rate base of $407.4 million and an equity ratio of 57.1 percent. The formula rate would be estimated each year for the following year and then trued-up to actual costs after the conclusion of the calendar year. A decision is expected in the first quarter of 2012.
Electric, Purchased Gas and Resource Incentive Adjustment Clauses
PSCo has several retail adjustment clauses that recover fuel, purchased energy, other resource costs, lost margins and/or performance incentives, which are generally recovered concurrently through riders and base rates. At Dec. 31, 2011, pending adjustment clauses, which contain amounts related to incentive programs were as follows:
DSM and the DSMCA — The CPUC approved higher savings goals and a slightly higher financial incentive mechanism for PSCo’s electric DSM energy efficiency programs starting in 2012. Savings goals will increase to 130 percent of the current goals and incentives will be awarded as one installment in the year following plan achievements. PSCo will also be able to earn an incentive on 11 percent of net economic benefits at an achievement level of 130 percent and a maximum annual incentive of $30 million.
The CPUC approved the PSCo electric DSM budget of $77.3 million and gas DSM budget of $12.2 million effective Jan. 1, 2012. This is in addition to $29.4 million for electricity demand response programs recovered through the DSMCA. Energy efficiency and demand response related DSM costs are recovered through a combination of the DSMCA riders and base rates. The DSMCA riders are adjusted biannually to capture program costs, performance incentives, and any over- or under-recoveries are trued-up in the following year.
REC Sharing — In May 2011, the CPUC determined that margin sharing on stand-alone REC transactions would be shared 20 percent to PSCo and 80 percent to customers beginning in 2011 and ultimately becoming 10 percent to PSCo and 90 percent to customers by 2014. The CPUC also approved a change to the treatment of hybrid REC trading margins (RECs that are bundled with energy) that allows the customers’ share of the margins to be netted against the RESA regulatory asset balance. In the second quarter of 2011, PSCo credited approximately $37 million against the RESA regulatory asset balance.
In June 2011, PSCo filed an application with the CPUC for permanent treatment of RECs that are bundled with energy into California. The application is seeking margin sharing of 30 percent to PSCo and 70 percent to customers for deliveries outside of California and 40 percent to PSCo and 60 percent to customers for deliveries inside of California. PSCo also proposed that sales of RECs bundled with on-system energy be aggregated with other trading margins and shared 20 percent to PSCo and 80 percent to customers. In September 2011, the CPUC Staff, the OCC, and the Colorado Energy Consumers filed answer testimony requesting the CPUC approve margin sharing of 8 percent to 25 percent to PSCo for deliveries outside of California and 8 percent to 35 percent for deliveries inside of California.
In January 2012, the CPUC approved the margin sharing on the first $20 million of margins on hybrid REC trades of 80 percent to the customers and 20 percent to PSCo. Margins in excess of the $20 million are to be shared 90 percent to the customers and 10 percent to PSCo. All customer margin sharing and unspent carbon offset funds will be credited to the RESA regulatory asset balance. Because the sharing percentage was less than recommended by the CPUC Staff, OCC, and the Colorado Energy Consumers, PSCo plans to file an Application for Rehearing, Rearguement and Reconsideration during the first quarter of 2012.
SPS
Recently Concluded Regulatory Proceedings — NMPRC and PUCT
Base Rate
SPS – New Mexico Retail Rate Case — In February 2011, SPS filed a request with the NMPRC seeking to increase New Mexico electric rates approximately $19.9 million. The rate filing was based on a 2011 test year adjusted for known and measurable changes for 2012, a requested ROE of 11.25 percent, an electric rate base of $390.3 million and an equity ratio of 51.11 percent.
In December 2011, the NMPRC approved a black box settlement with new rates effective Jan. 1, 2012. The settlement increased base rates by $13.5 million. SPS agreed not to file another base rate case until Dec. 3, 2012 with new final rates from the result of such case not going into effect until Jan. 1, 2014 (Settlement Period). However, SPS can request to implement interim rates if the NMPRC standard for interim rates is met. During the Settlement Period, rates are to remain fixed aside from the continued operation of the fuel adjustment clause and certain exceptions for energy efficiency, a rider for an approved renewable portfolio standard regulatory asset, and actual costs incurred for environmental regulations with an effective date after Dec. 31, 2010.
SPS – Texas Retail Rate Case — In May 2010, SPS filed a request with the PUCT seeking to increase Texas electric rates by approximately $71.5 million inclusive of franchise fees. The rate filing was based on a 2009 test year adjusted for known and measurable changes, a requested ROE of 11.35 percent, an electric rate base of $1.031 billion and an equity ratio of 51.0 percent. In November 2010, SPS filed an update to the cost of service to reflect the sale of Lubbock facilities which reduced the total request to approximately $63.7 million.
Effective Feb. 16, 2011, the parties reached an unopposed settlement to resolve all issues in the case and increase base rates by $39.4 million, of which $16.9 million is associated with the transfer of two riders, the TCRF and the PCRF, into base rates. Effective Jan. 1, 2012, base rates increased by an additional $13.1 million.
SPS agreed not to file another rate case until Sept. 15, 2012. In addition, SPS cannot file a TCRF application until 2013, and if SPS files a TCRF application before the effective date of rates in its next rate case, it must reduce the calculated TCRF revenue requirement by $12.2 million.
13. Commitments and Contingent Liabilities
Commitments
Capital Commitments — Xcel Energy has made commitments in connection with a portion of its projected capital expenditures. Xcel Energy’s capital commitments primarily relate to the following major projects:
Nuclear Lifecycle Management and Extended Power Uprates — NSP-Minnesota is pursuing improvements to make sure the plants operate safely until the end of their extended licensed life and is making capacity increases of the Monticello and Prairie Island generating plants that could total up to approximately 188 MW. The MPUC approved the CON for the extended power uprate for Monticello in 2008. The license amendment application was filed with the NRC in November 2008, but a concern was raised by the Advisory Committee on Reactor Safeguards related to containment pressure associated with pump performance. In October 2011, the Advisory Committee recommended that all licensing actions that credit the use of containment accident pressure be suspended until the causes and risks of Japan’s Fukushima incident are better understood. NSP-Minnesota has rescheduled the remaining equipment changes needed to complete the Monticello power uprate projects during the planned spring 2013 refueling outage.
The MPUC approved an extended power uprate for the Prairie Island Units in 2009. Analysis of recent extended power uprate submittals to the NRC concluded that significant additional design work beyond current schedule and cost plan estimates are now being required to submit a successful application. As a result, NSP-Minnesota is completing an economic and new project design analysis to determine project impacts and anticipates submitting a Change in Circumstances filing with the MPUC in the first quarter of 2012.
CapX2020 — CapX2020 is an alliance of electric cooperatives, municipals and investor-owned utilities in the upper Midwest, including Xcel Energy that have proposed several groups of transmission projects to be complete by 2020. Group 1 project investments consist of four transmission lines. Major construction began in 2010 on the Group 1 transmission lines with an expected completion date in 2015. NSP System’s investment depends on the routes and configurations approved by affected state commissions. The remainder of the costs will be born by other utilities in the upper Midwest.
CACJA — The CACJA aims to reduce annual emissions of NOx by at least 70 to 80 percent or greater from 2008 levels by 2017 from the coal fired generation identified in the plan.
CSAPR — CSAPR addresses long range transport of particulate matter and ozone by requiring reductions in SO2 and NOx from utilities located in the eastern half of the U.S. CSAPR is discussed further at Environmental Contingencies. Xcel Energy is in the process of determining various scenarios to respond to the CSAPR depending on whether the CSAPR is upheld, reversed, or modified.
Fuel Contracts — Xcel Energy has contracts providing for the purchase and delivery of a significant portion of its current coal, nuclear fuel and natural gas requirements. These contracts expire in various years between 2012 and 2060. In addition, Xcel Energy is required to pay additional amounts depending on actual quantities shipped under these agreements. Xcel Energy’s risk of loss, in the form of increased costs from market price changes in fuel, is mitigated through the use of natural gas and energy cost-rate adjustment mechanisms, which provide for pass-through of most fuel, storage and transportation costs to customers.
The estimated minimum purchases for Xcel Energy under these contracts as of Dec. 31, 2011 are as follows:
| (Millions of Dollars) | | Dec. 31, 2011 | |
| Coal | | $ | 3,683 | |
| Nuclear fuel | | | 1,546 | |
| Natural gas supply | | | 1,122 | |
| Natural gas storage and transportation | | | 2,755 | |
Estimated coal requirements at Dec. 31, 2011 have been adjusted to account for Sherco Unit 3, which was shut down in November 2011 after experiencing a significant failure of its turbine, generator and exciter systems. It is uncertain when Sherco Unit 3 will recommence operations. See Note 5 for further discussion.
Purchased Power Agreements — Xcel Energy has entered into agreements with other utilities and energy suppliers for purchased power to meet system load and energy requirements, replace generation from company-owned units under maintenance or during outages, and meet operating reserve obligations.
NSP-Minnesota, PSCo and SPS have various pay-for-performance contracts with expiration dates through 2033. In general, these contracts provide for energy payments based on actual power taken under the contracts, as well as capacity payments. Capacity payments are typically contingent on the independent power producing entity meeting certain contract obligations, including plant availability requirements. Certain contractual payments are adjusted based on market indices; however, the effects of price adjustments are mitigated through purchased energy cost recovery mechanisms.
Included in electric fuel and purchased power expenses for purchased power agreements were payments for capacity of $325.3 million, $426.7 million and $461.3 million in 2011, 2010 and 2009, respectively. At Dec. 31, 2011, the estimated future payments for capacity that the utility subsidiaries of Xcel Energy are obligated to purchase, subject to availability, are as follows:
| (Millions of Dollars) | | | |
| 2012 | | $ | 275.5 | |
| 2013 | | | 227.2 | |
| 2014 | | | 224.9 | |
| 2015 | | | 198.6 | |
| 2016 | | | 148.7 | |
| 2017 and thereafter | | | 404.0 | |
| Total | | $ | 1,478.9 | |
Variable Interest Entities — The accounting guidance for consolidation of variable interest entities requires enterprises to consider the activities that most significantly impact an entity’s financial performance, and power to direct those activities, when determining whether an enterprise is a variable interest entity’s primary beneficiary.
Purchased Power Agreements — Under certain purchased power agreements, NSP-Minnesota, PSCo and SPS purchase power from independent power producing entities that own natural gas or biomass fueled power plants for which the utility subsidiaries are required to reimburse natural gas or biomass fuel costs, or to participate in tolling arrangements under which the subsidiaries procure the natural gas required to produce the energy that they purchase. These specific purchased power agreements create a variable interest in the associated independent power producing entity.
Xcel Energy has determined that certain independent power producing entities are variable interest entities. Xcel Energy is not subject to risk of loss from the operations of these entities, and no significant financial support has been, or is in the future required to be provided other than contractual payments for energy and capacity set forth in the purchased power agreements.
Xcel Energy has evaluated each of these variable interest entities for possible consolidation, including review of qualitative factors such as the length and terms of the contract, control over O&M, control over dispatch of electricity, historical and estimated future fuel and electricity prices, and financing activities. Xcel Energy has concluded that these entities are not required to be consolidated in its consolidated financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance. Xcel Energy had approximately 3,773 MW and 4,101 MW of capacity under long-term purchased power agreements as of Dec. 31, 2011 and Dec. 31, 2010 with entities that have been determined to be variable interest entities. These agreements have expiration dates through the year 2033.
Fuel Contracts — SPS purchases all of its coal requirements for its Harrington and Tolk electric generating stations from TUCO under contracts for those facilities that expire in 2016 and 2017, respectively. TUCO arranges for the purchase, receiving, transporting, unloading, handling, crushing weighing, and delivery of coal to meet SPS’ requirements. TUCO is responsible for negotiating and administering contracts with coal suppliers, transporters and handlers.
No significant financial support has been, or is in the future, required to be provided to TUCO by SPS, other than contractual payments for delivered coal. However, the fuel contracts create a variable interest in TUCO due to SPS’ reimbursement of certain fuel procurement costs. SPS has determined that TUCO is a variable interest entity. SPS has concluded that it is not the primary beneficiary of TUCO because SPS does not have the power to direct the activities that most significantly impact TUCO’s economic performance.
Low-Income Housing Limited Partnerships — Eloigne and NSP-Wisconsin have entered into limited partnerships for the construction and operation of affordable rental housing developments which qualify for low-income housing tax credits. Xcel Energy Inc. has determined Eloigne and NSP-Wisconsin’s low-income housing limited partnerships to be variable interest entities primarily due to contractual arrangements within each limited partnership that establish sharing of ongoing voting control and profits and losses that does not consistently align with the partners’ proportional equity ownership. These limited partnerships are designed to qualify for low-income housing tax credits, and Eloigne and NSP-Wisconsin generally receive a larger allocation of the tax credits than the general partners at inception of the arrangements. Xcel Energy Inc. has determined that Eloigne and NSP-Wisconsin have the power to direct the activities that most significantly impact these entities’ economic performance, and therefore Xcel Energy Inc. consolidates these limited partnerships in its consolidated financial statements.
Equity financing for these entities has been provided by Eloigne and NSP-Wisconsin and the general partner of each limited partnership, and Xcel Energy’s risk of loss is limited to its capital contributions, adjusted for any distributions and its share of undistributed profits and losses; no significant additional financial support has been, or is in the future, required to be provided to the limited partnerships by Eloigne or NSP-Wisconsin. Mortgage-backed debt typically comprises the majority of the financing at inception of each limited partnership and is paid over the life of the limited partnership arrangement. Obligations of the limited partnerships are generally secured by the housing properties of each limited partnership, and the creditors of each limited partnership have no significant recourse to Xcel Energy Inc. or its subsidiaries. Likewise, the assets of the limited partnerships may only be used to settle obligations of the limited partnerships, and not those of Xcel Energy Inc. or its subsidiaries.
Amounts reflected in Xcel Energy’s consolidated balance sheets for the Eloigne and NSP-Wisconsin low-income housing limited partnerships include the following:
| (Thousands of Dollars) | | Dec. 31, 2011 | | | Dec. 31, 2010 | |
| Current assets | | $ | 4,034 | | | $ | 3,794 | |
| Property, plant and equipment, net | | | 90,914 | | | | 97,602 | |
| Other noncurrent assets | | | 8,053 | | | | 8,236 | |
| Total assets | | $ | 103,001 | | | $ | 109,632 | |
| | | | | | | | | |
| Current liabilities | | $ | 12,297 | | | $ | 11,884 | |
| Mortgages and other long-term debt payable | | | 48,863 | | | | 53,195 | |
| Other noncurrent liabilities | | | 8,278 | | | | 8,333 | |
| Total liabilities | | $ | 69,438 | | | $ | 73,412 | |
Leases — Xcel Energy leases a variety of equipment and facilities used in the normal course of business. Three of these leases qualify as capital leases and are accounted for accordingly. The assets and liabilities at the inception of the capital leases are recorded at the lower of fair market value or the present value of future lease payments and are amortized over their actual contract term.
WYCO was formed as a joint venture with CIG to develop and lease natural gas pipeline, storage, and compression facilities. Xcel Energy Inc. has a 50 percent ownership interest in WYCO. WYCO leases the facilities to CIG, and CIG operates the facilities, providing natural gas storage services to PSCo under a service arrangement.
PSCo accounts for its Totem natural gas storage service arrangement with CIG as a capital lease. As a result, PSCo had $152.7 million and $149.9 million of capital lease obligations recorded for the arrangement as of Dec. 31, 2011 and 2010, respectively. Xcel Energy Inc. eliminates 50 percent of the capital lease obligation related to WYCO in the consolidated balance sheet along with an equal amount of Xcel Energy Inc.’s equity investment in WYCO.
PSCo records amortization for its capital leases as cost of natural gas sold and transported on the consolidated statements of income. Total amortization expenses under capital lease assets were approximately $3.2 million, $5.3 million, and $3.5 million for 2011, 2010 and 2009, respectively. Following is a summary of property held under capital leases:
| (Millions of Dollars) | | 2011 | | | 2010 | |
| Storage, leaseholds and rights | | $ | 200.5 | | | $ | 196.1 | |
| Gas pipeline | | | 20.7 | | | | 20.7 | |
| Property held under capital lease | | | 221.2 | | | | 216.8 | |
| Accumulated depreciation | | | (29.8 | ) | | | (26.6 | ) |
| Total property held under capital leases, net | | $ | 191.4 | | | $ | 190.2 | |
The remainder of the leases, primarily for office space, railcars, generating facilities, trucks, aircraft, cars and power-operated equipment, are accounted for as operating leases. Total expenses under operating lease obligations for Xcel Energy were approximately $204.8 million, $197.4 million, and $209.5 million for 2011, 2010 and 2009, respectively. These expenses include payments for capacity recorded to electric fuel and purchased power expenses for purchased power agreements accounted for as operating leases of $160.5 million, $163.7 million, and $171.3 million in 2011, 2010 and 2009, respectively.
Included in the future commitments under operating leases are estimated future payments under purchased power agreements that have been accounted for as operating leases in accordance with the applicable accounting guidance. Future commitments under operating and capital leases are:
| | | Other | | | Purchased | | | Total | | | | | |
| | | Operating | | | Power Agreement | | | Operating | | | | | |
| (Millions of Dollars) | | Leases | | | Operating Leases (a) (b) | | | Leases | | | Capital Leases | | |
| 2012 | | $ | 26.6 | | | $ | 159.0 | | | $ | 185.6 | | | $ | 18.2 | | |
| 2013 | | | 24.8 | | | | 173.5 | | | | 198.3 | | | | 18.0 | | |
| 2014 | | | 24.3 | | | | 180.6 | | | | 204.9 | | | | 18.0 | | |
| 2015 | | | 23.2 | | | | 182.0 | | | | 205.2 | | | | 17.9 | | |
| 2016 | | | 18.2 | | | | 173.9 | | | | 192.1 | | | | 17.2 | | |
| Thereafter | | | 89.6 | | | | 1,908.7 | | | | 1,998.3 | | | | 306.2 | | |
| Total minimum obligation | | | | | | | | | | | | | | | 395.5 | | |
| Interest component of obligation | | | | | | | | | | | | | | | (280.5 | ) | |
| Present value of minimum obligation | | | | | | | | | | | | | | $ | 115.0 | | (c) |
| (a) | Amounts do not include purchased power agreements accounted for as other commitments, which are recorded to O&M as executed. |
| (b) | Purchased power agreement operating leases contractually expire through 2033. |
| (c) | Future commitments exclude certain amounts related to Xcel Energy’s 50 percent ownership interest in WYCO. |
Technology Agreements — Xcel Energy has a contract that extends through Sept. 30, 2015 with IBM for information technology services. The contract is cancelable at Xcel Energy’s option, although there are financial penalties for early termination. In 2011, Xcel Energy paid IBM $93.6 million under the contract which included $1.4 million for other project business. In 2010, Xcel Energy paid IBM $95.6 million under the contract which included $2.0 million for other project business.
Xcel Energy’s contract with Accenture for information technology services extends through Jan. 31, 2017. It is cancelable at Xcel Energy’s option, although Xcel Energy would be obligated to pay 50 percent of the contract value for early termination. In 2011, Xcel Energy paid Accenture $15.2 million under the contract which included $5.6 million for other project business. In 2010, Xcel Energy paid Accenture $22.7 million under the contract which included $8.4 million for other project business.
Committed minimum payments under these obligations are as follows:
| | | IBM | | | Accenture | |
| (Millions of Dollars) | | Agreement | | | Agreement | |
| 2012 | | $ | 19.2 | | | $ | 8.7 | |
| 2013 | | | 17.6 | | | | 8.4 | |
| 2014 | | | 17.2 | | | | 8.2 | |
| 2015 | | | 11.9 | | | | 8.2 | |
| 2016 and thereafter | | | - | | | | 8.1 | |
Guarantees and Indemnifications
Xcel Energy Inc. and its subsidiaries provide guarantees and bond indemnities under specified agreements or transactions. The guarantees and bond indemnities issued by Xcel Energy Inc. guarantee payment or performance by its subsidiaries. As a result, Xcel Energy Inc.’s exposure under the guarantees and bond indemnities is based upon the net liability of the relevant subsidiary under the specified agreements or transactions. Most of the guarantees and bond indemnities issued by Xcel Energy Inc. and its subsidiaries limit the exposure to a maximum amount stated in the guarantees and bond indemnities. As of Dec. 31, 2011, Xcel Energy Inc. and its subsidiaries have no assets held as collateral related to their guarantees, bond indemnities and indemnification agreements.
Guarantees and Surety Bonds
The following table presents guarantees and bond indemnities issued and outstanding, including those guarantees related to Xcel Energy Wholesales Group Inc., Seren, UE, Viking, and Xcel Energy Argentina Inc., which are components of discontinued operations, as of Dec. 31, 2011:
| (Millions of Dollars) | | Guarantor | | Guarantee Amount | | | Current Exposure | | Triggering Event |
Guarantee of the indemnification obligations of Xcel Energy Wholesale Group Inc. under a stock purchase agreement (e) | | Xcel Energy Inc. | | $ | 17.5 | | | $ | 17.5 | | (b) |
| | | | | | | | | | | | |
Guarantee of the indemnification obligations of Xcel Energy Argentina Inc. under a stock purchase agreement (d) | | Xcel Energy Inc. | | | 14.7 | | | | — | | (b) |
| | | | | | | | | | | | |
Guarantee of the indemnification obligations of various Xcel Energy Inc. subsidiaries under different asset purchase agreements (d) | | Xcel Energy Inc. | | | 25.5 | | | | — | | (b) |
| | | | | | | | | | | | |
Guarantee of customer loans for the Farm Rewiring Program (f) | | NSP-Wisconsin | | | 1.0 | | | | 0.5 | | (c) |
| | | | | | | | | | | | |
Guarantee of the indemnification obligations of Xcel Energy Services Inc. under the aircraft leases (g) | | Xcel Energy Inc. | | | 8.3 | | | | — | | (a) |
| | | | | | | | | | | | |
Guarantee benefiting Young Gas Storage Company Ltd. (f) | | Xcel Energy Inc. | | | 0.5 | | | | — | | (a) |
| Total guarantees issued | | | | $ | 67.5 | | | $ | 18.0 | | |
| | | | | | | | | | | | |
Guarantee performance and payment of surety bonds for Xcel Energy Inc. and its subsidiaries (j) (k) | | Xcel Energy Inc. | | $ | 31.2 | | | (h) | | (i) |
| (a) | Nonperformance and/or nonpayment. |
| (b) | Losses caused by default in performance of covenants or breach of any warranty or representation in the purchase agreement. |
| (c) | The debtor becomes the subject of bankruptcy or other insolvency proceedings. |
| (d) | The term of this guarantee is continuing. Certain representations and warranties relating to due organization, transaction authorization and tax matters survive indefinitely. As of Dec. 31, 2011, no claims have been made. |
| (e) | The indemnification provisions of the guarantee expired in 2010. As of Dec. 31, 2011, there is a pending indemnification claim causing the guarantee liability to remain outstanding until the final resolution. |
| (f) | The term of this guarantee is continuing. |
| (g) | The term of this guarantee expires in 2012 when the associated leases expire. At the time of renewal of the aircraft leases, the related guarantees will also be renewed. |
| (h) | Due to the magnitude of projects associated with the surety bonds, the total current exposure of this indemnification cannot be determined. Xcel Energy Inc. believes the exposure to be significantly less than the total amount of the outstanding bonds. |
| (i) | Failure of Xcel Energy Inc. or one of its subsidiaries to perform under the agreement that is the subject of the relevant bond. In addition, per the indemnity agreement between Xcel Energy Inc. and the various surety companies, the surety companies have the discretion to demand that collateral be posted. |
| (j) | Xcel Energy Inc. has on ongoing agreement to indemnify an insurance company in connection with surety bonds they may issue or have issued for UE up to $80 million. Xcel Energy Inc.’s indemnification will be triggered only in the event that UE has failed to meet its obligations to the surety company. |
| (k) | The expiration date of the surety bonds is project based. Accordingly, the surety bonds expire in conjunction with the completion of the related projects. |
Indemnification Agreements
In connection with the purchase and sale agreement of certain electric distribution assets in Lubbock, Texas, SPS agreed to indemnify the purchaser for losses arising out of any breach of the representations, warranties and covenants under the related asset purchase agreement and for losses arising out of certain other matters, including pre-closing unknown liabilities. SPS’ indemnification obligation is capped at $87 million, in the aggregate. The indemnification provisions for most representations and warranties expired in October 2011. The remaining representations and warranties, which relate to due organization and transaction authorization, survive indefinitely. SPS has not recorded a liability related to this indemnity.
In connection with the acquisition of the 201 MW Nobles wind project, NSP-Minnesota agreed to indemnify the seller for losses arising out of a breach of certain representations and warranties. NSP-Minnesota’s indemnification obligation is capped at $20 million, in the aggregate. The indemnification obligation expires in March 2013. NSP-Minnesota has not recorded a liability related to this indemnity.
In connection with the acquisition of 900 MW of gas-fired generation from subsidiaries ofCalpine Development Holdings Inc., PSCo agreed to indemnify the seller for losses arising out of a breach of certain representations and warranties. The aggregate liability for PSCo pursuant to these indemnities is not subject to a capped dollar amount. The indemnification obligation expires in December 2012. PSCo has not recorded a liability related to this indemnity.
Xcel Energy Inc. and its subsidiaries provide other indemnifications through contracts entered into in the normal course of business. These are primarily indemnifications against adverse litigation outcomes in connection with underwriting agreements, as well as breaches of representations and warranties, including due organization, transaction authorization and income tax matters with respect to assets sold. Xcel Energy Inc.’s and its subsidiaries’ obligations under these agreements may be limited in terms of time and amount. The maximum potential amount of future payments under these indemnifications cannot be reasonably estimated as the obligated amounts of these indemnifications often are not explicitly stated.
Environmental Contingencies
Xcel Energy has been or is currently involved with the cleanup of contamination from certain hazardous substances at several sites. In many situations, the subsidiary involved believes it will recover some portion of these costs through insurance claims. Additionally, where applicable, the subsidiary involved is pursuing, or intends to pursue, recovery from other PRPs and through the regulated rate process. New and changing federal and state environmental mandates can also create added financial liabilities for Xcel Energy, which are normally recovered through the regulated rate process. To the extent any costs are not recovered through the options listed above, Xcel Energy would be required to recognize an expense.
Site Remediation — The Comprehensive Environmental Response, Compensation and Liability Act of 1980 and other comparable federal and state environmental laws impose liability, without regard to the legality of the original conduct, on certain classes of persons where hazardous substances or other regulated materials have been released to the environment. Xcel Energy Inc.’s subsidiaries may sometimes pay all or a portion of the cost to remediate sites where past activities of their predecessors or other parties have caused environmental contamination. Environmental contingencies could arise from various situations, including sites of former MGPs operated by Xcel Energy Inc.’s subsidiaries or their predecessors, or other entities; and third-party sites, such as landfills, for which one or more of Xcel Energy Inc.’s subsidiaries are alleged to be a PRP that sent hazardous materials and wastes to that site.
MGP Sites
Ashland MGP Site — NSP-Wisconsin has been named a PRP for contamination at a site in Ashland, Wis. The Ashland/Northern States Power Lakefront Superfund Site (the Ashland site) includes property owned by NSP-Wisconsin, which was a site previously operated by a predecessor company as a MGP facility (the Upper Bluff), and two other properties: an adjacent city lakeshore park area (Kreher Park), on which an unaffiliated third party previously operated a sawmill and conducted creosote treating operations; and an area of Lake Superior’s Chequamegon Bay adjoining the park (the Sediments).
The EPA issued its Record of Decision (ROD) in September 2010, which documents the remedy that the EPA has selected for the cleanup of the Ashland site. In April 2011, the EPA issued special notice letters identifying several entities, including NSP-Wisconsin, as PRPs, for future cleanup at the site. The special notice letters requested that those PRPs participate in negotiations with the EPA regarding how the PRPs intend to conduct or pay for the cleanup. On June 30, 2011, NSP-Wisconsin submitted a settlement offer to the EPA related to the future cleanup of the Ashland site. On July 14, 2011, the EPA informed NSP-Wisconsin and the other PRPs that it was rejecting all of their individual offers and can now choose to initiate enforcement actions at any time. Despite this decision, the EPA also indicated a willingness to continue settlement negotiations with NSP-Wisconsin. Settlement negotiations are ongoing.
At Dec. 31, 2011 and Dec. 31, 2010, NSP-Wisconsin had recorded a liability of $104.3 million and $97.5 million, respectively, based upon potential remediation and design costs together with estimated outside legal and consultant costs; of which $26.6 million and $4.8 million, respectively, was considered a current liability. NSP-Wisconsin’s potential liability, the actual cost of remediation and the time frame over which the amounts may be paid are subject to change until after negotiations or litigation with the EPA and other PRPs are fully resolved. NSP-Wisconsin also continues to work to identify and access state and federal funds to apply to the ultimate remediation cost of the entire site. Unresolved issues or factors that could result in higher or lower NSP-Wisconsin remediation costs for the Ashland site include, but are not limited to, the cleanup approach implemented, which party implements the cleanup, the timing of when the cleanup is implemented and the contributions, if any, by other PRPs.
NSP-Wisconsin has deferred, as a regulatory asset, the estimated site remediation expenses and spending to date less insurance and rate recoveries, based on an expectation that the PSCW will continue to allow NSP-Wisconsin to recover payments for environmental remediation from its customers. The PSCW has consistently authorized in NSP-Wisconsin rates recovery of all remediation costs incurred at the Ashland site, and has authorized recovery of MGP remediation costs by other Wisconsin utilities. External MGP remediation costs are subject to deferral in the Wisconsin retail jurisdiction and are reviewed for prudence as part of the Wisconsin biennial retail rate case process. Under an existing PSCW policy with respect to recovery of remediation costs for MGPs, utilities have recovered remediation costs in natural gas rates, amortized over a four- to six-year period. The PSCW has not allowed utilities to recover their carrying costs on unamortized regulatory assets for MGP remediation. In a recent rate case decision, the PSCW recognized the potential magnitude of the future liability for, and circumstances of, the cleanup at the Ashland site and indicated it may consider alternatives to its established MGP site cleanup cost accounting and cost recovery guidelines for the Ashland site in a future proceeding. NSP-Wisconsin is working with the PSCW Staff to develop alternatives for consideration by the PSCW.
Other MGP Sites — Xcel Energy is currently involved in investigating and/or remediating several other MGP sites where hazardous or other regulated materials may have been deposited. Xcel Energy has identified 8 sites, where former MGP activities have or may have resulted in actual site contamination and are under current investigation and/or remediation. At some or all of these MGP sites, there are other parties that may have responsibility for some portion of any ultimate remediation that may be conducted. Xcel Energy anticipates that the majority of the remediation at these sites will continue through at least 2014. For these sites, Xcel Energy had accrued $3.9 million and $3.2 million at Dec. 31, 2011 and Dec. 31, 2010, respectively. There may be insurance recovery and/or recovery from other PRPs that will offset any costs actually incurred at these sites. Xcel Energy anticipates that any amounts actually spent will be fully recovered from customers.
Asbestos Removal — Some of Xcel Energy’s facilities contain asbestos. Most asbestos will remain undisturbed until the facilities that contain it are demolished or removed. Xcel Energy has recorded an estimate for final removal of the asbestos as an ARO. See additional discussion of AROs below. It may be necessary to remove some asbestos to perform maintenance or make improvements to other equipment. The cost of removing asbestos as part of other work is not expected to be material and is recorded as incurred as operating expenses for maintenance projects, capital expenditures for construction projects or removal costs for demolition projects.
Other Environmental Requirements
EPA GHG Regulation — In December 2009, the EPA issued its “endangerment” finding that GHG emissions pose a threat to public health and welfare. In January 2011, new EPA permitting requirements became effective for GHG emissions of new and modified large stationary sources, which are applicable to the construction of new power plants or power plant modifications that increase emissions above a certain threshold. Xcel Energy is unable to determine what the cost of compliance with these new EPA requirements will be as it is not clear whether these requirements will apply to futures changes at Xcel Energy’s power plants.
New Mexico GHG Regulations — In 2010, the EIB adopted two regulations to limit GHG emissions, including CO2 emissions from power plants and other industrial sources. SPS, other utilities and industry groups have filed separate appeals with the New Mexico Court of Appeals challenging the validity of these two GHG regulations. The appellate cases have been stayed pending further proceedings before the EIB.
In July 2011, SPS and other parties filed a petition for repeal of each state GHG rule with the EIB. The EIB held hearings for both repeal petitions in 2011. The first of these two regulations was repealed by the EIB in February 2012. The second will be reviewed in March 2012. Unless repealed, the second rule is scheduled to become applicable to SPS beginning in 2013. Efforts to quantify compliance costs have been suspended pending the outcome on the second rule.
GHG New Source Performance Standard Proposal — The EPA plans to propose GHG regulations applicable to emissions from new and existing power plants under the CAA. The EPA had planned to release its proposal in September 2011, but has delayed it without establishing a new proposal date.
CSAPR — In July 2011, the EPA issued its CSAPR to address long range transport of particulate matter and ozone by requiring reductions in SO2 and NOx from utilities located in the eastern half of the U.S. For Xcel Energy, the rule applies to Minnesota, Wisconsin and Texas. The CSAPR sets more stringent requirements than the proposed CATR and, in contrast to that proposal, specifically requires plants in Texas to reduce their SO2 and annual NOx emissions. The rule also creates an emissions trading program. Xcel Energy intends to comply by reducing emissions and/or purchasing allowances.
On Dec. 30, 2011, the U.S. Court of Appeals for the D.C. Circuit issued a stay of the CSAPR, pending completion of judicial review. The Court is expected to hear the case in April 2012. Xcel Energy anticipates that the court may rule on the challenges to the CSAPR in the second half of 2012. It is not known at this time whether the CSAPR will be upheld, reversed or will require modifications pursuant to a future Court decision.
If the CSAPR is upheld and unmodified, Xcel Energy believes that the CSAPR could ultimately require the installation of additional emission controls on some of SPS’ coal-fired electric generating units. If compliance is required in a short time frame, SPS may be required to redispatch its system to reduce coal plant operating hours, in order to decrease emissions from its facilities prior to the installation of emission controls. The expected cost for these scenarios may vary significantly and SPS has estimated capital expenditures of approximately $470 million over the next four years for the plant modifications related to the CSAPR requirements. SPS believes the cost of any required capital investment or possible increased fuel costs would be recoverable from customers through regulatory mechanisms and does not expect a material impact on its results of operations, financial position or cash flows.
If the CSAPR is upheld and unmodified, NSP-Minnesota would likely utilize a combination of emissions reductions through upgrades to its existing SO2 control technology at NSP-Minnesota’s Sherco plant, which is estimated to cost a total of $10 million through 2014, and system operating changes to the Black Dog and the Sherco plants. If available, NSP-Minnesota would also consider allowance purchases. In addition, NSP-Minnesota has filed a petition for reconsideration with the EPA and a petition for review of the CSAPR with the U.S. Court of Appeals for the D.C. Circuit seeking the allocation of additional emission allowances to NSP-Minnesota. NSP-Minnesota contends that the EPA’s method of allocating allowances arbitrarily resulted in fewer allowances for its Riverside and High Bridge plants than should have been awarded to reflect their operations during the baseline period, which included coal-fired operations prior to their conversion to natural gas. If successful, additional allowances would reduce NSP-Minnesota’s costs to comply with the reductions that may be imposed by the CSAPR.
If the CSAPR is upheld and unmodified, NSP-Wisconsin would likely make a combination of system operating changes and allowance purchases. NSP-Wisconsin estimates the cost of compliance would be $0.2 million, and expects the cost of any required capital investment will be recoverable from customers.
CAIR — In 2005, the EPA issued the CAIR to further regulate SO2 and NOx emissions. The CAIR applies to Texas and Wisconsin. The CAIR does not currently apply in Minnesota because the Court specifically found that the EPA had not adequately justified the application of the CAIR to Minnesota. In granting the stay of the CSAPR, the Court specifically noted that the CAIR would remain in place during its pending review of the CSAPR.
Under the CAIR’s cap and trade structure, companies can comply through capital investments in emission controls or purchase of emission allowances from other utilities making reductions on their systems. To comply with the CAIR in 2012, NSP-Wisconsin will likely make a combination of system operating changes and allowance purchases, if available. In the SPS region, installation of low-NOx combustion control technology began on Tolk Unit 1 in January 2012. Installation will begin on Tolk Unit 2 at a yet to be determined date. These installations will reduce or eliminate SPS’ need to purchase NOx emission allowances. In addition, SPS has sufficient SO2 allowances to comply with CAIR in 2012. At Dec. 31, 2011, the estimated annual CAIR NOx allowance cost for Xcel Energy does not have a material impact on the results of operations, financial position or cash flows.
EGU Mercury and Air Toxics Standards (MATS) Rule — In December 2011, the EPA issued the final EGU MATS rule to replace the proposed EGU MACT rule. The EGU MATS rule sets emission limits for acid gases, mercury and other hazardous air pollutants and will require coal-fired utility facilities greater than 25 MW to demonstrate compliance within three to four years. Xcel Energy believes these costs would be recoverable through regulatory mechanisms, and it does not expect a material impact on its results of operations, financial position or cash flows.
Colorado Mercury Regulation — Colorado’s mercury regulations require mercury emission controls capable of achieving 80 percent capture to be installed at the Pawnee Generating Station by the end of 2011. The cost for the Pawnee Generating Station mercury controls was $1.1 million for capital costs with an annual estimate of $0.5 million for sorbent expense. PSCo has evaluated the Colorado mercury control requirements for its other units in Colorado and believes that, under the current regulations, no further controls will be required other than the planned controls at the Pawnee Generating Station, which are included in the CACJA compliance plan.
Minnesota Mercury Legislation — Under the 2006 mercury legislation, NSP-Minnesota installed sorbent control systems at the Sherco Unit 3 and A.S. King generating plants, with project costs collected through the MCR rider in 2010. Subsequently, in the 2010 Minnesota electric rate case, the costs of these projects were moved into base rates as part of the interim rates effective Jan. 2, 2011. NSP-Minnesota has also obtained MPUC approval to install mercury controls on Sherco Units 1 and 2 by the end of 2014.
For Sherco Units 1 and 2, NSP-Minnesota has incurred $1.5 million in study costs to date and spent $0.6 million through Dec. 31, 2011 for testing and studying of technologies. At Dec. 31, 2011, the estimated annual testing and study cost is $0.5 million. NSP-Minnesota projects installation costs of $12.0 million for the mercury controls on the units and O&M expense of $10.0 million per year beginning in 2014. NSP-Minnesota believes these costs would be recoverable through regulatory mechanisms.
Industrial Broiler (IB) MACT Rules — In March 2011, the EPA finalized IB MACT rules to regulate boilers and process heaters fueled with coal, biomass and liquid fuels, which would apply to NSP-Wisconsin’s Bay Front units 1 and 2. On Dec. 23, 2011, the EPA proposed reconsideration of certain provisions of the final rule. The estimated capital cost of $9.0 million per unit, which is currently targeted for 2014, is dependent on the outcome of the reconsideration proceedings.
Colorado Proposed Surface Impoundment Regulations (Section 9) — In February 2012, the Colorado Department of Public Health and the Environment promulgated new solid waste regulations that establish new design and operating requirements for surface impoundments, including coal ash ponds and cooling tower ponds. The regulations provide a partial exemption on design upgrades for coal ash ponds pending a final Coal Combustion Residuals Rule from EPA. The final rule also exempts PSCo’s ponds that will be closed under the CACJA. The effective date will be March 30, 2012. Estimated costs for compliance are approximately $18 million in total through 2018.
Regional Haze Rules — In 2005, the EPA finalized amendments to its regional haze rules regarding provisions that require the installation and operation of emission controls, known as BART, for industrial facilities emitting air pollutants that reduce visibility in certain national parks and wilderness areas throughout the U.S. Xcel Energy generating facilities in several states will be subject to BART requirements. Individual states are required to identify the facilities located in their states that will have to reduce SO2, NOx and particulate matter emissions under BART and then set emissions limits for those facilities.
PSCo
In 2006, the Colorado Air Quality Control Commission promulgated BART regulations requiring certain major stationary sources to evaluate, install, operate and maintain BART to make reasonable progress toward meeting the national visibility goal. In January 2011, the Colorado Air Quality Control Commission approved a revised Regional Haze BART SIP incorporating the Colorado CACJA emission reduction plan, which will satisfy regional haze requirements. The Colorado SIP is currently pending before the EPA. PSCo expects the cost of any required capital investment will be recoverable from customers through the CACJA plan recovery mechanisms or other regulatory mechanisms. Emissions controls are expected to be installed between 2012 and 2017. The costs associated with the CACJA plan are discussed in Capital Commitments.
In March 2010, two environmental groups petitioned the U.S. DOI to certify that 12 coal-fired boilers and one coal-fired cement kiln in Colorado are contributing to visibility problems in Rocky Mountain National Park. Four PSCo plants are named in the petition: Cherokee, Hayden, Pawnee and Valmont. The groups allege that the Colorado BART rule is inadequate to satisfy the CAA mandate of ensuring reasonable further progress towards restoring natural visibility conditions in the park. It is not known when the DOI will rule on the petition.
NSP-Minnesota
In December 2009, the MPCA Citizens Board approved the Regional Haze SIP, which has been submitted to the EPA for approval. The MPCA selected the BART controls for Sherco Units 1 and 2 to improve visibility in the national parks. The MPCA concluded SCRs should not be required because the minor visibility benefits derived from SCRs do not outweigh the substantial costs. The MPCA’s BART controls for Sherco Units 1 and 2 consist of combustion controls for NOx and scrubber upgrades for SO2. The combustion controls have been installed on Sherco Units 1 and 2, and the scrubber upgrades are scheduled to be installed by 2015. At this time, the estimated cost for meeting the BART and other CAA requirements is approximately $50 million of which $20 million has already been spent on projects to reduce NOx emissions on Sherco Units 1 and 2. Xcel Energy anticipates that all costs associated with BART compliance will be fully recoverable.
In June 2011, the EPA provided comments to the MPCA on the SIP, stating the EPA’s preliminary review indicates that SCR controls should be added to Sherco Units 1 and 2. The MPCA has since proposed that the CSAPR should be considered BART for EGUs and the EPA has proposed that states be allowed to find that CSAPR compliance meets BART requirements for EGUs, and specifically that Minnesota’s proposal to find the CSAPR to meet BART requirements should be approved, if finalized by the state. It is not yet known what the final requirements will be. NSP-Minnesota does not expect that a finding that the CSAPR meets BART requirements would result in changes to the control equipment plans described above, and has requested that the MPCA retain its 2009 BART determination.
In October 2009, the DOI certified that a portion of the visibility impairment in Voyageurs and Isle Royale National Parks is reasonably attributable to emissions from NSP-Minnesota’s Sherco Units 1 and 2. The EPA is required to make its own determination as to whether Sherco Units 1 and 2 cause or contribute to visibility impairment and, if so, whether the level of controls proposed by the MPCA is appropriate. In its Jan. 25, 2012 notice concerning its review of Minnesota’s Regional Haze SIP, the EPA noted that it plans to issue a separate notice on the issue of BART for Sherco Units 1 and 2 under the Reasonably Attributable Visibility Impairment (RAVI) program. It is not yet known when the EPA will publish a proposal under RAVI, or what that proposal will entail.
SPS
Harrington Units 1 and 2 are potentially subject to BART. Texas has developed a Regional Haze SIP that finds the CAIR equal to BART for EGUs, and as a result, no additional controls for these units beyond the CAIR compliance, described above are required.
Federal Clean Water Act (CWA) Section 316 (b) — The federal CWA requires the EPA to regulate cooling water intake structures to assure that these structures reflect the best technology available for minimizing adverse environmental impacts to aquatic species. In April 2011, the EPA published the proposed rule that sets prescriptive standards for minimization of aquatic species impingement, but leaves entrainment reduction requirements at the discretion of the permit writer and the regional EPA office. Xcel Energy provided comments to the proposed rule, which is expected to be finalized in late 2012. Due to the uncertainty of the final regulatory requirements, it is not possible to provide an accurate estimate of the overall cost of this rulemaking at this time.
As part of NSP-Minnesota’s 2009 CWA permit renewal for the Black Dog plant, the MPCA required the submission of a plan for compliance with the CWA. The compliance plan was submitted for MPCA review and approval in April 2010. The MPCA is currently reviewing the proposal in consultation with the EPA.
Proposed Coal Ash Regulation — Xcel Energy’s operations generate hazardous wastes that are subject to the Federal Resource Recovery and Conservation Act and comparable state laws that impose detailed requirements for handling, storage, treatment and disposal of hazardous waste. In June 2010, the EPA published a proposed rule seeking comment on whether to regulate coal combustion byproducts (coal ash) as hazardous or nonhazardous waste. Coal ash is currently exempt from hazardous waste regulation. If the EPA ultimately issues a final rule under which coal ash is regulated as hazardous waste, Xcel Energy’s costs associated with the management and disposal of coal ash would significantly increase and the beneficial reuse of coal ash would be negatively impacted. The EPA has not announced a planned date for a final rule. The timing, scope and potential cost of any final rule that might be implemented are not determinable at this time.
PSCo NOV — In 2002, PSCo received an NOV from the EPA alleging violations of the New Source Review (NSR) requirements of the CAA at the Comanche Station and Pawnee Generating Station in Colorado. The NOV specifically alleges that various maintenance, repair and replacement projects undertaken at the plants in the mid to late 1990s should have required a permit under the NSR process. PSCo believes it has acted in full compliance with the CAA and NSR process. PSCo also believes that the projects identified in the NOV fit within the routine maintenance, repair and replacement exemption contained within the NSR regulations or are otherwise not subject to the NSR requirements. PSCo disagrees with the assertions contained in the NOV and intends to vigorously defend its position. It is not known whether any costs would be incurred as a result of this NOV.
Cunningham Compliance Order — In December, 2011, SPS entered into a final agreement with the NMED that resolved allegations that Cunningham exceeded its permit limits for NOx and failed to report these exceedances as required by its permit. The settlement was $0.8 million.
NSP-Minnesota NOV — In June 2011, NSP-Minnesota received an NOV from the EPA alleging violations of the NSR requirements of the CAA at the Sherco plant and Black Dog plant in Minnesota. The NOV specifically alleges that various maintenance, repair and replacement projects undertaken at the plants in the mid 2000s should have required a permit under the NSR process. NSP-Minnesota believes it has acted in full compliance with the CAA and NSR process. NSP-Minnesota also believes that the projects identified in the NOV fit within the routine maintenance, repair and replacement exemption contained within the NSR regulations or are otherwise not subject to the NSR requirements. NSP-Minnesota disagrees with the assertions contained in the NOV and intends to vigorously defend its position. It is not known whether any costs would be incurred as a result of this NOV.
Asset Retirement Obligations
Recorded AROs — AROs have been recorded for plant related to nuclear production, steam production, wind production, electric transmission and distribution, natural gas transmission and distribution and office buildings. The steam production obligation includes asbestos, ash-containment facilities, radiation sources and decommissioning. The asbestos recognition associated with the steam production includes certain plants at NSP-Minnesota, PSCo and SPS. NSP-Minnesota also recorded asbestos recognition for its general office building. This asbestos abatement removal obligation originated in 1973 with the CAA, which applied to the demolition of buildings or removal of equipment containing asbestos that can become airborne on removal. AROs also have been recorded for NSP-Minnesota, PSCo and SPS steam production related to ash-containment facilities such as bottom ash ponds, evaporation ponds and solid waste landfills. The origination dates on the ARO recognition for ash-containment facilities at steam plants was the in-service dates of the various facilities. Additional AROs have been recorded for NSP-Minnesota and PSCo steam production plant related to radiation sources in equipment used to monitor the flow of coal, lime and other materials through feeders.
Xcel Energy recognized an ARO for the retirement costs of natural gas mains at NSP-Minnesota, NSP-Wisconsin and PSCo. In addition, an ARO was recognized for the removal of electric transmission and distribution equipment at NSP-Minnesota, NSP-Wisconsin, PSCo and SPS, which consists of many small potential obligations associated with PCBs, mineral oil, storage tanks, treated poles, lithium batteries, mercury and street lighting lamps. These electric and natural gas assets have many in-service dates for which it is difficult to assign the obligation to a particular year. Therefore, the obligation was measured using an average service life.
For the nuclear assets, the ARO associated with the decommissioning of the NSP-Minnesota nuclear generating plants, Monticello and Prairie Island, originated with the in-service date of the facility. See Note 14 for further discussion of nuclear obligations.
A reconciliation of the beginning and ending aggregate carrying amounts of Xcel Energy’s AROs is shown in the table below for the years ended Dec. 31, 2011 and Dec. 31, 2010:
| | | Beginning | | | | | | | | | | | | Revisions | | Ending | |
| | | Balance | | | Liabilities | | | Liabilities | | | | | | to Prior | | Balance | |
| (Thousands of Dollars) | | Jan. 1, 2011 | | | Recognized | | | Settled | | | Accretion | | | Estimates | | Dec. 31, 2011 | |
| Electric plant | | | | | | | | | | | | | | | | | | |
| Steam production asbestos | | $ | 93,629 | | | $ | - | | | $ | (514 | ) | | $ | 5,958 | | | $ | (44,731 | ) | | $ | 54,342 | |
| Steam production ash containment | | | 19,688 | | | | - | | | | - | | | | 919 | | | | 20,551 | | | | 41,158 | |
| Steam production radiation sources | | | 166 | | | | - | | | | - | | | | 12 | | | | (39 | ) | | | 139 | |
| Nuclear production decommissioning | | | 809,474 | | | | - | | | | - | | | | 57,641 | | | | 615,626 | (a) | | | 1,482,741 | |
| Wind production | | | 38,553 | | | | - | | | | - | | | | 1,962 | | | | - | | | | 40,515 | |
| Electric transmission and distribution | | | 5,727 | | | | - | | | | - | | | | 290 | | | | 24,687 | | | | 30,704 | |
| Natural gas plant | | | | | | | | | | | | | | | | | | | | | | | | |
| Gas transmission and distribution | | | 996 | | | | - | | | | - | | | | 63 | | | | - | | | | 1,059 | |
| Common and other property | | | | | | | | | | | | | | | | | | | | | | | | |
| Common general plant asbestos | | | 1,077 | | | | - | | | | - | | | | 58 | | | | - | | | | 1,135 | |
| Total liability | | $ | 969,310 | | | $ | - | | | $ | (514 | ) | | $ | 66,903 | | | $ | 616,094 | | | $ | 1,651,793 | |
| (a) | The increase is primarily due to the completion of NSP-Minnesota’s triennial nuclear decommissioning study, which reflects an increase in the estimated cost of retirement, increase in the escalation rates for each nuclear unit and a decrease in the discount rate used to calculate the net present value of the future cash flows. |
The fair value of NSP-Minnesota’s legally restricted assets, for purposes of settling the nuclear ARO, was $1.3 billion as of Dec. 31, 2011, including external nuclear decommissioning investment funds and internally funded amounts.
In 2011, revisions were made for nuclear, asbestos, ash-containment facilities, radiation sources and electric transmission and distribution asset retirement obligations due to revised estimates and end of life dates.
| | | Beginning | | | | | | | | | | | | Revisions | | | Ending | |
| | | Balance | | | Liabilities | | | Liabilities | | | | | | to Prior | | | Balance | |
| (Thousands of Dollars) | | Jan. 1, 2010 | | | Recognized | | | Settled | | | Accretion | | | Estimates | | | Dec. 31, 2010 | |
| Electric plant | | | | | | | | | | | | | | | | | | |
| Steam production asbestos | | $ | 95,093 | | | $ | 3,771 | | | $ | (2,330 | ) | | $ | 6,037 | | | $ | (8,942 | ) | | $ | 93,629 | |
| Steam production ash containment | | | 17,552 | | | | 32 | | | | - | | | | 903 | | | | 1,201 | | | | 19,688 | |
| Steam production radiation sources | | | 176 | | | | - | | | | - | | | | 12 | | | | (22 | ) | | | 166 | |
| Nuclear production decommissioning | | | 758,923 | | | | - | | | | - | | | | 50,551 | | | | - | | | | 809,474 | |
| Wind production | | | 7,751 | | | | 25,671 | | | | - | | | | 592 | | | | 4,539 | | | | 38,553 | |
| Electric transmission and distribution | | | 27 | | | | - | | | | - | | | | 12 | | | | 5,688 | | | | 5,727 | |
| Natural gas plant | | | | | | | | | | | | | | | | | | | | | | | | |
| Gas transmission and distribution | | | 936 | | | | - | | | | - | | | | 60 | | | | - | | | | 996 | |
| Common and other property | | | | | | | | | | | | | | | | | | | | | | | | |
| Common general plant asbestos | | | 1,021 | | | | - | | | | - | | | | 56 | | | | - | | | | 1,077 | |
| Total liability | | $ | 881,479 | | | $ | 29,474 | | | $ | (2,330 | ) | | $ | 58,223 | | | $ | 2,464 | | | $ | 969,310 | |
The fair value of NSP-Minnesota’s legally restricted assets, for purposes of settling the nuclear ARO, was $1.4 billion as of Dec. 31, 2010, including external nuclear decommissioning investment funds and internally funded amounts.
In 2010, revisions were made for asbestos, ash-containment facilities, wind turbines, radiation sources and electric transmission and distribution asset retirement obligations due to revised estimates and end of life dates.
Indeterminate AROs — PSCo has underground natural gas storage facilities that have special closure requirements for which the final removal date cannot be determined; therefore, an ARO has not been recorded.
Removal Costs — Xcel Energy records a regulatory liability for the plant removal costs of other generation, transmission and distribution facilities of its utility subsidiaries. Generally, the accrual of future non-ARO removal obligations is not required. However, long-standing ratemaking practices approved by applicable state and federal regulatory commissions have allowed provisions for such costs in historical depreciation rates. These removal costs have accumulated over a number of years based on varying rates as authorized by the appropriate regulatory entities. Given the long time periods over which the amounts were accrued and the changing of rates over time, the utility subsidiaries have estimated the amount of removal costs accumulated through historic depreciation expense based on current factors used in the existing depreciation rates.
The accumulated balances by entity were as follows at Dec. 31:
| (Millions of Dollars) | | 2011 | | | 2010 | |
| NSP-Minnesota | | $ | 382 | | | $ | 400 | |
| NSP-Wisconsin | | | 109 | | | | 107 | |
| PSCo | | | 380 | | | | 385 | |
| SPS | | | 74 | | | | 88 | |
| Total Xcel Energy | | $ | 945 | | | $ | 980 | |
Nuclear Insurance
NSP-Minnesota’s public liability for claims resulting from any nuclear incident is limited to $12.6 billion under the Price-Anderson amendment to the Atomic Energy Act. NSP-Minnesota has secured $375 million of coverage for its public liability exposure with a pool of insurance companies. The remaining $12.2 billion of exposure is funded by the Secondary Financial Protection Program, available from assessments by the federal government in case of a nuclear accident. NSP-Minnesota is subject to assessments of up to $117.5 million per reactor per accident for each of its three licensed reactors, to be applied for public liability arising from a nuclear incident at any licensed nuclear facility in the United States. The maximum funding requirement is $17.5 million per reactor during any one year. These maximum assessment amounts are both subject to inflation adjustment by the NRC and state premium taxes. The NRC’s last adjustment was effective April 2010.
NSP-Minnesota purchases insurance for property damage and site decontamination cleanup costs from Nuclear Electric Insurance Ltd. (NEIL). The coverage limits are $2.25 billion for each of NSP-Minnesota’s two nuclear plant sites. NEIL also provides business interruption insurance coverage, including the cost of replacement power obtained during certain prolonged accidental outages of nuclear generating units. Premiums are expensed over the policy term. All companies insured with NEIL are subject to retroactive premium adjustments if losses exceed accumulated reserve funds. Capital has been accumulated in the reserve funds of NEIL to the extent that NSP-Minnesota would have no exposure for retroactive premium assessments in case of a single incident under the business interruption and the property damage insurance coverage. However, in each calendar year, NSP-Minnesota could be subject to maximum assessments of approximately $15.7 million for business interruption insurance and $33.6 million for property damage insurance if losses exceed accumulated reserve funds.
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. The ultimate outcome of these matters cannot presently be determined. Accordingly, the ultimate resolution of these matters could have a material effect on Xcel Energy’s financial position and results of operations.
Environmental Litigation
State of Connecticut vs. Xcel Energy Inc. et al. — In July 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 the following utilities, including Xcel Energy, to force reductions in CO2 emissions: American Electric Power Co., Southern Co., Cinergy Corp. (merged into Duke Energy Corporation) and Tennessee Valley Authority. The lawsuits alleged that CO2 emitted by each company is a public nuisance and asked the court to order each utility to cap and reduce its CO2 emissions. The lawsuits did not demand monetary damages. In December 2011, the U.S. District Court entered an order dismissing this lawsuit, bringing a close to this litigation.
Native Village of Kivalina vs. Xcel Energy Inc. et al. — In February 2008, the City and Native Village of Kivalina, Alaska, filed a lawsuit in U.S. District Court for the Northern District of California against Xcel Energy and 23 other utility, oil, gas and coal companies. Plaintiffs claim that defendants’ emission of CO2 and other GHGs contribute to global warming, which is harming their village. Xcel Energy believes the claims asserted in this lawsuit are without merit and joined with other utility defendants in filing a motion to dismiss in June 2008. In October 2009, the U.S. District Court dismissed the lawsuit on constitutional grounds. In November 2009, plaintiffs filed a notice of appeal to the U.S. Court of Appeals for the Ninth Circuit. In November 2011, oral arguments were presented. It is unknown when the Ninth Circuit will render a final opinion. The amount of damages claimed by plaintiffs is unknown, but likely includes the cost of relocating the village of Kivalina. Plaintiffs’ alleged relocation is estimated to cost between $95 million to $400 million. While Xcel Energy believes the likelihood of loss is remote, given the nature of this case and any surrounding uncertainty, it may have a material impact on Xcel Energy’s consolidated results of operations, cash flows or financial position. No accrual has been recorded for this matter.
Comer vs. Xcel Energy Inc. et al. — On May 27, 2011, less than a year after their initial lawsuit was dismissed, plaintiffs in this purported class action lawsuit filed a second lawsuit against more than 85 utility, oil, chemical and coal companies in U.S. District Court in Mississippi. The complaint alleges defendants’ CO2 emissions intensified the strength of Hurricane Katrina and increased the damage plaintiffs purportedly sustained to their property. Plaintiffs base their claims on public and private nuisance, trespass and negligence. Among the defendants named in the complaint are Xcel Energy Inc., SPS, PSCo, NSP-Wisconsin and NSP-Minnesota. The amount of damages claimed by plaintiffs is unknown. The defendants, including Xcel Energy Inc., believe this lawsuit is without merit and have filed a motion to dismiss the lawsuit. It is uncertain when the court will rule on this motion. While Xcel Energy believes the likelihood of loss is remote, given the nature of this case and any surrounding uncertainty, it may have a material impact on Xcel Energy’s consolidated results of operations, cash flows or financial position. No accrual has been recorded for this matter.
Employment, Tort and Commercial Litigation
Stone & Webster, Inc. vs. PSCo — In July 2009, Stone & Webster, Inc. (Shaw) filed a complaint against PSCo in State District Court in Denver, Colo. for damages allegedly arising out of its construction work on the Comanche Unit 3 coal-fired plant. Shaw, a contractor retained to perform certain engineering, procurement and construction work on Comanche Unit 3, alleged, among other things, that PSCo mismanaged the construction of Comanche Unit 3. Shaw further claimed that this alleged mismanagement caused delays and damages. The complaint also alleged that Xcel Energy Inc. and related entities guaranteed Shaw $10 million in future profits under the terms of a 2003 settlement agreement. In total, Shaw sought approximately $144 million in damages.
In August 2009, PSCo filed an answer and counterclaim denying the allegations in the complaint and alleging that Shaw failed to discharge its contractual obligations and caused delays, and that PSCo is entitled to liquidated damages and excess costs incurred of approximately $82 million.
Following a November 2010 jury trial and subsequent appeal, in November 2011, a confidential settlement was reached dismissing all actions. This settlement did not have a material effect on Xcel Energy’s consolidated results of operations, cash flows or financial position.
Merricourt Wind Project Litigation — On April 1, 2011, NSP-Minnesota terminated its agreements with enXco Development Corporation (enXco) for the development of a 150 MW wind project in southeastern North Dakota. NSP-Minnesota’s decision to terminate the agreements was based in large part on the adverse impact this project could have on endangered or threatened species protected by federal law and the uncertainty in cost and timing in mitigating this impact. NSP-Minnesota also terminated the agreements due to enXco’s nonperformance of certain other conditions, including failure to obtain a Certificate of Site Compatibility and the failure to close on the contracts by an agreed upon date of March 31, 2011. As a result, NSP-Minnesota recorded a $101 million deposit in the first quarter 2011, which was collected in April 2011. On May 5, 2011, NSP-Minnesota filed a declaratory judgment action in U.S. District Court in Minnesota to obtain a determination that it acted properly in terminating the agreements. On that same day, enXco also filed a separate lawsuit in the same court seeking, among other things, in excess of $240 million for an alleged breach of contract. NSP-Minnesota believes enXco’s lawsuit is without merit and has filed a motion to dismiss. On Sept. 16, 2011, the U.S. District Court denied the motion to dismiss. The trial is set to begin in late 2012 or early 2013. While Xcel Energy believes the likelihood of loss is remote, given the nature of this case and any surrounding uncertainty, it may have a material impact on Xcel Energy’s consolidated results of operations, cash flows or financial position. No accrual has been recorded for this matter.
Other Contingencies
See Note 12 for further discussion.
14. Nuclear Obligations
Fuel Disposal — NSP-Minnesota is responsible for temporarily storing used or spent nuclear fuel from its nuclear plants. The DOE is responsible for permanently storing spent fuel from NSP-Minnesota’s nuclear plants as well as from other U.S. nuclear plants. NSP-Minnesota has funded its portion of the DOE’s permanent disposal program since 1981. The fuel disposal fees are based on a charge of 0.1 cent per KWh sold to customers from nuclear generation. Fuel expense includes the DOE fuel disposal assessments of approximately $11 million in 2011, $13 million in 2010 and $12 million in 2009. In total, NSP-Minnesota had paid approximately $422.3 million to the DOE through Dec. 31, 2011. The Nuclear Waste Policy Act of 1982 required the DOE to begin accepting spent nuclear fuel no later than Jan. 31, 1998. NSP-Minnesota and other utilities have commenced lawsuits against the DOE to recover damages caused by the DOE’s failure to meet its statutory and contractual obligations. In 2011, NSP-Minnesota received from the DOE pursuant to a Settlement with the DOE, an initial payment of approximately $100 million to cover damages through the end of 2008. As of Dec. 31, 2011, NSP-Minnesota has recorded the payment as restricted cash and a regulatory liability.
NSP-Minnesota has its own temporary on-site storage facilities for spent fuel at its Monticello and Prairie Island nuclear plants, which consist of storage pools and dry cask facilities at both sites. The amount of spent fuel storage capacity currently authorized by the NRC and the MPUC will allow NSP-Minnesota to continue operation of its Prairie Island nuclear plant until the end of its renewed licenses terms in 2033 for Unit 1 and 2034 for Unit 2 and its Monticello nuclear plant until the end of its renewed operating license in 2030. Other alternatives for spent fuel storage are being investigated until a DOE facility is available, including pursuing the establishment of a private facility for interim storage of spent nuclear fuel as part of a consortium of electric utilities.
Regulatory Plant Decommissioning Recovery — Decommissioning of NSP-Minnesota’s nuclear facilities is planned for the period from cessation of operations through at least 2067, assuming the prompt dismantlement method. NSP-Minnesota is currently recording the regulatory costs for decommissioning over the MPUC-approved cost-recovery period and including the accruals in a regulatory liability account. The total decommissioning cost obligation is recorded as an ARO in accordance with the applicable accounting guidance.
Monticello received its initial operating license in 1970 and began commercial operation in 1971. With its renewed operating license and CON for spent fuel capacity to support 20 years of extended operation, Monticello can operate until 2030. The Monticello 20-year depreciation life extension until September 2030 was granted by the MPUC in 2007. Construction of the Monticello dry-cask storage facility is complete, and 10 of the 30 canisters authorized have been filled and placed in the facility.
Prairie Island Units 1 and 2 received their initial operating license and began commercial operations in 1973 and 1974. In April 2008, NSP-Minnesota filed an application with the NRC to renew the operating license of its two nuclear reactors at Prairie Island that allowed for operation for an additional 20 years until 2033 and 2034, respectively. The NRC approved Prairie Island’s license renewal application in 2011. Based on the NRC approval, a full life extension for Prairie Island’s depreciation life was approved by the MPUC in September 2011, bringing the depreciation remaining life in line with the NRC approved operating license. The Prairie Island dry-cask storage facility currently stores 29 casks, with MPUC approval for the use of 35 additional casks, to support operations until the end of the renewed operating licenses in 2033 and 2034.
The total obligation for decommissioning currently is expected to be funded 100 percent by the external decommissioning trust fund, as approved by the MPUC, when decommissioning commences. The MPUC last approved NSP-Minnesota’s nuclear decommissioning study request in October 2009, using 2008 cost data. An updated nuclear decommissioning study was submitted to the MPUC in both November and December 2011. Due to new state statute requirements, five decommissioning scenarios were presented, which each reflected a different timeline for the removal of spent nuclear fuel from the sites. A decision on this filing is expected either in late 2012 or the beginning of 2013.
Consistent with cost-recovery in utility customer rates, NSP-Minnesota previously recorded annual decommissioning accruals based on periodic site-specific cost studies and a presumed level of dedicated funding. Cost studies quantify decommissioning costs in current dollars. The most recent study, which resulted in an authorization of no funding, presumes that costs will escalate in the future at a rate of 2.89 percent per year. The total estimated decommissioning costs that will ultimately be paid, net of income earned by the external decommissioning trust fund, is currently being accrued using an annuity approach over the approved plant-recovery period. This annuity approach uses an assumed rate of return on funding, which is currently 6.3 percent, net of tax, for external funding. The net unrealized gain or loss on nuclear decommissioning investments is deferred as a regulatory asset or liability, respectively.
The external funds are held in trust and in escrow. The portion in escrow is subject to refund if approved by the various commissions. The MPUC authorized the return of funds associated with the Monticello plant for the Minnesota retail jurisdictions in 2009, with refunds made on customers’ bills in 2010. An amount of approximately $5.9 million was also withdrawn from the Monticello plant portion of the escrow fund in March 2010 in preparation for a refund to Wisconsin and Michigan retail customers. The funds have not yet been refunded as of Dec. 31, 2011, and the timing of the refunds will be determined in future rate cases in each jurisdiction.
At Dec. 31, 2011, NSP-Minnesota recorded and recovered in rates cumulative decommissioning expense of $1.3 billion. The following table summarizes the funded status of NSP-Minnesota’s decommissioning obligation based on approved regulatory recovery parameters from the most recently approved decommissioning study. Xcel Energy believes future decommissioning cost expense, if necessary, will continue to be recovered in customer rates. These amounts are not those recorded in the financial statements for the ARO.
| | | Regulatory Basis | |
| (Thousands of Dollars) | | 2011 | | | 2010 | |
| Estimated decommissioning cost obligation (2008 dollars) | | $ | 2,308,196 | | | $ | 2,308,196 | |
| Effect of escalating costs (to 2011 and 2010 dollars, respectively, at 2.89 percent per year) | | | 205,960 | | | | 135,342 | |
| Estimated decommissioning cost obligation (in current dollars) | | | 2,514,156 | | | | 2,443,538 | |
| Effect of escalating costs to payment date (2.89 percent per year) | | | 2,602,207 | | | | 2,672,825 | |
| Estimated future decommissioning costs (undiscounted) | | | 5,116,363 | | | | 5,116,363 | |
| Effect of discounting obligation (using risk-free interest rate) | | | (3,187,914 | ) | | | (3,856,516 | ) |
| Discounted decommissioning cost obligation | | | 1,928,449 | | | | 1,259,847 | |
| Assets held in external decommissioning trust | | | 1,336,431 | | | | 1,350,630 | |
| Underfunding (overfunding) of external decommissioning fund compared to the discounted decommissioning obligation | | $ | 592,018 | | | $ | (90,783 | ) |
Decommissioning expenses recognized as a result of regulation include the following components:
| (Thousands of Dollars) | | 2011 | | | 2010 | | | 2009 | |
Annual decommissioning recorded as depreciation expense: (a) | | | | | | | | | |
| Externally funded | | $ | - | | | $ | 934 | | | $ | 2,849 | |
| Internally funded (including interest costs) | | | (456 | ) | | | (777 | ) | | | (884 | ) |
| Net decommissioning expense recorded | | $ | (456 | ) | | $ | 157 | | | $ | 1,965 | |
(a) | Decommissioning expense does not include depreciation of the capitalized nuclear asset retirement costs. |
Reductions to expense for internally-funded portions in 2011, 2010 and 2009 are a direct result of the 2008 decommissioning study jurisdictional allocation and 100 percent external funding approval, effectively unwinding the remaining internal fund over the previously licensed operating life of the unit (2010 for Monticello, 2013 for Prairie Island Unit 1 and 2014 for Prairie Island Unit 2). The 2008 nuclear decommissioning filing approved in 2009 has been used for the regulatory presentation.
15. Regulatory Assets and Liabilities
Xcel Energy Inc. and subsidiaries prepare their consolidated financial statements in accordance with the applicable accounting guidance, as discussed in Note 1. Under this guidance, regulatory assets and liabilities are created for amounts that regulators may allow to be collected, or may require to be paid back to customers in future electric and natural gas rates. Any portion of Xcel Energy’s business that is not regulated cannot establish regulatory assets and liabilities. If changes in the utility industry or the business of Xcel Energy no longer allow for the application of regulatory accounting guidance under GAAP, Xcel Energy would be required to recognize the write-off of regulatory assets and liabilities in net income or OCI.
The components of regulatory assets and liabilities shown on the consolidated balance sheets at Dec. 31, 2011 and Dec. 31, 2010 are:
| | | See | | Remaining | | | | | | | | | | | | |
| (Thousands of Dollars) | | Note(s) | | Amortization Period | | Dec. 31, 2011 | | | Dec. 31, 2010 | |
| Regulatory Assets | | | | | | Current | | | Noncurrent | | | Current | | | Noncurrent | |
| | | | | | | | | | | | | | | | | |
Pension and retiree medical obligations (a) | | | 9 | | Various | | $ | 130,764 | | | $ | 1,299,399 | | | $ | 115,218 | | | $ | 1,209,879 | |
Recoverable deferred taxes on AFUDC recorded in plant (b) | | | 1 | | Plant lives | | | - | | | | 294,549 | | | | - | | | | 276,861 | |
Contract valuation adjustments (c) | | | 1, 11 | | Term of related contract | | | 73,608 | | | | 142,210 | | | | 45,155 | | | | 134,027 | |
Net AROs (d) | | | 1, 13, 14 | | Plant lives | | | - | | | | 209,626 | | | | - | | | | 150,913 | |
Conservation programs (e) | | | 1 | | One to seven years | | | 46,769 | | | | 80,981 | | | | 57,679 | | | | 74,236 | |
| Environmental remediation costs | | | 1, 13 | | Various | | | 2,309 | | | | 109,720 | | | | 3,561 | | | | 98,725 | |
Renewable resources and environmental initiatives (b) | | | 13 | | One to four years | | | 51,622 | | | | 25,378 | | | | 75,372 | | | | 20,487 | |
Depreciation differences (b) | | | 1 | | One to seven years | | | 4,150 | | | | 54,892 | | | | 5,859 | | | | 12,379 | |
| Purchased power contract costs | | | 13 | | Term of related contract | | | - | | | | 54,471 | | | | - | | | | 44,464 | |
| Losses on reacquired debt | | | 4 | | Term of related debt | | | 5,554 | | | | 43,729 | | | | 6,319 | | | | 49,001 | |
| Nuclear refueling outage costs | | | 1 | | One to two years | | | 40,365 | | | | 8,810 | | | | 33,819 | | | | 7,169 | |
| Gas pipeline inspection and remediation costs | | | 12 | | Pending rate case | | | 13,779 | | | | 27,511 | | | | 2,000 | | | | 29,358 | |
| Recoverable purchased natural gas and electric energy costs | | | 1 | | One to two years | | | 17,031 | | | | 9,867 | | | | 27,770 | | | | 9,907 | |
State commission adjustments (b) | | | 1 | | Plant lives | | | 311 | | | | 9,399 | | | | - | | | | 9,235 | |
| Other | | | | | Various | | | 15,973 | | | | 18,466 | | | | 15,789 | | | | 24,819 | |
| Total regulatory assets | | | | | | | $ | 402,235 | | | $ | 2,389,008 | | | $ | 388,541 | | | $ | 2,151,460 | |
| | | | | | | | | | | | | | | | | | | | | | |
| Regulatory Liabilities | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | |
| Plant removal costs | | | 1, 13 | | Plant lives | | $ | - | | | $ | 945,377 | | | $ | - | | | $ | 979,666 | |
| Deferred electric, gas and steam production costs | | | 1 | | Less than one year | | | 108,057 | | | | - | | | | 107,674 | | | | - | |
| DOE settlement | | | 14 | | Less than one year | | | 94,734 | | | | - | | | | - | | | | - | |
| Investment tax credit deferrals | | | 1, 6 | | Various | | | - | | | | 61,710 | | | | - | | | | 65,856 | |
| Deferred income tax adjustment | | | 1, 6 | | Various | | | - | | | | 46,835 | | | | - | | | | 42,863 | |
Conservation programs (e) | | | 1, 12 | | Less than one year | | | 15,898 | | | | - | | | | - | | | | - | |
Contract valuation adjustments (c) | | | 1, 11 | | Term of related contract | | | 25,268 | | | | 15,450 | | | | 6,684 | | | | 19,743 | |
| Gain from asset sales | | | 18 | | One to three years | | | 5,780 | | | | 18,696 | | | | 4,281 | | | | 25,492 | |
Renewable resources and environmental initiatives (b) | | | 12, 13 | | Various | | | 4,358 | | | | 8,525 | | | | 14,752 | | | | - | |
| Low income discount program | | | | | One to two years | | | 8,696 | | | | 347 | | | | 7,062 | | | | 4,032 | |
| Nuclear refueling outage costs | | | 1 | | One year | | | 3,441 | | | | - | | | | 3,441 | | | | 3,441 | |
REC margin sharing (f) | | | 1, 12 | | | | | - | | | | - | | | | - | | | | 26,104 | |
| Other | | | | | Various | | | 8,863 | | | | 4,594 | | | | 12,144 | | | | 12,568 | |
| Total regulatory liabilities | | | | | | | $ | 275,095 | | | $ | 1,101,534 | | | $ | 156,038 | | | $ | 1,179,765 | |
| (a) | Includes $365.3 million and $400.2 million for the regulatory recognition of the NSP-Minnesota pension expense at Dec. 31, 2011 and Dec. 31, 2010, respectively. These amounts are offset by $3.9 million and $7.8 million for PSCo unamortized prior service costs at Dec. 31, 2011 and Dec. 31, 2010, respectively. Also included are $27.2 million and $20.4 million of regulatory assets related to the non-qualified pension plan of which $12.1 million and $2.2 million is included in the current asset at Dec. 31, 2011 and Dec. 31, 2010, respectively. |
| (b) | Earns a return on investment in the ratemaking process. These amounts are amortized consistent with recovery in rates. |
| (c) | Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases. |
| (d) | Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments. |
| (e) | Includes over- or under-recovered costs for DSM and conservation programs as well as incentives allowed in certain jurisdictions. |
| (f) | As described in Note 12, in 2011 the CPUC determined that the customers’ share of REC margins will be netted against the RESA regulatory asset balance. This is reflected in the Dec. 31, 2011 regulatory asset balance. |
16. Segments and Related Information
The regulated electric utility operating results of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS, as well as the regulated natural gas utility operating results of NSP-Minnesota, NSP-Wisconsin and PSCo are each separately and regularly reviewed by Xcel Energy’s chief operating decision maker. Xcel Energy evaluates performance by each utility subsidiary based on profit or loss generated from the product or service provided. These segments are managed separately because the revenue streams are dependent upon regulated rate recovery, which is separately determined for each segment.
Given the similarity of the regulated electric and regulated natural gas utility operations of its utility subsidiaries, Xcel Energy has the following reportable segments: regulated electric utility, regulated natural gas utility and all other.
| | · | Xcel Energy’s regulated electric utility segment generates, transmits, and distributes electricity in Minnesota, Wisconsin, Michigan, North Dakota, South Dakota, Colorado, Texas, and New Mexico. In addition, this segment includes sales for resale and provides wholesale transmission service to various entities in the United States. Regulated electric utility also includes commodity trading operations. |
| | · | Xcel Energy’s regulated natural gas utility segment transports, stores and distributes natural gas primarily in portions of Minnesota, Wisconsin, North Dakota, Michigan and Colorado. |
| | · | Revenues from operating segments not included above are below the necessary quantitative thresholds and are therefore included in the all other category. Those primarily include steam revenue, appliance repair services, nonutility real estate activities, revenues associated with processing solid waste into refuse-derived fuel and investments in rental housing projects that qualify for low-income housing tax credits. |
Xcel Energy had equity investments in unconsolidated subsidiaries of $92.7 million and $97.6 million as of Dec. 31, 2011 and 2010, respectively, included in the regulated natural gas segment.
Asset and capital expenditure information is not provided for Xcel Energy’s reportable segments because as an integrated electric and natural gas utility, Xcel Energy operates significant assets that are not dedicated to a specific business segment, and reporting assets and capital expenditures by business segment would require arbitrary and potentially misleading allocations which may not necessarily reflect the assets that would be required for the operation of the business segments on a stand-alone basis.
To report income from continuing operations for regulated electric and regulated natural gas utility segments, the majority of costs are directly assigned to each segment. However, some costs, such as common depreciation, common O&M expenses and interest expense are allocated based on cost causation allocators. A general allocator is used for certain general and administrative expenses, including office supplies, rent, property insurance and general advertising.
The accounting policies of the segments are the same as those described in Note 1.
| | | Regulated | | | Regulated | | | All | | | Reconciling | | | Consolidated | |
| (Thousands of Dollars) | | Electric | | | Natural Gas | | | Other | | | Eliminations | | | Total | |
| 2011 | | | | | | | | | | | | | | | |
| Operating revenues from external customers | | $ | 8,766,593 | | | $ | 1,811,926 | | | $ | 76,251 | | | $ | - | | | $ | 10,654,770 | |
| Intersegment revenues | | | 1,269 | | | | 2,358 | | | | - | | | | (3,627 | ) | | | - | |
| Total revenues | | $ | 8,767,862 | | | $ | 1,814,284 | | | $ | 76,251 | | | $ | (3,627 | ) | | $ | 10,654,770 | |
| | | | | | | | | | | | | | | | | | | | | |
| Depreciation and amortization | | $ | 773,392 | | | $ | 106,870 | | | $ | 10,357 | | | $ | - | | | $ | 890,619 | |
| Interest charges and financing costs | | | 402,668 | | | | 52,115 | | | | 108,134 | | | | - | | | | 562,917 | |
| Income tax expense (benefit) | | | 473,848 | | | | 57,408 | | | | (62,940 | ) | | | - | | | | 468,316 | |
| Income (loss) from continuing operations | | | 788,967 | | | | 101,842 | | | | (49,435 | ) | | | - | | | | 841,374 | |
| | | Regulated | | | Regulated | | | All | | | Reconciling | | | Consolidated | |
| (Thousands of Dollars) | | Electric | | | Natural Gas | | | Other | | | Eliminations | | | Total | |
| 2010 | | | | | | | | | | | | | | | |
| Operating revenues from external customers | | $ | 8,451,845 | | | $ | 1,782,582 | | | $ | 76,520 | | | $ | - | | | $ | 10,310,947 | |
| Intersegment revenues | | | 1,015 | | | | 5,653 | | | | - | | | | (6,668 | ) | | | - | |
| Total revenues | | $ | 8,452,860 | | | $ | 1,788,235 | | | $ | 76,520 | | | $ | (6,668 | ) | | $ | 10,310,947 | |
| | | | | | | | | | | | | | | | | | | | | |
| Depreciation and amortization | | $ | 748,815 | | | $ | 99,220 | | | $ | 10,847 | | | $ | - | | | $ | 858,882 | |
| Interest charges and financing costs | | | 380,074 | | | | 49,314 | | | | 119,233 | | | | - | | | | 548,621 | |
| Income tax expense (benefit) | | | 434,756 | | | | 59,790 | | | | (57,911 | ) | | | - | | | | 436,635 | |
| Income (loss) from continuing operations | | | 665,155 | | | | 114,554 | | | | (27,753 | ) | | | - | | | | 751,956 | |
| | | Regulated | | | Regulated | | | All | | | Reconciling | | | Consolidated | |
| (Thousands of Dollars) | | Electric | | | Natural Gas | | | Other | | | Eliminations | | | Total | |
| 2009 | | | | | | | | | | | | | | | |
| Operating revenues from external customers | | $ | 7,704,723 | | | $ | 1,865,703 | | | $ | 73,877 | | | $ | - | | | $ | 9,644,303 | |
| Intersegment revenues | | | 816 | | | | 2,931 | | | | - | | | | (3,747 | ) | | | - | |
| Total revenues | | $ | 7,705,539 | | | $ | 1,868,634 | | | $ | 73,877 | | | $ | (3,747 | ) | | $ | 9,644,303 | |
| | | | | | | | | | | | | | | | | | | | | |
| Depreciation and amortization | | $ | 711,090 | | | $ | 95,633 | | | $ | 11,329 | | | $ | - | | | $ | 818,052 | |
| Interest charges and financing costs | | | 371,525 | | | | 44,572 | | | | 105,758 | | | | - | | | | 521,855 | |
| Income tax expense (benefit) | | | 357,128 | | | | 81,956 | | | | (67,770 | ) | | | - | | | | 371,314 | |
| Income (loss) from continuing operations | | | 611,851 | | | | 108,948 | | | | (35,275 | ) | | | - | | | | 685,524 | |
17. Summarized Quarterly Financial Data (Unaudited)
| | | Quarter Ended | |
| (Amounts in thousands, except per share data) | | March 31, 2011 | | | June 30, 2011 | | | Sept. 30, 2011 | | | Dec. 31, 2011 | |
| Operating revenues | | $ | 2,816,540 | | | $ | 2,438,222 | | | $ | 2,831,598 | | | $ | 2,568,410 | |
| Operating income | | | 426,663 | | | | 359,442 | | | | 651,496 | | | | 344,001 | |
| Income from continuing operations | | | 203,467 | | | | 158,671 | | | | 338,295 | | | | 140,941 | |
| Discontinued operations — income (loss) | | | 102 | | | | 91 | | | | 37 | | | | (432 | ) |
| Net income | | | 203,569 | | | | 158,762 | | | | 338,332 | | | | 140,509 | |
| Earnings available to common shareholders | | | 202,509 | | | | 157,702 | | | | 333,658 | | | | 140,509 | |
| Earnings per share total — basic | | $ | 0.42 | | | $ | 0.33 | | | $ | 0.69 | | | $ | 0.29 | |
| Earnings per share total — diluted | | | 0.42 | | | | 0.33 | | | | 0.69 | | | | 0.29 | |
| Cash dividends declared per common share | | | 0.25 | | | | 0.26 | | | | 0.26 | | | | 0.26 | |
| | | Quarter Ended | |
| (Amounts in thousands, except per share data) | | March 31, 2010 | | | June 30, 2010 | | | Sept. 30, 2010 | | | Dec. 31, 2010 | |
| Operating revenues | | $ | 2,807,462 | | | $ | 2,307,764 | | | $ | 2,628,787 | | | $ | 2,566,934 | |
| Operating income | | | 403,665 | | | | 325,304 | | | | 568,630 | | | | 322,370 | |
| Income from continuing operations | | | 167,340 | | | | 135,625 | | | | 312,488 | | | | 136,503 | |
| Discontinued operations — income (loss) | | | (222 | ) | | | 4,151 | | | | (182 | ) | | | 131 | |
| Net income | | | 167,118 | | | | 139,776 | | | | 312,306 | | | | 136,634 | |
| Earnings available to common shareholders | | | 166,058 | | | | 138,716 | | | | 311,246 | | | | 135,573 | |
| Earnings per share total — basic | | $ | 0.36 | | | $ | 0.30 | | | $ | 0.68 | | | $ | 0.29 | |
| Earnings per share total — diluted | | | 0.36 | | | | 0.30 | | | | 0.67 | | | | 0.29 | |
| Cash dividends declared per common share | | | 0.25 | | | | 0.25 | | | | 0.25 | | | | 0.25 | |
18. Asset Acquisition and Sale
Acquisition of Generation Assets — In December 2010, PSCo purchased Blue Spruce Energy Center and Rocky Mountain Energy Center from Calpine Development Holdings, Inc. and Riverside Energy Center LLC for $739.0 million plus an additional $3.0 million for working capital adjustments. The working capital adjustments consisted of the settlement of PSCo’s most recent purchases of energy and capacity under the terminated purchased power agreements, adjusted for accrued operating liabilities of the acquired plants of $6.5 million.
The Blue Spruce Energy Center is a 310 MW simple cycle natural gas-fired power plant that began commercial operations in 2003. The Rocky Mountain Energy Center is a 652 MW combined-cycle natural gas-fired power plant that began commercial operations in 2004. Both power plants previously provided energy and capacity to PSCo under purchased power agreements, which were set to expire in 2013 and 2014, respectively. The acquisition developed out of PSCo’s resource planning activities, in which customers’ future energy needs are addressed in a formal planning process for meeting PSCo’s generation obligations, considering various assumptions and objectives including prices, reliability, and emissions levels. The generation assets were offered to PSCo as a competitive bid in the resource planning process, and the offer was the least cost option for thermal generation resources.
The purchase price has been allocated as follows based on the estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition, including working capital adjustments of approximately $0.2 million recorded in 2011 which were identified through examination of the plants’ books and records:
| (Thousands of Dollars) | | | |
| Assets acquired | | | |
| Inventory | | $ | 3,791 | |
| Property, plant and equipment | | | 735,959 | |
| Total assets acquired | | | 739,750 | |
| | | | | |
| Liabilities assumed | | | | |
| Accrued expenses | | | 7,437 | |
| Total liabilities assumed | | | 7,437 | |
| | | | | |
| Net assets acquired | | $ | 732,313 | |
Operating results for the plants subsequent to the date of acquisition are included in the consolidated statements of income for the years ended Dec. 31, 2010 and Dec. 31, 2011.
Sale of Lubbock Electric Distribution Assets — In November 2009, SPS entered into an asset purchase agreement with the city of Lubbock, Texas. This agreement had set forth that SPS would sell its electric distribution system assets within the city limits to Lubbock Power and Light (LP&L) for approximately $87 million. The sale and related transactions eliminate the inefficiencies of maintaining duplicate distribution systems, by both SPS and by the city-owned LP&L.
SPS served about 24,000 customers within Lubbock, representing about 25 percent of the total customers in the dually certified service area. As part of this transaction, SPS will continue to provide wholesale power to meet the electric load for these customers, initially by amending the current wholesale full-requirements contract with WTMPA, which provides service to LP&L through 2019 and then for an additional 25 years under a new contract directly with LP&L when the WTMPA contract terminates. Both of these wholesale power agreements provide for formula rates that change annually based on the actual cost of service. The formula rate with WTMPA reflects an initial 10.5 percent ROE. All or portions of this transaction were reviewed and approved by the PUCT, the NMPRC and the FERC.
Additionally, SPS and the city of Lubbock entered into an amended long-term treated sewage effluent water agreement under which SPS will continue to purchase waste water from the city for cooling SPS’ Jones Station southeast of Lubbock.
In October 2010, the transaction closed resulting in a pre-tax gain of approximately $20 million that has been deferred as a regulatory liability and will be shared with retail customers in Texas over a four year period.
Item 9 — Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A — Controls and Procedures
Disclosure Controls and Procedures
Xcel Energy 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 SEC 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 Dec. 31, 2011, based on an evaluation carried out under the supervision and with the participation of Xcel Energy’s management, including the CEO and CFO, of the effectiveness of its disclosure controls and the procedures, the CEO and CFO have concluded that Xcel Energy’s disclosure controls and procedures were effective.
Internal Controls Over Financial Reporting
No change in Xcel Energy’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, Xcel Energy’s internal control over financial reporting. Xcel Energy maintains internal control over financial reporting to provide reasonable assurance regarding the reliability of the financial reporting. Xcel Energy has evaluated and documented its controls in process activities, general computer activities, and on an entity-wide level. During the year and in preparation for issuing its report for the year ended Dec. 31, 2011 on internal controls under section 404 of the Sarbanes-Oxley Act of 2002, Xcel Energy conducted testing and monitoring of its internal control over financial reporting. Based on the control evaluation, testing and remediation performed, Xcel Energy did not identify any material control weaknesses, as defined under the standards and rules issued by the Public Company Accounting Oversight Board and as approved by the SEC and as indicated in Management Report on Internal Controls herein.
None.
PART III
Item 10 — Directors, Executive Officers and Corporate Governance
Information required under this Item with respect to Directors and Corporate Governance is set forth in Xcel Energy Inc.’s Proxy Statement for its 2012 Annual Meeting of Shareholders, which is incorporated by reference. Information with respect to Executive Officers is included in Item 1 to this report.
Information required under this Item is set forth in Xcel Energy Inc.’s Proxy Statement for its 2012 Annual Meeting of Shareholders, which is incorporated by reference.
Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Information required under this Item is contained in Xcel Energy Inc.’s Proxy Statement for its 2012 Annual Meeting of Shareholders, which is incorporated by reference.
Information required under this Item is contained in Xcel Energy Inc.’s Proxy Statement for its 2012 Annual Meeting of Shareholders, which is incorporated by reference.
Item 14 — Principal Accountant Fees and Services
Information required under this Item is contained in Xcel Energy Inc.’s Proxy Statement for its 2012 Annual Meeting of Shareholders, which is incorporated by reference.
PART IV
| 1. | | Consolidated Financial Statements: |
| | | Management Report on Internal Controls Over Financial Reporting — For the year ended Dec. 31, 2011. |
| | | Report of Independent Registered Public Accounting Firm — Financial Statements |
| | | Report of Independent Registered Public Accounting Firm — Internal Controls Over Financial Reporting Consolidated Statements of Income — For the three years ended Dec. 31, 2011, 2010 and 2009. |
| | | Consolidated Statements of Cash Flows — For the three years ended Dec. 31, 2011, 2010 and 2009. |
| | | Consolidated Balance Sheets — As of Dec. 31, 2011 and 2010. |
| 2. | | Schedule I — Condensed Financial Information of Registrant. |
| | | Schedule II — Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2011, 2010 and 2009. |
| 3. | | Exhibits |
| * | Indicates incorporation by reference |
| + | Executive Compensation Arrangements and Benefit Plans Covering Executive Officers and Directors |
| t | Certain portions of this agreement have been omitted pursuant to a request for confidential treatment and have been filed separately with the SEC. |
| PSCo |
| |
| 2.01* t | | Purchase and Sale Agreement by and between Riverside Energy Center, LLC and Calpine Development Holdings, Inc., as Sellers, and PSCo, as Purchaser, dated as of April 2, 2010 (excluding certain schedules and exhibits referred to in the agreement, as amended, which the Registrant agrees to furnish supplemental to the SEC upon request) (Exhibit 2.01 to Form 10-Q for the quarter ended June 30, 2010 (file no. 001-03034)). |
| |
| Xcel Energy Inc. |
| |
| 3.01* | | Amended and Restated Articles of Incorporation of Xcel Energy Inc., as filed on May 20, 2011 (Exhibit 3.01 to Form 8-K of Xcel Energy file number 001-03034, dated May 18, 2011). |
| 3.02* | | Restated By-Laws of Xcel Energy Inc. (Exhibit 3.01 to Form 8-K dated Aug. 12, 2008 (file no. 001-03034)). |
| | | |
| Xcel Energy Inc. |
| | | |
| 4.01* | | Indenture dated Dec. 1, 2000, between Xcel Energy Inc. and Wells Fargo Bank, Minnesota, National Association (NA), as Trustee. (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated Dec. 18, 2000). |
| 4.02* | | Supplemental Indenture No. 3 dated June 1, 2006 between Xcel Energy Inc. and Wells Fargo Bank, Minnesota, NA, as Trustee, creating $300 million principal amount of 6.5 percent Senior Notes, Series due 2036 (Exhibit 4.01 to Current Report on Form 8-K (file no. 001-03034) dated June 6, 2006). |
| 4.03* | | Supplemental Indenture No. 4 dated March 30, 2007 between Xcel Energy Inc. and Wells Fargo Bank, Minnesota, NA, as Trustee, creating $253.979 million aggregate principal amount of 5.613 percent Senior Notes, Series due 2017 (Exhibit 4.1 to Form 8-K (file no. 001-03034) dated March 30, 2007). |
| 4.04* | | Junior Subordinated Indenture, dated as of Jan. 1, 2008, by and between Xcel Energy Inc. and Wells Fargo Bank, Minnesota, NA, as Trustee (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated Jan. 16, 2008). |
| 4.05* | | Supplemental Indenture No. 1, dated Jan. 16, 2008, by and between Xcel Energy Inc. and Wells Fargo Bank, Minnesota, NA, as Trustee, creating $400 million principal amount of 7.6 percent Junior Subordinated Notes, Series due 2068 (Exhibit 4.02 to Form 8-K (file no. 001-03034) dated Jan. 16, 2008). |
| 4.06* | | Replacement Capital Covenant, dated Jan. 16, 2008 (Exhibit 4.03 to Form 8-K (file no. 001-03034) dated Jan. 16, 2008). |
| 4.07* | | Supplemental Indenture No. 5 dated as of May 1, 2010 between Xcel Energy Inc. and Wells Fargo Bank, NA, as Trustee, creating $550 million principal amount of 4.70 percent Senior Notes, Series due May 15, 2020 (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated May 13, 2010). |
| 4.08* | | Supplemental Indenture No. 6 dated as of Sept. 1, 2011 between Xcel Energy Inc. and Wells Fargo Bank, National Association (NA), as Trustee, creating $250 million principal amount of 4.80 percent Senior Notes, Series due 2041. (Exhibit 4.01 to Form 8-K dated Sept. 12, 2011 (file no. 001-03034)). |
| NSP-Minnesota |
| |
| 4.09* | | Supplemental and Restated Trust Indenture, dated May 1, 1988, from NSP-Minnesota to Harris Trust and Savings Bank, as Trustee, providing for the issuance of First Mortgage Bonds (Exhibit 4.02 to Form 10-K of NSP-Minnesota for the year 1988, file no. 001-03034). Supplemental Indentures between NSP-Minnesota and said Trustee, dated as follows: |
| | | Supplemental Indenture dated June 1, 1995, creating $250 million principal amount of 7.125 percent First Mortgage Bonds, Series due July 1, 2025 (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated June 28, 1995, Rider A). |
| | | Supplemental Indenture dated April 1, 1997, creating $100 million principal amount of 8.5 percent First Mortgage Bonds, Series due Sept. 1, 2019 and $27.9 million principal amount of 8.5 percent First Mortgage Bonds, Series due March 1, 2019 (Exhibit 4.47 to Form 10-K (file no. 001-03034) dated Dec. 31, 1997.) |
| | | Supplemental Indenture dated March 1, 1998, creating $150 million principal amount of 6.5 percent First Mortgage Bonds, Series due March 1, 2028 (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated March 11, 1998, Rider A). |
| 4.10* | | Supplemental Indenture Aug. 1, 2000 (Assignment and Assumption of Trust Indenture) (Exhibit 4.51 to NSP-Minnesota Form 10-12G (file no. 000-31709) dated Oct. 5, 2000). |
| 4.11* | | Indenture, dated July 1, 1999, between NSP-Minnesota and Norwest Bank Minnesota, NA, as Trustee, providing for the issuance of Sr. Debt Securities. (Exhibit 4.01 to NSP-Minnesota Form 8-K (file no. 001-03034) dated July 21, 1999). |
| 4.12* | | Supplemental Indenture, dated Aug. 18, 2000, supplemental to the Indenture dated July 1, 1999, among Xcel Energy, NSP-Minnesota and Wells Fargo Bank Minnesota, NA, as Trustee (Assignment and Assumption of Indenture). (Exhibit 4.63 to NSP-Minnesota Form 10-12G (file no. 000-31709) dated Oct. 5, 2000). |
| 4.13* | | Supplemental Indenture dated July 1, 2002 between NSP-Minnesota and BNY Midwest Trust Company, as successor Trustee, creating $69 million principal amount of 8.5 percent First Mortgage Bonds, Series due April 1, 2030 (Exhibit 4.06 to NSP-Minnesota Current Report on Form 10-Q, (file no. 000-31387) dated Sept. 30, 2002). |
| 4.14* | | Supplemental Trust Indenture dated Aug. 1, 2002 between NSP-Minnesota and BNY Midwest Trust Company, as successor Trustee, creating $450 million principal amount of 8.0 percent First Mortgage Bonds, Series due Aug. 28, 2012 (Exhibit 4.01 to NSP-Minnesota Current Report on Form 8-K, (file no. 000-31387) dated Aug. 22, 2002). |
| 4.15* | | Supplemental Indenture dated July 1, 2005 between NSP-Minnesota and BNY Midwest Trust Company, as successor Trustee, creating $250 million principal amount of 5.25 percent First Mortgage Bonds, Series due July 15, 2035 (Exhibit 4.01 to NSP-Minnesota Current Report on Form 8-K, (file no. 000-31387) dated July 14, 2005). |
| 4.16* | | Supplemental Indenture dated May 1, 2006 between NSP-Minnesota and BNY Midwest Trust Company, as successor Trustee, creating $400 million principal amount of 6.25 percent First Mortgage Bonds, Series due June 1, 2036 (Exhibit 4.01 to NSP-Minnesota Current Report on Form 8-K, (file no. 000-31387) dated May 18, 2006). |
| 4.17* | | Supplemental Indenture, dated June 1, 2007, between NSP-Minnesota and BNY Midwest Trust Company, as successor Trustee (Exhibit 4.01 to NSP-Minnesota Form 8-K (file no. 001-31387) dated June 19, 2007). |
| 4.18* | | Supplemental Indenture dated March 1, 2008 between NSP-Minnesota and BNY Midwest Trust Company, as successor Trustee (Exhibit 4.01 to Form 8-K (file no. 001-31387) dated March 11, 2008). |
| 4.19* | | Supplemental Indenture dated as of Nov. 1, 2009 between NSP-Minnesota and The Bank of New York Mellon Trust Co., NA, as successor Trustee, creating $300 million principal amount of 5.35 percent First Mortgage Bonds, Series due Sept. 1, 2039 (Exhibit 4.01 of Form 8-K of NSP-Minnesota dated Nov. 16, 2009 (file no. 001-31387)). |
| 4.20* | | Supplemental Indenture dated as of Aug. 1, 2010 between NSP-Minnesota and The Bank of New York Mellon Trust Company, NA, as successor Trustee, creating $250 million principal amount of 1.950 percent First Mortgage Bonds, Series due Aug. 15, 2015 and $250 million principal amount of 4.850 percent First Mortgage Bonds, Series due Aug. 15, 2040 (Exhibit 4.01 to Form 8-K dated Aug. 11, 2010 (file no. 001-31387)). |
| | | |
| NSP-Wisconsin |
| |
| 4.21* | | Supplemental and Restated Trust Indenture, dated March 1, 1991, between NSP-Wisconsin and First Wisconsin Trust company, providing for the issuance of First Mortgage Bonds (Exhibit 4.01 to Registration Statement 33-39831). |
| 4.22* | | Supplemental Trust Indenture, dated April 1, 1991 (Exhibit 4.01 to Form 10-Q (file no. 001-03140) for the quarter ended March 31, 1991). |
| 4.23* | | Supplemental Trust Indenture, dated Dec. 1, 1996. (Exhibit 4.01 to Form 8-K (file no. 001-03140) dated Dec. 12, 1996). |
| 4.24* | | Trust Indenture dated Sept. 1, 2000, between NSP-Wisconsin and Firstar Bank, NA as Trustee. (Exhibit 4.01 to Form 8-K (file no. 001-03140) dated Sept. 25, 2000). |
| 4.25* | | Supplemental Trust Indenture dated Sept. 1, 2003 between NSP-Wisconsin and US Bank NA, supplementing indentures dated April 1, 1947 and March 1, 1991 (Exhibit 4.05 to Xcel Energy Form 10-Q (file no. 001-03034) dated Nov. 13, 2003). |
| 4.26* | | Supplemental Trust Indenture dated as of Sept. 1, 2008 between NSP-Wisconsin and U.S. Bank NA, as successor Trustee, creating $200 million principal amount of 6.375 percent First Mortgage Bonds, Series due Sept. 1, 2038 (Exhibit 4.01 of Form 8-K of NSP-Wisconsin dated Sept. 3, 2008 (file no. 001-03140)). |
| | | |
| PSCo |
| |
| 4.27* | | Indenture, dated as of Oct. 1, 1993, between PSCo and Morgan Guaranty Trust Company of New York, as trustee, providing for the issuance of First Collateral Trust Bonds (Form 10-Q, Sept. 30, 1993 — Exhibit 4(a)). |
| 4.28* | | Indentures supplemental to Indenture dated as of Oct. 1, 1993, between PSCo and Morgan Guaranty Trust Company of New York, as trustee,: |
| Dated as of | | Previous Filing: Form; Date or file no. | | Exhibit No. | | Dated as of | | Previous Filing: Form; Date or file no. | | Exhibit No. |
| Nov. 1, 1993 | | S-3, (33-51167) | | 4(b)(2) | | Aug. 15, 2002 | | 10-Q, Sept. 30, 2002 (001-03280) | | 4.03 |
| Jan. 1, 1994 | | 10-K, 1993 | | 4(b)(3) | | Sept. 1, 2002 | | 8-K, Sept. 18, 2002 (001-03280) | | 4.01 |
| Sept. 2, 1994 | | 8-K, September 1994 | | 4(b) | | Sept. 15, 2002 | | 10-Q, Sept. 30, 2002 (001-03280) | | 4.04 |
| May 1, 1996 | | 10-Q, June 30, 1996 | | 4(b) | | March 1, 2003 | | S-3, April 14, 2003 (333-104504) | | 4(b)(3) |
| Nov. 1, 1996 | | 10-K, 1996 (001-03280) | | 4(b)(3) | | April 1, 2003 | | 10-Q May 15, 2003 (001-03280) | | 4.02 |
| Feb. 1, 1997 | | 10-Q, March 31, 1997 (001-03280) | | 4(a) | | May 1, 2003 | | S-4, June 11, 2003 (333-106011) | | 4.9 |
| April 1, 1998 | | 10-Q, March 31,1998 (001-03280) | | 4(b) | | Sept. 1, 2003 | | 8-K, Sept. 2, 2003 (001-03280) | | 4.02 |
| | | | | | | Sept. 15, 2003 | | Xcel 10-K, March 15, 2004 (001-03034) | | 4.100 |
| | | | | | | Aug. 1, 2005 | | PSCo 8-K, Aug. 18, 2005 (001-03280) | | 4.02 |
| 4.29* | | Indenture dated July 1, 1999, between PSCo and The Bank of New York, providing for the issuance of Senior Debt Securities and Supplemental Indenture dated July 15, 1999, between PSCo and The Bank of New York (Exhibits 4.1 and 4.2 to Form 8-K (file no. 001-03280) dated July 13, 1999). |
| 4.30* | | Financing Agreement between Adams County, Colorado and PSCo, dated as of Aug. 1, 2005 relating to $129.5 million Adams County, Colorado Pollution Control Refunding Revenue Bonds, 2005 Series A. (Exhibit 4.01 to PSCo Current Report on Form 8-K, dated Aug. 18, 2005, file number 001-3280). |
| 4.31* | | Supplemental Indenture, dated Aug. 1, 2007, between PSCo and U.S. Bank Trust NA, as successor Trustee (Exhibit 4.01 to PSCo Form 8-K (file no 001-03280) dated Aug. 14, 2007). |
| 4.32* | | Supplemental Indenture dated as of Aug. 1, 2008, between PSCo and U.S. Bank Trust NA, as successor Trustee, creating $300 million principal amount of 5.80 percent First Mortgage Bonds, Series No. 18 due 2018 and $300 million principal amount of 6.50 percent First Mortgage Bonds, Series No. 19 due 2038 (Exhibit 4.01 of Form 8-K of PSCo dated Aug. 6, 2008 (file no. 001-03280)). |
| 4.33* | | Supplemental Indenture dated as of May 1, 2009 between PSCo and U.S. Bank Trust NA, as successor Trustee, creating $400 million principal amount of 5.125 percent First Mortgage Bonds, Series No. 20 due 2019 (Exhibit 4.01 of Form 8-K of PSCo dated May 28, 2009 (file no. 001-03280)). |
| 4.34* | | Supplemental Indenture dated as of Nov. 1, 2010 between PSCo and U.S. Bank Trust NA, as successor Trustee, creating $400 million principal amount of 3.200 percent First Mortgage Bonds, Series No. 21 due 2020 (Exhibit 4.01 of Form 8-K of PSCo dated Nov. 16, 2010 (file no. 001-03280)). |
| 4.35* | | Supplemental Indenture dated as of Aug. 1, 2011 between PSCo and U.S. Bank NA, as successor Trustee, creating $250 million principal amount of 4.75 percent First Mortgage Bonds, Series No. 22 due 2041. (Exhibit 4.01 to Form 8-K dated Aug. 9, 2011 (file no. 001-03280)). |
| SPS |
| |
| 4.36* | | Indenture dated Feb. 1, 1999 between SPS and The Chase Manhattan Bank (Exhibit 99.2 to Form 8-K (file no. 001-03789) dated Feb. 25, 1999). |
| 4.37* | | First Supplemental Indenture dated March 1, 1999 between SPS and The Chase Manhattan Bank (Exhibit 99.3 to Form 8-K (file no. 001-03789) dated Feb. 25, 1999). |
| 4.38* | | Second Supplemental Indenture dated Oct. 1, 2001 between SPS and The Chase Manhattan Bank (Exhibit 4.01 to Form 8-K (file no. 001-03789) dated Oct. 23, 2001). |
| 4.39* | | Third Supplemental Indenture dated Oct. 1, 2003 to the indenture dated Feb. 1, 1999 between SPS and JPMorgan Chase Bank, as successor Trustee, creating $100 million principal amount of Series C and Series D Notes, 6 percent due 2033 (Exhibit 4.04 to Xcel Energy Form 10-Q (file no. 001-03034) dated Nov. 13, 2003). |
| 4.40* | | Fourth Supplemental Indenture dated Oct. 1, 2006 between SPS and The Bank of New York, as successor Trustee (Exhibit 4.01 to Form 8-K (file no. 001-03789) dated Oct. 3, 2006). |
| 4.41* | | Red River Authority for Texas Indenture of Trust dated July 1, 1991 (Form 10-K, Aug. 31, 1991 — Exhibit 4(b)). |
| 4.42* | | Supplemental Trust Indenture dated as of Nov. 1, 2008 between SPS and The Bank of New York Mellon Trust Company, NA, as successor Trustee, creating $250 million principal amount of Series G Senior Notes, 8.75 percent due 2018 (Exhibit 4.01 of Form 8-K of SPS, dated Nov. 14, 2008 (file no. 001- 03789)). |
| 4.43* | | Indenture dated as of Aug. 1, 2011 between SPS and U.S. Bank NA, as Trustee. (Exhibit 4.01 to Form 8-K dated Aug. 10, 2011 (file no. 001-03789)). |
| 4.44* | | Supplemental Indenture dated as of Aug. 3, 2011 between SPS and U.S. Bank NA, as Trustee, creating $200 million principal amount of 4.50 percent First Mortgage Bonds, Series No. 1 due 2041. (Exhibit 4.02 to Form 8-K dated Aug. 10, 2011 (file no. 001-03789)). |
| | | |
| Xcel Energy Inc. |
| |
| 10.01*+ | | Xcel Energy Non-Qualified Pension Plan (2009 Restatement) (Exhibit 10.02 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008). |
| 10.02*+ | | Xcel Energy Senior Executive Severance Policy (2009 Amendment and Restatement) (Exhibit 10.05 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008). |
| 10.03*+ | | Xcel Energy Non-employee Directors’ Deferred Compensation Plan as amended and restated Jan. 1, 2009 (Exhibit 10.08 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008). |
| 10.04* | | Form of Services Agreement between Xcel Energy Services Inc. and utility companies (Exhibit H-1 to Form U5B (file no. 001-03034) dated Nov. 16, 2000). |
| 10.05*+ | | Xcel Energy Supplemental Executive Retirement Plan as amended and restated Jan. 1, 2009 (Exhibit 10.17 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008). |
| 10.06*+ | | Amendment dated Aug. 26, 2009 to the Xcel Energy Senior Executive Severance and Change-in-Control Policy (Exhibit 10.06 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended Sept. 30, 2009). |
| 10.07*+ | | Xcel Energy Inc. Executive Annual Incentive Award Plan Form of Restricted Stock Agreement (Exhibit 10.08 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended Sept. 30, 2009). |
| 10.08* | | Xcel Energy Executive Annual Incentive Award Plan (as amended and restated effective Feb. 17, 2010) (incorporated by reference to Appendix A to Schedule 14A, Definitive Proxy Statement to Xcel Energy Inc. (file no. 001-03034) dated April 6, 2010). |
| 10.09*+ | | Xcel Energy 2010 Executive Annual Discretionary Award Plan (Exhibit 10.24 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2009). |
| 10.10*+ | | Xcel Energy 2005 Long-Term Incentive Plan (as amended and restated effective Feb. 17, 2010) (incorporated by reference to Appendix B to Schedule 14A, Definitive Proxy Statement to Xcel Energy Inc. (file no. 001-03034) dated April 6, 2010). |
| 10.11*+ | | Xcel Energy 2010 Executive Annual Discretionary Award Plan (as amended and restated effective Dec. 15, 2010) (Exhibit 10.23 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2010). |
| 10.12*+ | | Xcel Energy 2005 Long-Term Incentive Plan Form of Bonus Stock Agreement (Exhibit 10.24 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2010). |
| 10.13*+ | | Xcel Energy 2005 Long-Term Incentive Plan Form of Performance Share Agreement (Exhibit 10.25 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2010). |
| 10.14*+ | | Xcel Energy 2005 Long-Term Incentive Plan Form of Restricted Stock Unit Agreement (Exhibit 10.26 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2010). |
| 10.15* | | Credit Agreement, dated as of March 17, 2011 among Xcel Energy Inc., as Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A., and Barclays Capital, the investment banking division of Barclays Bank Plc, as Syndication Agents, and Wells Fargo Bank, National Association, as Documentation Agent (Exhibit 99.01 to Form 8-K of Xcel Energy, file number 001-03034, dated March 23, 2011). |
| 10.16*+ | | Stock Equivalent Plan for Non-Employee Directors of Xcel Energy as amended and restated effective Feb. 23, 2011 (Appendix A to the Xcel Energy Definitive Proxy Statement (file no. 001-03034) filed April 5, 2011). |
| | Xcel Energy Inc. Nonqualified Deferred Compensation Plan (2009 Restatement) (as amended and restated effective Nov. 29, 2011). |
| | Second Amendment dated Oct. 26, 2011 to the Xcel Energy Senior Executive Severance and Change-in-Control Policy. |
| NSP-Minnesota |
| | | |
| 10.19* | | Ownership and Operating Agreement, dated March 11, 1982, between NSP-Minnesota, Southern Minnesota Municipal Power Agency and United Minnesota Municipal Power Agency concerning Sherburne County Generating Unit No. 3 (Exhibit 10.01 to Form 10-Q for the quarter ended Sept. 30, 1994, file no. 001-03034). |
| 10.20* | | Restated Interchange Agreement dated Jan. 16, 2001 between NSP-Wisconsin and NSP-Minnesota (Exhibit 10.01 to NSP-Wisconsin Form S-4 (file no. 333-112033) dated Jan. 21, 2004). |
| | | |
| 10.21* | | Credit Agreement, dated as of March 17, 2011 among NSP-Minnesota, as Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A., and Barclays Capital, the investment banking division of Barclays Bank Plc, as Syndication Agents, and Wells Fargo Bank, National Association, as Documentation Agent (Exhibit 99.02 to Form 8-K of Xcel Energy, file number 001-03034, dated March 23, 2011). |
| |
| NSP-Wisconsin |
| | | |
| 10.22* | | Restated Interchange Agreement dated Jan. 16, 2001 between NSP- Wisconsin and NSP-Minnesota (Exhibit 10.01 to Form S-4 (file no. 333-112033) dated Jan. 21, 2004). |
10.23* | | Credit Agreement, dated as of March 17, 2011 among NSP-Wisconsin, as Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A., and Barclays Capital, the investment banking division of Barclays Bank Plc, as Syndication Agents, and Wells Fargo Bank, National Association, as Documentation Agent (Exhibit 99.03 to Form 8-K of Xcel Energy, file number 001-03034, dated March 23, 2011). |
| | | |
| PSCo | | |
| | | |
| 10.24* | | Amended and Restated Coal Supply Agreement entered into Oct. 1, 1984 but made effective as of Jan. 1, 1976 between PSCo and Amax Inc. on behalf of its division, Amax Coal Co. (Form 10-K (file no. 001-03280) Dec. 31, 1984 — Exhibit 10I (1)). |
| 10.25* | | First Amendment to Amended and Restated Coal Supply Agreement entered into May 27, 1988 but made effective Jan. 1, 1988 between PSCo and Amax Coal Co. (Form 10-K (file no. 001-03280) Dec. 31, 1988 — Exhibit 10I (2)). |
| 10.26* | | Proposed Settlement Agreement excerpts, as filed with the CPUC (Exhibit 99.02 to Form 8-K (file no. 001-03034) dated Dec. 3, 2004). |
| 10.27* | | Settlement Agreement among PSCo and Concerned Environmental and Community Parties, dated Dec. 3, 2004 (Exhibit 99.03 to Form 8-K (file no. 001-03034) dated Dec. 3, 2004). |
| 10.28* | | Credit Agreement, dated as of March 17, 2011 among PSCo as Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A., and Barclays Capital, the investment banking division of Barclays Bank Plc, as Syndication Agents, and Wells Fargo Bank, National Association, as Documentation Agent (Exhibit 99.04 to Form 8-K of Xcel Energy, file number 001-03034, dated March 23, 2011). |
| | | |
| SPS | | |
| | | |
| 10.29* | | Coal Supply Agreement (Harrington Station) between SPS and TUCO, dated May 1, 1979 (Form 8-K (file no. 001-03789), May 14, 1979 — Exhibit 3). |
| 10.30* | | Master Coal Service Agreement between Swindell-Dressler Energy Supply Co. and TUCO, dated July 1, 1978 (Form 8-K, (file no. 001-03789) May 14, 1979 — Exhibit 5(A)). |
| 10.31* | | Guaranty of Master Coal Service Agreement between Swindell-Dressler Energy Supply Co. and TUCO (Form 8-K, (file no. 3789) May 14, 1979 — Exhibit 5(B)). |
| 10.32* | | Coal Supply Agreement (Tolk Station) between SPS and TUCO dated April 30, 1979, as amended Nov. 1, 1979 and Dec. 30, 1981 (Form 10-Q, (file no. 3789) Feb. 28, 1982 — Exhibit 10(b)). |
| 10.33* | | Master Coal Service Agreement between Wheelabrator Coal Services Co. and TUCO dated Dec. 30, 1981, as amended Nov. 1, 1979 and Dec. 30, 1981 (Form 10-Q, (file no. 3789) Feb. 28, 1982 — Exhibit 10I). |
| 10.34* | | Power Purchase Agreement dated May 23, 1997 between Borger Energy Associates, L.P, and SPS. |
| 10.35* | | Credit Agreement, dated as of March 17, 2011 among SPS, as Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A., and Barclays Capital, the investment banking division of Barclays Bank Plc, as Syndication Agents, and Wells Fargo Bank, National Association, as Documentation Agent (Exhibit 99.05 to Form 8-K of Xcel Energy, file number 001-03034, dated March 23, 2011). |
| Xcel Energy Inc. |
| |
| | Statement of Computation of Ratio of Earnings to Fixed Charges. |
| | Subsidiaries of Xcel Energy Inc. |
| | Consent of Independent Registered Public Accounting Firm. |
| | Written Consent Resolution of the Board of Directors of Xcel Energy Inc., adopting Power of Attorney. |
| | Principal Executive Officer’s certification pursuant to 18 U.S. C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
| | Principal Financial Officer’s certification pursuant to 18 U.S. C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
| | Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
| | Statement pursuant to Private Securities Litigation Reform Act of 1995. |
| 101 | | The following materials from Xcel Energy Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, 2011 are formatted in XBRL (eXtensible Business Reporting Language): (i) the Consolidated Statements of Income, (ii) the Consolidated Statements of Cash Flows, (iii) the Consolidated Balance Sheets, (iv) the Consolidated Statements of Common Stockholders’ Equity and Comprehensive Income, (v) Consolidated Statements of Capitalization, (vi) Notes to Consolidated Financial Statements, and (vii) document and entity information. |
SCHEDULE I
XCEL ENERGY INC.
CONDENSED STATEMENTS OF INCOME
(amounts in thousands, except per share data)
| | | Year Ended Dec. 31 | |
| | | 2011 | | | 2010 | | | 2009 | |
| Income | | | | | | | | | |
| Equity earnings of subsidiaries | | $ | 904,315 | | | $ | 818,212 | | | $ | 743,798 | |
| Total income | | | 904,315 | | | | 818,212 | | | | 743,798 | |
| | | | | | | | | | | | | |
| Expenses and other deductions | | | | | | | | | | | | |
| Operating expenses | | | 14,513 | | | | 11,849 | | | | 9,116 | |
| Other income | | | (760 | ) | | | (681 | ) | | | (1,295 | ) |
| Interest charges and financing costs | | | 104,297 | | | | 112,510 | | | | 101,118 | |
| Total expenses and other deductions | | | 118,050 | | | | 123,678 | | | | 108,939 | |
| | | | | | | | | | | | | |
| Income from continuing operations before income taxes | | | 786,265 | | | | 694,534 | | | | 634,859 | |
| Income tax benefit | | | (55,109 | ) | | | (57,422 | ) | | | (50,665 | ) |
| Income from continuing operations | | | 841,374 | | | | 751,956 | | | | 685,524 | |
| Income (loss) from discontinued operations, net of tax | | | (202 | ) | | | 3,878 | | | | (4,637 | ) |
| Net income | | | 841,172 | | | | 755,834 | | | | 680,887 | |
| Dividend requirements on preferred stock | | | 3,534 | | | | 4,241 | | | | 4,241 | |
| Premium on redemption of preferred stock | | | 3,260 | | | | - | | | | - | |
| Earnings available to common shareholders | | $ | 834,378 | | | $ | 751,593 | | | $ | 676,646 | |
| | | | | | | | | | | | | |
| Weighted average common shares outstanding: | | | | | | | | | | | | |
| Basic | | | 485,039 | | | | 462,052 | | | | 456,433 | |
| Diluted | | | 485,615 | | | | 463,391 | | | | 457,139 | |
| | | | | | | | | | | | | |
| Earnings per average common share — basic: | | | | | | | | | | | | |
| Income from continuing operations | | $ | 1.72 | | | $ | 1.62 | | | $ | 1.49 | |
| Income (loss) from discontinued operations | | | - | | | | 0.01 | | | | (0.01 | ) |
| Earnings per share | | $ | 1.72 | | | $ | 1.63 | | | $ | 1.48 | |
| | | | | | | | | | | | | |
| Earnings per average common share — diluted: | | | | | | | | | | | | |
| Income from continuing operations | | $ | 1.72 | | | $ | 1.61 | | | $ | 1.49 | |
| Income (loss) from discontinued operations | | | - | | | | 0.01 | | | | (0.01 | ) |
| Earnings per share | | $ | 1.72 | | | $ | 1.62 | | | $ | 1.48 | |
| | | | | | | | | | | | | |
| Cash dividends declared per common share | | $ | 1.03 | | | $ | 1.00 | | | $ | 0.97 | |
XCEL ENERGY INC.
CONDENSED STATEMENTS OF CASH FLOWS
(amounts in thousands)
| | | Year Ended Dec. 31 | |
| | | 2011 | | | 2010 | | | 2009 | |
| Operating activities | | | | | | | | | |
| Net cash provided by operating activities | | $ | 595,732 | | | $ | 537,840 | | | $ | 627,013 | |
| | | | | | | | | | | | | |
| Investing activities | | | | | | | | | | | | |
| Capital contributions to subsidiaries | | | (287,495 | ) | | | (523,369 | ) | | | (297,004 | ) |
| Net cash used in investing activities | | | (287,495 | ) | | | (523,369 | ) | | | (297,004 | ) |
| | | | | | | | | | �� | | | |
| Financing activities | | | | | | | | | | | | |
| Proceeds from (repayment of) short-term borrowings, net | | | (21,000 | ) | | | (216,000 | ) | | | 13,750 | |
| Proceeds from issuance of long-term debt | | | 246,877 | | | | 543,923 | | | | - | |
| Repayment of long-term debt | | | - | | | | (358,636 | ) | | | - | |
| Proceeds from issuance of common stock | | | 38,691 | | | | 457,258 | | | | 20,133 | |
| Redemption of preferred stock | | | (104,980 | ) | | | - | | | | - | |
| Dividends paid | | | (474,760 | ) | | | (432,110 | ) | | | (414,922 | ) |
| Net cash used in financing activities | | | (315,172 | ) | | | (5,565 | ) | | | (381,039 | ) |
| | | | | | | | | | | | | |
| Net change in cash and cash equivalents | | | (6,935 | ) | | | 8,906 | | | | (51,030 | ) |
| Cash and cash equivalents at beginning of period | | | 9,654 | | | | 748 | | | | 51,778 | |
| Cash and cash equivalents at end of period | | $ | 2,719 | | | $ | 9,654 | | | $ | 748 | |
XCEL ENERGY INC.
CONDENSED BALANCE SHEETS
(amounts in thousands)
| | | Dec. 31 | |
| | | 2011 | | | 2010 | |
| Assets | | | | | | |
| Cash and cash equivalents | | $ | 2,719 | | | $ | 9,654 | |
| Accounts receivable from subsidiaries | | | 271,895 | | | | 266,323 | |
| Other current assets | | | 28,399 | | | | 35,276 | |
| Total current assets | | | 303,013 | | | | 311,253 | |
| | | | | | | | | |
| Investment in subsidiaries | | | 10,089,116 | | | | 9,559,780 | |
| Other assets | | | 154,353 | | | | 134,157 | |
| Total other assets | | | 10,243,469 | | | | 9,693,937 | |
| Total assets | | $ | 10,546,482 | | | $ | 10,005,190 | |
| | | | | | | | | |
| Liabilities and Equity | | | | | | | | |
| Dividends payable | | $ | 126,487 | | | $ | 122,847 | |
| Short-term debt | | | 127,000 | | | | 148,000 | |
| Other current liabilities | | | 36,000 | | | | 24,453 | |
| Total current liabilities | | | 289,487 | | | | 295,300 | |
| | | | | | | | | |
| Other liabilities | | | 31,616 | | | | 29,192 | |
| Total other liabilities | | | 31,616 | | | | 29,192 | |
| | | | | | | | | |
| Commitments and contingencies | | | | | | | | |
| Capitalization | | | | | | | | |
| Long-term debt | | | 1,743,181 | | | | 1,492,199 | |
| Preferred stockholders' equity | | | - | | | | 104,980 | |
| Common stockholders' equity | | | 8,482,198 | | | | 8,083,519 | |
| Total capitalization | | | 10,225,379 | | | | 9,680,698 | |
| Total liabilities and equity | | $ | 10,546,482 | | | $ | 10,005,190 | |
NOTES TO CONDENSED FINANCIAL STATEMENTS
Incorporated by reference are Xcel Energy’s consolidated statements of common stockholders’ equity and OCI in Part II, Item 8.
Basis of Presentation — The condensed financial information of Xcel Energy Inc. is presented to comply with Rule 12-04 of Regulation S-X. Xcel Energy Inc.’s investments in subsidiaries are presented under the equity method of accounting. Under this method, the assets and liabilities of subsidiaries are not consolidated. The investments in net assets of the subsidiaries are recorded in the balance sheets. The income from operations of the subsidiaries is reported on a net basis as equity in income of subsidiaries.
Related Party Transactions — Xcel Energy Inc. presents its related party receivables net of payables. Accounts receivable and payable with affiliates at Dec. 31 were:
| | | 2011 | | | 2010 | |
| | | Accounts | | | Accounts | | | Accounts | | | Accounts | |
| (Thousands of Dollars) | | Receivable | | | Payable | | | Receivable | | | Payable | |
| NSP-Minnesota | | $ | 58,321 | | | $ | - | | | $ | 81,447 | | | $ | - | |
| NSP-Wisconsin | | | 8,620 | | | | - | | | | 12,510 | | | | - | |
| PSCo | | | 83,263 | | | | - | | | | 66,828 | | | | (11,532 | ) |
| SPS | | | 17,440 | | | | - | | | | 24,769 | | | | - | |
| Xcel Energy Services Inc. | | | 52,994 | | | | (1,690 | ) | | | 35,311 | | | | (997 | ) |
| Xcel Energy Ventures Inc. | | | 37,700 | | | | - | | | | 41,692 | | | | - | |
| Other subsidiaries of Xcel Energy Inc. | | | 20,574 | | | | (5,327 | ) | | | 20,076 | | | | (3,784 | ) |
| | | $ | 278,912 | | | $ | (7,017 | ) | | $ | 282,633 | | | $ | (16,313 | ) |
Dividends — Cash dividends paid to Xcel Energy Inc. by its subsidiaries were $626 million, $663 million, and $647 million for the years ended Dec. 31, 2011, 2010 and 2009, respectively.
See Xcel Energy’s notes to the consolidated financial statements in Part II, Item 8 for other disclosures.
SCHEDULE II
XCEL ENERGY INC. AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS
YEARS ENDED DEC. 31, 2011, 2010 AND 2009
(amounts in thousands)
| | | | | | Additions | | | | | | | |
| | | Balance at Jan. 1 | | | Charged to Costs and Expenses | | | Charged to Other Accounts (a) | | | Deductions from Reserves (b) (c) | | | Balance at Dec. 31 | |
| Allowance for bad debts: | | | | | | | | | | | | | | | |
| 2011 | | $ | 54,563 | | | $ | 44,521 | | | $ | 15,636 | | | $ | 56,155 | | | $ | 58,565 | |
| 2010 | | | 56,103 | | | | 44,068 | | | | 15,202 | | | | 60,810 | | | | 54,563 | |
| 2009 | | | 64,239 | | | | 49,023 | | | | 21,869 | | | | 79,028 | | | | 56,103 | |
| | | | | | | | | | | | | | | | | | | | | |
| NOL and tax credit valuation allowances: | | | | | | | | | | | | | | | | | | | | |
| 2011 | | $ | 1,927 | | | $ | 4,379 | | | $ | - | | | $ | 623 | | | $ | 5,683 | |
| 2010 | | | 9,324 | | | | 240 | | | | - | | | | 7,637 | | | | 1,927 | |
| 2009 | | | 2,044 | | | | 7,280 | | | | - | | | | - | | | | 9,324 | |
| (a) | Recovery of amounts previously written off as related to allowance for bad debts. |
| (b) | Principally bad debts written off or transferred as related to allowance for bad debts. |
| (c) | Reductions to valuation allowances for NOL and tax credit carryforwards primarily due to changes in tax laws and expirations of certain carryforwards. |
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this annual report to be signed on its behalf by the undersigned thereunto duly authorized.
| | | XCEL ENERGY INC. |
| | | |
| Feb. 24, 2012 | By: | /s/ TERESA S. MADDEN |
| | | Teresa S. Madden Senior Vice President and Chief Financial Officer (Principal Financial Officer) |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities on the date indicated above.
| | /s/ BENJAMIN G.S. FOWKE III | Chairman, President, Chief Executive Officer and Director |
| | Benjamin G.S. Fowke III | (Principal Executive Officer) |
| | | |
| | /s/ TERESA S. MADDEN | Senior Vice President and Chief Financial Officer |
| | Teresa S. Madden | (Principal Financial Officer) |
| | | |
| | /s/ JEFFREY S. SAVAGE | Vice President and Controller |
| | Jeffrey S. Savage | (Principal Accounting Officer) |
| | | |
| * | | Director |
| | Fredric W. Corrigan | |
| | | |
| * | | Director |
| | Richard K. Davis | |
| | | |
| * | | Director |
| | Albert F. Moreno | |
| | | |
| * | | Director |
| | Christopher J. Policinski | |
| | | |
| * | | Director |
| | A. Patricia Sampson | |
| | | |
| * | | Director |
| | James J. Sheppard | |
| | | |
| * | | Director |
| | David A. Westerlund | |
| | | |
| * | | Director |
| | Kim Williams | |
| | | |
| * | | Director |
| | Timothy V. Wolf | |
| | | |
| * | /s/ TERESA S. MADDEN | Attorney-in-Fact |
| | Teresa S. Madden | |
162
