|• XCEL ENERGY INC 10-Q 6-30-2012 • EXHIBIT 31.01 • EXHIBIT 31.02 • EXHIBIT 32.01 • EXHIBIT 99.01 • INSTANCE DOCUMENT • XBRL TAXONOMY EXTENSION SCHEMA DOCUMENT • XBRL TAXONOMY EXTENSION CALCULATION LINKBASE DOCUMENT • XBRL TAXONOMY EXTENSION DEFINITION LINKBASE DOCUMENT • XBRL TAXONOMY EXTENSION LABEL LINKBASE DOCUMENT • XBRL TAXONOMY EXTENSION PRESENTATION LINKBASE DOCUMENT|
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
For the quarterly period ended June 30, 2012
Commission File Number: 001-3034
Xcel Energy Inc.
(Exact name of registrant as specified in its charter)
(Registrant’s telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. xYes oNo
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 and Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). xYes oNo
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). oYes xNo
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.
This Form 10-Q is filed by Xcel Energy Inc. Xcel Energy Inc. wholly owns the following subsidiaries: Northern States Power Company, a Minnesota corporation (NSP-Minnesota); Northern States Power Company, a Wisconsin corporation (NSP-Wisconsin); Public Service Company of Colorado (PSCo); and Southwestern Public Service Company (SPS). Xcel Energy Inc. and its consolidated subsidiaries are also referred to herein as Xcel Energy. NSP-Minnesota, NSP-Wisconsin, PSCo and SPS are also referred to collectively as utility subsidiaries. Additional information on the wholly owned subsidiaries is available on various filings with the Securities and Exchange Commission (SEC).
XCEL ENERGY INC. AND SUBSIDIARIES
(amounts in thousands, except per share data)
See Notes to Consolidated Financial Statements
XCEL ENERGY INC. AND SUBSIDIARIES
(amounts in thousands)
See Notes to Consolidated Financial Statements
XCEL ENERGY INC. AND SUBSIDIARIES
(amounts in thousands)
See Notes to Consolidated Financial Statements
XCEL ENERGY INC. AND SUBSIDIARIES
(amounts in thousands, except share and per share data)
See Notes to Consolidated Financial Statements
XCEL ENERGY INC. AND SUBSIDIARIES
(amounts in thousands)
See Notes to Consolidated Financial Statements
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY (UNAUDITED)
(amounts in thousands)
See Notes to Consolidated Financial Statements
XCEL ENERGY INC. AND SUBSIDIARIES
In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly, in accordance with accounting principles generally accepted in the United States of America (GAAP), the financial position of Xcel Energy Inc. and its subsidiaries as of June 30, 2012 and Dec. 31, 2011; the results of its operations, including the components of net income and comprehensive income, and changes in stockholders’ equity for the three and six months ended June 30, 2012 and 2011; and its cash flows for the six months ended June 30, 2012 and 2011. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after June 30, 2012 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation. The Dec. 31, 2011 balance sheet information has been derived from the audited 2011 consolidated financial statements included in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 2011. These notes to the consolidated financial statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP on an annual basis have been condensed or omitted pursuant to such rules and regulations. For further information, refer to the consolidated financial statements and notes thereto, included in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 2011, filed with the SEC on Feb. 24, 2012. Due to the seasonality of Xcel Energy’s electric and natural gas sales, interim results are not necessarily an appropriate base from which to project annual results.
The significant accounting policies set forth in Note 1 to the consolidated financial statements in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 2011, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.
Fair Value Measurement — In May 2011, the Financial Accounting Standards Board (FASB) issued Fair Value Measurement (Topic 820) — Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (Accounting Standards Update (ASU) No. 2011-04), which provides 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 requirements were effective for interim and annual periods beginning after Dec. 15, 2011. Xcel Energy implemented the accounting and disclosure guidance effective Jan. 1, 2012, and the implementation did not have a material impact on its consolidated financial statements. For required fair value measurement disclosures, see Note 8.
Comprehensive Income — In June 2011, the FASB issued Comprehensive Income (Topic 220) — Presentation of Comprehensive Income (ASU No. 2011-05), which requires the presentation of the components of net income, the components of other comprehensive income (OCI) and total comprehensive income in either a single continuous financial statement of comprehensive income or in two separate, but consecutive financial 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 requirements were effective for interim and annual periods beginning after Dec. 15, 2011. Xcel Energy implemented the financial statement presentation guidance effective Jan. 1, 2012.
Balance Sheet Offsetting — In December 2011, the FASB issued Balance Sheet (Topic 210) — Disclosures about Offsetting Assets and Liabilities (ASU No. 2011-11), which requires 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 disclosure requirements 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 annual reporting periods. Xcel Energy does not expect the implementation of this disclosure guidance to have a material impact on its consolidated financial statements.
Except to the extent noted below, the circumstances set forth in Note 6 to the consolidated financial statements included in Xcel Energy Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, 2011 appropriately represent, in all material respects, the current status of other income tax matters, and are incorporated herein by reference.
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. As of June 30, 2012, there was no federal income tax audit in progress.
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 June 30, 2012, Xcel Energy’s earliest open tax years that are subject to examination by state taxing authorities in its major operating jurisdictions were as follows:
As of June 30, 2012, 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 effective tax rate (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 benefits is as follows:
The unrecognized tax benefit amounts were reduced by the tax benefits associated with net operating loss (NOL) and tax credit carryforwards. The amounts of tax benefits associated with NOL and tax credit carryforwards are as follows:
It is reasonably possible that Xcel Energy’s amount of unrecognized tax benefits could significantly change in the next 12 months as the Internal Revenue Service and state audits resume. At this time, due to the uncertain nature of the audit process, an overall range of possible change cannot be reasonably estimated.
The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. The payables for interest related to unrecognized tax benefits at June 30, 2012 and Dec. 31, 2011 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of June 30, 2012 or Dec. 31, 2011.
Federal Tax Loss Carryback Claims — Xcel Energy completed an analysis in the first quarter of 2012 on the eligibility of certain expenses that qualified for an extended carryback beyond the typical two-year carryback period. As a result of a higher tax rate in prior years, Xcel Energy recognized a discrete tax benefit of approximately $15 million in the first quarter of 2012.
Except to the extent noted below, the circumstances set forth in Note 12 to the consolidated financial statements included in Xcel Energy Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, 2011 appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.
Recently Concluded Regulatory Proceedings — Minnesota Public Utilities Commission (MPUC)
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, a requested return on equity (ROE) of 11.25 percent, an electric rate base of $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 August 2011, NSP-Minnesota submitted supplemental testimony, revising its requested rate increase to approximately $122 million for 2011 and an additional increase of approximately $29 million in 2012.
In November 2011, NSP-Minnesota reached a settlement agreement with certain customer intervenors. In February 2012, NSP-Minnesota filed to reduce the interim rate request to $72.8 million to align with the settlement agreement. In March 2012, the MPUC approved the settlement. In May 2012, the MPUC issued an order approving the following:
As of June 30, 2012 and Dec. 31, 2011, NSP-Minnesota recorded a provision for revenue subject to refund of approximately $80 million and $67 million, respectively.
NSP-Minnesota – Minnesota Property Tax Deferral Request — In December 2011, NSP-Minnesota filed a request to defer incremental 2012 property taxes that would not be recovered in base rates, estimated to be approximately $24 million, or alternatively that a property tax rider be approved. In June 2012, the MPUC denied NSP-Minnesota’s request for deferred accounting for incremental property taxes and also denied the request for a property tax rider. There were no incremental 2012 property taxes deferred as a regulatory asset.
Recently Concluded Regulatory Proceedings — North Dakota Public Service Commission (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, and a step increase of $4.2 million, or 2.6 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 $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.
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. In February 2012, the NDPSC approved the settlement agreement, which provided for 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 2012 sales coming in below forecast revenue projections, the settlement includes a true-up to 2012 non-fuel revenues plus the settlement rate increase. NSP-Minnesota implemented final rates in May 2012 and issued refunds in June 2012.
Pending and Recently Concluded Regulatory Proceedings — South Dakota Public Utilities Commission (SDPUC)
NSP-Minnesota – South Dakota 2011 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 was 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. On Jan. 2, 2012, interim rates of $12.7 million were implemented. In June 2012, the SDPUC authorized a rate increase of approximately $8.0 million, based on an ROE of 9.25 percent, and an equity ratio of 53 percent. On July 17, 2012, the SDPUC approved implementation of final rates on Aug. 1, 2012, with refunds to be issued in September 2012.
NSP-Minnesota – South Dakota 2012 Electric Rate Case — On June 29, 2012, NSP-Minnesota filed a request with the SDPUC to increase South Dakota electric rates by $19.4 million annually. The request was based on a 2011 historic test year adjusted for certain known and measurable changes for 2012 and 2013, a requested ROE of 10.65 percent, an average rate base of $367.5 million and an equity ratio of 52.89 percent. A SDPUC decision is expected in late 2012 or early 2013.
Pending Regulatory Proceedings — Public Service Commission of Wisconsin (PSCW)
NSP-Wisconsin 2012 Electric and Gas Rate Case — On June 1, 2012, NSP-Wisconsin filed a request with the PSCW to increase rates for electric and natural gas service effective Jan. 1, 2013. NSP-Wisconsin requested an overall increase in annual electric rates of $39.1 million, or 6.7 percent, and an increase in natural gas rates of $5.3 million, or 4.9 percent.
The electric rate filing was based on a 2013 forecast test year, a return on equity of 10.40 percent, an equity ratio of 52.50 percent and an average 2013 electric rate base of approximately $788.6 million. The natural gas rate request was solely due to a proposal to recover the initial costs associated with the environmental cleanup of a site in Ashland, Wis., which includes the site of a former manufactured gas plant (MGP) that was owned by a predecessor company to NSP-Wisconsin.
A PSCW decision is anticipated in the fourth quarter of 2012.
Recently Concluded Regulatory Proceedings — CPUC
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, an electric rate base of $5.4 billion and an equity ratio of 56 percent.
On April 26, 2012, the CPUC approved a comprehensive multi-year settlement agreement, which covers 2012 through 2014. Key terms of the agreement include the following:
Pending and Recently Concluded Regulatory Proceedings — Federal Energy Regulatory Commission (FERC)
PSCo 2011 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. In September 2011, PSCo implemented an interim rate increase of $7.8 million, subject to refund.
In April 2012, PSCo filed an unopposed settlement agreement with wholesale customers for an annual rate increase of $7.8 million. The primary reasons for the decrease from the original request were a reduction to depreciation expense of $5.8 million and a lower ROE, ranging from 10.1 percent to 10.4 percent. The settlement was approved by the FERC in June 2012.
PSCo Transmission Formula Rate Cases — In April 2012, PSCo filed with the FERC to revise the wholesale transmission rates formula from a historic test year formula rate to a forecast transmission formula rate and to establish formula ancillary services rates. PSCo proposed that the formula rates be updated annually to reflect changes in costs, subject to a true-up. The request would increase PSCo’s wholesale transmission and ancillary services revenue by approximately $2.0 million. In June 2012, the FERC issued an order accepting the proposed transmission and ancillary services formula rates, suspending the increase to Nov. 17, 2012, subject to refund, and setting the case for settlement judge or hearing procedures.
Separately, several wholesale customers filed a complaint with the FERC in June 2012 seeking to have the transmission formula rate ROE reduced from 10.25 to 9.15 percent effective July 1, 2012. It is expected that the FERC will consider both matters concurrently.
SPS Wholesale Rate Complaint — In April 2012, Golden Spread Electric Cooperative, Inc. (Golden Spread) filed a rate complaint with the FERC alleging that SPS’ rates for wholesale service were excessive. Golden Spread alleges that the base ROE currently charged to them through their production formula rate, of 10.25 percent, and the transmission formula rate, of 10.77 percent, is unjust and unreasonable. Golden Spread alleges that the appropriate base ROE is 9.15 percent, or an annual difference of approximately $3.3 million. An additional 50 basis point incentive is added to the base ROE for the transmission formula rate for participation in a Regional Transmission Organization (RTO). Golden Spread is not contesting this transmission incentive. The FERC has taken no action on this complaint.
Electric, Purchased Gas and Resource Adjustment Clauses
Renewable Energy Credit (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 renewable energy standard adjustment (RESA) regulatory asset balance. In the second quarter of 2011, PSCo credited approximately $37 million against the RESA regulatory asset balance.
In March 2012, the CPUC approved an annual 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. The CPUC authorized PSCo to return to customers unspent carbon offset funds by crediting the RESA regulatory asset balance. In March 2012, PSCo credited approximately $28.7 million against the RESA regulatory asset balance.
This sharing mechanism will be effective through 2014 to provide the CPUC an opportunity to review the framework and to review evidence regarding actual deliveries in relatively more complex markets such as California.
Except to the extent noted below and in Note 5, the circumstances set forth in Notes 12, 13 and 14 to the consolidated financial statements included in Xcel Energy Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, 2011, appropriately represent, in all material respects, the current status of commitments and contingent liabilities, including those regarding public liability for claims resulting from any nuclear incident, and are incorporated herein by reference. The following include commitments, contingencies and unresolved contingencies that are material to Xcel Energy’s financial position.
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 utility 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 had approximately 3,773 megawatts (MW) of capacity under long-term purchased power agreements as of June 30, 2012 and Dec. 31, 2011 with entities that have been determined to be variable interest entities. 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. These agreements have expiration dates through the year 2033.
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 June 30, 2012 and Dec. 31, 2011, Xcel Energy Inc. and its subsidiaries have no assets held as collateral related to their guarantees, bond indemnities and indemnification agreements.
The following table presents guarantees and bond indemnities issued and outstanding for Xcel Energy Inc.:
In connection with the acquisition of the 201 MW Nobles wind project in 2011, 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, at June 30, 2012 and Dec. 31, 2011. The indemnification obligation expires in March 2013. NSP-Minnesota has not recorded a liability related to this indemnity at June 30, 2012 or Dec. 31, 2011.
In connection with the acquisition of 900 MW of natural gas-fired generation from subsidiaries of Calpine Development Holdings Inc. in 2010, 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 at June 30, 2012 or Dec. 31, 2011.
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.
Ashland MGP Site — NSP-Wisconsin has been named a potentially responsible party (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 U.S. Environmental Protection Agency (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 remediation at the site. The special notice letters requested that those PRPs participate in negotiations with the EPA regarding how the PRPs intended to conduct or pay for the remediation. As a result of those settlement negations, the EPA agreed to segment the Ashland site into separate areas. The first area (Phase I Project Area) includes soil and groundwater in Kreher Park and the Upper Bluff. The second area includes the Sediments.
In June 2012, a settlement in principle (Settlement) was reached among the EPA, the Wisconsin Department of Natural Resources (WDNR), the Bad River and Red Cliff Bands of the Lake Superior Tribe of Chippewa Indians and NSP-Wisconsin which, if it becomes effective, would resolve claims against NSP-Wisconsin for its alleged responsibility for the remediation of the Phase I Project Area. Under the terms of the proposed Settlement, NSP-Wisconsin agrees to perform the remediation of the Phase I Project Area, but does not admit any liability with respect to the Ashland site. The proposed Settlement reflects a cost estimate for the clean up of the Phase I Project Area of $40 million. The proposed Settlement also would resolve claims by the federal, state and tribal trustees against NSP-Wisconsin for alleged natural resource damages at the Ashland site, including both the Phase I Project Area and the Sediments. As part of the proposed Settlement, NSP-Wisconsin would convey approximately 1,390 acres of land to the State of Wisconsin and tribes so that they may manage and preserve the natural resource benefits associated with those properties.
Once the proposed Settlement is executed by all parties, a consent decree reflecting this settlement will be lodged with the U.S. District Court for the Western District of Wisconsin, pending solicitation of public notice and comment. Following a 30-day public comment period, if no material adverse comments are received, the U.S. District Court would be expected to enter the consent decree as a final order, at which time it and the terms of the Settlement will become effective. While it is expected that the consent decree will be signed, there are no assurances that the consent decree will be fully executed by all parties and ultimately entered as a final order.
Negotiations between the EPA and NSP-Wisconsin regarding who will pay or perform the cleanup of the Sediments are ongoing. The EPA’s ROD for the Ashland site estimates that the cost of the preferred remediation related to the Sediments is between $63.3 million and $77.1 million, with a potential deviation in such estimated costs of up to 50 percent higher to 30 percent lower.
At each of June 30, 2012 and Dec. 31, 2011, NSP-Wisconsin had recorded a liability of $104.3 million for the Ashland site based upon potential remediation and design costs together with estimated outside legal and consultant costs; of which $26.6 million 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 for the Sediments, which party implements the cleanup, the timing of when the cleanup is implemented, the contributions, if any, by other PRPs and whether federal or state funding may be directed to help offset remediation costs at the Ashland site.
NSP-Wisconsin has deferred, as a regulatory asset, the estimated site remediation costs 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 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. Pursuant to the PSCW decision, NSP-Wisconsin proposed an alternative long-term plan to recover costs related to the Ashland site in the rate case application filed on June 1, 2012. As compared to the current cost recovery policy, NSP-Wisconsin’s alternative proposal mitigates the rate impact to natural gas customers and allows for partial recovery of carrying costs.
NSP-Wisconsin expects a decision on the alternative cost recovery plan by the end of 2012.
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 eight 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 $4.0 million and $3.9 million at June 30, 2012 and Dec. 31, 2011, 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.
Greenhouse Gas (GHG) New Source Performance Standard Proposal (NSPS) and Emission Guideline for Existing Sources — In April 2012, the EPA proposed a GHG NSPS for newly constructed power plants. The proposal requires that carbon dioxide (CO2) emission rates be equal to those achieved by a natural gas combined-cycle plant, even if the plant is coal-fired. The EPA also proposed that NSPS not apply to modified or reconstructed existing power plants and noted that, pursuant to its general NSPS regulations, installation of control equipment on existing plants would not constitute a “modification” to those plants under the NSPS program. Xcel Energy submitted comments on the proposed GHG NSPS in June 2012. It is not possible to evaluate the impact of this regulation until its final requirements are known.
The EPA also plans to propose GHG regulations applicable to emissions from existing power plants under the Clean Air Act (CAA). It is not known when the EPA will propose new standards for existing sources.
New Mexico GHG Regulations — In 2010, the New Mexico Environmental Improvement Board (EIB) adopted two regulations to limit GHG emissions, including CO2 emissions from power plants and other industrial sources. In July 2011, SPS and other parties filed a petition to repeal each GHG rule with the EIB. The EIB repealed both regulations in the first quarter of 2012.
Western Resource Advocates and New Energy Economy, Inc. have since filed appeals with the New Mexico Court of Appeals to challenge each of the EIB’s decisions to repeal the two GHG rules. SPS has been granted intervention in one of the appeals and filed a petition to intervene in the other appeal, which has not yet been acted upon by the New Mexico Court of Appeals.
In late 2010 and early 2011, SPS, other utilities and industry groups filed separate appeals with the New Mexico Court of Appeals challenging the validity of the adoption of these two GHG regulations. These appeals were stayed pending the EIB’s consideration of the petitions for repeal of both rules. In July 2012, the New Mexico Court of Appeals conditionally dismissed both appeals without prejudice. These appeals are subject to reinstatement if the New Mexico Court of Appeals reverses the EIB’s repeal of either rule and if the originally adopted rule is revived.
Cross-State Air Pollution Rule (CSAPR) — In July 2011, the EPA issued its CSAPR to address long range transport of particulate matter (PM) and ozone by requiring reductions in sulfur dioxide (SO2) and nitrogen oxide (NOx) from utilities located in the eastern half of the United States. For Xcel Energy, the rule applies to Minnesota, Wisconsin and Texas. The CSAPR sets more stringent requirements than the proposed Clean Air Transport Rule and specifically requires plants in Texas to reduce their SO2 and annual NOx emissions. The rule also creates an emissions trading program.
On Dec. 30, 2011, the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit) issued a stay of the CSAPR, pending completion of judicial review. Oral arguments in the case were held in April 2012 and it is anticipated the D.C. Circuit will rule on the challenges to the CSAPR during the summer of 2012. It is not known at this time whether the CSAPR will be upheld, reversed or will require modifications pursuant to a future D.C. Circuit 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 five 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. In April 2012, SPS appealed to the D.C. Circuit on a final rule that the EPA issued that made changes to certain allowance allocations under the CSAPR. While this rule increases the allowance allocations for SO2 for SPS, it did not increase them by as much as the proposed rule. SPS is seeking additional allowance allocations through this appeal, which, if successful, would reduce SPS’ costs to comply with the CSAPR. The D.C. Circuit held this appeal in abeyance until it issues its decision.
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 Sherco Units 1 and 2, which is estimated to cost a total of $10 million through 2014, and system operating changes to Black Dog and Sherco Units 1 and 2. Costs for the Sherco Units 1 and 2 SO2 control technology are discussed below in the regional haze rules as SO2 reductions are part of the compliance plan for both the CSAPR and the regional haze rules. 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 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. In April 2012, NSP-Minnesota appealed to the D.C. Circuit on a final rule that the EPA issued that made changes to certain allowance allocations under the CSAPR, seeking to secure additional allocations for its Riverside and High Bridge plants. If successful, additional allowances would reduce NSP-Minnesota’s costs to comply with the CSAPR. The D.C. Circuit held this appeal in abeyance until it issues its decision.
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.
Electric Generating Unit (EGU) Mercury and Air Toxics Standards (MATS) Rule — The final EGU MATS rule became effective April 2012. The EGU MATS rule sets emission limits for acid gases, mercury and other hazardous air pollutants and requires coal-fired utility facilities greater than 25 MW to demonstrate compliance within three to four years of the effective date. Xcel Energy believes these costs will be recoverable through regulatory mechanisms and does not expect a material impact on results of operations, financial position or cash flows.
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 best available retrofit technology (BART), for industrial facilities emitting air pollutants that reduce visibility in certain national parks and wilderness areas throughout the United States. Xcel Energy generating facilities in several states are subject to BART requirements. Individual states were required to identify the facilities located in their states that will have to reduce SO2, NOx and PM emissions under BART and then set emissions limits for those facilities.
In 2006, the Colorado Air Quality Control Commission (CAQCC) 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 CAQCC approved a revised regional haze BART state implementation plan (SIP) incorporating the Colorado CACJA emission reduction plan, which will satisfy regional haze requirements. In March 2012, the EPA proposed to approve the Colorado SIP, including the CACJA emission reduction plan for PSCo, as satisfying BART requirements. The emission controls are expected to be installed between late 2012 and 2017. PSCo expects the cost of any required capital investment will be recoverable from customers through the CACJA emission reduction plan recovery mechanisms or other regulatory mechanisms.
In March 2010, two environmental groups petitioned the U.S. Department of the Interior (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. The following 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.
In December 2009, the Minnesota Pollution Control Agency (MPCA) 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 Selective Catalytic Reduction (SCR) 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, regional haze 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 through regulatory recovery mechanisms.
In June 2011, the EPA provided comments to the MPCA on the SIP, stating that 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 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.
In April 2012, the MPCA approved a supplement to the 2009 regional haze SIP finding that the CSAPR meets BART for EGUs in Minnesota. The supplement also made a source-specific BART determination for Sherco Units 1 and 2 that requires installation of the combustion controls for NOx and scrubber upgrades for SO2 by January 2015. In May 2012, the EPA adopted a final rule that allows states to determine whether CSAPR compliance meets BART requirements. In June 2012, the EPA issued its final approval of the Minnesota SIP for EGUs.
In addition to the regional haze rules identified in the EPA’s visibility program, and addressed in the MPCA’s SIP discussed above, there are other visibility rules related to a program called the Reasonably Attributable Visibility Impairment (RAVI) program. 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 RAVI and, if so, whether the level of controls required by the MPCA is appropriate. The EPA plans to issue a separate notice on the issue of BART for Sherco Units 1 and 2 under the RAVI program. It is not yet known when the EPA will publish a proposal under RAVI, or what that proposal will entail. In May 2012, a notice of intent to sue was filed with the EPA by the following organizations: National Parks Conservation Association, Minnesota Center for Environmental Advocacy, Friends of the Boundary Waters Wilderness, Voyagers National Park Association, Fresh Energy and Sierra Club. The notice advised the EPA of the parties’ intent to sue the EPA in 180 days to attempt to require the EPA to determine BART for the Sherco Units 1 and 2 under the RAVI program. It is not yet known how the EPA intends to respond to this notice.
Harrington Units 1 and 2 are potentially subject to BART. Texas has developed a regional haze SIP that finds the Clean Air Interstate Rule (CAIR) equal to BART for EGUs, and as a result, no additional controls for these units beyond the CAIR compliance would be required. In May 2012, the EPA deferred its review of the Texas SIP in its final rule allowing states to find that CSAPR compliance meets BART requirements for EGUs.
Revisions to National Ambient Air Quality Standards (NAAQS) for PM — In June 2012, the EPA proposed to lower the primary (health-based) NAAQS for annual average fine PM and to retain the current daily standard for fine PM. In areas in which Xcel Energy operates power plants, current monitored air concentrations are below the range of the proposed annual primary standard. The EPA also proposed to add a secondary (welfare-based) NAAQS to improve visibility, primarily in urban areas. Xcel Energy expects the proposed visibility standard would likely be met where Xcel Energy operates power plants based on currently available information. A final rule is expected in December 2012 and the EPA is expected to designate non-compliant locations by December 2014. If such areas are identified, states would then study the sources of the nonattainment and make emission reduction plans to attain the standards. It is not possible to evaluate the impact of this regulation further until its final requirements are known.
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 consolidated financial position, results of operations, and cash flows.
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 (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 could potentially 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. — In May 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 filed a motion to dismiss the lawsuit. In March 2012, the U.S. District Court granted this motion for dismissal. In April 2012, plaintiffs appealed this decision to the U.S. Court of Appeals for the Fifth Circuit. While Xcel Energy believes the likelihood of loss is remote, given the nature of this case and any surrounding uncertainty, it could potentially 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
Merricourt Wind Project Litigation — In April 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. NSP-Minnesota recorded a $101 million deposit in the first quarter of 2011, which was collected in April 2011. In May 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 and 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 filed a motion to dismiss. In September 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 could potentially 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.
Exelon Wind (formerly John Deere Wind) Complaint — Four lawsuits and a regulatory petition have been filed arising out of a dispute concerning SPS’ payments for energy produced from the John Deere Wind Energy subsidiaries’ (JD Wind) projects.
State Lawsuit Regarding the PUCT’s May 2009 Order
The first lawsuit was filed in June 2009 in Texas State District Court against the Public Utility Commission of Texas (PUCT). In this lawsuit, JD Wind filed a petition seeking review of a May 2009 PUCT order denying JD Wind’s request for relief against SPS. In April 2011, JD Wind filed a non-suit of this case dropping the state appeal of the PUCT order.
Federal Lawsuit Regarding the PUCT’s May 2009 Order
A second lawsuit was filed in December 2009 by JD Wind against the PUCT in U.S. District Court for the Western District of Texas. This lawsuit was filed shortly after a declaratory order issued by the FERC stated that the PUCT’s May 2009 order is not consistent with the FERC’s regulations. In this lawsuit, JD Wind seeks declaratory and injunctive relief against the PUCT. The U.S. District Court issued an order preventing this lawsuit from proceeding pending the outcome of the Texas State District Court proceeding against the PUCT. As a result of the non-suit of the Texas State District Court proceeding, this case has moved forward. In March and June 2012, the U.S. District Court heard oral arguments on motions and cross motions for summary judgment, and took the motions under advisement. If the U.S. District Court does not grant one of these dispositive motions, the case will proceed with a trial date in October 2013 at the earliest.
State Lawsuit Regarding Disputed Energy Payments
In January 2010, a third lawsuit was filed by JD Wind against SPS in Texas State District Court related to payments made by SPS for energy produced from the JD Wind projects. On April 12, 2012, the Texas State District Court heard oral arguments on SPS’ motion to dismiss and took the motion under advisement. As the damages sought are indeterminate and given the uncertainty surrounding the circumstances of this case, Xcel Energy is unable to estimate the range or amount of possible damages. No accrual has been recorded for this lawsuit nor is it expected that this proceeding will have a material effect on Xcel Energy’s consolidated results of operations, cash flows or financial position.
Petition Regarding the PUCT’s Approval of SPS’ Revised Qualifying Facilities Tariff
In November 2010, JD Wind filed a petition in Texas State District Court seeking review of the PUCT’s approval of SPS’ revised tariff applicable to purchases of non-firm energy from qualifying facilities. The PUCT has denied all allegations contained in this petition. A hearing is scheduled for Sept. 6, 2012. On June 29, 2012, Exelon Wind filed a complaint with the FERC against the PUCT raising essentially the same alleged violations of federal law as those presented in the petition filed in November 2010. On July 30, 2012, the PUCT filed an answer to this complaint defending its order and SPS filed an intervention and protest in support of the PUCT’s order.
State Lawsuit Regarding Wind Facility Registration with Southwest Power Pool (SPP)
On April 3, 2012, SPS filed a lawsuit against Exelon Wind in Texas State District Court to enforce Exelon Wind’s contractual obligation to register its wind facilities with SPP effective April 1, 2012. SPS is not seeking monetary damages in this lawsuit. Instead, SPS intends to withhold certain payments to Exelon Wind pending the outcome of this lawsuit. On May 7, 2012, Exelon Wind filed a counter-claim seeking recovery of the payments withheld by SPS. A procedural schedule has not yet been established. For the period April 1, 2012 to June 20, 2012, Xcel Energy has accrued approximately $2 million, which is subject to adjustments as the amount, if any, owed to Exelon Wind will be a litigated issue in this lawsuit. This lawsuit is not expected to have a material effect on Xcel Energy’s consolidated results of operations, cash flows or financial position.
Registration Agreement Filed by SPP with the FERC
On June 21, 2012, the FERC conditionally accepted SPP’s filing of an unsigned Market Participation Agreement between SPP and Exelon covering Exelon’s wind facilities.
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:
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. The lines of credit provide short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.
At June 30, 2012, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available:
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 June 30, 2012 and Dec. 31, 2011.
Amended Credit Agreements — In July 2012, NSP-Minnesota, NSP-Wisconsin, PSCo, SPS and Xcel Energy Inc. entered into amended five-year credit agreements with a syndicate of banks, replacing their previous four-year credit agreements. The amended credit agreements have substantially the same terms and conditions as the prior credit agreements with an improvement in pricing and an extension of maturity from March 2015 to July 2017. The Eurodollar borrowing margins on these lines of credit were reduced from a range of 100 to 200 basis points per year, to a range of 87.5 to 175 basis points per year based on applicable long-term credit ratings. The commitment fees, calculated on the unused portion of the lines of credit, were reduced from a range of 10 to 35 basis points per year, to a range of 7.5 to 27.5 basis points per year, also based on applicable long-term credit ratings.
Xcel Energy Inc. and its utility subsidiaries, other than NSP-Wisconsin, have the right to request an extension of the revolving termination date for two additional one-year periods, and NSP-Wisconsin has the right to request an extension of the revolving termination date for an additional one-year period, each subject to majority bank group approval.
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 June 30, 2012 and Dec. 31, 2011, there were $11.7 million and $12.7 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 June 30, 2012 and Dec. 31, 2011, respectively. The contract amounts of these letters of credit approximate their fair value and are subject to fees determined in the marketplace.
In June 2012, SPS issued an additional $100 million of its 4.5 percent first mortgage bonds due Aug. 15, 2041 at a premium of $10.1 million. Including the $200 million of this series previously issued in August 2011, total principal outstanding for this series is $300 million.
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 hierarchical 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 with proper notice. 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. Based on Xcel Energy’s evaluation of its ability to redeem 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 — Fair values for debt securities are determined by a third party pricing service using recent trades and observable spreads from benchmark interest rates for similar securities, except for asset-backed and mortgage-backed securities, for which the third party service may also consider additional, more subjective inputs. Since the impact of the use of these less observable inputs can be significant to the valuation of asset-backed and mortgage-backed securities, fair value measurements for these instruments have been assigned a Level 3. Inputs that may be considered in the valuation of asset-backed and mortgage-backed securities in conjunction with pricing of similar securities in active markets include the use of risk-based discounting and estimated prepayments in a discounted cash flow model. When these additional inputs and models are utilized, increases in the risk-adjusted discount rates and decreases in the assumed principal prepayment rates each have the impact of reducing reported fair values for these instruments.
Interest rate derivatives — The fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts.
Commodity derivatives — The methods used to measure the fair value of commodity derivative forwards and options utilize forward prices and volatilities, as well as pricing adjustments for specific delivery locations, and are generally assigned a Level 2. When contractual settlements extend to periods beyond those readily observable on active exchanges or quoted by brokers, the significance of the use of less observable forecasts of long-term forward prices and volatilities on a valuation is evaluated, and may result in Level 3 classification.
Electric commodity derivatives held by NSP-Minnesota include financial transmission rights (FTRs) purchased from Midwest Independent Transmission System Operator, Inc. (MISO). FTRs purchased from MISO are financial instruments that entitle the holder to one year of monthly revenues or charges based on transmission congestion across a given transmission path. The value of an FTR is derived from, and designed to offset, the cost of that energy congestion, which is caused by overall transmission load and other transmission constraints. Congestion is also influenced by the operating schedules of power plants and the consumption of electricity pertinent to a given transmission path. Unplanned plant outages, scheduled plant maintenance, changes in the relative costs of fuels used in generation, weather and overall changes in demand for electricity can each impact the operating schedules of the power plants on the transmission grid and the value of an FTR. NSP-Minnesota’s valuation process for FTRs utilizes complex iterative modeling to predict the impacts of forecasted changes in these drivers of transmission system congestion on the historical pricing of FTR purchases.
If forecasted costs of electric transmission congestion increase or decrease for a given FTR path, the value of that particular FTR instrument will likewise increase or decrease. Given the limited observability of management’s forecasts for several of the inputs to this complex valuation model – including expected plant operating schedules and retail and wholesale demand, fair value measurements for FTRs have been assigned a Level 3. Monthly FTR settlements are included in the fuel clause adjustment, and therefore changes in the fair value of the yet to be settled portions of FTRs are deferred as a regulatory asset or liability. Given this regulatory treatment and the limited magnitude of NSP-Minnesota’s FTRs relative to its electric utility operations, the numerous unobservable quantitative inputs to the complex model used for valuation of FTRs are insignificant to the consolidated financial statements of Xcel Energy.
Xcel Energy continuously monitors the creditworthiness of the counterparties to its interest rate derivatives and commodity derivatives, 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 derivative liabilities, the impact of considering credit risk was immaterial to the fair value of interest rate derivatives and commodity derivatives presented in the consolidated balance sheets.
Non-Derivative Instruments Fair Value Measurements
The Nuclear Regulatory Commission (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 $109.8 million and $79.8 million at June 30, 2012 and Dec. 31, 2011, respectively, and unrealized losses and amounts recorded as other-than-temporary impairments were $76.6 million and $87.5 million at June 30, 2012 and Dec. 31, 2011, 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 June 30, 2012 and Dec. 31, 2011:
The following tables present the changes in Level 3 nuclear decommissioning fund investments for the three and six months ended June 30, 2012 and 2011: