UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
| ý | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 2013
or
| o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Commission file number 001-31387
NORTHERN STATES POWER COMPANY
(Exact name of registrant as specified in its charter)
| Minnesota | 41-1967505 | |
| (State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |
414 Nicollet Mall, Minneapolis, Minnesota 55401
(Address of principal executive offices)
Registrant’s telephone number, including area code: 612-330-5500
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. ý Yes o No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. o Yes ý No
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. ý Yes o No
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). ý Yes o No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulations S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ý
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.
Large accelerated filer o | Accelerated filer o | |
Non-accelerated filer x | Smaller Reporting Company o | |
| (Do not check if a smaller reporting company) | ||
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). o Yes ý No
As of Feb. 24, 2014, 1,000,000 shares of common stock, par value $0.01 per share, were outstanding, all of which were held by Xcel Energy Inc., a Minnesota corporation.
DOCUMENTS INCORPORATED BY REFERENCE
Xcel Energy Inc.’s Definitive Proxy Statement for its 2014 Annual Meeting of Shareholders is incorporated by reference into Part III of this Form 10-K.
Northern States Power Company meets the conditions set forth in General Instructions I(1)(a) and (b) of Form 10-K and is therefore filing this form with the reduced disclosure format permitted by General Instruction I(2).
TABLE OF CONTENTS
Index
| PART I | |
Item 1 — Business | |
Item 1A — Risk Factors | |
Item 1B — Unresolved Staff Comments | |
Item 2 — Properties | |
Item 3 — Legal Proceedings | |
Item 4 — Mine Safety Disclosures | |
| PART II | |
Item 6 — Selected Financial Data | |
Item 9A — Controls and Procedures | |
Item 9B — Other Information | |
| PART III | |
Item 11 — Executive Compensation | |
Item 14 — Principal Accountant Fees and Services | |
| PART IV | |
Item 15 — Exhibits, Financial Statement Schedules | |
This Form 10-K is filed by NSP-Minnesota. NSP-Minnesota is a wholly owned subsidiary of Xcel Energy Inc. Additional information on Xcel Energy is available in various filings with the SEC. This report should be read in its entirety.
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PART I
Item l — Business
DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS
| Xcel Energy Inc.’s Subsidiaries and Affiliates (current and former) | |
| NMC | Nuclear Management Company, LLC |
| NSP-Minnesota | Northern States Power Company, a Minnesota corporation |
| NSP System | The electric production and transmission system of NSP-Minnesota and NSP-Wisconsin operated on an integrated basis and managed by NSP-Minnesota |
| NSP-Wisconsin | Northern States Power Company, a Wisconsin corporation |
| PSCo | Public Service Company of Colorado |
| SPS | Southwestern Public Service Company |
| Utility subsidiaries | NSP-Minnesota, NSP-Wisconsin, PSCo and SPS |
| Xcel Energy | Xcel Energy Inc. and its subsidiaries |
| Federal and State Regulatory Agencies | |
| ASLB | Atomic Safety and Licensing Board |
| CFTC | Commodity Futures Trading Commission |
| D.C. Circuit | United States Court of Appeals for the District of Columbia Circuit |
| DOC | Minnesota Department of Commerce |
| DOE | United States Department of Energy |
| DOI | United States Department of the Interior |
| DOT | United States Department of Transportation |
| EPA | United States Environmental Protection Agency |
| FERC | Federal Energy Regulatory Commission |
| IRS | Internal Revenue Service |
| MPCA | Minnesota Pollution Control Agency |
| MPSC | Michigan Public Service Commission |
| MPUC | Minnesota Public Utilities Commission |
| NDPSC | North Dakota Public Service Commission |
| NERC | North American Electric Reliability Corporation |
| NRC | Nuclear Regulatory Commission |
| PSCW | Public Service Commission of Wisconsin |
| SDPUC | South Dakota Public Utilities Commission |
| SEC | Securities and Exchange Commission |
| Electric, Purchased Gas and Resource Adjustment Clauses | |
| CIP | Conservation improvement program |
| EIR | Environmental improvement rider |
| EPU | Extended power uprate |
| FCA | Fuel clause adjustment |
| PGA | Purchased gas adjustment |
| RDF | Renewable development fund |
| RES | Renewable energy standard |
| SEP | State energy policy |
| TCR | Transmission cost recovery adjustment |
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| Other Terms and Abbreviations | |
| AFUDC | Allowance for funds used during construction |
| ALJ | Administrative law judge |
| APBO | Accumulated postretirement benefit obligation |
| ARO | Asset retirement obligation |
| ASU | FASB Accounting Standards Update |
| BART | Best available retrofit technology |
| CAA | Clean Air Act |
| CAIR | Clean Air Interstate Rule |
| CapX2020 | Alliance of electric cooperatives, municipals and investor-owned utilities in the upper Midwest involved in a joint transmission line planning and construction effort |
CO2 | Carbon dioxide |
| CON | Certificate of need |
| CPCN | Certificate of public convenience and necessity |
| CSAPR | Cross-State Air Pollution Rule |
| CWIP | Construction work in progress |
| EGU | Electric generating unit |
| ERCOT | Electric Reliability Council of Texas |
| ETR | Effective tax rate |
| FASB | Financial Accounting Standards Board |
| FTR | Financial transmission right |
| FTY | Forecast test year |
| GAAP | Generally accepted accounting principles |
| GHG | Greenhouse gas |
| JOA | Joint operating agreement |
| LCM | Life cycle management |
| LLW | Low-level radioactive waste |
| LNG | Liquefied natural gas |
| MGP | Manufactured gas plant |
| MISO | Midcontinent Independent Transmission System Operator, Inc. |
| Moody’s | Moody’s Investor Services |
| MVP | Multi-value project |
| Native load | Customer demand of retail and wholesale customers that a utility has an obligation to serve under statute or long-term contract. |
| NEI | Nuclear Energy Institute |
| NOL | Net operating loss |
| NOx | Nitrogen oxide |
| NSPS | New source performance standard |
| NYISO | New York Independent System Operator |
| O&M | Operating and maintenance |
| OCI | Other comprehensive income |
| PCB | Polychlorinated biphenyl |
| PFS | Private Fuel Storage, LLC |
| PJM | PJM Interconnection, LLC |
| PM | Particulate matter |
| PPA | Purchased power agreement |
| PRP | Potentially responsible party |
| PTC | Production tax credit |
| PV | Photovoltaic |
| REC | Renewable energy credit |
| ROE | Return on equity |
| ROFR | Right of first refusal |
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| RPS | Renewable portfolio standard |
| RSG | Revenue sufficiency guarantee |
| RTO | Regional Transmission Organization |
| SCR | Selective catalytic reduction |
| SIP | State implementation plan |
SO2 | Sulfur dioxide |
| Standard & Poor’s | Standard & Poor’s Ratings Services |
| Measurements | |
| Bcf | Billion cubic feet |
| KV | Kilovolts |
| KWh | Kilowatt hours |
| MMBtu | Million British thermal units |
| MW | Megawatts |
| MWh | Megawatt hours |
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COMPANY OVERVIEW
NSP-Minnesota was incorporated in 2000 under the laws of Minnesota. NSP-Minnesota is a utility primarily engaged in the generation, purchase, transmission, distribution and sale of electricity in Minnesota, North Dakota and South Dakota. The wholesale customers served by NSP-Minnesota comprised approximately four percent of its total KWh sold in 2013. NSP-Minnesota also purchases, transports, distributes and sells natural gas to retail customers and transports customer-owned natural gas in Minnesota and North Dakota. NSP-Minnesota provides electric utility service to approximately 1.4 million customers and natural gas utility service to approximately 0.5 million customers. Approximately 88 percent of NSP-Minnesota’s retail electric operating revenues were derived from operations in Minnesota during 2013. Although NSP-Minnesota’s large commercial and industrial electric retail customers are comprised of many diversified industries, a significant portion of NSP-Minnesota’s large commercial and industrial electric sales include the following industries: petroleum, coal and food products. For small commercial and industrial customers, significant electric retail sales include the following industries: real estate and educational services. Generally, NSP-Minnesota’s earnings contribute approximately 35 percent to 45 percent of Xcel Energy’s consolidated net income.
The electric production and transmission costs of the entire NSP System are shared by NSP-Minnesota and NSP-Wisconsin. A FERC-approved Interchange Agreement between the two companies provides for the sharing of all generation and transmission costs of the NSP System.
NSP-Minnesota owns the following direct subsidiaries: United Power and Land Company, which holds real estate; and NSP Nuclear Corporation, which owns NMC, an inactive company.
NSP-Minnesota conducts its utility business in the following reportable segments: regulated electric utility, regulated natural gas utility and all other. See Note 15 to the consolidated financial statements for further discussion relating to comparative segment revenues, net income and related financial information.
NSP-Minnesota’s corporate strategy focuses on four core objectives: driving operational excellence; providing options and solutions to customers; investing for the future; and enhancing engagement with employees, customers, shareholders, communities and policy makers. NSP-Minnesota files periodic rate cases and establishes formula rates or automatic rate adjustment mechanisms with state and federal regulators to earn a return on its investments and recover costs of operations. Environmental leadership is a core priority for NSP-Minnesota and is designed to meet customer and policy maker expectations for clean energy at a competitive price while creating shareholder value.
ELECTRIC UTILITY OPERATIONS
Public Utility Regulation
Summary of Regulatory Agencies and Areas of Jurisdiction — Retail rates, services and other aspects of NSP-Minnesota’s operations are regulated by the MPUC, the NDPSC and the SDPUC within their respective states. The MPUC also has regulatory authority over security issuances, property transfers, mergers, dispositions of assets and transactions between NSP-Minnesota and its affiliates. In addition, the MPUC reviews and approves NSP-Minnesota’s electric resource plans for meeting customers’ future energy needs. The MPUC also certifies the need for generating plants greater than 50 MW and transmission lines greater than 100 KV that will be located within the state. No large power plant or transmission line may be constructed in Minnesota except on a site or route designated by the MPUC. The NDPSC and SDPUC have regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in North Dakota and South Dakota, respectively.
NSP-Minnesota is subject to the jurisdiction of the FERC with respect to its wholesale electric operations, hydroelectric licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transfers and mergers, and natural gas transactions in interstate commerce. NSP-Minnesota has been granted continued authorization from the FERC to make wholesale electric sales at market-based prices. NSP-Minnesota is a transmission owning member of the MISO RTO.
Fuel, Purchased Energy and Conservation Cost-Recovery Mechanisms — NSP-Minnesota has several retail adjustment clauses that recover fuel, purchased energy and other resource costs:
| • | CIP — The CIP recovers the costs of programs that help customers save energy. The CIP includes a comprehensive list of programs that benefit all customers including Saver’s Switch®, energy efficiency rebates and energy audits. |
| • | EIR — The EIR recovers the costs of environmental improvement projects. |
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| • | RDF — The RDF allocates money collected from retail customers to support the research and development of emerging renewable energy projects and technologies. |
| • | RES — The RES recovers the cost of new renewable generation. |
| • | SEP — The SEP recovers costs related to various energy policies approved by the Minnesota legislature. |
| • | TCR — The TCR recovers costs associated with new investments in electric transmission. |
| • | Infrastructure — The Infrastructure rider recovers costs associated with specific investments in generation and incremental property taxes. |
The MPUC approved NSP-Minnesota’s request that the recovery of the costs associated with the EIR and RES be included in base rates in the Minnesota electric rate case in 2012. No costs are being recovered through the EIR at this time. NSP-Minnesota will continue to track PTCs associated with company-owned renewable projects and reflect the difference between the base rate amount and actual costs in the RES adjustment clause.
NSP-Minnesota’s retail electric rates in Minnesota, North Dakota and South Dakota include a FCA for monthly billing adjustments for changes in prudently incurred costs of fuel, fuel related items and purchased energy. NSP-Minnesota is permitted to recover these costs through FCA mechanisms approved by the regulators in each jurisdiction. In general, capacity costs are not recovered through the FCA. In addition, costs associated with MISO are generally recovered through either the FCA or base rates.
Minnesota state law requires NSP-Minnesota to invest two percent of its state electric revenues in CIP. NSP-Minnesota was in compliance with this standard in 2013 and expects to be in compliance in 2014. These costs are recovered through an annual cost-recovery mechanism for electric conservation and energy management program expenditures.
CIP Triennial Plan — In October 2012, the DOC approved NSP-Minnesota’s 2013 through 2015 CIP Triennial Plan, which increases the savings goals and budgets over the previous plan. The plan sets an electric goal of annually saving the equivalent of 1.5 percent of sales (calculated on a historical three-year average, excluding opt-out customers) and an annual natural gas goal of saving 1.0 percent of sales. The combined electric and gas budgets average $104.9 million per year over the 2013 through 2015 period.
Capacity and Demand
Uninterrupted system peak demand for the NSP System’s electric utility for each of the last three years and the forecast for 2014, assuming normal weather, is listed below.
| System Peak Demand (in MW) | ||||||||||||
| 2011 | 2012 | 2013 | 2014 Forecast | |||||||||
| NSP System | 9,792 | 9,475 | 9,524 | 9,212 | ||||||||
The peak demand for the NSP System typically occurs in the summer. The 2013 uninterrupted system peak demand for the NSP System occurred on Aug. 26, 2013. The 2011 peak demand occurred on a day with extremely high temperatures and humidity, which resulted in the highest uninterrupted system peak demand since July 31, 2006. The 2012 peak demand occurred uninterrupted on a day with weather much closer to normal peak day conditions. The 2013 peak demand includes the effect of warmer weather partially offset by the impact of the termination of several firm wholesale contracts primarily at NSP-Wisconsin and also reflects the impact of two large commercial and industrial customers at NSP-Minnesota that have ceased operations. These two large customers represented 1.3 percent, 0.4 percent, and zero percent of NSP System sales in 2011, 2012 and 2013 respectively. The 2014 forecast assumes normal peak day weather.
Energy Sources and Related Transmission Initiatives
The NSP System expects to use existing power plants, power purchases, CIP options, new generation facilities and expansion of existing power plants to meet its system capacity requirements.
Purchased Power — NSP-Minnesota has contracts to purchase power from other utilities and independent power producers. Long-term purchased power contracts typically require a periodic payment to secure the capacity and a charge for the associated energy actually purchased. NSP-Minnesota also makes short-term purchases to meet system load and energy requirements, to replace generation from company-owned units under maintenance or during outages, to meet operating reserve obligations, or to obtain energy at a lower cost.
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Purchased Transmission Services — In addition to using their integrated transmission system, NSP-Minnesota and NSP-Wisconsin have contracts with MISO and regional transmission service providers to deliver power and energy to the NSP System.
NSP System Resource Plans — In March 2013, the MPUC approved NSP-Minnesota’s 2011-2025 Resource Plan and ordered a competitive acquisition process be conducted with the goal of adding approximately 500 MW of generation to the NSP System by 2019. Bid proposals were received in April 2013.
In September 2013, NSP-Minnesota recommended a self-build, 215 MW natural gas combustion turbine at the Black Dog site and a PPA with either Calpine’s Mankato combined cycle natural gas project or Invenergy’s Cannon Falls combustion turbine natural gas project. In October 2013, the DOC recommended the MPUC approve NSP-Minnesota’s proposal.
On Dec. 31, 2013, the ALJ recommended the MPUC select a combination of a 100 MW solar proposal by Geronimo Energy, LLC and capacity credits offered by Great River Energy.
In January 2014, NSP-Minnesota filed exceptions to the ALJ’s report which supported NSP-Minnesota’s original proposal, reiterated its commitment to meeting the solar mandate and made the following points:
| • | The ALJ’s report focused on meeting a portion of the solar mandate even though the docket was designed to meet our resource need; |
| • | Solar acquisition to meet the solar mandate should be conducted separately to encourage competition among solar developers; |
| • | One or more gas fueled plants should be selected because they are large enough to meet the range of reasonably expected need, are least cost, and comply with environmental regulations; and |
| • | Resource need uncertainty should be addressed through contract options to delay or cancel resources. |
The MPUC is expected to make its selection determination in March 2014.
In the first half of 2013, NSP-Minnesota also issued a request for proposal for cost effective wind generation. In the summer of 2013, NSP-Minnesota filed a petition with the MPUC and the NDPSC seeking approval of four wind generation projects. The projects are as follows:
| • | A 200 MW ownership project for the Pleasant Valley wind farm in Minnesota, which is expected to be operational by October 2015; |
| • | A 150 MW ownership project for the Border Winds wind farm in North Dakota, which is expected to be operational by 2015; |
| • | A 200 MW PPA with Geronimo Energy, LLC for the Odell wind farm in Minnesota; and |
| • | A 200 MW PPA with Geronimo Energy, LLC for the Courtenay wind farm in North Dakota. |
In October 2013, the four wind projects were approved by the MPUC. A NDPSC decision is anticipated in early 2014. The feasibility of the Border Winds and Pleasant Valley projects are also dependent on the finalization of estimated transmission costs, which MISO is expected to determine in the first half of 2014.
CapX2020 — In 2009, the MPUC granted CONs to construct one 230 KV electric transmission line and three 345 KV electric transmission lines as part of the CapX2020 project. The estimated cost of the four major transmission projects is $1.9 billion. NSP-Minnesota and NSP-Wisconsin are responsible for approximately $1.1 billion of the total investment.
Hampton, Minn. to Rochester, Minn. to La Crosse, Wis. 345 KV transmission line
In May 2012, the MPUC issued a route permit for the Minnesota portion of the project and the PSCW approved a CPCN for the Wisconsin portion of the project. Federal approval of the project was granted in January 2013. All avenues of appeal for the grant of project permits have now been exhausted. In July 2013, the FERC denied a complaint filed by two citizen groups in March 2013 against the project. Construction on the project started in Minnesota in January 2013 and the project is expected to go into service in 2015.
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Monticello, Minn. to Fargo, N.D. 345 KV transmission line
In December 2011, the Monticello, Minn. to St. Cloud, Minn. portion of the Monticello, Minn. to Fargo, N.D. project was placed in service. The MPUC issued a route permit for the Minnesota portion of the St. Cloud, Minn. to Fargo, N.D. section in June 2011. Construction started on the Minnesota portion of the St. Cloud, Minn. to Fargo, N.D. segment in January 2012. The NDPSC granted a CPCN in January 2011 and a certificate of corridor compatibility and route permit for the portion of the line in North Dakota in September 2012. In January 2013, construction started on the project in North Dakota. The project is expected to go fully into service in 2015, although segments will be placed in service as they are completed.
Brookings County, S.D. to Hampton, Minn. 345 KV transmission line
The MPUC route permit approvals for the Minnesota segments were obtained in 2010 and 2011. In June 2011, the SDPUC approved a facility permit for the South Dakota segment. In December 2011, MISO granted the final approval of the project as a MVP. Construction started on the project in Minnesota in May 2012. The project is expected to go fully into service in 2015, although segments will be placed in service as they are completed.
Bemidji, Minn. to Grand Rapids, Minn. 230 KV transmission line
The Bemidji, Minn. to Grand Rapids, Minn. line was placed in service in September 2012.
Minnesota Solar Initiatives — In May 2013, Minnesota’s Governor signed into law legislation requiring that 1.5 percent of a public utility’s total electric retail sales to retail customers be generated using solar energy by 2020. Of the 1.5 percent, 10 percent must come from systems sized less than 20 kilowatts. The legislation also authorized NSP-Minnesota to offer two new solar programs: a community solar garden program that will provide bill credits to participating solar garden subscribers and a new solar energy incentive program for solar energy systems equal to or less than 20 kilowatts that authorizes the spending of $5.0 million over five years for production incentive payments. NSP-Minnesota is continuing to work toward bringing solar energy generation on line in support of these solar programs and legislative requirements. NSP-Minnesota submitted its proposal for a community solar garden program to the MPUC in September 2013. The MPUC may approve, disapprove or modify the program. NSP-Minnesota is currently developing the new solar energy incentive program. The legislation also provides for an alternative tariff based on a distributed solar value or Value of Solar methodology. As required by the legislation, the DOC developed and filed a distributed solar value methodology with the MPUC on Jan. 31, 2014. The MPUC must approve, modify with the consent of the DOC or disapprove the methodology within 60 days. Once the methodology is approved, NSP-Minnesota may elect to file a Value of Solar tariff. NSP-Minnesota provided comments to the DOC on the methodology of this Value of Solar alternative tariff on Oct. 1 and Oct. 8, 2013.
On Jan. 24, 2014, the MPUC approved $42 million in grants for renewable energy generation and research projects in Minnesota. Xcel Energy will fund the grants through its renewable development fund.
Annual Automatic Adjustment (AAA) of Charges — In June 2013, the DOC proposed that the MPUC adopt a fuel clause incentive that would normalize FCA recovery using monthly patterns derived from averages of the prior three year period, setting and fixing this level during a rate case with no adjustment between rate cases. In August 2013, NSP-Minnesota filed comments opposing the DOC’s proposal including a demonstration of the random and volatile results the DOC’s fuel clause incentive proposal would have had if it were in place during the 2008-2012 period. Other utilities filed comments expressing similar concern with the DOC’s incentive proposal, further indicating no support for modification to operation of the fuel clause. Subsequently, the DOC requested the MPUC convene a stakeholder meeting to discuss general purpose and function of the FCA program. In October 2013, the MPUC allowed the DOC an opportunity to discuss current challenges in evaluating the prudence of fuel clause costs and the DOC recommended that the MPUC consider using a three-year average of fuel costs established in base rates. The DOC continues to independently meet with a stakeholder group to explore alternative options to their proposal. The 2012 AAA docket is pending.
Additionally, the DOC has indicated it will review prudence of replacement power costs associated with the Sherco Unit 3 outage event within the 2013 AAA docket.
Minneapolis, Minn. Franchise Agreement — The franchise agreement with the City of Minneapolis expires Dec. 31, 2014. In June 2013, the Minneapolis City Council authorized (i) public hearings to be held regarding the establishment of a municipal electric and natural gas utility and (ii) a $250,000 study that will explore the various paths the City of Minneapolis could take to achieve its energy goals, including examination of potential utility partnerships, changes to how the City of Minneapolis uses energy utility franchise fees and the potential for municipalization of one or both energy utilities. In August 2013, following public hearings, the Minneapolis City Council elected not to conduct a special election to pursue forming a municipal utility. Results of the exploratory study authorized by the Minneapolis City Council are due in the first quarter of 2014.
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Nuclear Power Operations and Waste Disposal
NSP-Minnesota owns two nuclear generating plants: the Monticello plant and the Prairie Island plant. Nuclear power plant operations produce gaseous, liquid and solid radioactive wastes. The discharge and handling of such wastes are controlled by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. LLW consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment that have become contaminated through use in a plant.
NRC Regulation — The NRC regulates the nuclear operations of NSP-Minnesota. Decisions by the NRC can significantly impact the operations of the nuclear generating plants. The event at the nuclear generating plant in Fukushima, Japan in 2011 has resulted in additional regulation, which is expected to require additional capital expenditures and operating expenses. The NRC created an internal task force that developed recommendations on requirements for immediate emergency preparedness and mitigating enhancements at U.S. reactors and any changes to NRC regulations, inspection procedures and licensing processes. The task force released its recommendations in July 2011 in a written report which recommended actions to enhance U.S. nuclear generating plant readiness to safely manage severe events.
In March 2012, the NRC issued three orders which included requirements for mitigation strategies for beyond-design-basis external events, requirements with regard to reliable spent fuel instrumentation and requirements with regard to reliable hardened containment vents, which are applicable to boiling water reactor containments at the Monticello plant. The NRC also requested additional information including requirements to perform walkdowns of seismic and flood protection, to evaluate seismic and flood hazards and to assess the emergency preparedness staffing and communications capabilities at each plant. Based on current refueling outage plans specific to each nuclear facility, the dates of the required compliance to meet the orders is expected to begin in the second quarter of 2015 with all units expected to be fully compliant by December 2016.
In June 2013, the NRC issued a revised order with regard to reliable hardened containment vents. The revised order added severe accident conditions under which the existing hardened vent which comes off of the wet portion of the containment needs to operate and requires a second hardened vent off of the dry portion of the containment. The revised order requires that any necessary changes to the existing vent are to be completed by the second quarter of the 2017 refueling outage at the Monticello plant and a new vent to be added by the second quarter of the 2019 refueling outage. Portions of the work that fall under the requests for additional information are expected to be completed by 2018.
NSP-Minnesota expects that complying with these external event requirements will cost approximately $50 to $60 million at the Monticello and Prairie Island plants. The majority of these costs are expected to be capital in nature and are included in NSP-Minnesota’s capital expenditure forecasts. NSP-Minnesota believes the costs associated with compliance 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.
LLW Disposal — LLW from NSP-Minnesota’s Monticello and Prairie Island nuclear plants is currently disposed at the Clive facility located in Utah. If off-site LLW disposal facilities become unavailable, NSP-Minnesota has storage capacity available on-site at Prairie Island and Monticello that would allow both plants to continue to operate until the end of their current licensed lives.
High-Level Radioactive Waste Disposal — The federal government has the responsibility to permanently dispose of domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high-level waste management. This includes the siting, licensing, construction and operation of a repository for spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent federal storage or disposal facility.
Nuclear Geologic Repository - Yucca Mountain Project
In 2002, the U.S. Congress designated Yucca Mountain, Nevada as the first deep geologic repository. In 2008, the DOE submitted an application to construct a deep geologic repository at this site to the NRC. In 2010, the DOE announced its intention to stop the Yucca Mountain project and requested the NRC approve the withdrawal of the application. In June 2010, the ASLB issued a ruling that the DOE could not withdraw the Yucca Mountain application. In September 2011, the NRC announced that it was evenly divided on whether to take the affirmative action of overturning or upholding the ASLB decision. Because the NRC could not reach a decision, an order was issued instructing that information associated with the ASLB adjudication should be preserved. The ASLB complied and the proceeding has been suspended.
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The DOE’s decision and the resulting stoppage of the NRC’s review has prompted multiple legal challenges, including the DOE’s authority to stop the project and withdraw the application, the DOE’s authority to continue to collect the nuclear waste fund fee and the NRC’s authority to stop their review of the DOE’s application. The utility industry, including Xcel Energy Inc. and NSP-Minnesota, are represented in these challenges by the NEI.
In August 2013, the D.C. Court of Appeals ordered the NRC to complete their review of the DOE’s application to construct the Yucca Mountain repository. In November 2013, the NRC complied by issuing an order to the NRC Staff to complete and publish a safety evaluation report on the proposed Yucca Mountain nuclear spent fuel and waste repository. The NRC also requested that the DOE prepare a supplemental environmental impact statement (EIS) so the NRC Staff can complete its review.
In November 2013, the U.S. Court of Appeals ordered the DOE to suspend the collection of the nuclear waste fund fee from nuclear utilities. The order required the DOE to recommend to Congress that the nuclear waste fund fee be set to zero. In January 2014, the DOE sent its court mandated proposal to adjust the current fee to zero. The Nuclear Waste Policy Act provides that a proposal by the Secretary of Energy to adjust the fee shall be effective after a period of 90 days of continuous session unless either House of Congress adopts a resolution disapproving the Secretary’s proposed adjustment.
At the time that the DOE decided to stop the Yucca Mountain project and withdraw the application, the Secretary of Energy convened a Blue Ribbon Commission to recommend alternatives to Yucca Mountain for disposal of used nuclear fuel. In January 2012, the Blue Ribbon Commission report was issued. The report provided numerous policy recommendations that are being considered by the Secretary of Energy. In January 2013, the DOE provided its report to Congress relative to their plans to implement the Blue Ribbon Commission’s recommendations including the required legislative changes and authorizations. The report also announced the Obama Administration’s intent to make a pilot consolidated interim storage facility available in 2021, a larger consolidated interim storage facility available in 2025 and a deep geologic repository available in 2048. See Note 12 and Note 13 to the consolidated financial statements for further discussion.
Nuclear Spent Fuel Storage
NSP-Minnesota has interim on-site storage for spent nuclear fuel at its Monticello and Prairie Island nuclear generating plants. As of Dec. 31, 2013, there were 35 casks loaded and stored at the Prairie Island plant and 15 canisters loaded and stored at the Monticello plant. An additional 29 casks for Prairie Island and 15 canisters for Monticello have been authorized by the State of Minnesota. This currently authorized storage capacity is sufficient to allow NSP-Minnesota to operate until the end of the operating licenses in 2030 for Monticello, 2033 for Prairie Island Unit 1, and 2034 for Prairie Island Unit 2.
PFS — The eight partners of PFS, including NSP-Minnesota, have agreed to dissolve the LLC. PFS filed a letter with the NRC in December 2012 requesting to terminate the PFS license effective immediately. Subsequent to PFS requesting that the NRC terminate the PFS license, the NRC granted PFS a fee exemption for the 2013 license fees. Therefore, PFS has requested a 2014 fee exemption and is re-evaluating the future of the project. The efforts to dissolve the LLC are pending.
NRC Waste Confidence Decision (WCD) — In June 2012, the D.C. Circuit issued a ruling to vacate and remand the NRC’s WCD. The WCD assesses how long temporary on-site storage can remain safe and when facilities for the disposal of nuclear waste will become available. The D.C. Circuit remanded the WCD to the NRC and directed it to prepare an EIS if there are significant impacts or an environmental assessment to support a finding of no significant impact. In September 2012, the NRC directed the NRC Staff to develop a Generic Environmental Impact Statement (GEIS) and revised WCD rule on the temporary storage of spent nuclear fuel, and to issue the final GEIS and WCD rule by September 2014.
NSP-Minnesota does not believe that there will be an immediate impact on operations at the Prairie Island or Monticello nuclear generating plants.
See Notes 11 and 12 to the consolidated financial statements for further discussion regarding nuclear related items.
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Nuclear Plant Power Uprates and Life Extension
Prairie Island Independent Spent Fuel Storage Installation (ISFSI) License Renewal — The current license to operate an ISFSI at Prairie Island was scheduled to expire in October 2013. An application to renew the ISFSI license for an additional 40 years until 2053 was submitted by NSP-Minnesota to the NRC in October 2011. As Prairie Island met the NRC’s criteria for timely renewal by submitting its ISFSI license renewal application more than two years in advance of the expiration of the ISFSI’s current license, it will be allowed to continue to operate under the current license until the NRC has rendered a decision on the license renewal application. In December 2012, the ASLB found that the Prairie Island Indian Community (PIIC) had standing to intervene and admitted three of the seven contentions put forward by the PIIC. The ASLB will establish a schedule for the hearing which should be completed by mid-2014.
Monticello Nuclear Uprate Project — NSP-Minnesota has filed with the MPUC two CONs related to changes at its Monticello nuclear generating plant. The first CON is related to state approval of a 20-year extension of the plant’s operating license, which also needed approval by the NRC. The second CON is related to the expansion of output capacity at the plant by 71 MW, or 12 percent, referred to as an EPU. The MPUC approved the first life extension CON for resource planning purposes in 2008. In 2006, the NRC approved the 20-year extension of Monticello’s operating license through 2030. The MPUC approved the second CON for EPU in 2008, and the NRC approved an EPU license amendment for the plant in December 2013.
NSP-Minnesota prepared for the upgrading and replacement of equipment at the plant to support an extended license period through a capital program known as LCM. Since the EPU project design also affected equipment needs and modifications at the plant, the LCM and EPU projects were integrated from an implementation standpoint to leverage project planning and efficiency.
The plant life extension CON dealt mainly with the need for additional on-site storage of spent nuclear fuel, pending resolution of the longer-term federal issues with permanent fuel storage. The economic modeling for the life extension CON included underlying assumptions regarding future capital requirements, but the scope of the life extension CON proceeding did not specifically include discussion or request approval of capital investment for LCM work.
The EPU project CON dealt mainly with a resource planning proposal to expand output capacity at the plant and was planned to occur with the LCM project. The MPUC approval of the EPU CON authorized the resource need for additional capacity but did not include approval of a total project cost estimate. However, the modeling assumptions that combined EPU and LCM work were estimated to be $320 million in NSP-Minnesota’s internal models. Estimated capital expenditures for the EPU portion of the integrated project were discussed in the EPU CON filing, and at the time such capital expenditures were estimated at approximately $133 million based on an allocation method.
In July 2013, NSP-Minnesota completed the Monticello 20-year life extension and EPU projects. Final costs for the integrated LCM/EPU project were approximately $665 million, excluding possible reductions from the results of ongoing vendor negotiations. Of that total cost amount, NSP-Minnesota estimated that approximately $146 million related to EPU capital work and $519 million related to LCM capital work. This cost level for the EPU work completed exceeded the CON estimate by approximately 10 percent. NSP-Minnesota believes that the LCM/EPU costs, while substantially higher than the preliminary estimates assumed at the time of the EPU CON, were reasonable and prudently incurred to allow for safe and reliable operations of the plant until 2030. NSP-Minnesota asserts that had it known of the higher costs at any earlier date, it would still have made economic sense to complete the project. NSP-Minnesota also believes that even at the higher cost level, the total capital investment made to prepare the Monticello plant for another 20 years of operation provides customers with a highly reliable, cost-effective carbon free generation source.
With the approval of the NRC EPU license amendment, the Monticello plant began testing ascension to higher power levels in December 2013. A second NRC license amendment (Maximum Extended Load Line Limit Analysis Plus, or MELLLA+) is also needed to proceed to full uprate capacity, for final approval of fuel configuration and utilization under full uprate conditions. NRC approval of this complementary MELLLA+ fuel license amendment, which includes a plant safety analysis allowing for greater operational flexibility, is anticipated to be received in the first half of 2014.
The method and timing of rate recovery of the costs associated with the Monticello life extension and EPU construction projects were included as part of the 2013 electric rate case and 2014 electric rate case filed in November 2013. The project costs will be subject to a prudence review by the MPUC coincident with the 2014 electric rate case, as discussed below.
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In the 2013 Minnesota electric rate case final order, the MPUC initiated an investigation to determine whether the costs in excess of those included in the CON for NSP-Minnesota’s Monticello LCM/EPU project were prudent. In October 2013, NSP-Minnesota filed a summary report and witness testimony to further support the change in and prudence of the incurred costs. The filing indicated the increase in costs was primarily attributable to three factors; (1) the original estimate was based on a high level conceptual design and the project scope increased as the actual conditions of the plant were incorporated into the design; (2) implementation difficulties, including the amount of work that occurred in confined and radioactive or electrically sensitive spaces and NSP-Minnesota’s and its vendor’s ability to attract and retain experienced workers; and (3) additional NRC licensing related requests over the five-plus year application process. The prudence investigation is currently scheduled to conclude in the fourth quarter of 2014.
In NSP-Wisconsin’s recent rate case for 2014 rates, the PSCW ordered NSP-Wisconsin to defer cost recovery of $4.1 million, the portion of the interchange agreement amounts from NSP-Minnesota relating to the Monticello EPU project costs until the MPUC completes its prudence review.
Fuel Supply and Costs
The following table shows the delivered cost per MMBtu of each significant category of fuel consumed for owned electric generation, the percentage of total fuel requirements represented by each category of fuel and the total weighted average cost of all fuels.
Coal (a) | Nuclear | Natural Gas | Weighted Average Owned Fuel Cost | ||||||||||||||||||||||
| NSP System Generating Plants | Cost | Percent | Cost | Percent | Cost | Percent | |||||||||||||||||||
| 2013 | $ | 2.20 | 49 | % | $ | 0.95 | 40 | % | $ | 5.08 | 11 | % | $ | 2.03 | |||||||||||
| 2012 | 2.13 | 47 | 0.90 | 42 | 4.21 | 11 | 1.88 | ||||||||||||||||||
| 2011 | 2.06 | 55 | 0.89 | 40 | 6.56 | 5 | 1.82 | ||||||||||||||||||
(a) | Includes refuse-derived fuel and wood. |
See Item 1A for further discussion of fuel supply and costs.
Fuel Sources
Coal — The NSP System normally maintains approximately 41 days of coal inventory. Coal supply inventories at Dec. 31, 2013 and 2012 were approximately 34 and 39 days usage, respectively. NSP-Minnesota’s generation stations use low-sulfur western coal purchased primarily under contracts with suppliers operating in Wyoming and Montana. During 2013 and 2012, coal requirements for the NSP System’s major coal-fired generating plants were approximately 7.3 million tons and 7.2 million tons, respectively. The estimated coal requirements for 2014 are approximately 9.2 million tons. The coal requirements estimated for 2014 are higher primarily due to Sherco Unit 3 being placed back in service.
NSP-Minnesota and NSP-Wisconsin have contracted for coal supplies to provide 94 percent of their estimated coal requirements in 2014, and a declining percentage of the requirements in subsequent years. The NSP System’s general coal purchasing objective is to contract for approximately 100 percent of requirements for the following year, 67 percent of requirements in two years, and 33 percent of requirements in three years. Remaining requirements will be filled through the procurement process or over-the-counter transactions.
NSP-Minnesota and NSP-Wisconsin have a number of coal transportation contracts that provide for delivery of 100 percent of their coal requirements in 2014 and 2015. Coal delivery may be subject to short-term interruptions or reductions due to operation of the mines, transportation problems, weather and availability of equipment.
Nuclear — To operate NSP-Minnesota’s nuclear generating plants, NSP-Minnesota secures contracts for uranium concentrates, uranium conversion, uranium enrichment and fuel fabrication. The contract strategy involves a portfolio of spot purchases and medium and long-term contracts for uranium concentrates, conversion services and enrichment services with multiple producers and with a focus on diversification to minimize potential impacts caused by supply interruptions due to geographical and world political issues.
| • | Current nuclear fuel supply contracts cover 100 percent of uranium concentrates requirements through 2018 and approximately 67 percent of the requirements for 2019 through 2026. |
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| • | Current contracts for conversion services cover 100 percent of the requirements through 2021 and approximately 57 percent of the requirements for 2022 through 2026. |
| • | Current enrichment service contracts cover 100 percent of the requirements through 2024 and approximately 48 percent of the requirements for 2025 through 2026. |
Fabrication services for Monticello and Prairie Island are 100 percent committed through 2027 and 2019, respectively.
NSP-Minnesota expects sufficient uranium concentrates, conversion services and enrichment services to be available for the total fuel requirements of its nuclear generating plants. Some exposure to spot market price volatility will remain due to index-based pricing structures contained in certain supply contracts.
Natural gas — The NSP System uses both firm and interruptible natural gas supply and standby oil in combustion turbines and certain boilers. Natural gas supplies and associated transportation and storage services for power plants are procured under contracts with various terms to provide an adequate supply of fuel. However, as natural gas primarily serves intermediate and peak demand, remaining forecasted requirements are able to be procured through a liquid spot market. Generally, natural gas supply contracts have pricing that is tied to various natural gas indices. Most transportation contract pricing is based on FERC approved transportation tariff rates. These transportation rates are subject to revision based upon FERC approval of changes in the timing or amount of allowable cost recovery by providers. Certain natural gas supply and transportation agreements include obligations for the purchase and/or delivery of specified volumes of natural gas or to make payments in lieu of delivery. At Dec. 31, 2013 and 2012, the NSP System did not have any commitments related to gas supply contracts; however commitments related to gas transportation and storage contracts were approximately $389 million and $384 million, respectively. Commitments related to gas transportation and storage contracts expire in various years from 2014 to 2028.
The NSP System also has limited on-site fuel oil storage facilities and primarily relies on the spot market for incremental supplies.
Renewable Energy Sources
The NSP System’s renewable energy portfolio includes wind, hydroelectric, biomass and solar power from both owned generating facilities and PPAs. As of Dec. 31, 2013, the NSP System was in compliance with mandated RPS, which require generation from renewable resources of 18 percent and 8.89 percent of NSP-Minnesota and NSP-Wisconsin electric retail sales, respectively. Renewable energy comprised 22.9 percent and 22.4 percent of the NSP System’s total owned and purchased energy for 2013 and 2012, respectively. Wind energy comprised 12.6 percent and 11.9 percent of the total owned and purchased energy on the NSP System for 2013 and 2012, respectively. Hydroelectric energy comprised 7.4 percent and 7.0 percent of the total owned and purchased energy on the NSP System for 2013 and 2012, respectively. Biomass and solar power comprised approximately 3.0 percent and 3.5 percent of the total owned and purchased energy on the NSP System for 2013 and 2012, respectively.
The NSP System also offers customer-focused renewable energy initiatives. Windsource®, one of the nation’s largest voluntary renewable energy programs, allows customers in Minnesota, Wisconsin, and Michigan to purchase a portion or all of their electricity from renewable sources. In 2013, the number of customers increased to approximately 37,000 from 24,000 in 2012. Windsource MWh sales declined slightly due to the loss of a large commercial participant from approximately 184,000 MWh in 2012 to 181,000 MWh in 2013. Additionally, to encourage the growth of solar energy on the system, customers are offered incentives to install solar panels on their homes and businesses under the Solar*Rewards® program. Over 679 PV systems with approximately 7.3 MW of aggregate capacity and over 561 PV systems with approximately 6.3 MW of aggregate capacity have been installed in Minnesota under this program as of Dec. 31, 2013 and 2012, respectively.
Wind — The NSP System acquires the majority of its wind energy from PPAs with wind farm owners, primarily located in Southwestern Minnesota. The NSP System currently has more than 100 of these agreements in place, with facilities ranging in size from under one MW to more than 200 MW. In October 2013, the MPUC approved four new projects, which are anticipated to provide up to 750 MW of capacity, including two projects totaling 350 MW that will be owned by NSP-Minnesota. Two of the projects, the Pleasant Valley wind farm in Minnesota and the Border Winds wind farm in North Dakota are expected to be operational by 2015. In addition to receiving purchased wind energy under these agreements, the NSP System also typically receives wind RECs, which are used to meet state renewable resource requirements. The average cost per MWh of wind energy under these contracts was approximately $41 for 2013 and 2012. The cost per MWh of wind energy varies by contract and may be influenced by a number of factors including regulation, state-specific renewable resource requirements, and the year of contract execution. Generally, contracts executed in 2013 continued to benefit from improvements in technology, excess capacity among manufacturers, and motivation to commence new construction prior to the expiration of the Federal PTCs in 2013.
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The NSP System also owns and operates two wind farms. The 101 MW Grand Meadow Wind Farm and the 201 MW Nobles Wind Farm began generating electricity in 2008 and 2010, respectively. Collectively, the NSP System had approximately 1,870 MW of wind energy on its system at the end of 2013 and 2012. With the new projects, the NSP System is anticipated to have approximately 2,600 MW of wind power.
Hydroelectric — The NSP System acquires its hydroelectric energy from both owned generation and PPAs. The NSP System owns 20 hydroelectric plants throughout Wisconsin and Minnesota which provide 274 MW of capacity. For 2013, there were nine PPAs in place which provided approximately 37 MW of hydroelectric capacity. Additionally, the NSP System purchases approximately 850 MW of generation from Manitoba Hydro which is sourced primarily from its fleet of hydroelectric facilities.
Wholesale Commodity Marketing Operations
NSP-Minnesota conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy and energy related products. See Item 7A for further discussion.
Summary of Recent Federal Regulatory Developments
The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electricity sold at wholesale, hydro facility licensing, natural gas transportation, asset transactions and mergers, accounting practices and certain other activities of NSP-Minnesota, including enforcement of NERC mandatory electric reliability standards. State and local agencies have jurisdiction over many of NSP-Minnesota’s activities, including regulation of retail rates and environmental matters. In addition to the matters discussed below, see Note 10 to the accompanying consolidated financial statements for discussion of other regulatory matters.
FERC Order 1000, Transmission Planning and Cost Allocation (Order 1000) — The FERC issued Order 1000 in July 2011 adopting new requirements for transmission planning, cost allocation and development to be effective prospectively. In Order 1000, the FERC required utilities, including RTO’s such as MISO, to file compliance tariffs that provide for joint regional transmission planning and cost allocation for all FERC-jurisdictional utilities within a region. In addition, Order 1000 required that regions coordinate to develop interregional plans for transmission planning and cost allocation. A key provision of Order 1000 is a requirement that FERC-jurisdictional wholesale transmission tariffs exclude provisions that would grant the incumbent transmission owner a federal ROFR to build certain types of transmission projects in its service area. Various parties have appealed Order 1000 final rules to the D.C. Circuit. NSP-Minnesota is participating in the appeals in coordination with other MISO transmission owners and utilities who oppose certain aspects of the rules, including the ROFR prohibition. Briefs have been filed by parties challenging the final rules, by the FERC and by parties supporting the final rules. Oral arguments are scheduled for March 20, 2014. The date for a Court ruling is uncertain.
The removal of a federal ROFR would eliminate rights that NSP-Minnesota currently has under the MISO tariff to build certain transmission projects within its footprint. The FERC required that the opportunity to build such projects would extend to competitive transmission developers. Compliance with Order 1000 for NSP-Minnesota will occur through changes to the MISO tariff. MISO made its initial compliance filings to incorporate new provisions into its tariff regarding regional planning and cost allocation. The FERC has ruled on the initial regional compliance filings for MISO, and directed further changes to fully address the requirements of Order 1000. An additional regional compliance filing has been submitted by MISO, and FERC action on the supplemental compliance filing is pending. Several parties, including Xcel Energy, also sought rehearing of the FERC orders requiring changes to the initial MISO compliance filing. The rehearing requests are also pending FERC action.
Filings to address Order 1000 interregional planning and cost allocation requirements with other regions were made in July 2013. The filings are pending action by the FERC.
In 2012, Minnesota enacted legislation that preserves ROFR rights for Minnesota utilities at the state level. This legislation is similar to legislation previously passed in North Dakota and South Dakota. The FERC’s initial order to address the regional requirements of Order 1000 required MISO to remove proposed tariff provisions that would have recognized state ROFR rights and allowed state regulators to select the developer of a transmission project. NSP-Minnesota, NSP-Wisconsin and other MISO transmission owners requested rehearing of this issue. The rehearing request is pending the FERC’s action. The FERC has accepted changes to MISO’s transmission cost allocation procedures that will protect the ROFR for projects needed for system reliability.
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American Transmission Company, LLC (ATC) vs. Xcel Energy Services Inc. and MISO (Hampton, Minn. to Rochester, Minn. to La Crosse, Wis. Transmission Line) — In October 2012, ATC filed a complaint against MISO, Xcel Energy Services Inc., NSP-Minnesota and NSP-Wisconsin, alleging that, under the legal principles set forth in the July 2012 FERC ruling in the La Crosse, Wis. to Madison, Wis. transmission line complaint filed by Xcel Energy Services Inc. and NSP-Wisconsin against ATC, that the FERC should determine that MISO should have designated the Hampton, Minn. to Rochester, Minn. to La Crosse, Wis. CapX2020 line and the La Crosse, Wis. to Madison, Wis. line as a single facility under the MISO Transmission Owners Agreement and Tariff. Thus, ATC should have been designated as the owner of the La Crosse, Wis. to Madison, Wis. line portion of the purported single facility. Xcel Energy filed an answer seeking dismissal of the ATC complaint in October 2012. On Feb. 4, 2013, the FERC issued an order denying the ATC complaint. The FERC found that MISO properly applied its planning process and that Hampton, Minn. to La Crosse, Wis. and the La Crosse, Wis. to Madison, Wis. lines are separate. ATC did not seek rehearing and therefore the FERC order is final and MISO’s prior ownership decisions stand, which brings this matter to a close.
MISO Transmission Pricing — The MISO Tariff presently provides for different allocation methods for the costs of new transmission investments depending on whether the project is primarily local or regional in nature. If a project qualifies as a MVP, the costs would be fully allocated to all loads in the MISO region. MVP eligibility is generally obtained for higher voltage (345 KV and higher) projects expected to serve multiple purposes such as improved reliability, reduced congestion, transmission for renewable energy and load serving. Certain parties appealed the FERC MVP tariff orders to the U.S. Court of Appeals for the Seventh Circuit (Seventh Circuit). In June 2013, the Seventh Circuit upheld the FERC MVP tariff orders allocating MVP project costs regionally, but remanded the FERC decision to not apply the regional charge to transmission service transactions crossing into the PJM RTO. U.S. Supreme Court review of the Seventh Circuit decision has been requested and the response is pending. The NSP System has certain new transmission facilities for which other customers in MISO contribute to cost recovery. Likewise, the NSP System also pays a share of the costs of projects constructed by other transmission owning entities. The transmission revenues received by the NSP System from MISO and the transmission charges paid to MISO associated with projects subject to regional cost allocation could be significant in future periods.
RSG Charges — The MISO tariff charges certain market participants a real-time RSG charge, designed to ensure that any generator scheduled or dispatched by MISO receives no less than its offer price for start-up, no-load and incremental energy. In August 2010, the FERC issued two orders relating to RSG charge exemptions and the allocation of the RSG costs among MISO participants. The FERC has allowed allocating a greater portion of the RSG costs related to resources committed for voltage and local reliability requirements to the market participants serving the loads that benefit from such commitments. Certain of the FERC’s orders remain pending on rehearing. An appeal to the D.C. Circuit has been held in abeyance, pending the FERC’s disposition of rehearing requests. If the FERC were to reverse or modify the prior orders on rehearing, the NSP system could be subject to additional RSG charges for prior periods. NSP-Minnesota is permitted to recover the RSG costs through FCA mechanisms.
MISO ROE Complaint — In November 2013, a group of customers filed a complaint at the FERC against all FERC jurisdictional MISO transmission owners, including NSP-Minnesota and NSP-Wisconsin. The complaint argues for a reduction in the ROE applicable to transmission formula rates in the MISO region from 12.38 percent to 9.15 percent, a prohibition on capital structures in excess of 50 percent equity, and the removal of ROE adders (including those for RTO membership and being an independent transmission company), effective Nov. 12, 2013. In January 2014, Xcel Energy Services, Inc. filed an answer to the complaint asserting that the 9.15 percent ROE would be unreasonable and that the complainants failed to demonstrate the NSP System equity capital structure was unreasonable. The MISO Transmission Owners separately answered the complaint, arguing the complainants do not have standing to challenge the MISO Tariff provisions, have not met their burden of proof to demonstrate that the current FERC-approved ROE, capital structure and other incentives are unjust and unreasonable, and the complaint should be dismissed. Other parties filed comments supporting a reduction in the MISO regional ROE, the equity capital structure limitations, and limits on ROE incentives, and supported the proposed effective date. In January 2014, the complainants filed an answer to the MISO Transmission Owners’ motion to dismiss. The complaint is pending FERC action. The estimated impact of FERC granting the complaint could amount to a reduction of revenue of $11.7 million annually for NSP-Minnesota and NSP-Wisconsin. NSP-Minnesota and NSP-Wisconsin would seek to offset any reduction in wholesale revenues through increases in retail rates.
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Electric Operating Statistics
Electric Sales Statistics
| Year Ended Dec. 31 | ||||||||||||||
| 2013 | 2012 | 2011 | ||||||||||||
| Electric sales (Millions of KWh) | ||||||||||||||
| Residential | 10,486 | 10,377 | 10,448 | |||||||||||
| Large commercial and industrial | 8,963 | 9,302 | 9,750 | |||||||||||
| Small commercial and industrial | 15,577 | 15,478 | 15,439 | |||||||||||
| Public authorities and other | 267 | 264 | 260 | |||||||||||
| Total retail | 35,293 | 35,421 | 35,897 | |||||||||||
| Sales for resale | 1,397 | 1,625 | 1,711 | |||||||||||
| Total energy sold | 36,690 | 37,046 | 37,608 | |||||||||||
| Number of customers at end of period | ||||||||||||||
| Residential | 1,263,575 | 1,252,589 | 1,245,413 | |||||||||||
| Large commercial and industrial | 483 | 496 | 500 | |||||||||||
| Small commercial and industrial | 152,769 | 151,978 | 151,144 | |||||||||||
| Public authorities and other | 6,869 | 6,699 | 6,470 | |||||||||||
| Total retail | 1,423,696 | 1,411,762 | 1,403,527 | |||||||||||
| Wholesale | 12 | 15 | 17 | |||||||||||
| Total customers | 1,423,708 | 1,411,777 | 1,403,544 | |||||||||||
| Electric revenues (Thousands of Dollars) | ||||||||||||||
| Residential | $ | 1,244,712 | $ | 1,165,413 | $ | 1,140,598 | ||||||||
| Large commercial and industrial | 686,970 | 632,831 | 660,083 | |||||||||||
| Small commercial and industrial | 1,410,083 | 1,324,989 | 1,270,757 | |||||||||||
| Public authorities and other | 36,207 | 34,444 | 34,211 | |||||||||||
| Total retail | 3,377,972 | 3,157,677 | 3,105,649 | |||||||||||
| Wholesale | 47,511 | 42,748 | 47,316 | |||||||||||
| Interchange revenues from NSP-Wisconsin | 458,633 | 449,958 | 440,519 | |||||||||||
| Other electric revenues | 178,324 | 192,146 | 179,144 | |||||||||||
| Total electric revenues | $ | 4,062,440 | $ | 3,842,529 | $ | 3,772,628 | ||||||||
| KWh sales per retail customer | 24,790 | 25,090 | 25,576 | |||||||||||
| Revenue per retail customer | $ | 2,373 | $ | 2,237 | $ | 2,213 | ||||||||
| Residential revenue per KWh | 11.87 | ¢ | 11.23 | ¢ | 10.92 | ¢ | ||||||||
| Large commercial and industrial revenue per KWh | 7.66 | 6.80 | 6.77 | |||||||||||
| Small commercial and industrial revenue per KWh | 9.05 | 8.56 | 8.23 | |||||||||||
| Total retail revenue per KWh | 9.57 | 8.91 | 8.65 | |||||||||||
| Wholesale revenue per KWh | 3.40 | 2.63 | 2.76 | |||||||||||
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Energy Source Statistics
| Year Ended Dec. 31 | |||||||||||||||||
| 2013 | 2012 | 2011 | |||||||||||||||
| NSP System | Millions of KWh | Percent of Generation | Millions of KWh | Percent of Generation | Millions of KWh | Percent of Generation | |||||||||||
| Coal | 15,844 | 36 | % | 16,023 | 35 | % | 20,131 | 44 | % | ||||||||
| Nuclear | 12,161 | 28 | 13,231 | 29 | 13,332 | 29 | |||||||||||
| Natural Gas | 5,550 | 13 | 6,200 | 13 | 3,016 | 7 | |||||||||||
Wind (a) | 5,481 | 13 | 5,443 | 12 | 4,312 | 9 | |||||||||||
| Hydroelectric | 3,223 | 7 | 3,193 | 7 | 3,444 | 8 | |||||||||||
Other (b) | 1,323 | 3 | 1,617 | 4 | 1,453 | 3 | |||||||||||
| Total | 43,582 | 100 | % | 45,707 | 100 | % | 45,688 | 100 | % | ||||||||
| Owned generation | 29,249 | 67 | % | 31,365 | 69 | % | 31,668 | 69 | % | ||||||||
| Purchased generation | 14,333 | 33 | 14,342 | 31 | 14,020 | 31 | |||||||||||
| Total | 43,582 | 100 | % | 45,707 | 100 | % | 45,688 | 100 | % | ||||||||
(a) | This category includes wind energy de-bundled from RECs and also includes Windsource RECs. The NSP System uses RECs to meet or exceed state resource requirements and may sell surplus RECs. |
(b) | Includes energy from other sources, including solar, biomass, oil and refuse. Distributed generation from the Solar*Rewards program is not included, and was approximately 0.008, 0.006, and 0.003 net million KWh for 2013, 2012, and 2011, respectively. |
NATURAL GAS UTILITY OPERATIONS
Overview
The most significant developments in the natural gas operations of NSP-Minnesota are continued volatility in natural gas market prices, uncertainty regarding political and regulatory developments that impact hydraulic fracturing, safety requirements for natural gas pipelines and the continued trend of declining use per customer, as a result of improved building construction technologies, higher appliance efficiencies and conservation. From 2000 to 2013, average annual sales to the typical residential customer declined from 18 percent and the typical small commercial and industrial customer declined 2 percent on a weather-normalized basis. Although wholesale price increases do not directly affect earnings because of natural gas cost recovery mechanisms, high prices can encourage further efficiency efforts by customers.
The Pipeline and Hazardous Materials Safety Administration
Pipeline Safety Act — The Pipeline Safety, Regulatory Certainty, and Job Creation Act, signed into law in January 2012 (Pipeline Safety Act) requires additional verification of pipeline infrastructure records by pipeline owners and operators to confirm the maximum allowable operating pressure of lines located in high consequence areas or more-densely populated areas. The DOT Pipeline and Hazardous Materials Safety Administration (PHMSA) will require operators to re-confirm the maximum allowable operating pressure if records are inadequate. This process could cause temporary or permanent limitations on throughput for affected pipelines. In addition, the Pipeline Safety Act requires PHMSA to issue reports and develop new regulations including: requiring use of automatic or remote-controlled shut-off valves; requiring testing of certain previously untested transmission lines; and expanding integrity management requirements. The Pipeline Safety Act also raises the maximum penalty for violating pipeline safety rules to $2 million per day for related violations. While NSP-Minnesota cannot predict the ultimate impact Pipeline Safety Act will have on its costs, operations or financial results, it is taking actions that are intended to comply with the Pipeline Safety Act and any related PHMSA regulations as they become effective.
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Public Utility Regulation
Summary of Regulatory Agencies and Areas of Jurisdiction — Retail rates, services and other aspects of NSP-Minnesota’s retail natural gas operations are regulated by the MPUC and the NDPSC within their respective states. The MPUC has regulatory authority over security issuances, certain property transfers, mergers with other utilities and transactions between NSP-Minnesota and its affiliates. In addition, the MPUC reviews and approves NSP-Minnesota’s natural gas supply plans for meeting customers’ future energy needs. NSP-Minnesota is subject to the jurisdiction of the FERC with respect to certain natural gas transactions in interstate commerce. NSP-Minnesota is subject to the DOT, the Minnesota Office of Pipeline Safety, the NDPSC and the SDPUC for pipeline safety compliance, including pipeline facilities used in electric utility operations for fuel deliveries.
Purchased Gas and Conservation Cost-Recovery Mechanisms — NSP-Minnesota’s retail natural gas rates for Minnesota and North Dakota include a PGA clause that provides for prospective monthly rate adjustments to reflect the forecasted cost of purchased natural gas, transportation service and storage service. The annual difference between the natural gas cost revenues collected through PGA rates and the actual natural gas costs is collected or refunded over the subsequent 12-month period. The MPUC and NDPSC have the authority to disallow recovery of certain costs if they find the utility was not prudent in its procurement activities.
Minnesota state law requires utilities to invest 0.5 percent of their state natural gas revenues in CIP. These costs are recovered through customer base rates and an annual cost-recovery mechanism for the CIP expenditures.
Capability and Demand
Natural gas supply requirements are categorized as firm or interruptible (customers with an alternate energy supply). The maximum daily send-out (firm and interruptible) for NSP-Minnesota was 767,636 MMBtu, which occurred on Jan. 21, 2013 and 732,135 MMBtu, which occurred on Jan. 19, 2012.
NSP-Minnesota purchases natural gas from independent suppliers, generally based on market indices that reflect current prices. The natural gas is delivered under transportation agreements with interstate pipelines. These agreements provide for firm deliverable pipeline capacity of 596,411 MMBtu per day. In addition, NSP-Minnesota contracts with providers of underground natural gas storage services. These agreements provide storage for approximately 26 percent of winter natural gas requirements and 31 percent of peak day firm requirements of NSP-Minnesota.
NSP-Minnesota also owns and operates one LNG plant with a storage capacity of 2.0 Bcf equivalent and three propane-air plants with a storage capacity of 1.3 Bcf equivalent to help meet its peak requirements. These peak-shaving facilities have production capacity equivalent to 246,000 MMBtu of natural gas per day, or approximately 31 percent of peak day firm requirements. LNG and propane-air plants provide a cost-effective alternative to annual fixed pipeline transportation charges to meet the peaks caused by firm space heating demand on extremely cold winter days.
NSP-Minnesota is required to file for a change in natural gas supply contract levels to meet peak demand, to redistribute demand costs among classes, or to exchange one form of demand for another. Contract demand levels for the past five years are being reviewed by the MPUC.
Natural Gas Supply and Costs
NSP-Minnesota actively seeks natural gas supply, transportation and storage alternatives to yield a diversified portfolio that provides increased flexibility, decreased interruption and financial risk and economical rates. In addition, NSP-Minnesota conducts natural gas price hedging activity that has been approved by the MPUC.
The following table summarizes the average delivered cost per MMBtu of natural gas purchased for resale by NSP-Minnesota’s regulated retail natural gas distribution business:
| 2013 | $ | 4.53 | |
| 2012 | 4.41 | ||
| 2011 | 5.25 | ||
NSP-Minnesota has firm natural gas transportation contracts with several pipelines, which expire in various years from 2014 through 2033.
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NSP-Minnesota has certain natural gas supply, transportation and storage agreements that include obligations for the purchase and/or delivery of specified volumes of natural gas or to make payments in lieu of delivery. At Dec. 31, 2013, NSP-Minnesota was committed to approximately $356 million in such obligations under these contracts.
NSP-Minnesota purchases firm natural gas supply utilizing long-term and short-term agreements from approximately 28 domestic and Canadian suppliers. This diversity of suppliers and contract lengths allows NSP-Minnesota to maintain competition from suppliers and minimize supply costs.
See Item 1A for further discussion of natural gas supply and costs.
| Natural Gas Operating Statistics | |||||||||||
| Year Ended Dec. 31 | |||||||||||
| 2013 | 2012 | 2011 | |||||||||
| Natural gas deliveries (Thousands of MMBtu) | |||||||||||
| Residential | 42,446 | 32,817 | 37,683 | ||||||||
| Commercial and industrial | 42,459 | 35,054 | 39,878 | ||||||||
| Total retail | 84,905 | 67,871 | 77,561 | ||||||||
| Transportation and other | 11,076 | 10,943 | 10,797 | ||||||||
| Total deliveries | 95,981 | 78,814 | 88,358 | ||||||||
| Number of customers at end of period | |||||||||||
| Residential | 450,958 | 446,677 | 443,513 | ||||||||
| Commercial and industrial | 41,929 | 41,542 | 41,190 | ||||||||
| Total retail | 492,887 | 488,219 | 484,703 | ||||||||
| Transportation and other | 24 | 21 | 17 | ||||||||
| Total customers | 492,911 | 488,240 | 484,720 | ||||||||
| Natural gas revenues (Thousands of Dollars) | |||||||||||
| Residential | $ | 329,810 | $ | 263,233 | $ | 326,983 | |||||
| Commercial and industrial | 249,620 | 199,097 | 266,258 | ||||||||
| Total retail | 579,430 | 462,330 | 593,241 | ||||||||
| Transportation and other | 11,587 | 9,435 | 11,482 | ||||||||
| Total natural gas revenues | $ | 591,017 | $ | 471,765 | $ | 604,723 | |||||
| MMBtu sales per retail customer | 172.26 | 139.02 | 160.02 | ||||||||
| Revenue per retail customer | $ | 1,176 | $ | 947 | $ | 1,224 | |||||
| Residential revenue per MMBtu | 7.77 | 8.02 | 8.68 | ||||||||
| Commercial and industrial revenue per MMBtu | 5.88 | 5.68 | 6.68 | ||||||||
| Transportation and other revenue per MMBtu | 1.05 | 0.86 | 1.06 | ||||||||
GENERAL
Seasonality
The demand for electric power and natural gas is affected by seasonal differences in the weather. In general, peak sales of electricity occur in the summer and winter months, and peak sales of natural gas occur in the winter months. As a result, the overall operating results may fluctuate substantially on a seasonal basis. Additionally, NSP-Minnesota’s operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer. See Item 7 for further discussion.
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Competition
NSP-Minnesota remains a vertically integrated utility subject to traditional cost-of-service regulation. Within this construct, however, NSP-Minnesota is subject to different public policies that promote competition and the development of energy markets. NSP-Minnesota’s industrial and large commercial customers have the ability to own or operate facilities to generate their own electricity. In addition, customers may have the option of substituting other fuels, such as natural gas, steam or chilled water for heating, cooling and manufacturing purposes, or the option of relocating their facilities to a lower cost region. Customers also have the opportunity to supply their own power with on-site solar generation (typically rooftop solar) and in most jurisdictions can currently avoid paying for most of the fixed production, transmission and distribution costs incurred to serve them.
The FERC has continued to promote competitive wholesale markets through open access transmission and other means. As a result, NSP-Minnesota and its wholesale customers can purchase generation resources from competing wholesale suppliers and use the transmission systems of the Xcel Energy Inc.’s utility subsidiaries on a comparable basis to serve their native load. State public utilities commissions, including the MPUC, have created resource planning programs that promote competition in the acquisition of electricity generation resources used to provide service to retail customers. In addition, FERC Order 1000 seeks to establish competition for construction and operation of new electric transmission facilities. NSP-Minnesota has franchise agreements with certain cities subject to periodic renewal. If a city elected not to renew the franchise agreement, it could seek alternative means for its citizens to access electric power or gas, such as municipalization. Several states, including Minnesota, have policies designed to promote the development of solar and other distributed energy resources through significant incentive policies; with these incentives and federal tax subsidies, distributed generating resources are potential competitors to NSP-Minnesota’s electric service business. These competitive challenges continue to evolve over time. While facing these challenges, NSP-Minnesota believes its rates and services are competitive with currently available alternatives. NSP-Minnesota continues to evaluate policies, products and strategies to enable it to compete in the changing energy marketplace.
ENVIRONMENTAL MATTERS
NSP-Minnesota’s facilities are regulated by federal and state environmental agencies. These agencies have jurisdiction over air emissions, water quality, wastewater discharges, solid wastes and hazardous substances. Various company activities require registrations, permits, licenses, inspections and approvals from these agencies. NSP-Minnesota has received all necessary authorizations for the construction and continued operation of its generation, transmission and distribution systems. NSP-Minnesota’s facilities have been designed and constructed to operate in compliance with applicable environmental standards. NSP-Minnesota strives to comply with all environmental regulations applicable to its operations. However, it is not possible to determine when or to what extent additional facilities or modifications of existing or planned facilities will be required as a result of changes to environmental regulations, interpretations or enforcement policies or what effect future laws or regulations may have upon NSP-Minnesota’s operations. See Notes 10 and 11 to the consolidated financial statements for further discussion.
There are significant future environmental regulations under consideration to encourage the use of clean energy technologies and regulate emissions of GHGs to address climate change. While environmental regulations related to climate change and clean energy continue to evolve, NSP-Minnesota has undertaken a number of initiatives to meet current requirements and prepare for potential future regulations, reduce GHG emissions and respond to state renewable and energy efficiency goals. Although the impact of these policies on NSP-Minnesota will depend on the specifics of state and federal policies, legislation, and regulation, we believe that, based on prior state commission practice, we would recover the cost of these initiatives through rates.
EMPLOYEES
As of Dec. 31, 2013, NSP-Minnesota had 3,775 full-time employees and six part-time employees, of which 2,270 were covered under collective-bargaining agreements. See Note 7 to the consolidated financial statements for further discussion.
Item 1A — Risk Factors
Like other companies in our industry, Xcel Energy, which includes NSP-Minnesota, is subject to a variety of risks, many of which are beyond our control. Important risks that may adversely affect the business, financial condition, and results of operations are further described below. These risks should be carefully considered together with the other information set forth in this report and in future reports that Xcel Energy files with the SEC.
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There may be further risks and uncertainties that are not presently known or are not currently believed to be material that may adversely affect our performance or financial condition in the future.
Oversight of Risk and Related Processes
The goal of Xcel Energy’s risk management process, which includes NSP-Minnesota, is to understand, manage and, when possible, mitigate material risk. Management is responsible for identifying and managing risks, while the Board of Directors oversees and holds management accountable. NSP-Minnesota is faced with a number of different types of risk. Many of these risks are cross-cutting risks such that these risks are discussed and managed across business areas and coordinated by Xcel Energy Inc.’s and NSP-Minnesota’s senior management. Our risk management process has three parts: identification and analysis, management and mitigation and communication and disclosure.
Management identifies and analyzes risks to determine materiality and other attributes such as timing, probability and controllability. Management broadly considers our business, the utility industry, the domestic and global economy and the environment to identify risks. Identification and analysis occurs formally through a key risk assessment process conducted by senior management, the financial disclosure process, the hazard risk management process and internal auditing and compliance with financial and operational controls. Management also identifies and analyzes risk through its business planning process and development of goals and key performance indicators, which include risk identification to determine barriers to implementing our strategy. At the same time, the business planning process identifies areas in which there is a potential for a business area to take inappropriate risk to meet goals and determines how to prevent inappropriate risk-taking.
Management seeks to mitigate the risks inherent in the implementation of Xcel Energy Inc.’s and NSP-Minnesota’s strategy. The process for risk mitigation includes adherence to our code of conduct and other compliance policies, operation of formal risk management structures and groups, and overall business management. At a threshold level, we have developed a robust compliance program and promote a culture of compliance, including tone at the top, which mitigates risk. Building on this culture of compliance, we manage and further mitigate risks through operation of formal risk management structures and groups, including management councils, risk committees and the services of corporate areas such as internal audit, the corporate controller and legal services. While we have developed a number of formal structures for risk management, many material risks affect the business as a whole and are managed across business areas.
Management communicates regularly with Xcel Energy Inc.’s Board and key stakeholders regarding risk. Senior management presents a periodic assessment of key risks to the Board. The presentation of the key risks and the discussion provides the Board with information on the risks management believes are material, including the earnings impact, timing, likelihood and controllability. Management also provides information to the Board in presentations and communications over the course of the year.
The guidelines on corporate governance and Board committee charters define the scope of review and inquiry for the Board and its committees. Each Board committee has responsibility for overseeing aspects of risk and our management and mitigation of the risk. Xcel Energy Inc.’s Board of Directors has overall responsibility for risk oversight and with the committees periodically undertakes the review of the charters to ensure that oversight of key risks are appropriately considered by the various Board committees. Xcel Energy Inc.’s Board also reviews risks at an enterprise level and annually conducts a full day strategy session where it considers risks and confirms that Xcel Energy’s and NSP-Minnesota’s strategy appropriately addresses risk management and mitigation and reviews the performance and annual goals of each business area.
As described above, the Board reviews senior management’s key risk assessment that analyzes the most likely areas of future risk to Xcel Energy. This review, when combined with the oversight of specific risks by the committees, allows the Board to confirm risk is considered in the development of goals and that risk has been adequately considered and mitigated in the execution of corporate strategy. The presentation of the assessment of key risks also provides the basis for the discussion of risk in our public filings and securities disclosures.
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Risks Associated with Our Business
Environmental Risks
We are subject to environmental laws and regulations, with which compliance could be difficult and costly.
We are subject to environmental laws and regulations that affect many aspects of our past, present and future operations, including air emissions, water quality, wastewater discharges and the generation, transport and disposal of solid wastes and hazardous substances. These laws and regulations require us to obtain and comply with a wide variety of environmental requirements including those for protected natural and cultural resources (such as wetlands, endangered species and other protected wildlife, and archaeological and historical resources), licenses, permits, inspections and other approvals. Environmental laws and regulations can also require us to restrict or limit the output of certain facilities or the use of certain fuels, install pollution control equipment at our facilities, clean up spills and other contamination and correct environmental hazards. Environmental regulations may also lead to shutdown of existing facilities, either due to the difficulty in assuring compliance or that the costs of compliance no longer makes operation of the units economic. Both public officials and private individuals may seek to enforce the applicable environmental laws and regulations against us. We may be required to pay all or a portion of the cost to remediate (i.e., cleanup) sites where our past activities, or the activities of certain other parties, caused environmental contamination. At Dec. 31, 2013, these sites included:
| • | Sites of former MGPs operated by us, our predecessors, or other entities; and |
| • | Third party sites, such as landfills, for which we are alleged to be a PRP that sent hazardous materials and wastes. |
We are also subject to mandates to provide customers with clean energy, renewable energy and energy conservation offerings. These mandates are designed in part to mitigate the potential environmental impacts of utility operations. Failure to meet the requirements of these mandates may result in fines or penalties, which could have a material effect on our results of operations. If our regulators do not allow us to recover all or a part of the cost of capital investment or the O&M costs incurred to comply with the mandates, it could have a material effect on our results of operations, financial position or cash flows.
In addition, existing environmental laws or regulations may be revised, and new laws or regulations seeking to protect the environment may be adopted or become applicable to us, including but not limited to, regulation of mercury, NOx, SO2, CO2, and other GHGs particulates, coal ash and cooling water intake systems. We may also incur additional unanticipated obligations or liabilities under existing environmental laws and regulations.
We are subject to physical and financial risks associated with climate change.
There is a growing consensus that emissions of GHGs are linked to global climate change. Climate change creates physical and financial risk. Physical risks from climate change include an increase in sea level and changes in weather conditions, such as changes in precipitation and extreme weather events. We do not serve any coastal communities so the possibility of sea level rises does not directly affect us or our customers.
Our customers’ energy needs vary with weather conditions, primarily temperature and humidity. For residential customers, heating and cooling represent their largest energy use. To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease depending on the duration and magnitude of the changes.
Increased energy use due to weather changes may require us to invest in additional generating assets, transmission and other infrastructure to serve increased load. Decreased energy use due to weather changes may affect our financial condition, through decreased revenues. Extreme weather conditions in general require more system backup, adding to costs, and can contribute to increased system stress, including service interruptions. Weather conditions outside of our service territory could also have an impact on our revenues. We buy and sell electricity depending upon system needs and market opportunities. Extreme weather conditions creating high energy demand on our own and/or other systems may raise electricity prices as we buy short-term energy to serve our own system, which would increase the cost of energy we provide to our customers.
Severe weather impacts our service territories, primarily when thunderstorms, tornadoes and snow or ice storms occur. To the extent the frequency of extreme weather events increases, this could increase our cost of providing service. Changes in precipitation resulting in droughts or water shortages could adversely affect our operations, principally our fossil generating units. A negative impact to water supplies due to long-term drought conditions could adversely impact our ability to provide electricity to customers, as well as increase the price they pay for energy. We may not recover all costs related to mitigating these physical and financial risks.
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To the extent climate change impacts a region’s economic health, it may also impact our revenues. Our financial performance is tied to the health of the regional economies we serve. The price of energy, as a factor in a region’s cost of living as well as an important input into the cost of goods and services, has an impact on the economic health of our communities. The cost of additional regulatory requirements, such as a tax on GHGs or additional environmental regulation could impact the availability of goods and prices charged by our suppliers which would normally be borne by consumers through higher prices for energy and purchased goods. To the extent financial markets view climate change and emissions of GHGs as a financial risk, this could negatively affect our ability to access capital markets or cause us to receive less than ideal terms and conditions.
Financial Risks
Our profitability depends in part on our ability to recover costs from our customers and there may be changes in circumstances or in the regulatory environment that impair our ability to recover costs from our customers.
We are subject to comprehensive regulation by federal and state utility regulatory agencies. The state utility commissions regulate many aspects of our utility operations, including siting and construction of facilities, customer service and the rates that we can charge customers. The FERC has jurisdiction, among other things, over wholesale rates for electric transmission service, the sale of electric energy in interstate commerce and certain natural gas transactions in interstate commerce.
Our profitability is dependent on our ability to recover the costs of providing energy and utility services to our customers and earn a return on our capital investment in our utility operations. We provide service at rates approved by one or more regulatory commissions. These rates are generally regulated and based on an analysis of our costs incurred in a test year. Thus, the rates we are allowed to charge may or may not match our costs at any given time. While rate regulation is premised on providing an opportunity to earn a reasonable rate of return on invested capital, in a continued low interest rate environment there has been pressure pushing down ROE. There can also be no assurance that the applicable regulatory commission will judge all of our costs to have been prudent or that the regulatory process in which rates are determined will always result in rates that will produce full recovery of our costs. Judgments may arise as a result of prudence investigations (e.g., Monticello LCM/EPU project). Rising fuel costs could increase the risk that we will not be able to fully recover our fuel costs from our customers. Furthermore, there could be changes in the regulatory environment that would impair our ability to recover costs historically collected from our customers.
Management currently believes these prudently incurred costs are recoverable given the existing regulatory mechanisms in place. However, adverse regulatory rulings or the imposition of additional regulations, including additional environmental or climate change regulation, could have an adverse impact on our results of operations and hence could materially and adversely affect our ability to meet our financial obligations, including debt payments.
Any reductions in our credit ratings could increase our financing costs and the cost of maintaining certain contractual relationships.
We cannot be assured that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency. In addition, our credit ratings may change as a result of the differing methodologies or change in the methodologies used by the various rating agencies. For example, Standard & Poor’s calculates an imputed debt associated with capacity payments from purchased power contracts. An increase in the overall level of capacity payments would increase the amount of our imputed debt, based on Standard & Poor’s methodology. Therefore, our credit ratings could be adversely affected based on the level of capacity payments associated with purchased power contracts or changes in how imputed debt is determined. Any downgrade could lead to higher borrowing costs. Also, we may enter into certain procurement and derivative contracts that require the posting of collateral or settlement of applicable contracts if credit ratings fall below investment grade.
We are subject to capital market and interest rate risks.
Utility operations require significant capital investment in property, plant and equipment; consequently, we are an active participant in debt and equity markets. Any disruption in capital markets could have a material impact on our ability to fund our operations. Capital markets are global in nature and are impacted by numerous issues and events throughout the world economy. Capital market disruption events and resulting broad financial market distress, could prevent us from issuing new securities or cause us to issue securities with less than ideal terms and conditions, such as higher interest rates.
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Higher interest rates on short-term borrowings with variable interest rates or on incremental commercial paper issuances could also have an adverse effect on our operating results. Changes in interest rates may also impact the fair value of the debt securities in the nuclear decommissioning fund and master pension trust, as well as our ability to earn a return on short-term investments of excess cash.
We are subject to credit risks.
Credit risk includes the risk that our retail customers will not pay their bills, which may lead to a reduction in liquidity and an eventual increase in bad debt expense. Retail credit risk is comprised of numerous factors including the price of products and services provided, the overall economy and local economies in the geographic areas we serve, including local unemployment rates.
Credit risk also includes the risk that various counterparties that owe us money or product will breach their obligations. Should the counterparties to these arrangements fail to perform, we may be forced to enter into alternative arrangements. In that event, our financial results could be adversely affected and we could incur losses.
One alternative available to address counterparty credit risk is to transact on liquid commodity exchanges. The credit risk is then socialized through the exchange central clearinghouse function. While exchanges do remove counterparty credit risk, all participants are subject to margin requirements, which create an additional need for liquidity to post margin as exchange positions change value daily. The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) requires broad clearing of financial swap transactions through a central counterparty, which could lead to additional margin requirements that would impact our liquidity: however, we have taken advantage of an exception to mandatory clearing afforded to commercial end-users who are not classified as a major swap participant. The Board of Directors has authorized Xcel Energy and its subsidiaries to take advantage of this end-user exception. In addition, the CFTC has granted an increase in the de minimis level for swap transactions with defined utility special entities, generally entities owning or operating electric or natural gas facilities, from $25 million to $800 million. Our current level of financial swap activity with special entities is significantly below this new threshold; therefore, we will not be classified as a swap dealer in our special entity activity. Swap transactions with non special entities have a much higher level of activity considered to be de minimis, currently $8 billion, and our level of activity is well under this limit; therefore, we will not be classified as a swap dealer under the Dodd-Frank Act. We are currently reporting all of our swap transactions as part of the Dodd-Frank Act.
We may at times have direct credit exposure in our short-term wholesale and commodity trading activity to various financial institutions trading for their own accounts or issuing collateral support on behalf of other counterparties. We may also have some indirect credit exposure due to participation in organized markets, such as Southwest Power Pool, Inc., PJM and MISO, in which any credit losses are socialized to all market participants.
We do have additional indirect credit exposures to various domestic and foreign financial institutions in the form of letters of credit provided as security by power suppliers under various long-term physical purchased power contracts. If any of the credit ratings of the letter of credit issuers were to drop below the designated investment grade rating stipulated in the underlying long-term purchased power contracts, the supplier would need to replace that security with an acceptable substitute. If the security were not replaced, the party could be in technical default under the contract, which would enable us to exercise our contractual rights.
Increasing costs associated with our defined benefit retirement plans and other employee benefits may adversely affect our results of operations, financial position or liquidity.
We have defined benefit pension and postretirement plans that cover substantially all of our employees. Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions have a significant impact on our funding requirements related to these plans. These estimates and assumptions may change based on economic conditions, actual stock and bond market performance, changes in interest rates and changes in governmental regulations. In addition, the Pension Protection Act of 2006 changed the minimum funding requirements for defined benefit pension plans with modifications to these funding requirements that allowed additional flexibility in the timing of contributions. Therefore, our funding requirements and related contributions may change in the future. Also, the payout of a significant percentage of pension plan liabilities in a single year due to high retirements or employees leaving the company would trigger settlement accounting and could require the company to recognize material incremental pension expense related to unrecognized plan losses in the year these liabilities are paid.
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Increasing costs associated with health care plans may adversely affect our results of operations.
Our self-insured costs of health care benefits for eligible employees and costs for retiree health care plans have increased substantially in recent years. Increasing levels of large individual health care claims and overall health care claims could have an adverse impact on our operating results, financial position and liquidity. We believe that our employee benefit costs, including costs related to health care plans for our employees and former employees, will continue to rise. Legislation related to health care could also significantly change our benefit programs and costs.
Operational Risks
We are subject to commodity risks and other risks associated with energy markets and energy production.
We engage in wholesale sales and purchases of electric capacity, energy and energy-related products as well as natural gas. As a result we are subject to market supply and commodity price risk. Commodity price changes can affect the value of our commodity trading derivatives. We mark certain derivatives to estimated fair market value on a daily basis (mark-to-market accounting), which may cause earnings volatility. Actual settlements can vary significantly from these estimates, and significant changes from the assumptions underlying our fair value estimates could cause significant earnings variability.
If we encounter market supply shortages or our suppliers are otherwise unable to meet their contractual obligations, we may be unable to fulfill our contractual obligations customers at previously authorized or anticipated costs. Any such disruption, if significant, would cause us to seek alternative supply services at potentially higher costs or suffer increased liability for unfulfilled contractual obligations. Any significantly higher energy or fuel costs relative to corresponding sales commitments would have a negative impact on our cash flows and could potentially result in economic losses. Potential market supply shortages may not be fully resolved through alternative supply sources and such interruptions may cause short-term disruptions in our ability to provide electric and/or natural gas services to our customers. The impact of these cost and reliability issues depends on our operating conditions such as generation fuels mix, availability of water for cooling, availability of fuel transportation, electric generation capacity, transmission, natural gas pipeline capacity, etc.
We are subject to the risks of nuclear generation.
Our two nuclear stations, Prairie Island and Monticello, subject us to the risks of nuclear generation, which include:
| • | The risks associated with use of radioactive material in the production of energy, the management, handling, storage and disposal of these radioactive materials and the current lack of a long-term disposal solution for radioactive materials; |
| • | Limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with nuclear operations; and |
| • | Uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their licensed lives. |
The NRC has authority to impose licensing and safety-related requirements for the operation of nuclear generation facilities. In the event of non-compliance, the NRC has the authority to impose fines or shut down a unit, or both, until compliance is achieved. Revised NRC safety requirements could necessitate substantial capital expenditures or a substantial increase in operating expenses at our nuclear plants. In addition, the Institute for Nuclear Power Operations reviews our nuclear operations and nuclear generation facilities. Compliance with the Institute for Nuclear Power Operations’ recommendations could result in substantial capital expenditures or a substantial increase in operating expenses.
If an incident did occur, it could have a material effect on our results of operations or financial condition. Furthermore, the non-compliance of other nuclear facilities operators with applicable regulations or the occurrence of a serious nuclear incident at other facilities could result in increased regulation of the industry as a whole, which could then increase our compliance costs and impact the results of operations of its facilities.
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Our utility operations are subject to long-term planning risks.
Our utility operations file long-term resource plans with our regulators. These plans are based on numerous assumptions over the planning horizon such as: sales growth, customer usage patterns, economic activity, costs, regulatory mechanisms, impact of technology, the installation of distributed energy generation, customer behavioral response and continuation of the existing utility business model. Given the uncertainty in these planning assumptions, there is a risk that the magnitude and timing of resource additions and demand may not coincide. NSP-Minnesota’s aging infrastructure may pose a risk to system reliability and expose us to premature financial obligations. NSP-Minnesota is engaged in significant and ongoing infrastructure investment programs.
In some of our state jurisdictions, large industrial customers may leave our system and invest in their own on-site distributed generation or seek law changes to give them authority to purchase directly from other suppliers or organized markets. The recent low natural gas price environment has caused some customers to consider their options in this area, particularly customers with industrial processes using steam. Wholesale customers may purchase directly from other suppliers and procure only transmission service from us. These circumstances provide for greater long-term planning uncertainty related to future load growth. Similarly, distributed solar generation may become an economic competitive threat to our load growth in the future; however we believe the economics, absent significant subsidies, do not support such a trend in the near term unless a state mandates the purchase of such generation. Some states have considered such legislation.
Our natural gas transmission and distribution operations involve numerous risks that may result in accidents and other operating risks and costs.
Our natural gas transmission and distribution activities include a variety of inherent hazards and operating risks, such as leaks, explosions and mechanical problems, which could cause substantial financial losses. In addition, these risks could result in loss of human life, significant damage to property, environmental pollution, and impairment of our operations and substantial losses to us. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses.
The occurrence of any of these events not fully covered by insurance could have a material effect on our financial position and results of operations. For our natural gas transmission or distribution lines located near populated areas the level of potential damages resulting from these risks is greater.
Additionally, the operating or other costs that may be required in order to comply with potential new regulations, including the Pipeline Safety Act, could be significant. The Pipeline Safety Act requires additional verification of pipeline infrastructure records by intrastate and interstate pipeline owners and operators to confirm the maximum allowable operating pressure of lines located in high consequence areas or more-densely populated areas. A significant incident could increase regulatory scrutiny and result in penalties and higher costs of operations.
As we are a subsidiary of Xcel Energy Inc., we may be negatively affected by events impacting the credit or liquidity of Xcel Energy Inc. and its affiliates.
If Xcel Energy Inc. were to become obligated to make payments under various guarantees and bond indemnities or to fund its other contingent liabilities, or if either Standard & Poor’s or Moody’s were to downgrade Xcel Energy Inc.’s credit rating below investment grade, Xcel Energy Inc. may be required to provide credit enhancements in the form of cash collateral, letters of credit or other security to satisfy part or potentially all of these exposures. If either Standard & Poor’s or Moody’s were to downgrade Xcel Energy Inc.’s debt securities below investment grade, it would increase Xcel Energy Inc.’s cost of capital and restrict its access to the capital markets. This could limit Xcel Energy Inc.’s ability to contribute equity or make loans to us, or may cause Xcel Energy Inc. to seek additional or accelerated funding from us in the form of dividends. If such event were to occur, we may need to seek alternative sources of funds to meet our cash needs.
As of Dec. 31, 2013, Xcel Energy Inc. and its utility subsidiaries had approximately $10.9 billion of long-term debt and $1.0 billion of short-term debt and current maturities. Xcel Energy Inc. provides various guarantees and bond indemnities supporting some of its subsidiaries by guaranteeing the payment or performance by these subsidiaries for specified agreements or transactions.
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Xcel Energy also has other contingent liabilities resulting from various tax disputes and other matters. Xcel Energy Inc.’s exposure under the guarantees is based upon the net liability of the relevant subsidiary under the specified agreements or transactions. The majority of Xcel Energy Inc.’s guarantees limit its exposure to a maximum amount that is stated in the guarantees. As of Dec. 31, 2013, Xcel Energy had guarantees outstanding with a maximum stated amount of approximately $19.4 million and $0.3 million of exposure. Xcel Energy also had additional guarantees of $32.1 million at Dec. 31, 2013 for performance and payment of surety bonds for the benefit of itself and its subsidiaries, with total exposure that cannot be estimated at this time. If Xcel Energy Inc. were to become obligated to make payments under these guarantees and bond indemnities or become obligated to fund other contingent liabilities, it could limit Xcel Energy Inc.’s ability to contribute equity or make loans to us, or may cause Xcel Energy Inc. to seek additional or accelerated funding from us in the form of dividends. If such event were to occur, we may need to seek alternative sources of funds to meet our cash needs.
We are a wholly owned subsidiary of Xcel Energy Inc. Xcel Energy Inc. can exercise substantial control over our dividend policy and business and operations and may exercise that control in a manner that may be perceived to be adverse to our interests.
All of the members of our board of directors, as well as many of our executive officers, are officers of Xcel Energy Inc. Our board makes determinations with respect to a number of significant corporate events, including the payment of our dividends.
We have historically paid quarterly dividends to Xcel Energy Inc. In 2013, 2012 and 2011 we paid $235.5 million, $234.1 million and $232.5 million of dividends to Xcel Energy Inc., respectively. If Xcel Energy Inc.’s cash requirements increase, our board of directors could decide to increase the dividends we pay to Xcel Energy Inc. to help support Xcel Energy Inc.’s cash needs. This could adversely affect our liquidity. The most restrictive dividend limitation for NSP-Minnesota is imposed by our state regulatory commissions. State regulatory commissions indirectly limit the amount of dividends NSP-Minnesota can pay to Xcel Energy Inc., by requiring a minimum equity-to-total capitalization ratio. See Item 5 for further discussion on dividend limitations.
Public Policy Risks
We may be subject to legislative and regulatory responses to climate change and emissions, with which compliance could be difficult and costly.
Increased public awareness and concern regarding climate change may result in more regional and/or federal requirements to reduce or mitigate the effects of GHGs. Numerous states have announced or adopted programs to stabilize and reduce GHGs, and federal legislation has been introduced in both houses of Congress. The U.S. continues to participate in international negotiations related to the United Nations Framework Convention on Climate Change. Such legislative and regulatory responses related to climate change and new interpretations of existing laws through climate change litigation create financial risk as our electric generating facilities may be subject to regulation under climate change laws at either the state or federal level in the future. The EPA is regulating GHGs under the CAA. The EPA has regulated GHG emissions from motor vehicles and adopted new permitting requirements for GHG emissions of new and modified large stationary sources, which are applicable to construction of new power plants or power plant modifications that increase emissions above a certain threshold. The EPA has proposed regulations that would establish NSPS for any new fossil fuel-fired power plants that may be built. If adopted, these regulations could significantly increase the cost of building new generating plants. By 2016, the EPA plans to develop and implement GHG regulations applicable to emissions from existing power plants. Such regulations could impose substantial costs on our system.
We have been, and in the future may be subject to climate change lawsuits. An adverse outcome in any of these cases could require substantial capital expenditures and could possibly require payment of substantial penalties or damages. Defense costs associated with such litigation can also be significant. Such payments or expenditures could affect results of operations, cash flows and financial condition if such costs are not recovered through regulated rates.
There are many uncertainties regarding when and in what form climate change legislation or regulations may be enacted. The impact of legislation and regulations will depend on a number of factors, including whether GHG sources in multiple sectors of the economy are regulated, the overall GHG emissions cap level, the degree to which GHG offsets are recognized as compliance options, the allocation of emission allowances to specific sources and the indirect impact of carbon regulation on natural gas and coal prices. While we do not have operations outside of the U.S., any international treaties or accords could have an impact to the extent they lead to future federal or state regulations. Another important factor is our ability to recover the costs incurred to comply with any regulatory requirements that are ultimately imposed. We may not be able to timely recover all costs related to complying with regulatory requirements imposed on us. If our regulators do not allow us to recover all or a part of the cost of capital investment or the O&M costs incurred to comply with the mandates, it could have a material effect on our results of operations.
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We are also subject to a significant number of proposed and potential rules that will impact our coal-fired and other generation facilities. These include rules associated with emissions of SO2 and NOx, mercury, regional haze, ozone, ash management and cooling water intake systems. The costs of investment to comply with these rules could be substantial. We may not be able to timely recover all costs related to complying with regulatory requirements imposed on us.
Increased risks of regulatory penalties could negatively impact our business.
The Energy Act increased civil penalty authority for violation of FERC statutes, rules and orders. The FERC can now impose penalties of $1 million per violation per day. In addition, NERC electric reliability standards are now mandatory and subject to potential financial penalties by regional entities, the NERC or the FERC for violations. If a serious reliability incident did occur, it could have a material effect on our operations or financial results.
The FERC issued NOVs of its market manipulation rules to several market participants during 2013. The potential penalties in one pending case exceed $400 million.We attempt to mitigate this risk through formal training on such prohibited practices and a compliance function that reviews our interaction with the markets under FERC and CFTC jurisdictions. However, there is no guarantee our compliance program will be sufficient to ensure against violations.
Macroeconomic Risks
Economic conditions could negatively impact our business.
Our operations are affected by local, national and worldwide economic conditions. The consequences of a prolonged economic recession and uncertainty of recovery has lowered the correlation between sales and economic growth. Sales growth has been relatively flat due to lower level of economic activity, increased focus on energy efficiency and distributed generation. Instability in the financial markets also may affect the cost of capital and our ability to raise capital, which are discussed in greater detail in the capital market risk section above.
Economic conditions may be impacted by insufficient financial sector liquidity leading to potential increased unemployment, which may impact customers’ ability to pay timely, increase customer bankruptcies, and may lead to increased bad debt.
Further, worldwide economic activity has an impact on the demand for basic commodities needed for utility infrastructure, such as steel, copper, aluminum, etc., which may impact our ability to acquire sufficient supplies. Additionally, the cost of those commodities may be higher than expected.
Our operations could be impacted by war, acts of terrorism, and threats of terrorism or disruptions in normal operating conditions due to localized or regional events.
Our generation plants, fuel storage facilities, transmission and distribution facilities and information systems may be targets of terrorist activities that could disrupt our ability to produce or distribute some portion of our energy products. Any such disruption could result in a decrease in revenues and additional costs to repair and insure our assets. These disruptions could have a material impact on our financial condition and results of operations. The potential for terrorism has subjected our operations to increased risks and could have a material effect on our business. We have already incurred increased costs for security and capital expenditures in response to these risks. In addition, we may experience additional capital and operating costs to implement security for our plants, including our nuclear power plants under the NRC’s design basis threat requirements, such as additional physical plant security and additional security personnel. We have also already incurred increased costs for compliance with NERC reliability standards associated with critical infrastructure protection, and may experience additional capital and operating costs to comply with the NERC critical infrastructure protection standards as they are implemented and clarified.
The insurance industry has also been affected by these events and the availability of insurance may decrease. In addition, the insurance we are able to obtain may have higher deductibles, higher premiums and more restrictive policy terms.
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A disruption of the regional electric transmission grid, interstate natural gas pipeline infrastructure or other fuel sources, could negatively impact our business. Because our generation, transmission systems and local natural gas distribution companies are part of an interconnected system, we face the risk of possible loss of business due to a disruption caused by the actions of a neighboring utility or an event (severe storm, severe temperature extremes, generator or transmission facility outage, pipeline rupture, railroad disruption, sudden and significant increase or decrease in wind generation, or any disruption of work force such as may be caused by flu or other epidemic) within our operating systems or on a neighboring system. Any such disruption could result in a significant decrease in revenues and significant additional costs to repair assets, which could have a material impact on our financial condition and results.
The degree to which we are able to maintain day-to-day operations in response to unforeseen events will in part determine the financial impact of certain events on our financial condition and results. It is difficult to predict the magnitude of such events and associated impacts.
A cyber incident or cyber security breach could have a material effect on our business.
We operate in a highly regulated industry that requires the continued operation of sophisticated information technology systems and network infrastructure. In addition, in the ordinary course of business, we use our systems and infrastructure to create, collect, use, disclose, store, dispose of and otherwise process sensitive information, including company data, customer energy usage data, and personal information regarding customers, employees and their dependents, contractors and other individuals.
Our generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or physical assets, as well as the information processed in our systems (e.g., information about our customers, employees, operations, infrastructure and assets) could be directly or indirectly affected by unintentional or deliberate cyber security incidents, including those caused by human error. Our industry has begun to see an increased volume and sophistication of cyber security incidents from international activist organizations, Nation States, and individuals. Cyber security incidents could harm our businesses by limiting our generating, transmitting and distributing capabilities, delaying our development and construction of new facilities or capital improvement projects to existing facilities, disrupting our customer operations, or exposing us to liability. Our generation, transmission systems and natural gas pipelines are part of an interconnected system. Therefore, a disruption caused by the impact of a cyber security incident of the regional electric transmission grid, natural gas pipeline infrastructure or other fuel sources of our third party service providers’ operations, could also negatively impact our business. In addition, we also anticipate that such an event would receive regulatory scrutiny at both the Federal and State level. We are unable to quantify the potential impact of such cyber security threats or subsequent related actions. These potential cyber security incidents and corresponding regulatory action could result in a material decrease in revenues and may cause significant additional costs (e.g., penalties, third party claims, repairs, insurance or compliance) and potentially disrupt our supply and markets for natural gas, oil and other fuels.
We maintain security measures designed to protect our information technology systems, network infrastructure and other assets. However, these assets and the information they process may be vulnerable to cyber security incidents, including the resulting disability, or failures of assets or unauthorized access to assets or information. If our technology systems were to fail or be breached, or those of our third-party service providers, we may be unable to fulfill critical business functions, including effectively maintaining certain internal controls over financial reporting. We are unable to quantify the potential impact of cyber security incidents on our business.
Rising energy prices could negatively impact our business.
Higher fuel costs could significantly impact our results of operations if requests for recovery are unsuccessful. In addition, higher fuel costs could reduce customer demand and/or increase bad debt expense, which could also have a material impact on our results of operations. Delays in the timing of the collection of fuel cost recoveries as compared with expenditures for fuel purchases could have an impact on our cash flows. We are unable to predict future prices or the ultimate impact of such prices on our results of operations or cash flows.
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Our operating results may fluctuate on a seasonal and quarterly basis and can be adversely affected by milder weather.
Our electric and natural gas utility businesses are seasonal, and weather patterns can have a material impact on our operating performance. Demand for electricity is often greater in the summer and winter months associated with cooling and heating. Because natural gas is heavily used for residential and commercial heating, the demand for this product depends heavily upon weather patterns throughout our service territory, and a significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. Accordingly, our operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer. Unusually mild winters and summers could have an adverse effect on our financial condition, results of operations, or cash flows.
Item 1B — Unresolved Staff Comments
None.
Item 2 — Properties
Virtually all of the utility plant property of NSP-Minnesota is subject to the lien of its first mortgage bond indenture.
| Electric Utility Generating Stations: | ||||||||
| Station, Location and Unit | Fuel | Installed | Summer 2013 Net Dependable Capability (MW) | |||||
| Steam: | ||||||||
| A.S. King-Bayport, Minn., 1 Unit | Coal | 1968 | 511 | |||||
| Sherco-Becker, Minn. | ||||||||
| Unit 1 | Coal | 1976 | 680 | |||||
| Unit 2 | Coal | 1977 | 682 | |||||
| Unit 3 | Coal | 1987 | 507 | (a) | ||||
| Monticello-Monticello, Minn., 1 Unit | Nuclear | 1971 | 554 | |||||
| Prairie Island-Welch, Minn. | ||||||||
| Unit 1 | Nuclear | 1973 | 521 | |||||
| Unit 2 | Nuclear | 1974 | 519 | |||||
| Black Dog-Burnsville, Minn., 2 Units | Coal/Natural Gas | 1955-1960 | 232 | |||||
| Various locations, 4 Units | Wood/Refuse-derived fuel | Various | 36 | (b) | ||||
| Combustion Turbine: | ||||||||
| Angus Anson-Sioux Falls, S.D., 3 Units | Natural Gas | 1994-2005 | 327 | |||||
| Black Dog-Burnsville, Minn., 2 Units | Natural Gas | 1987-2002 | 271 | |||||
| Blue Lake-Shakopee, Minn., 6 Units | Natural Gas | 1974-2005 | 453 | |||||
| High Bridge-St. Paul, Minn., 3 Units | Natural Gas | 2008 | 534 | |||||
| Inver Hills-Inver Grove Heights, Minn., 6 Units | Natural Gas | 1972 | 282 | |||||
| Riverside-Minneapolis, Minn., 3 Units | Natural Gas | 2009 | 470 | |||||
| Various locations, 17 Units | Natural Gas | Various | 101 | |||||
| Wind: | ||||||||
| Grand Meadow-Mower County, Minn., 67 Units | Wind | 2008 | 101 | (c) | ||||
| Nobles-Nobles County, Minn., 134 Units | Wind | 2010 | 201 | (c) | ||||
| Total | 6,982 | |||||||
(a) | Based on NSP-Minnesota’s ownership of 59 percent. |
(b) | Refuse-derived fuel is made from municipal solid waste. |
(c) | This capacity is only available when wind conditions are sufficiently high enough to support the noted generation values above. Therefore, the on-demand net dependable capacity is zero. |
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Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2013:
| Conductor Miles | ||
| 500 KV | 2,917 | |
| 345 KV | 6,392 | |
| 230 KV | 1,802 | |
| 161 KV | 353 | |
| 115 KV | 7,552 | |
| Less than 115 KV | 83,469 | |
NSP-Minnesota had 351 electric utility transmission and distribution substations at Dec. 31, 2013.
Natural gas utility mains at Dec. 31, 2013:
| Miles | ||
| Transmission | 137 | |
| Distribution | 9,855 | |
Item 3 — Legal Proceedings
NSP-Minnesota is involved in various litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.
Additional Information
See Note 11 to the consolidated financial statements for further discussion of legal claims and environmental proceedings. See Item 1 and Note 10 to the consolidated financial statements for a discussion of proceedings involving utility rates and other regulatory matters.
Item 4 — Mine Safety Disclosures
None.
PART II
Item 5 — Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
NSP-Minnesota is a wholly owned subsidiary of Xcel Energy Inc. and there is no market for its common equity securities.
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 this restriction, NSP-Minnesota could have paid more than $1.4 billion and $1.3 billion in additional cash dividends on common stock at Dec. 31, 2013 and 2012, respectively.
In addition, NSP-Minnesota has dividend restrictions imposed by FERC rules and state regulatory commissions:
| • | 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. |
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| • | The most restrictive dividend limitation for NSP-Minnesota is imposed by its state regulatory commissions. 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 46.8 percent and 57.2 percent. NSP-Minnesota’s equity-to-capitalization ratio was 52.5 percent at Dec. 31, 2013 and $912 million in retained earnings was not restricted. Total capitalization for NSP-Minnesota was $8.5 billion at Dec. 31, 2013, which did not exceed the limits imposed by the commissions of $9.0 billion. |
See Note 4 to the consolidated financial statements for further discussion of NSP-Minnesota’s dividend policy.
The dividends declared during 2013 and 2012 were as follows:
| (Thousands of Dollars) | 2013 | 2012 | ||||||
| First quarter | $ | 58,690 | $ | 58,028 | ||||
| Second quarter | 59,308 | 59,021 | ||||||
| Third quarter | 58,744 | 59,005 | ||||||
| Fourth quarter | 58,751 | 58,757 | ||||||
Item 6 — Selected Financial Data
This is omitted per conditions set forth in general instructions I(1)(a) and (b) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).
Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations
Discussion of financial condition and liquidity for NSP-Minnesota is omitted per conditions set forth in general instructions I(1)(a) and (b) of Form 10-K for wholly owned subsidiaries. It is replaced with management’s narrative analysis and the results of operations for the current year as set forth in general instructions I(2)(a) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).
Financial Review
The following discussion and analysis by management focuses on those factors that had a material effect on NSP-Minnesota’s financial condition, results of operations and cash flows during the periods presented, or are expected to have a material impact in the future. It should be read in conjunction with the accompanying consolidated financial statements and related notes to the consolidated financial statements.
Forward-Looking Statements
Except for the historical statements contained in this report, the matters discussed in the following discussion and analysis are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made and we do not undertake any obligation to update them to reflect changes that occur after that date. Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures and the ability of NSP-Minnesota and its subsidiaries to obtain financing on favorable terms; business conditions in the energy industry, including the risk of a slow down in the U.S. economy or delay in growth recovery; trade, fiscal, taxation and environmental policies in areas where NSP-Minnesota has a financial interest; customer business conditions; actions of credit rating agencies; competitive factors, including the extent and timing of the entry of additional competition in the markets served by NSP-Minnesota and its subsidiaries; unusual weather; effects of geopolitical events, including war and acts of terrorism; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates or have an impact on asset operation or ownership or impose environmental compliance conditions; structures that affect the speed and degree to which competition enters the electric and natural gas markets; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; actions by regulatory bodies impacting NSP-Minnesota’s nuclear operations, including those affecting costs, operations or the approval of requests pending before the NRC; financial or regulatory accounting policies imposed by regulatory bodies; availability or cost of capital; employee workforce factors; and the other risk factors listed from time to time by NSP-Minnesota in reports filed with the SEC, including “Risk Factors” in Item 1A of this Annual Report on Form 10-K and Exhibit 99.01 hereto.
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Results of Operations
NSP-Minnesota’s net income was approximately $393 million for 2013, compared with approximately $340 million for 2012. Earnings were positively impacted by electric rate increases in Minnesota and South Dakota, interim rates subject to refund in North Dakota, the impact of cooler winter weather and lower interest charges. These items were partially offset by higher O&M expenses.
Electric Revenues and Margin
Electric revenues and fuel and purchased power expenses are largely impacted by the fluctuation in the price of natural gas, coal and uranium used in the generation of electricity, but as a result of the design of fuel recovery mechanisms to recover current expenses, these price fluctuations have little impact on electric margin. The following table details the electric revenues and margin:
| (Millions of Dollars) | 2013 | 2012 | ||||||
| Electric revenues | $ | 4,062 | $ | 3,843 | ||||
| Electric fuel and purchased power | (1,684 | ) | (1,562 | ) | ||||
| Electric margin | $ | 2,378 | $ | 2,281 | ||||
The following tables summarize the components of the changes in electric revenues and electric margin for the year ended Dec. 31:
Electric Revenues
| (Millions of Dollars) | 2013 vs. 2012 | |||
Retail rate increases (a) | $ | 130 | ||
| Fuel and purchased power cost recovery | 93 | |||
| Transmission revenue | 47 | |||
| Estimated impact of weather | 17 | |||
| Conservation program revenue (offset by expenses) | (19 | ) | ||
| Conservation program incentives | (13 | ) | ||
| Retail sales decrease (excluding weather impact) | (13 | ) | ||
| Other, net | (23 | ) | ||
| Total increase in electric revenues | $ | 219 | ||
Electric Margin
| (Millions of Dollars) | 2013 vs. 2012 | |||
Retail rate increases (a) | $ | 130 | ||
| Transmission revenue, net of costs | 29 | |||
| Estimated impact of weather | 17 | |||
| Conservation program revenue (offset by expenses) | (19 | ) | ||
| Conservation program incentives | (13 | ) | ||
| Retail sales decrease (excluding weather impact) | (13 | ) | ||
| Other, net | (34 | ) | ||
| Total increase in electric margin | $ | 97 | ||
(a) | The retail rate increases include final rates in Minnesota and South Dakota and interim rates, subject to refund, in North Dakota. The Minnesota rate increase is net of a provision for customer refunds of $131 million for 2013 based on the final rate order received for the 2013 electric rate case. Due to the order, there was a reduction in revenues and expenses of approximately $40 million, primarily related to depreciation of $32 million and O&M expense of $8 million in 2013. |
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Natural Gas Revenues and Margin
The cost of natural gas tends to vary with changing sales requirements and the cost of natural gas purchases. However, due to the design of purchased natural gas cost recovery mechanisms to recover current expenses for sales to retail customers, fluctuations in the cost of natural gas have little effect on natural gas margin. The following table details natural gas revenues and margin:
| (Millions of Dollars) | 2013 | 2012 | ||||||
| Natural gas revenues | $ | 591 | $ | 472 | ||||
| Cost of natural gas sold and transported | (380 | ) | (287 | ) | ||||
| Natural gas margin | $ | 211 | $ | 185 | ||||
The following tables summarize the components of the changes in natural gas revenues and natural gas margin for the year ended Dec. 31:
Natural Gas Revenues
| (Millions of Dollars) | 2013 vs. 2012 | |||
| Purchased natural gas adjustment clause recovery | $ | 88 | ||
| Estimated impact of weather | 20 | |||
| Conservation program revenue (offset by expenses) | 5 | |||
| Retail sales increase (excluding weather impact) | 4 | |||
| Conservation program incentives | 3 | |||
| Other, net | (1 | ) | ||
| Total increase in natural gas revenues | $ | 119 | ||
Natural Gas Margin
| (Millions of Dollars) | 2013 vs. 2012 | |||
| Estimated impact of weather | $ | 20 | ||
| Conservation program revenue (offset by expenses) | 5 | |||
| Retail sales increase (excluding weather impact) | 4 | |||
| Conservation program incentives | 3 | |||
| Other, net | (6 | ) | ||
| Total increase in natural gas margin | $ | 26 | ||
Non-Fuel Operating Expenses and Other Items
O&M Expenses — O&M expenses increased $69.6 million, or 6.3 percent, for 2013 compared with 2012. The following table summarizes the changes in O&M expenses for the year ended Dec. 31:
| (Millions of Dollars) | 2013 vs. 2012 | |||
| Nuclear plant operations and amortization | $ | 33 | ||
| Electric and gas distribution expenses | 14 | |||
| Interchange agreement billing with NSP-Wisconsin | 8 | |||
| Employee benefits | 7 | |||
| Transmission costs | 4 | |||
| Other, net | 4 | |||
| Total increase in O&M expenses | $ | 70 | ||
| • | Nuclear cost increases are related to the amortization of prior outages and initiatives designed to improve the operational efficiencies of the plants; and |
| • | Electric and gas distribution expenses were primarily driven by increased maintenance activities due to outages, storms and vegetation management. |
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Conservation Program Expenses — Conservation program expenses decreased $13.4 million, or 12.1 percent, for 2013 compared with 2012. The decrease is primarily attributable to the timing of recovery of electric conservation program expenses partially offset by higher gas rates used to recover program expenses and higher gas volumes. Conservation program expenses are generally recovered in our major jurisdictions concurrently through riders and base rates.
Depreciation and Amortization — Depreciation and amortization expense increased $15.2 million, or 3.8 percent, for 2013 compared with 2012. The increase is primarily attributable to normal system expansion, which was partially offset by reductions related to the final rate order received for the 2013 Minnesota electric rate case that reduced depreciation expense by approximately $32 million for 2013.
Interest Charges — Interest charges decreased $9.3 million, or 4.6 percent, for 2013 compared with 2012. The decrease is primarily due to refinancings at lower interest rates. This was partially offset by higher long-term debt levels and $5 million of interest associated with customer refunds in Minnesota for the 2013 electric rate case.
Income Taxes — Income tax expense increased $6.3 million for 2013 compared with 2012. The increase in income tax expense was primarily due to higher pretax earnings in 2013 and a discrete tax benefit of approximately $15.0 million for a carryback in 2012. These were partially offset by recognition of research and experimentation credits in 2013 and a tax benefit for a carryback claim related to 2013. The ETR was 31.6 percent for 2013 compared with 34.0 percent for 2012. The lower ETR for 2013 was primarily due to the tax benefit for the carryback claim related to 2013 and research and experimentation credits in 2013. These were partially offset by the carryback adjustment in 2012.
Item 7A — Quantitative and Qualitative Disclosures About Market Risk
Derivatives, Risk Management and Market Risk
In the normal course of business, NSP-Minnesota is exposed to a variety of market risks. Market risk is the potential loss that may occur as a result of adverse changes in the market or fair value of a particular instrument or commodity. All financial and commodity-related instruments, including derivatives, are subject to market risk. See Note 9 to the consolidated financial statements for further discussion of market risks associated with derivatives.
NSP-Minnesota is exposed to the impact of adverse changes in price for energy and energy related products, which is partially mitigated by the use of commodity derivatives. In addition to ongoing monitoring and maintaining credit policies intended to minimize overall credit risk, when necessary, management takes steps to mitigate changes in credit and concentration risks associated with its derivatives and other contracts, including parental guarantees and requests of collateral. While NSP-Minnesota expects that the counterparties will perform under the contracts underlying its derivatives, the contracts expose NSP-Minnesota to some credit and nonperformance risk.
Though no material non-performance risk currently exists with the counterparties to NSP-Minnesota’s commodity derivative contracts, distress in the financial markets may in the future impact that risk to the extent it impacts those counterparties. Distress in the financial markets may also impact the fair value of the securities in the nuclear decommissioning fund and master pension trust, as well as NSP-Minnesota’s ability to earn a return on short-term investments of excess cash.
Commodity Price Risk — NSP-Minnesota is exposed to commodity price risk in its electric and natural gas operations. Commodity price risk is managed by entering into long- and short-term physical purchase and sales contracts for electric capacity, energy and energy-related products and for various fuels used in generation and distribution activities. Commodity price risk is also managed through the use of financial derivative instruments. NSP-Minnesota’s risk management policy allows it to manage commodity price risk within each rate-regulated operation to the extent such exposure exists.
Wholesale and Commodity Trading Risk — NSP-Minnesota conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and energy-related instruments. NSP-Minnesota’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.
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At Dec. 31, 2013, the fair values by source for net commodity trading contract assets were as follows:
| Futures / Forwards | |||||||||||||||||||||||
| (Thousands of Dollars) | Source of Fair Value | Maturity Less Than 1 Year | Maturity 1 to 3 Years | Maturity 4 to 5 Years | Maturity Greater Than 5 Years | Total Futures/ Forwards Fair Value | |||||||||||||||||
| NSP-Minnesota | 1 | $ | 9,746 | $ | 16,918 | $ | 2,516 | $ | 1,049 | $ | 30,229 | ||||||||||||
| 2 | (646 | ) | — | — | 604 | (42 | ) | ||||||||||||||||
| $ | 9,100 | $ | 16,918 | $ | 2,516 | $ | 1,653 | $ | 30,187 | ||||||||||||||
| Options | |||||||||||||||||||||||
| (Thousands of Dollars) | Source of Fair Value | Maturity Less Than 1 Year | Maturity 1 to 3 Years | Maturity 4 to 5 Years | Maturity Greater Than 5 Years | Total Options Fair Value | |||||||||||||||||
| NSP-Minnesota | 2 | $ | 9 | $ | — | $ | — | $ | — | $ | 9 | ||||||||||||
1 — Prices actively quoted or based on actively quoted prices.
2 — Prices based on models and other valuation methods.
Changes in the fair value of commodity trading contracts before the impacts of margin-sharing mechanisms for the years ended Dec. 31 were as follows:
| (Thousands of Dollars) | 2013 | 2012 | ||||||
| Fair value of commodity trading net contract assets outstanding at Jan. 1 | $ | 27,522 | $ | 19,160 | ||||
| Contracts realized or settled during the period | (11,651 | ) | (10,827 | ) | ||||
| Commodity trading contract additions and changes during the period | 14,325 | 19,189 | ||||||
| Fair value of commodity trading net contract assets outstanding at Dec. 31 | $ | 30,196 | $ | 27,522 | ||||
At Dec. 31, 2013, a 10 percent increase in market prices for commodity trading contracts would decrease pretax income by approximately $0.6 million, whereas a 10 percent decrease would increase pretax income by approximately $0.6 million. At Dec. 31, 2012, a 10 percent increase in market prices for commodity trading contracts would increase pretax income by approximately $0.5 million, whereas a 10 percent decrease would decrease pretax income by approximately $0.5 million.
NSP-Minnesota’s wholesale and commodity trading operations measure the outstanding risk exposure to price changes on transactions, contracts and obligations that have been entered into, but not closed, including transactions that are not recorded at fair value, using an industry standard methodology known as Value-at-Risk (VaR). VaR expresses the potential change in fair value on the outstanding transactions, contracts and obligations over a particular period of time under normal market conditions.
The VaRs for the NSP-Minnesota and PSCo commodity trading operations, calculated on a consolidated basis using a Monte Carlo simulation with a 95 percent confidence level and a one-day holding period, were as follows:
| (Millions of Dollars) | Year Ended Dec. 31 | VaR Limit | Average | High | Low | |||||||||||||||
| 2013 | $ | 0.29 | $ | 3.00 | $ | 0.41 | $ | 1.65 | $ | < 0.01 | ||||||||||
| 2012 | 0.45 | 3.00 | 0.36 | 1.56 | 0.06 | |||||||||||||||
Interest Rate Risk — NSP-Minnesota is subject to the risk of fluctuating interest rates in the normal course of business. NSP-Minnesota’s risk management policy allows interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate derivatives such as swaps, caps, collars and put or call options.
In conjunction with the NSP-Minnesota debt issuance in August 2012, NSP-Minnesota settled interest rate hedging instruments with a notional amount of $225 million with cash payments of $45.0 million. This loss is classified as a component of accumulated other comprehensive loss on the consolidated balance sheet, net of tax, and is being reclassified to earnings over the term of the hedged interest payments. See Note 4 to the consolidated financial statements for further discussion of long-term borrowings.
37
At Dec. 31, 2013 and 2012, a 100-basis-point change in the benchmark rate on NSP-Minnesota’s variable rate debt would impact pretax interest expense annually by approximately $1.7 million and $2.2 million, respectively. See Note 9 to the consolidated financial statements for a discussion of NSP-Minnesota’s interest rate derivatives.
NSP-Minnesota also maintains a nuclear decommissioning fund, as required by the NRC. The nuclear decommissioning fund is subject to interest rate risk and equity price risk. At Dec. 31, 2013, the fund was invested in a diversified portfolio of cash equivalents, debt securities, equity securities, and other investments. These investments may be used only for activities related to nuclear decommissioning. 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. Since the accounting for nuclear decommissioning recognizes that costs are recovered through rates, fluctuations in equity prices or interest rates do not have an impact on earnings.
Credit Risk — NSP-Minnesota is also exposed to credit risk. Credit risk relates to the risk of loss resulting from counterparties’ nonperformance on their contractual obligations. NSP-Minnesota maintains credit policies intended to minimize overall credit risk and actively monitors these policies to reflect changes and scope of operations.
At Dec. 31, 2013, a 10 percent increase in commodity prices would have resulted in an increase in credit exposure of $3.9 million, while a decrease in prices of 10 percent would have resulted in an increase in credit exposure of $4.8 million. At Dec. 31, 2012, a 10 percent increase in commodity prices would have resulted in a decrease in credit exposure of $10.2 million, while a decrease in prices of 10 percent would have resulted in an increase in credit exposure of $11.1 million.
NSP-Minnesota conducts standard credit reviews for all counterparties. NSP-Minnesota employs additional credit risk control mechanisms when appropriate, such as letters of credit, parental guarantees, standardized master netting agreements and termination provisions that allow for offsetting of positive and negative exposures. Credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided. Distress in financial markets could increase NSP-Minnesota’s credit risk.
Fair Value Measurements
NSP-Minnesota follows accounting and disclosure guidance on fair value measurements that contains a hierarchy for inputs used in measuring fair value and requires disclosure of the observability of the inputs used in these measurements. See Note 9 to the consolidated financial statements for further discussion of the fair value hierarchy and the amounts of assets and liabilities measured at fair value that have been assigned to Level 3.
Commodity Derivatives — NSP-Minnesota 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 and the typically short duration of these contracts, the impact of discounting commodity derivative assets for counterparty credit risk was not material to the fair value of commodity derivative assets at Dec. 31, 2013. NSP-Minnesota also assesses the impact of its own credit risk when determining the fair value of commodity derivative liabilities. The impact of discounting commodity derivative liabilities for credit risk was immaterial to the fair value of commodity derivative liabilities at Dec. 31, 2013.
Commodity derivative assets and liabilities assigned to Level 3 typically consist of FTRs, as well as forwards and options that are long-term in nature. Level 3 commodity derivative assets and liabilities represent 2.1 percent and 13.6 percent of gross assets and liabilities, respectively, measured at fair value at Dec. 31, 2013.
Determining the fair value of FTRs requires numerous management forecasts that vary in observability, including various forward commodity prices, retail and wholesale demand, generation and resulting transmission system congestion. Given the limited observability of management’s forecasts for several of these inputs, these instruments have been assigned a Level 3. Level 3 commodity derivatives assets and liabilities included $31.9 million and $3.5 million of estimated fair values, respectively, for FTRs held at Dec. 31, 2013.
38
Determining the fair value of certain commodity forwards and options can require management to make use of subjective price and volatility forecasts which extend to periods beyond those readily observable on active exchanges or quoted by brokers. When less observable forward price and volatility forecasts are significant to determining the value of commodity forwards and options, these instruments are assigned to Level 3. Level 3 commodity derivative assets and liabilities included $3.4 million and zero of estimated fair values, respectively, for forwards held at Dec. 31, 2013. There were no Level 3 options held at Dec. 31, 2013.
Nuclear Decommissioning Fund — Nuclear decommissioning fund assets assigned to Level 3 consist of private equity investments and real estate investments. Based on an evaluation of NSP-Minnesota’s ability to redeem private equity investments and real estate investment funds measured at net asset value, estimated fair values for these investments totaling $120.1 million in the nuclear decommissioning fund at Dec. 31, 2013 (approximately 7.0 percent of total assets measured at fair value) are assigned to Level 3. Realized and unrealized gains and losses on nuclear decommissioning fund investments are deferred as a regulatory asset.
Item 8 — Financial Statements and Supplementary Data
See Item 15-1 in Part IV for an index of financial statements included herein.
See Note 17 to the consolidated financial statements for summarized quarterly financial data.
39
Management Report on Internal Controls Over Financial Reporting
The management of NSP-Minnesota is responsible for establishing and maintaining adequate internal control over financial reporting. NSP-Minnesota’s internal control system was designed to provide reasonable assurance to Xcel Energy Inc.’s and NSP-Minnesota’s management and board of directors regarding the preparation and fair presentation of published financial statements.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
NSP-Minnesota management assessed the effectiveness of NSP-Minnesota’s internal control over financial reporting as of Dec. 31, 2013. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework (1992). Based on our assessment, we believe that, as of Dec. 31, 2013, NSP-Minnesota’s internal control over financial reporting is effective at the reasonable assurance level based on those criteria.
| /s/ DAVID M. SPARBY | /s/ TERESA S. MADDEN | |
| David M. Sparby | Teresa S. Madden | |
| President, Chief Executive Officer and Director | Senior Vice President, Chief Financial Officer and Director | |
| Feb. 24, 2014 | Feb. 24, 2014 | |
40
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholder of
Northern States Power Company, a Minnesota corporation
We have audited the accompanying consolidated balance sheets and statements of capitalization of Northern States Power Company, a Minnesota corporation, and subsidiaries (the “Company”) as of December 31, 2013 and 2012, and the related consolidated statements of income, comprehensive income, cash flows, and common stockholder’s equity for each of the three years in the period ended December 31, 2013. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Northern States Power Company, a Minnesota corporation, and subsidiaries as of December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
| /s/ DELOITTE & TOUCHE LLP |
| Minneapolis, Minnesota |
| February 24, 2014 |
41
NSP-MINNESOTA AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (amounts in thousands) | |||||||||||
| Year Ended Dec. 31 | |||||||||||
| 2013 | 2012 | 2011 | |||||||||
| Operating revenues | |||||||||||
| Electric, non-affiliates | $ | 3,603,807 | $ | 3,392,571 | $ | 3,332,109 | |||||
| Electric, affiliates | 458,633 | 449,958 | 440,519 | ||||||||
| Natural gas | 591,017 | 471,765 | 604,723 | ||||||||
| Other | 26,153 | 23,045 | 21,170 | ||||||||
| Total operating revenues | 4,679,610 | 4,337,339 | 4,398,521 | ||||||||
| Operating expenses | |||||||||||
| Electric fuel and purchased power | 1,683,977 | 1,562,286 | 1,542,760 | ||||||||
| Cost of natural gas sold and transported | 380,058 | 287,152 | 393,672 | ||||||||
| Cost of sales — other | 16,154 | 13,505 | 12,737 | ||||||||
| Operating and maintenance expenses | 1,171,855 | 1,102,302 | 1,064,665 | ||||||||
| Conservation program expenses | 96,635 | 109,989 | 138,001 | ||||||||
| Depreciation and amortization | 414,588 | 399,432 | 381,025 | ||||||||
| Taxes (other than income taxes) | 206,741 | 204,387 | 172,726 | ||||||||
| Total operating expenses | 3,970,008 | 3,679,053 | 3,705,586 | ||||||||
| Operating income | 709,602 | 658,286 | 692,935 | ||||||||
| Other (expense) income, net | (653 | ) | 979 | 1,717 | |||||||
| Allowance for funds used during construction — equity | 40,064 | 37,109 | 37,164 | ||||||||
| Interest charges and financing costs | |||||||||||
Interest charges — includes other financing costs of $6,337, $5,972 and $6,264 respectively | 191,889 | 201,158 | 208,003 | ||||||||
| Allowance for funds used during construction — debt | (18,079 | ) | (20,449 | ) | (20,817 | ) | |||||
| Total interest charges and financing costs | 173,810 | 180,709 | 187,186 | ||||||||
| Income before income taxes | 575,203 | 515,665 | 544,630 | ||||||||
| Income taxes | 181,857 | 175,524 | 191,649 | ||||||||
| Net income | $ | 393,346 | $ | 340,141 | $ | 352,981 | |||||
| See Notes to Consolidated Financial Statements | |||||||||||
42
NSP-MINNESOTA AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (amounts in thousands) | |||||||||||
| Year Ended Dec. 31 | |||||||||||
| 2013 | 2012 | 2011 | |||||||||
| Net income | $ | 393,346 | $ | 340,141 | $ | 352,981 | |||||
| Other comprehensive income (loss) | |||||||||||
| Pension and retiree medical benefits: | |||||||||||
Net pension and retiree medical benefits gains arising during the period, net of tax of $294, $315 and $97, respectively | 423 | 460 | 140 | ||||||||
Amortization of losses (gains) included in net periodic benefit cost, net of tax of $63, $106 and $(362), respectively | 91 | 161 | (528 | ) | |||||||
| 514 | 621 | (388 | ) | ||||||||
| Derivative instruments: | |||||||||||
Net fair value increase (decrease), net of tax of $10, $(6,885) and $(11,422), respectively | 5 | (9,889 | ) | (16,578 | ) | ||||||
Reclassification of losses (gains) to net income, net of tax of $560, $156 and $(94), respectively | 779 | 225 | (128 | ) | |||||||
| 784 | (9,664 | ) | (16,706 | ) | |||||||
| Marketable securities: | |||||||||||
Net fair value increase (decrease), net of tax of $120, $135 and $(63), respectively | 172 | 196 | (92 | ) | |||||||
| Other comprehensive income (loss) | 1,470 | (8,847 | ) | (17,186 | ) | ||||||
| Comprehensive income | $ | 394,816 | $ | 331,294 | $ | 335,795 | |||||
| See Notes to Consolidated Financial Statements | |||||||||||
43
NSP-MINNESOTA AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (amounts in thousands) | |||||||||||
| Year Ended Dec. 31 | |||||||||||
| 2013 | 2012 | 2011 | |||||||||
| Operating activities | |||||||||||
| Net income | $ | 393,346 | $ | 340,141 | $ | 352,981 | |||||
| Adjustments to reconcile net income to cash provided by operating activities: | |||||||||||
| Depreciation and amortization | 419,852 | 404,325 | 386,310 | ||||||||
| Nuclear fuel amortization | 98,089 | 102,651 | 100,902 | ||||||||
| Deferred income taxes | 168,444 | 239,981 | 196,120 | ||||||||
| Amortization of investment tax credits | (1,813 | ) | (2,700 | ) | (2,694 | ) | |||||
| Allowance for equity funds used during construction | (40,064 | ) | (37,109 | ) | (37,164 | ) | |||||
| Provision for bad debts | 13,418 | 11,241 | 15,936 | ||||||||
| Prairie Island extended power uprate | — | 10,100 | — | ||||||||
| Net realized and unrealized hedging and derivative transactions | (4,175 | ) | (53,881 | ) | (182 | ) | |||||
| Changes in operating assets and liabilities: | |||||||||||
| Accounts receivable | 3,220 | (214,886 | ) | (8,195 | ) | ||||||
| Accrued unbilled revenues | (25,748 | ) | 1,639 | 18,090 | |||||||
| Inventories | (19,404 | ) | 41,090 | (21,675 | ) | ||||||
| Other current assets | 22,316 | (30,708 | ) | (614 | ) | ||||||
| Accounts payable | 68,003 | (29,055 | ) | (33,806 | ) | ||||||
| Net regulatory assets and liabilities | 10,703 | (15,416 | ) | 75,390 | |||||||
| Other current liabilities | 36,709 | 33,727 | 91,532 | ||||||||
| Pension and other employee benefit obligations | (59,953 | ) | (71,149 | ) | (39,925 | ) | |||||
| Change in other noncurrent assets | (9,599 | ) | (14,465 | ) | (7,330 | ) | |||||
| Change in other noncurrent liabilities | (4,463 | ) | (552 | ) | (36,345 | ) | |||||
| Net cash provided by operating activities | 1,068,881 | 714,974 | 1,049,331 | ||||||||
| Investing activities | |||||||||||
| Utility capital/construction expenditures | (1,548,952 | ) | (1,172,403 | ) | (1,028,831 | ) | |||||
| Proceeds from insurance recoveries | 90,000 | 97,835 | — | ||||||||
| Merricourt refund | — | — | 101,261 | ||||||||
| Merricourt deposit | — | — | (90,833 | ) | |||||||
| Allowance for equity funds used during construction | 40,064 | 37,109 | 37,164 | ||||||||
| Purchases of investments in external decommissioning fund | (1,481,881 | ) | (1,102,025 | ) | (2,098,642 | ) | |||||
| Proceeds from the sale of investments in external decommissioning fund | 1,461,291 | 1,087,076 | 2,098,642 | ||||||||
| Investments in utility money pool arrangement | (29,000 | ) | — | (432,000 | ) | ||||||
| Repayments from utility money pool arrangement | 29,000 | — | 432,000 | ||||||||
| Advances to affiliate | — | — | (111,300 | ) | |||||||
| Advances from affiliate | — | — | 148,300 | ||||||||
| Change in restricted cash | — | 95,287 | (95,287 | ) | |||||||
| Other, net | (3,716 | ) | (3,507 | ) | (5,668 | ) | |||||
| Net cash used in investing activities | (1,443,194 | ) | (960,628 | ) | (1,045,194 | ) | |||||
| Financing activities | |||||||||||
| (Repayments of) proceeds from short-term borrowings, net | (90,000 | ) | 195,000 | 26,000 | |||||||
| Borrowings under utility money pool arrangement | 997,000 | 1,147,000 | 627,600 | ||||||||
| Repayments under utility money pool arrangement | (963,000 | ) | (1,212,000 | ) | (562,600 | ) | |||||
| Proceeds from issuance of long-term debt | 394,788 | 786,363 | — | ||||||||
| Repayments of long-term debt, including reacquisition premiums | — | (648,874 | ) | (34 | ) | ||||||
| Capital contributions from parent | 285,102 | 215,110 | 125,004 | ||||||||
| Dividends paid to parent | (235,499 | ) | (234,108 | ) | (232,510 | ) | |||||
| Net cash provided by (used in) financing activities | 388,391 | 248,491 | (16,540 | ) | |||||||
| Net change in cash and cash equivalents | 14,078 | 2,837 | (12,403 | ) | |||||||
| Cash and cash equivalents at beginning of period | 28,842 | 26,005 | 38,408 | ||||||||
| Cash and cash equivalents at end of period | $ | 42,920 | $ | 28,842 | $ | 26,005 | |||||
| Supplemental disclosure of cash flow information: | |||||||||||
| Cash paid for interest (net of amounts capitalized) | $ | (166,515 | ) | $ | (187,671 | ) | $ | (181,121 | ) | ||
| Cash paid for income taxes, net | (2,064 | ) | (5,104 | ) | (15,964 | ) | |||||
| Supplemental disclosure of non-cash investing transactions: | |||||||||||
| Property, plant and equipment additions in accounts payable | $ | 234,686 | $ | 125,948 | $ | 35,058 | |||||
| See Notes to Consolidated Financial Statements | |||||||||||
44
NSP-MINNESOTA AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (amounts in thousands, except share and per share data) | ||||||||
| Dec. 31 | ||||||||
| 2013 | 2012 | |||||||
| Assets | ||||||||
| Current assets | ||||||||
| Cash and cash equivalents | $ | 42,920 | $ | 28,842 | ||||
| Accounts receivable, net | 284,532 | 325,143 | ||||||
| Accounts receivable from affiliates | 19,769 | 26,660 | ||||||
| Accrued unbilled revenues | 255,412 | 229,664 | ||||||
| Inventories | 279,915 | 260,758 | ||||||
| Regulatory assets | 207,467 | 156,223 | ||||||
| Derivative instruments | 66,726 | 56,232 | ||||||
| Deferred income taxes | 80,095 | — | ||||||
| Prepayments and other | 118,036 | 94,019 | ||||||
| Total current assets | 1,354,872 | 1,177,541 | ||||||
| Property, plant and equipment, net | 10,589,522 | 9,546,968 | ||||||
| Other assets | ||||||||
| Nuclear decommissioning fund and other investments | 1,655,356 | 1,514,156 | ||||||
| Regulatory assets | 990,204 | 1,039,675 | ||||||
| Derivative instruments | 36,881 | 66,480 | ||||||
| Other | 68,060 | 56,438 | ||||||
| Total other assets | 2,750,501 | 2,676,749 | ||||||
| Total assets | $ | 14,694,895 | $ | 13,401,258 | ||||
| Liabilities and Equity | ||||||||
| Current liabilities | ||||||||
| Current portion of long-term debt | $ | 2 | $ | 2 | ||||
| Short-term debt | 131,000 | 221,000 | ||||||
| Borrowings under utility money pool arrangement | 34,000 | — | ||||||
| Accounts payable | 554,265 | 367,021 | ||||||
| Accounts payable to affiliates | 65,941 | 69,739 | ||||||
| Regulatory liabilities | 101,795 | 53,159 | ||||||
| Taxes accrued | 195,734 | 175,929 | ||||||
| Accrued interest | 59,846 | 58,135 | ||||||
| Dividends payable to parent | 58,752 | 58,757 | ||||||
| Derivative instruments | 13,066 | 20,117 | ||||||
| Other | 104,544 | 102,915 | ||||||
| Total current liabilities | 1,318,945 | 1,126,774 | ||||||
| Deferred credits and other liabilities | ||||||||
| Deferred income taxes | 2,253,915 | 1,944,910 | ||||||
| Deferred investment tax credits | 29,202 | 30,304 | ||||||
| Regulatory liabilities | 430,999 | 432,471 | ||||||
| Asset retirement obligations | 1,732,763 | 1,655,402 | ||||||
| Derivative instruments | 151,651 | 174,471 | ||||||
| Pension and employee benefit obligations | 307,282 | 422,496 | ||||||
| Other | 100,614 | 89,423 | ||||||
| Total deferred credits and other liabilities | 5,006,426 | 4,749,477 | ||||||
| Commitments and contingencies | ||||||||
| Capitalization | ||||||||
| Long-term debt | 3,888,730 | 3,488,638 | ||||||
Common stock — 5,000,000 shares authorized of $0.01 par value; 1,000,000 shares outstanding at Dec. 31, 2013 and 2012, respectively | 10 | 10 | ||||||
| Additional paid in capital | 2,866,603 | 2,581,501 | ||||||
| Retained earnings | 1,635,910 | 1,478,057 | ||||||
| Accumulated other comprehensive loss | (21,729 | ) | (23,199 | ) | ||||
| Total common stockholder’s equity | 4,480,794 | 4,036,369 | ||||||
| Total liabilities and equity | $ | 14,694,895 | $ | 13,401,258 | ||||
| See Notes to Consolidated Financial Statements | ||||||||
45
NSP-MINNESOTA AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY (amounts in thousands, except share data) | ||||||||||||||||||||||
| Common Stock | Accumulated Other Comprehensive Income (Loss) | Total Common Stockholder’s Equity | ||||||||||||||||||||
| Shares | Par Value | Additional Paid In Capital | Retained Earnings | |||||||||||||||||||
| Balance at Dec. 31, 2010 | 1,000,000 | $ | 10 | $ | 2,241,387 | $ | 1,251,938 | $ | 2,834 | $ | 3,496,169 | |||||||||||
| Net income | 352,981 | 352,981 | ||||||||||||||||||||
| Other comprehensive loss | (17,186 | ) | (17,186 | ) | ||||||||||||||||||
| Common dividends declared to parent | (232,192 | ) | (232,192 | ) | ||||||||||||||||||
| Contribution of capital by parent | 125,004 | 125,004 | ||||||||||||||||||||
| Balance at Dec. 31, 2011 | 1,000,000 | $ | 10 | $ | 2,366,391 | $ | 1,372,727 | $ | (14,352 | ) | $ | 3,724,776 | ||||||||||
| Net income | 340,141 | 340,141 | ||||||||||||||||||||
| Other comprehensive loss | (8,847 | ) | (8,847 | ) | ||||||||||||||||||
| Common dividends declared to parent | (234,811 | ) | (234,811 | ) | ||||||||||||||||||
| Contribution of capital by parent | 215,110 | 215,110 | ||||||||||||||||||||
| Balance at Dec. 31, 2012 | 1,000,000 | $ | 10 | $ | 2,581,501 | $ | 1,478,057 | $ | (23,199 | ) | $ | 4,036,369 | ||||||||||
| Net income | 393,346 | 393,346 | ||||||||||||||||||||
| Other comprehensive income | 1,470 | 1,470 | ||||||||||||||||||||
| Common dividends declared to parent | (235,493 | ) | (235,493 | ) | ||||||||||||||||||
| Contribution of capital by parent | 285,102 | 285,102 | ||||||||||||||||||||
| Balance at Dec. 31, 2013 | 1,000,000 | $ | 10 | $ | 2,866,603 | $ | 1,635,910 | $ | (21,729 | ) | $ | 4,480,794 | ||||||||||
| See Notes to Consolidated Financial Statements | ||||||||||||||||||||||
46
NSP-MINNESOTA AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CAPITALIZATION (amounts in thousand, except share and per share data) | |||||||
| Dec. 31 | |||||||
| 2013 | 2012 | ||||||
| Long-Term Debt | |||||||
| First Mortgage Bonds, Series due: | |||||||
| Aug. 15, 2015, 1.95% | $ | 250,000 | $ | 250,000 | |||
| March 1, 2018, 5.25% | 500,000 | 500,000 | |||||
| Aug. 15, 2022, 2.15% | 300,000 | 300,000 | |||||
| May 15, 2023, 2.6% | 400,000 | — | |||||
| July 1, 2025, 7.125% | 250,000 | 250,000 | |||||
| March 1, 2028, 6.5% | 150,000 | 150,000 | |||||
| July 15, 2035, 5.25% | 250,000 | 250,000 | |||||
| June 1, 2036, 6.25% | 400,000 | 400,000 | |||||
| July 1, 2037, 6.2% | 350,000 | 350,000 | |||||
| Nov. 1, 2039, 5.35% | 300,000 | 300,000 | |||||
| Aug. 15, 2040, 4.85% | 250,000 | 250,000 | |||||
| Aug. 15, 2042, 3.4% | 500,000 | 500,000 | |||||
| Other | 48 | 2 | |||||
| Unamortized discount | (11,316 | ) | (11,362 | ) | |||
| Total | 3,888,732 | 3,488,640 | |||||
| Less current maturities | 2 | 2 | |||||
| Total long-term debt | $ | 3,888,730 | $ | 3,488,638 | |||
| Common Stockholder’s Equity | |||||||
| Common stock — 5,000,000 shares authorized of $0.01 par value; 1,000,000 shares outstanding at Dec. 31, 2013 and 2012, respectively | $ | 10 | $ | 10 | |||
| Additional paid in capital | 2,866,603 | 2,581,501 | |||||
| Retained earnings | 1,635,910 | 1,478,057 | |||||
| Accumulated other comprehensive loss | (21,729 | ) | (23,199 | ) | |||
| Total common stockholder’s equity | $ | 4,480,794 | $ | 4,036,369 | |||
| See Notes to Consolidated Financial Statements | |||||||
47
Notes to Consolidated Financial Statements
1. Summary of Significant Accounting Policies
Business and System of Accounts — NSP-Minnesota is principally engaged in the regulated generation, purchase, transmission, distribution and sale of electricity and in the regulated purchase, transportation, distribution and sale of natural gas. NSP-Minnesota’s consolidated financial statements and disclosures are presented in accordance with GAAP. All of NSP-Minnesota’s underlying accounting records also conform to the FERC uniform system of accounts or to systems required by various state regulatory commissions, which are the same in all material respects.
Principles of Consolidation — NSP-Minnesota’s consolidated financial statements include its wholly-owned subsidiaries. In the consolidation process, all intercompany transactions and balances are eliminated. NSP-Minnesota has investments in certain plants and transmission facilities jointly owned with nonaffiliated utilities. NSP-Minnesota’s proportionate share of jointly owned facilities is recorded as property, plant and equipment on the consolidated balance sheets and NSP-Minnesota’s proportionate share of the operating costs associated with these facilities is included in its consolidated statements of income. See Note 5 for further discussion of jointly owned generation and transmission facilities and related ownership percentages.
NSP-Minnesota evaluates its arrangements and contracts with other entities, including but not limited to, investments, PPAs and fuel contracts to determine if the other party is a variable interest entity, if NSP-Minnesota has a variable interest and if NSP-Minnesota is the primary beneficiary. NSP-Minnesota follows accounting guidance for variable interest entities which requires consideration of the activities that most significantly impact an entity’s financial performance and power to direct those activities, when determining whether NSP-Minnesota is a variable interest entity’s primary beneficiary. See Note 11 for further discussion of variable interest entities.
Use of Estimates — In recording transactions and balances resulting from business operations, NSP-Minnesota uses estimates based on the best information available. Estimates are used for such items as plant depreciable lives, AROs, regulatory assets and liabilities, tax provisions, uncollectible amounts, environmental costs, unbilled revenues, jurisdictional fuel and energy cost allocations and actuarially determined benefit costs. The recorded estimates are revised when better information becomes available or when actual amounts can be determined. Those revisions can affect operating results.
Regulatory Accounting — NSP-Minnesota accounts for certain income and expense items in accordance with accounting guidance for regulated operations. Under this guidance:
| • | Certain costs, which would otherwise be charged to expense or OCI, are deferred as regulatory assets based on the expected ability to recover the costs in future rates; and |
| • | Certain credits, which would otherwise be reflected as income, are deferred as regulatory liabilities based on the expectation the amounts will be returned to customers in future rates, or because the amounts were collected in rates prior to the costs being incurred. |
Estimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with the treatment in the rate setting process.
If restructuring or other changes in the regulatory environment occur, NSP-Minnesota may no longer be eligible to apply this accounting treatment, and may be required to eliminate regulatory assets and liabilities from its balance sheet. Such changes could have a material effect on NSP-Minnesota’s financial condition, results of operations and cash flows. See Note 13 for further discussion of regulatory assets and liabilities.
Revenue Recognition — Revenues related to the sale of energy are generally recorded when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is based on the reading of their meter, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is recognized. NSP-Minnesota presents its revenues net of any excise or other fiduciary-type taxes or fees.
NSP-Minnesota participates in MISO. The revenues and charges from MISO related to serving retail and wholesale electric customers comprising the native load of NSP-Minnesota are recorded on a net basis within cost of sales. Revenues and charges for short term wholesale sales of excess energy transacted through MISO are recorded on a gross basis in electric revenues and cost of sales.
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NSP-Minnesota has various rate-adjustment mechanisms in place that provide for the recovery of natural gas, electric fuel and purchased energy costs. These cost-adjustment tariffs may increase or decrease the level of revenue collected from customers and are revised periodically for differences between the total amount collected under the clauses and the costs incurred. When applicable, under governing regulatory commission rate orders, fuel cost over-recoveries (the excess of fuel revenue billed to customers over fuel costs incurred) are deferred as regulatory liabilities and under-recoveries (the excess of fuel costs incurred over fuel revenues billed to customers) are deferred as regulatory assets.
Conservation Programs — NSP-Minnesota has implemented programs in its retail jurisdictions to assist customers in conserving energy and reducing peak demand on the electric and natural gas systems. These programs include commercial process efficiency and lighting updates, as well as residential rebates for participation in air conditioning interruption and energy-efficient appliances.
The costs incurred for CIP programs are deferred if it is probable future revenue will be provided to permit recovery of the incurred cost. For incentive programs designed to allow adjustments of future rates for recovery of lost margins and/or conservation performance incentives, recorded revenues are limited to those amounts expected to be collected within 24 months following the end of the annual period in which they are earned.
NSP-Minnesota’s CIP program costs are recovered through a combination of base rate revenue and rider mechanisms. The revenue billed to customers recovers incurred costs for conservation programs and also incentive amounts that are designed to encourage NSP-Minnesota’s achievement of energy conservation goals and to compensate for related lost sales margin. NSP-Minnesota recognizes regulatory assets to reflect the amount of costs or earned incentives that have not yet been collected from customers.
Property, Plant and Equipment and Depreciation — Property, plant and equipment is stated at original cost. The cost of plant includes direct labor and materials, contracted work, overhead costs and AFUDC. The cost of plant retired is charged to accumulated depreciation and amortization. Amounts recovered in rates for future removal costs are recorded as regulatory liabilities. Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance costs are charged to expense as incurred. Maintenance and replacement of items determined to be less than a unit of property are charged to operating expenses as incurred. Planned major maintenance activities are charged to operating expense unless the cost represents the acquisition of an additional unit of property or the replacement of an existing unit of property. Property, plant and equipment also includes costs associated with property held for future use. The depreciable lives of certain plant assets are reviewed annually and revised, if appropriate. Property, plant and equipment that is required to be decommissioned early by a regulator is reclassified as plant to be retired.
Property, plant and equipment is tested for impairment when it is determined that the carrying value of the assets may not be recoverable. Recently completed property, plant and equipment that is disallowed for cost recovery is expensed in the current period. For investments in property, plant and equipment that are not expected to go into service, incurred costs and related deferred tax amounts are compared to the discounted estimated future rate recovery, and a loss on abandonment is recognized, if necessary.
NSP-Minnesota records depreciation expense related to its plant using the straight-line method over the plant’s useful life. Actuarial and semi-actuarial life studies are performed on a periodic basis and submitted to the state and federal commissions for review. Upon acceptance by the various commissions, the resulting lives and net salvage rates are used to calculate depreciation. Depreciation expense, expressed as a percentage of average depreciable property, was approximately 2.9, 2.9 and 3.2 percent for the years ended Dec. 31, 2013, 2012 and 2011, respectively.
Leases — NSP-Minnesota evaluates a variety of contracts for lease classification at inception, including PPAs and rental arrangements for office space, vehicles, and equipment. Contracts determined to contain a lease because of per unit pricing that is other than fixed or market price, terms regarding the use of a particular asset, and other factors are evaluated further to determine if the arrangement is a capital lease. See Note 11 for further discussion of leases.
AFUDC — AFUDC represents the cost of capital used to finance utility construction activity. AFUDC is computed by applying a composite financing rate to qualified CWIP. The amount of AFUDC capitalized as a utility construction cost is credited to nonoperating income (for equity capital) and interest charges (for debt capital). AFUDC amounts capitalized are included in NSP-Minnesota’s rate base for establishing utility service rates. In addition to construction-related amounts, cost of capital also is recorded to reflect returns on capital used to finance conservation programs in Minnesota.
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Generally AFUDC costs are recovered from customers as the related property is depreciated. However, in some cases, including certain wind and transmission projects, the MPUC has approved a more current recovery of the cost of capital associated with large capital projects, through various riders, resulting in a lower recognition of AFUDC.
AROs — NSP-Minnesota accounts for AROs under accounting guidance that requires a liability for the fair value of an ARO to be recognized in the period in which it is incurred if it can be reasonably estimated, with the offsetting associated asset retirement costs capitalized as a long-lived asset. The liability is generally increased over time by applying the effective interest method of accretion, and the capitalized costs are depreciated over the useful life of the long-lived asset. Changes resulting from revisions to the timing or amount of expected asset retirement cash flows are recognized as an increase or a decrease in the ARO. NSP-Minnesota also recovers through rates certain future plant removal costs in addition to AROs. The accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability. See Note 11 for further discussion of AROs.
Nuclear Decommissioning — Nuclear decommissioning studies estimate NSP-Minnesota’s ultimate costs of decommissioning its nuclear power plants and are performed at least every three years and submitted to the MPUC and other state commissions for approval. The MPUC approved NSP-Minnesota’s most recent triennial nuclear decommissioning studies in December 2012. These studies reflect NSP-Minnesota’s plans, under the current operating licenses, for prompt dismantlement of the Monticello and Prairie Island facilities. These studies assume that NSP-Minnesota will be storing spent fuel on site pending removal to a U.S. government facility.
For rate making purposes, NSP-Minnesota recovers the total decommissioning costs related to its nuclear power plants over each facility’s expected service life based on the triennial decommissioning studies filed with the MPUC and other state commissions. The studies consider estimated future costs of decommissioning and the market value of investments in trust funds, and recommend annual funding amounts. Amounts collected in rates are deposited in the trust funds. See Note 12 for further discussion of the approved nuclear decommissioning studies and funded amounts. For financial reporting purposes, NSP-Minnesota accounts for nuclear decommissioning as an ARO as described above.
Restricted funds for the payment of future decommissioning expenditures for NSP-Minnesota’s nuclear facilities are included in the nuclear decommissioning fund on the consolidated balance sheets. See Note 9 for further discussion of the nuclear decommissioning fund.
Nuclear Fuel Expense — Nuclear fuel expense, which is recorded as NSP-Minnesota’s nuclear generating plants use fuel, includes the cost of fuel used in the current period (including AFUDC), as well as future disposal costs of spent nuclear fuel and costs associated with the end-of-life fuel segments.
Nuclear Refueling Outage Costs — NSP-Minnesota uses a deferral and amortization method for nuclear refueling O&M costs. This method amortizes refueling outage costs over the period between refueling outages consistent with how the costs are recovered ratably in electric rates.
Income Taxes — NSP-Minnesota 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. NSP-Minnesota defers income taxes for all temporary differences between pretax financial and taxable income, and between the book and tax bases of assets and liabilities. NSP-Minnesota 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 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 evidence is considered, including scheduled reversals of deferred tax liabilities, projected future taxable income, tax planning strategies and recent financial operations.
Due to the effects of past regulatory practices, when deferred taxes were not required to be recorded due to the use of flow through accounting for ratemaking purposes, 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 13.
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NSP-Minnesota 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. NSP-Minnesota 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.
NSP-Minnesota 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, including NSP-Minnesota, file consolidated federal income tax returns as well as combined or separate state income tax returns. Federal income taxes paid by Xcel Energy Inc. 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 which are recorded directly in equity by the 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 — NSP-Minnesota 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 including transmission in organized markets 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 commodity trading transactions are recorded as a component of electric operating revenues; 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. NSP-Minnesota is allowed to recover in electric or natural gas rates the costs of certain financial instruments purchased to reduce commodity cost volatility. For further information on derivatives entered to mitigate commodity price risk on behalf of electric and natural gas customers, see Note 9.
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 — NSP-Minnesota 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 if designated as normal purchases or normal sales.
NSP-Minnesota 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 9 for further discussion of NSP-Minnesota’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.
Pursuant to the JOA approved by the FERC, some of NSP-Minnesota’s commodity trading margins are apportioned to PSCo and SPS. Commodity trading activities are not associated with energy produced from NSP-Minnesota’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. For further information, see Note 9.
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Fair Value Measurements — NSP-Minnesota 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, NSP-Minnesota 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. For further information, see Note 9.
Cash and Cash Equivalents — NSP-Minnesota considers investments in certain instruments, including commercial paper and money market funds, with a remaining maturity of 3 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. NSP-Minnesota 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.
RECs — RECs are marketable environmental instruments 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. NSP-Minnesota acquires RECs from the generation or purchase of renewable power.
When RECs are purchased or acquired in the course of generation 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.
Sales of RECs that are purchased or acquired in the course of generation 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. 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 from the EPA, are recorded at cost plus associated broker commission fees. NSP-Minnesota follows the inventory accounting model for all emission allowances. 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 NSP-Minnesota is liable for remediation 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 NSP-Minnesota’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 11 for further discussion of environmental costs.
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Benefit Plans and Other Postretirement Benefits — NSP-Minnesota 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 regulatory recovery mechanisms, 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 7 for further discussion of benefit plans and other postretirement benefits.
Guarantees — NSP-Minnesota 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 NSP-Minnesota is released from risk under the guarantee. See Note 11 for specific details of issued guarantees.
Subsequent Events — Management has evaluated the impact of events occurring after Dec. 31, 2013 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
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. In January 2013, the FASB issued Balance Sheet (Topic 210) – Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities (ASU No. 2013-01) to clarify the specific instruments that should be considered in these disclosures. These disclosure requirements do not affect the presentation of amounts in the consolidated balance sheets, and were effective for annual reporting periods beginning on or after Jan. 1, 2013, and interim periods within those annual reporting periods. NSP-Minnesota implemented the disclosure guidance effective Jan. 1, 2013, and the implementation did not have a material impact on its consolidated financial statements. See Note 9 for the required disclosures.
Comprehensive Income Disclosures — In February 2013, the FASB issued Comprehensive Income (Topic 220) — Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (ASU No. 2013-02), which requires detailed disclosures regarding changes in components of accumulated OCI and amounts reclassified out of accumulated OCI. These disclosure requirements do not change how net income or comprehensive income are presented in the consolidated financial statements. These disclosure requirements were effective for annual reporting periods beginning on or after Dec. 15, 2012, and interim periods within those annual reporting periods. NSP-Minnesota implemented the disclosure guidance effective Jan. 1, 2013, and the implementation did not have a material impact on its consolidated financial statements. See Note 14 for the required disclosures.
| 3. | Selected Balance Sheet Data |
| (Thousands of Dollars) | Dec. 31, 2013 | Dec. 31, 2012 | ||||||
| Accounts receivable, net | ||||||||
| Accounts receivable | $ | 304,748 | $ | 345,563 | ||||
| Less allowance for bad debts | (20,216 | ) | (20,420 | ) | ||||
| $ | 284,532 | $ | 325,143 | |||||
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| (Thousands of Dollars) | Dec. 31, 2013 | Dec. 31, 2012 | ||||||
| Inventories | ||||||||
| Materials and supplies | $ | 144,140 | $ | 134,952 | ||||
| Fuel | 81,971 | 80,307 | ||||||
| Natural gas | 53,804 | 45,499 | ||||||
| $ | 279,915 | $ | 260,758 | |||||
| (Thousands of Dollars) | Dec. 31, 2013 | Dec. 31, 2012 | ||||||
| Property, plant and equipment, net | ||||||||
| Electric plant | $ | 13,530,767 | $ | 12,322,677 | ||||
| Natural gas plant | 1,092,314 | 1,027,632 | ||||||
| Common and other property | 503,168 | 493,322 | ||||||
| CWIP | 902,820 | 951,199 | ||||||
| Total property, plant and equipment | 16,029,069 | 14,794,830 | ||||||
| Less accumulated depreciation | (5,783,658 | ) | (5,594,064 | ) | ||||
| Nuclear fuel | 2,186,799 | 2,090,801 | ||||||
| Less accumulated amortization | (1,842,688 | ) | (1,744,599 | ) | ||||
| $ | 10,589,522 | $ | 9,546,968 | |||||
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. 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. Money pool borrowings for NSP-Minnesota were as follows:
| (Amounts in Millions, Except Interest Rates) | Three Months Ended Dec. 31, 2013 | |||
| Borrowing limit | $ | 250 | ||
| Amount outstanding at period end | 34 | |||
| Average amount outstanding | 45 | |||
| Maximum amount outstanding | 111 | |||
| Weighted average interest rate, computed on a daily basis | 0.13 | % | ||
| Weighted average interest rate at period end | 0.25 | |||
| (Amounts in Millions, Except Interest Rates) | Twelve Months Ended Dec. 31, 2013 | Twelve Months Ended Dec. 31, 2012 | Twelve Months Ended Dec. 31, 2011 | |||||||||
| Borrowing limit | $ | 250 | $ | 250 | $ | 250 | ||||||
| Amount outstanding at period end | 34 | — | 65 | |||||||||
| Average amount outstanding | 42 | 56 | 17 | |||||||||
| Maximum amount outstanding | 211 | 236 | 80 | |||||||||
| Weighted average interest rate, computed on a daily basis | 0.14 | % | 0.33 | % | 0.34 | % | ||||||
| Weighted average interest rate at period end | 0.25 | N/A | 0.35 | |||||||||
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Commercial Paper — NSP-Minnesota meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility. Commercial paper outstanding for NSP-Minnesota was as follows:
| (Amounts in Millions, Except Interest Rates) | Three Months Ended Dec. 31, 2013 | |||
| Borrowing limit | $ | 500 | ||
| Amount outstanding at period end | 131 | |||
| Average amount outstanding | 78 | |||
| Maximum amount outstanding | 170 | |||
| Weighted average interest rate, computed on a daily basis | 0.30 | % | ||
| Weighted average interest rate at period end | 0.25 | |||
| (Amounts in Millions, Except Interest Rates) | Twelve Months Ended Dec. 31, 2013 | Twelve Months Ended Dec. 31, 2012 | Twelve Months Ended Dec. 31, 2011 | |||||||||
| Borrowing limit | $ | 500 | $ | 500 | $ | 500 | ||||||
| Amount outstanding at period end | 131 | 221 | 26 | |||||||||
| Average amount outstanding | 97 | 59 | 7 | |||||||||
| Maximum amount outstanding | 347 | 302 | 80 | |||||||||
| Weighted average interest rate, computed on a daily basis | 0.34 | % | 0.39 | % | 0.34 | % | ||||||
| Weighted average interest rate at end of period | 0.25 | 0.39 | 0.45 | |||||||||
Letters of Credit — NSP-Minnesota uses letters of credit, generally with terms of one-year, to provide financial guarantees for certain operating obligations. At Dec. 31, 2013 and 2012, there were $15.9 million and $10.2 million of letters of credit outstanding, respectively, under the credit facility. The contract amounts of these letters of credit approximate their fair value and are subject to fees.
Credit Facility — In order to use its commercial paper program to fulfill short-term funding needs, NSP-Minnesota must have a revolving credit facility in place at least equal to the amount of its commercial paper borrowing limit and cannot issue commercial paper in an amount exceeding available capacity under this credit facility. The line of credit provides short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.
NSP-Minnesota has a five-year credit agreement with a syndicate of banks. The total size of the credit facility is $500 million and the credit facility terminates in July 2017.
NSP-Minnesota has the right to request an extension of the revolving termination date for two additional one-year periods. All extension requests are subject to majority bank group approval.
Other features of NSP-Minnesota’s credit facility include:
| • | NSP-Minnesota may increase its credit facility by up to $100 million. |
| • | The credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65 percent. NSP-Minnesota was in compliance as its debt-to-total capitalization ratio was 47 percent at Dec. 31, 2013. If NSP-Minnesota does 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 credit facility has a cross-default provision that provides NSP-Minnesota will be in default on its borrowings under the facility if NSP-Minnesota or any of its subsidiaries whose total assets exceed 15 percent of NSP-Minnesota’s consolidated total assets, default on certain indebtedness in an aggregate principal amount exceeding $75 million. |
| • | The interest rates under the line of credit are based on Eurodollar borrowing margins ranging from 87.5 to 175 basis points per year based on the applicable long-term 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 7.5 to 27.5 basis points per year. |
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At Dec. 31, 2013, NSP-Minnesota had the following committed credit facility available (in millions):
Credit Facility (a) | Drawn (b) | Available | ||||||||
| $ | 500.0 | $ | 146.9 | $ | 353.1 | |||||
(a) | Credit facility expires in July 2017. |
(b) | 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 credit facility. NSP-Minnesota had no direct advances on the credit facility outstanding at Dec. 31, 2013 and 2012.
Long-Term Borrowings and Other Financing Instruments
Generally, all real and personal property of NSP-Minnesota is subject to the lien of its first mortgage indenture. 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.
In May 2013, NSP-Minnesota issued $400 million of 2.60 percent first mortgage bonds due May 15, 2023. In August 2012, NSP-Minnesota issued $300 million of 2.15 percent first mortgage bonds due Aug. 15, 2022 and $500 million of 3.40 percent first mortgage bonds, due Aug. 15, 2042.
During the next five years, NSP-Minnesota has long-term debt maturities of $250 million and $500 million due in 2015 and 2018, respectively.
Deferred Financing Costs — Other assets included deferred financing costs of approximately $32.6 million and $30.6 million, net of amortization, at Dec. 31, 2013 and 2012, respectively. NSP-Minnesota is amortizing these financing costs over the remaining maturity periods of the related debt.
Dividend and Other Capital-Restrictions — NSP-Minnesota’s 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 this restriction, NSP-Minnesota could have paid more than $1.4 billion and $1.3 billion in additional cash dividends on common stock at Dec. 31, 2013 and 2012, respectively.
The most restrictive dividend limitation for NSP-Minnesota is imposed by its state regulatory commissions. 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 46.8 percent and 57.2 percent. NSP-Minnesota’s equity-to-total capitalization ratio was 52.5 percent at Dec. 31, 2013 and $912 million in retained earnings was not restricted. Total capitalization for NSP-Minnesota was $8.5 billion at Dec. 31, 2013, which did not exceed the limits imposed by the commissions of $9.0 billion.
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5. | Joint Ownership of Generation and Transmission Facilities |
Following are the investments by NSP-Minnesota in jointly owned generation and transmission facilities and the related ownership percentages as of Dec. 31, 2013:
| (Thousands of Dollars) | Plant in Service | Accumulated Depreciation | CWIP | Ownership % | |||||||||||
| Electric Generation: | |||||||||||||||
| Sherco Unit 3 | $ | 596,314 | $ | 371,925 | $ | 4,533 | 59.0 | % | |||||||
| Sherco Common Facilities Units 1, 2 and 3 | 145,579 | 87,289 | 61 | 80.0 | |||||||||||
| Sherco Substation | 4,790 | 2,884 | — | 59.0 | |||||||||||
| Electric Transmission: | |||||||||||||||
| Grand Meadow Line and Substation | 10,647 | 1,225 | — | 50.0 | |||||||||||
| CapX2020 | 340,333 | 77,803 | 503,714 | 53.3 | |||||||||||
| Total | $ | 1,097,663 | $ | 541,126 | $ | 508,308 | |||||||||
NSP-Minnesota has approximately 500 MW of jointly owned generating capacity. NSP-Minnesota’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.
6. Income Taxes
Federal Tax Loss Carryback Claims — In 2012 and 2013, NSP-Minnesota identified certain expenses related to 2009, 2010, 2011 and 2013 that qualify for an extended carryback beyond the typical two-year carryback period. As a result of a higher tax rate in prior years, NSP-Minnesota recognized a tax benefit of approximately $15 million in 2012 and $12 million in 2013.
Federal Audit — NSP-Minnesota is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. The statute of limitations applicable to Xcel Energy’s 2008 federal income tax return expired in September 2012. The statute of limitations applicable to Xcel Energy’s 2009 federal income tax return expires in June 2015. In the third quarter of 2012, the IRS commenced an examination of tax years 2010 and 2011, including the 2009 carryback claim. As of Dec. 31, 2013, the IRS had proposed an adjustment to the federal tax loss carryback claims that would result in $10 million of income tax expense for the 2009 through 2011 claims and the anticipated claim for 2013. Xcel Energy is continuing to work through the audit process, but the outcome and timing of a resolution are uncertain.
State Audits — NSP-Minnesota is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Dec. 31, 2013, NSP-Minnesota’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2009. There are currently 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, 2013 | Dec. 31, 2012 | ||||||
| Unrecognized tax benefit — Permanent tax positions | $ | 8.5 | $ | 2.8 | ||||
| Unrecognized tax benefit — Temporary tax positions | 16.7 | 16.7 | ||||||
| Total unrecognized tax benefit | $ | 25.2 | $ | 19.5 | ||||
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A reconciliation of the beginning and ending amount of unrecognized tax benefit is as follows:
| (Millions of Dollars) | 2013 | 2012 | 2011 | |||||||||
| Balance at Jan. 1 | $ | 19.5 | $ | 16.7 | $ | 22.5 | ||||||
| Additions based on tax positions related to the current year | 8.1 | 1.7 | 6.5 | |||||||||
| Reductions based on tax positions related to the current year | — | (2.2 | ) | (0.8 | ) | |||||||
| Additions for tax positions of prior years | 11.6 | 6.4 | 4.9 | |||||||||
| Reductions for tax positions of prior years | (1.9 | ) | (3.1 | ) | (0.9 | ) | ||||||
| Settlements with taxing authorities | (12.1 | ) | — | (15.5 | ) | |||||||
| Balance at Dec. 31 | $ | 25.2 | $ | 19.5 | $ | 16.7 | ||||||
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 carryforwards are as follows:
| (Millions of Dollars) | Dec. 31, 2013 | Dec. 31, 2012 | ||||||
| NOL and tax credit carryforwards | $ | (12.4 | ) | $ | (16.8 | ) | ||
It is reasonably possible that NSP-Minnesota’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS audit progresses and state audits resume. As the IRS examination moves closer to completion, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $14 million.
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 Dec. 31, 2013, 2012 and 2011 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2013, 2012 or 2011.
Tangible Property Regulations — In September 2013, the U.S. Treasury issued final regulations addressing the tax consequences associated with the acquisition, production and improvement of tangible property. As NSP-Minnesota had adopted certain utility-specific guidance previously issued by the IRS, the issuance is not expected to have a material impact on its consolidated financial statements.
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) | 2013 | 2012 | ||||||
| Federal NOL carryforward | $ | 593.8 | $ | 394.0 | ||||
| Federal tax credit carryforwards | 107.0 | 70.9 | ||||||
| State tax credit carryforwards, net of federal detriment | 2.4 | 2.0 | ||||||
The federal carryforward periods expire between 2021 and 2033. The state carryforward periods expire between 2017 and 2028.
Total income tax expense from 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:
| 2013 | 2012 | 2011 | |||||||
| Federal statutory rate | 35.0 | % | 35.0 | % | 35.0 | % | |||
| Increases (decreases) in tax from: | |||||||||
| Tax credits recognized, net of federal income tax expense | (5.3 | ) | (4.6 | ) | (5.0 | ) | |||
| NOL carryback | (2.0 | ) | (2.9 | ) | — | ||||
| Regulatory differences — utility plant items | (1.8 | ) | (1.6 | ) | (1.8 | ) | |||
| State income taxes, net of federal income tax benefit | 5.6 | 8.5 | 7.0 | ||||||
| Change in unrecognized tax benefits | 1.0 | (0.1 | ) | (0.1 | ) | ||||
| Other, net | (0.9 | ) | (0.3 | ) | 0.1 | ||||
| Effective income tax rate | 31.6 | % | 34.0 | % | 35.2 | % | |||
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The components of income tax expense for the years ending Dec. 31 were:
| (Thousands of Dollars) | 2013 | 2012 | 2011 | |||||||||
| Current federal tax (benefit) expense | $ | (6,181 | ) | $ | (85,347 | ) | $ | 8,059 | ||||
| Current state tax expense | 11,197 | 19,593 | 3,055 | |||||||||
| Current change in unrecognized tax expense (benefit) | 10,210 | 3,997 | (12,891 | ) | ||||||||
| Deferred federal tax expense | 135,539 | 196,655 | 128,206 | |||||||||
| Deferred state tax expense | 37,381 | 47,869 | 55,658 | |||||||||
| Deferred change in unrecognized tax (benefit) expense | (4,476 | ) | (4,543 | ) | 12,256 | |||||||
| Deferred investment tax credits | (1,813 | ) | (2,700 | ) | (2,694 | ) | ||||||
| Total income tax expense | $ | 181,857 | $ | 175,524 | $ | 191,649 | ||||||
The components of deferred income tax expense for the years ending Dec. 31 were:
| (Thousands of Dollars) | 2013 | 2012 | 2011 | |||||||||
| Deferred tax expense excluding items below | $ | 210,856 | $ | 285,726 | $ | 190,470 | ||||||
| Tax (expense) benefit allocated to other comprehensive income and other | (1,046 | ) | 6,172 | 11,841 | ||||||||
| Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities | (41,366 | ) | (51,917 | ) | (6,191 | ) | ||||||
| Deferred tax expense | $ | 168,444 | $ | 239,981 | $ | 196,120 | ||||||
The components of the net deferred tax liability (current and noncurrent) at Dec. 31 were as follows:
| (Thousands of Dollars) | 2013 | 2012 | ||||||
| Deferred tax liabilities: | ||||||||
| Differences between book and tax bases of property | $ | 2,371,864 | $ | 2,108,983 | ||||
| Regulatory assets | 169,411 | 149,531 | ||||||
| Other | 27,720 | 24,812 | ||||||
| Total deferred tax liabilities | $ | 2,568,995 | $ | 2,283,326 | ||||
| Deferred tax assets: | ||||||||
| NOL carryforward | $ | 209,353 | $ | 142,094 | ||||
| Tax credit carryforward | 109,495 | 72,842 | ||||||
| Employee benefits | 16,232 | 33,357 | ||||||
| Regulatory liabilities | 16,232 | 13,135 | ||||||
| Deferred investment tax credits | 12,951 | 13,487 | ||||||
| Bad debts | 8,259 | 8,352 | ||||||
| Property tax | — | 17,569 | ||||||
| Other | 22,654 | 19,527 | ||||||
| Total deferred tax assets | $ | 395,176 | $ | 320,363 | ||||
| Net deferred tax liability | $ | 2,173,819 | $ | 1,962,963 | ||||
| 7. | Benefit Plans and Other Postretirement Benefits |
Consistent with the process for rate recovery of pension and postretirement benefits for its employees, NSP-Minnesota accounts for its participation in, and related costs of, pension and other postretirement benefit plans sponsored by Xcel Energy Inc. as multiple employer plans. NSP-Minnesota is responsible for its share of cash contributions, plan costs and obligations and is entitled to its share of plan assets; accordingly, NSP-Minnesota accounts for its pro rata share of these plans, including pension expense and contributions, resulting in accounting consistent with that of a single employer plan exclusively for NSP-Minnesota employees.
Xcel Energy, which includes NSP-Minnesota, offers various benefit plans to its employees. Approximately 60 percent of employees that receive benefits are represented by several local labor unions under several collective-bargaining agreements. At Dec. 31, 2013, NSP-Minnesota had 2,022 bargaining employees covered under a collective-bargaining agreement, which expires at the end of 2016. NSP-Minnesota also had an additional 248 nuclear operation bargaining employees covered under several collective-bargaining agreements, which expire at various dates in 2015 and 2016.
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The plans invest in various instruments which are disclosed under the accounting guidance for fair value measurements which establishes a hierarchical 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.
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.
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.
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.
Insurance contracts — Insurance contract fair values take into consideration the value of the investments in separate accounts of the insurer, which are priced based on observable inputs.
Investments in equity securities and other funds — Equity securities are valued using quoted prices in active markets. The fair values for commingled 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 may be redeemed for net asset value with proper notice. Proper notice varies by fund and can range from daily with one or two days notice to annually with 90 days 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, which is typically quarterly with 45-90 days notice; however, withdrawals from real estate investments may be delayed or discounted as a result of fund illiquidity. Based on the plan’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.
Derivative Instruments — Fair values for foreign currency derivatives are determined using pricing models based on the prevailing forward exchange rate of the underlying currencies. The fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts.
Pension Benefits
Xcel Energy, which includes NSP-Minnesota, 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 Inc.’s and NSP-Minnesota’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.
In addition to the qualified pension plans, Xcel Energy maintains a supplemental executive retirement plan (SERP) and a nonqualified pension plan. The SERP is maintained for certain executives that were participants in the plan in 2008, when the SERP was closed to new participants. The nonqualified pension plan provides unfunded, nonqualified benefits for compensation that is in excess of the limits applicable to the qualified pension plans. The total obligations of the SERP and nonqualified plan as of Dec. 31, 2013 and 2012 were $36.5 million and $39.4 million, respectively, of which $5.3 million and $5.7 million was attributable to NSP-Minnesota. In 2013 and 2012, Xcel Energy recognized net benefit cost for financial reporting for the SERP and nonqualified plans of $6.6 million and $15.6 million, respectively, of which $0.5 million and $0.6 million was attributable to NSP-Minnesota. Benefits for these unfunded plans are paid out of Xcel Energy’s consolidated operating cash flows.
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Xcel Energy Inc. and NSP-Minnesota base the investment-return assumption on expected long-term performance for each of the investment types included in the pension asset portfolio and consider the historical returns achieved by the 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 pension cost determination assumes a forecasted mix of investment types over the long term. Investment returns in 2013 were below the assumed level of 7.25 percent. Investment returns in 2012 were above the assumed level of 7.50 percent while returns in 2011 were below the assumed level of 8.00 percent. Xcel Energy Inc. and NSP-Minnesota continually review pension assumptions. In 2014, NSP-Minnesota’s expected investment-return assumption is 7.25 percent.
The assets are invested in a portfolio according to Xcel Energy Inc.’s and NSP-Minnesota’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. 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 NSP-Minnesota:
| 2013 | 2012 | |||||
| Domestic and international equity securities | 31 | % | 29 | % | ||
| Long-duration fixed income and interest rate swap securities | 29 | 30 | ||||
| Short-to-intermediate term fixed income securities | 16 | 12 | ||||
| Alternative investments | 22 | 27 | ||||
| Cash | 2 | 2 | ||||
| Total | 100 | % | 100 | % | ||
The 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, NSP-Minnesota’s pension plan assets that are measured at fair value as of Dec. 31, 2013 and 2012:
| Dec. 31, 2013 | ||||||||||||||||
| (Thousands of Dollars) | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
| Cash equivalents | $ | 28,078 | $ | — | $ | — | $ | 28,078 | ||||||||
| Derivatives | — | 6,073 | — | 6,073 | ||||||||||||
| Government securities | — | 43,501 | — | 43,501 | ||||||||||||
| Corporate bonds | — | 161,761 | — | 161,761 | ||||||||||||
| Asset-backed securities | — | 1,991 | — | 1,991 | ||||||||||||
| Mortgage-backed securities | — | 4,436 | — | 4,436 | ||||||||||||
| Common stock | 29,384 | — | — | 29,384 | ||||||||||||
| Private equity investments | — | — | 48,633 | 48,633 | ||||||||||||
| Commingled funds | — | 546,863 | — | 546,863 | ||||||||||||
| Real estate | — | — | 14,904 | 14,904 | ||||||||||||
| Securities lending collateral obligation and other | — | 2,018 | — | 2,018 | ||||||||||||
| Total | $ | 57,462 | $ | 766,643 | $ | 63,537 | $ | 887,642 | ||||||||
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| Dec. 31, 2012 | ||||||||||||||||
| (Thousands of Dollars) | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
| Cash equivalents | $ | 50,360 | $ | — | $ | — | $ | 50,360 | ||||||||
| Derivatives | — | 2,471 | — | 2,471 | ||||||||||||
| Government securities | — | 59,541 | — | 59,541 | ||||||||||||
| Corporate bonds | — | 158,535 | — | 158,535 | ||||||||||||
| Asset-backed securities | — | — | 4,741 | 4,741 | ||||||||||||
| Mortgage-backed securities | — | — | 13,472 | 13,472 | ||||||||||||
| Common stock | 25,173 | — | — | 25,173 | ||||||||||||
| Private equity investments | — | — | 54,091 | 54,091 | ||||||||||||
| Commingled funds | — | 483,598 | — | 483,598 | ||||||||||||
| Real estate | — | — | 21,978 | 21,978 | ||||||||||||
| Securities lending collateral obligation and other | — | (9,630 | ) | — | (9,630 | ) | ||||||||||
| Total | $ | 75,533 | $ | 694,515 | $ | 94,282 | $ | 864,330 | ||||||||
The following tables present the changes in NSP-Minnesota’s Level 3 pension plan assets for the years ended Dec. 31, 2013, 2012 and 2011:
| (Thousands of Dollars) | Jan. 1, 2013 | Net Realized Gains (Losses) | Net Unrealized Gains (Losses) | Purchases, Issuances and Settlements, Net | Transfers out of Level 3 (a) | Dec. 31, 2013 | ||||||||||||||||||
| Asset-backed securities | $ | 4,741 | $ | — | $ | — | $ | — | $ | (4,741 | ) | $ | — | |||||||||||
| Mortgage-backed securities | 13,472 | — | — | — | (13,472 | ) | — | |||||||||||||||||
| Private equity investments | 54,091 | 7,018 | (11,403 | ) | (1,073 | ) | — | 48,633 | ||||||||||||||||
| Real estate | 21,978 | (833 | ) | 1,860 | 2,920 | (11,021 | ) | 14,904 | ||||||||||||||||
| Total | $ | 94,282 | $ | 6,185 | $ | (9,543 | ) | $ | 1,847 | $ | (29,234 | ) | $ | 63,537 | ||||||||||
(a) | Transfers out of Level 3 into Level 2 were principally due to diminished use of unobservable inputs that were previously significant to these fair value measurements and were subsequently sold during 2013. |
| (Thousands of Dollars) | Jan. 1, 2012 | Net Realized Gains (Losses) | Net Unrealized Gains (Losses) | Purchases, Issuances and Settlements, Net | Transfers out of Level 3 | Dec. 31, 2012 | ||||||||||||||||||
| Asset-backed securities | $ | 10,188 | $ | 1,249 | $ | (1,744 | ) | $ | (4,952 | ) | $ | — | $ | 4,741 | ||||||||||
| Mortgage-backed securities | 24,413 | 588 | (705 | ) | (10,824 | ) | — | 13,472 | ||||||||||||||||
| Private equity investments | 54,499 | 5,985 | (7,724 | ) | 1,331 | — | 54,091 | |||||||||||||||||
| Real estate | 12,967 | 6 | 2,141 | 6,864 | — | 21,978 | ||||||||||||||||||
| Total | $ | 102,067 | $ | 7,828 | $ | (8,032 | ) | $ | (7,581 | ) | $ | — | $ | 94,282 | ||||||||||
| (Thousands of Dollars) | Jan. 1, 2011 | Net Realized Gains (Losses) | Net Unrealized Gains (Losses) | Purchases, Issuances and Settlements, Net | Transfers out of Level 3 | Dec. 31, 2011 | ||||||||||||||||||
| Asset-backed securities | $ | 8,771 | $ | 781 | $ | (805 | ) | $ | 1,441 | $ | — | $ | 10,188 | |||||||||||
| Mortgage-backed securities | 38,403 | 355 | (1,894 | ) | (12,451 | ) | — | 24,413 | ||||||||||||||||
| Private equity investments | 43,027 | 1,354 | 4,196 | 5,922 | — | 54,499 | ||||||||||||||||||
| Real estate | 24,041 | (219 | ) | 6,416 | (17,271 | ) | — | 12,967 | ||||||||||||||||
| Total | $ | 114,242 | $ | 2,271 | $ | 7,913 | $ | (22,359 | ) | $ | — | $ | 102,067 | |||||||||||
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Benefit Obligations — A comparison of the actuarially computed pension benefit obligation and plan assets for NSP-Minnesota is presented in the following table:
| (Thousands of Dollars) | 2013 | 2012 | ||||||
| Accumulated Benefit Obligation at Dec. 31 | $ | 1,002,737 | $ | 1,081,074 | ||||
| Change in Projected Benefit Obligation: | ||||||||
| Obligation at Jan. 1 | $ | 1,139,356 | $ | 1,031,594 | ||||
| Service cost | 33,167 | 29,411 | ||||||
| Interest cost | 43,734 | 49,813 | ||||||
| Plan amendments | (3,637 | ) | 230 | |||||
| Actuarial (gain) loss | (41,173 | ) | 120,770 | |||||
| Benefit payments | (108,814 | ) | (92,462 | ) | ||||
| Obligation at Dec. 31 | $ | 1,062,633 | $ | 1,139,356 | ||||
| (Thousands of Dollars) | 2013 | 2012 | ||||||
| Change in Fair Value of Plan Assets: | ||||||||
| Fair value of plan assets at Jan. 1 | $ | 864,330 | $ | 783,529 | ||||
| Actual return on plan assets | 59,714 | 93,679 | ||||||
| Employer contributions | 72,412 | 79,584 | ||||||
| Benefit payments | (108,814 | ) | (92,462 | ) | ||||
| Fair value of plan assets at Dec. 31 | $ | 887,642 | $ | 864,330 | ||||
| (Thousands of Dollars) | 2013 | 2012 | ||||||
| Funded Status of Plans at Dec. 31: | ||||||||
Funded status (a) | $ | (174,991 | ) | $ | (275,026 | ) | ||
(a) | Amounts are recognized in noncurrent liabilities on NSP-Minnesota’s consolidated balance sheet. |
| (Thousands of Dollars) | 2013 | 2012 | ||||||
| Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost: | ||||||||
| Net loss | $ | 574,062 | $ | 664,795 | ||||
| Prior service cost | 6,582 | 12,266 | ||||||
| Total | $ | 580,644 | $ | 677,061 | ||||
| (Thousands of Dollars) | 2013 | 2012 | ||||||
| Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates: | ||||||||
| Current regulatory assets | $ | 50,623 | $ | 46,071 | ||||
| Noncurrent regulatory assets | 530,021 | 630,990 | ||||||
| Total | $ | 580,644 | $ | 677,061 | ||||
| Measurement date | Dec. 31, 2013 | Dec. 31, 2012 | ||
| 2013 | 2012 | |||||
| Significant Assumptions Used to Measure Benefit Obligations: | ||||||
| Discount rate for year-end valuation | 4.75 | % | 4.00 | % | ||
| Expected average long-term increase in compensation level | 3.75 | % | 3.75 | % | ||
| Mortality table | RP 2000 | RP 2000 | ||||
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, 2012 and 2013 to meet minimum funding requirements.
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The following are the pension funding contributions, both voluntary and required, made by Xcel Energy for 2011 through January 2014:
| • | In January 2014, contributions of $130.0 million were made across three of Xcel Energy’s pension plans, of which $52.1 million was attributable to NSP-Minnesota; |
| • | In 2013, contributions of $192.4 million were made across four of Xcel Energy’s pension plans, of which $72.4 million was attributable to NSP-Minnesota; |
| • | In 2012, contributions of $198.1 million were made across four of Xcel Energy’s pension plans, of which $79.6 million was attributable to NSP-Minnesota; |
| • | In 2011, contributions of $137.3 million were made across three of Xcel Energy’s pension plans, of which $41.4 million was attributable to NSP-Minnesota; |
| • | For future years, Xcel Energy and NSP-Minnesota anticipate contributions will be made as necessary. |
Plan Amendments —Xcel Energy, which includes NSP-Minnesota, amended the plan in 2013 resulting in a decrease of the projected benefit obligation due to fully insuring the long-term disability benefit for NSP bargaining participants. This decrease was partially offset by an increase to the projected benefit obligation resulting from a change in the discount rate basis for lump sum conversion of annuities for participants in the Xcel Energy Pension Plan. In 2012, the plan was amended to allow a one time transfer of a portion of qualifying obligations from the nonqualified pension plan into the qualified pension plans. Xcel Energy and NSP-Minnesota also modified the benefit formula for nonbargaining new hires beginning in 2012 to a reduced benefit level.
Benefit Costs — The components of NSP-Minnesota’s net periodic pension cost were:
| (Thousands of Dollars) | 2013 | 2012 | 2011 | |||||||||
| Service cost | $ | 33,167 | $ | 29,411 | $ | 28,016 | ||||||
| Interest cost | 43,734 | 49,813 | 51,946 | |||||||||
| Expected return on plan assets | (63,152 | ) | (67,315 | ) | (74,241 | ) | ||||||
| Amortization of prior service cost | 2,057 | 11,819 | 13,169 | |||||||||
| Amortization of net loss | 52,988 | 41,147 | 28,736 | |||||||||
| Net periodic pension cost | 68,794 | 64,875 | 47,626 | |||||||||
| Costs not recognized due to effects of regulation | (35,455 | ) | (34,917 | ) | (34,898 | ) | ||||||
| Net benefit cost recognized for financial reporting | $ | 33,339 | $ | 29,958 | $ | 12,728 | ||||||
| 2013 | 2012 | 2011 | |||||||
| Significant Assumptions Used to Measure Costs: | |||||||||
| Discount rate | 4.00 | % | 5.00 | % | 5.50 | % | |||
| Expected average long-term increase in compensation level | 3.75 | 4.00 | 4.00 | ||||||
| Expected average long-term rate of return on assets | 7.25 | 7.50 | 8.00 | ||||||
In addition to the benefit costs in the table above, for the pension plans sponsored by Xcel Energy, Inc., costs are allocated to NSP-Minnesota based on Xcel Energy Services Inc. employees’ labor costs. Amounts allocated to NSP-Minnesota were $12.9 million, $10.8 million and $7.6 million in 2013, 2012 and 2011, respectively. 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 2014 pension cost calculations is 7.25 percent. The cost calculation uses a market-related valuation of pension assets. Xcel Energy, including NSP-Minnesota, uses a calculated value method to determine the market-related value of the plan assets. The market-related value begins with the fair market value of assets as of the beginning of the year. The market-related value is determined by adjusting the fair market value of assets to reflect the investment gains and losses (the difference between the actual investment return and the expected investment return on the market-related value) during each of the previous five years at the rate of 20 percent per year. As these differences between actual investment returns and the expected investment returns are incorporated into the market-related value, the differences are recognized over the expected average remaining years of service for active employees.
Defined Contribution Plans
Xcel Energy, which includes NSP-Minnesota, maintains 401(k) and other defined contribution plans that cover substantially all employees. The expense to these plans for NSP-Minnesota was approximately $10.4 million in 2013, $9.0 million in 2012 and $8.6 million in 2011.
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Postretirement Health Care Benefits
Xcel Energy, which includes NSP-Minnesota, has a contributory health and welfare benefit plan that provides health care and death benefits to certain Xcel Energy retirees. The former NSP, which includes NSP-Minnesota, discontinued contributing toward health care benefits for nonbargaining employees retiring after 1998 and for bargaining employees who retired after 1999.
In 1993, Xcel Energy Inc. and NSP-Minnesota 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 retail and wholesale utility customers have allowed rate recovery of accrued postretirement benefit costs.
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. 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 Inc. and NSP-Minnesota base investment-return assumptions for the postretirement health care fund assets on expected long-term performance for each of the investment types included in the asset portfolio. The assets are invested in a portfolio according to Xcel Energy Inc.’s and NSP-Minnesota’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, NSP-Minnesota’s postretirement benefit plan assets that are measured at fair value as of Dec. 31, 2013 and 2012:
| Dec. 31, 2013 | ||||||||||||||||
| (Thousands of Dollars) | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
| Cash equivalents | $ | 179 | $ | — | $ | — | $ | 179 | ||||||||
| Derivatives | — | (3 | ) | — | (3 | ) | ||||||||||
| Government securities | — | 510 | — | 510 | ||||||||||||
| Insurance contracts | — | 461 | — | 461 | ||||||||||||
| Corporate bonds | — | 453 | — | 453 | ||||||||||||
| Asset-backed securities | — | 29 | — | 29 | ||||||||||||
| Mortgage-backed securities | — | 212 | — | 212 | ||||||||||||
| Commingled funds | — | 2,606 | — | 2,606 | ||||||||||||
| Other | — | (148 | ) | — | (148 | ) | ||||||||||
| Total | $ | 179 | $ | 4,120 | $ | — | $ | 4,299 | ||||||||
| Dec. 31, 2012 | ||||||||||||||||
| (Thousands of Dollars) | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
| Cash equivalents | $ | 1,105 | $ | — | $ | — | $ | 1,105 | ||||||||
| Derivatives | — | 889 | — | 889 | ||||||||||||
| Government securities | — | 605 | — | 605 | ||||||||||||
| Corporate bonds | — | 530 | — | 530 | ||||||||||||
| Asset-backed securities | — | — | 9 | 9 | ||||||||||||
| Mortgage-backed securities | — | — | 483 | 483 | ||||||||||||
| Commingled funds | — | 2,764 | — | 2,764 | ||||||||||||
| Other | — | (567 | ) | — | (567 | ) | ||||||||||
| Total | $ | 1,105 | $ | 4,221 | $ | 492 | $ | 5,818 | ||||||||
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The following tables present the changes in NSP-Minnesota’s Level 3 postretirement benefit plan assets for the years ended Dec. 31, 2013, 2012 and 2011:
| (Thousands of Dollars) | Jan. 1, 2013 | Net Realized Gains (Losses) | Net Unrealized Gains (Losses) | Purchases, Issuances and Settlements, Net | Transfers Out of Level 3 (a) | Dec. 31, 2013 | ||||||||||||||||||
| Asset-backed securities | $ | 9 | $ | — | $ | — | $ | — | $ | (9 | ) | $ | — | |||||||||||
| Mortgage-backed securities | 483 | — | — | — | (483 | ) | — | |||||||||||||||||
| Total | $ | 492 | $ | — | $ | — | $ | — | $ | (492 | ) | $ | — | |||||||||||
(a) | Transfers out of Level 3 into Level 2 were principally due to diminished use of unobservable inputs that were previously significant to these fair value measurements and were subsequently sold during 2013. |
| (Thousands of Dollars) | Jan. 1, 2012 | Net Realized Gains (Losses) | Net Unrealized Gains (Losses) | Purchases, Issuances and Settlements, Net | Transfers Out of Level 3 | Dec. 31, 2012 | ||||||||||||||||||
| Asset-backed securities | $ | 119 | $ | (4 | ) | $ | 28 | $ | (134 | ) | $ | — | $ | 9 | ||||||||||
| Mortgage-backed securities | 415 | (9 | ) | 57 | 20 | — | 483 | |||||||||||||||||
| Total | $ | 534 | $ | (13 | ) | $ | 85 | $ | (114 | ) | $ | — | $ | 492 | ||||||||||
| (Thousands of Dollars) | Jan. 1, 2011 | Net Realized Gains (Losses) | Net Unrealized Gains (Losses) | Purchases, Issuances and Settlements, Net | Transfers Out of Level 3 | Dec. 31, 2011 | ||||||||||||||||||
| Asset-backed securities | $ | 47 | $ | — | $ | (15 | ) | $ | 87 | $ | — | $ | 119 | |||||||||||
| Mortgage-backed securities | 350 | (26 | ) | 41 | 50 | — | 415 | |||||||||||||||||
| Total | $ | 397 | $ | (26 | ) | $ | 26 | $ | 137 | $ | — | $ | 534 | |||||||||||
Benefit Obligations — A comparison of the actuarially computed benefit obligation and plan assets for NSP-Minnesota is presented in the following table:
| (Thousands of Dollars) | 2013 | 2012 | ||||||
| Change in Projected Benefit Obligation: | ||||||||
| Obligation at Jan. 1 | $ | 124,986 | $ | 146,043 | ||||
| Service cost | 120 | 96 | ||||||
| Interest cost | 4,901 | 7,129 | ||||||
| Medicare subsidy reimbursements | 126 | 748 | ||||||
| Plan amendments | — | (29,776 | ) | |||||
| Plan participants’ contributions | 2,367 | 5,216 | ||||||
| Actuarial (gain) loss | (13,385 | ) | 13,706 | |||||
| Benefit payments | (10,883 | ) | (18,176 | ) | ||||
| Obligation at Dec. 31 | $ | 108,232 | $ | 124,986 | ||||
| (Thousands of Dollars) | 2013 | 2012 | ||||||
| Change in Fair Value of Plan Assets: | ||||||||
| Fair value of plan assets at Jan. 1 | $ | 5,818 | $ | 6,493 | ||||
| Actual return on plan assets | 15 | 263 | ||||||
| Plan participants’ contributions | 2,367 | 5,216 | ||||||
| Employer contributions | 6,982 | 12,022 | ||||||
| Benefit payments | (10,883 | ) | (18,176 | ) | ||||
| Fair value of plan assets at Dec. 31 | $ | 4,299 | $ | 5,818 | ||||
| (Thousands of Dollars) | 2013 | 2012 | ||||||
| Funded Status of Plans at Dec. 31: | ||||||||
| Funded status | $ | (103,933 | ) | $ | (119,168 | ) | ||
| Current liabilities | (4,990 | ) | (3,893 | ) | ||||
| Noncurrent liabilities | (98,943 | ) | (115,275 | ) | ||||
| Net postretirement amounts recognized on consolidated balance sheets | $ | (103,933 | ) | $ | (119,168 | ) | ||
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| (Thousands of Dollars) | 2013 | 2012 | ||||||
| Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost: | ||||||||
| Net loss | $ | 56,899 | $ | 75,153 | ||||
| Prior service credit | (27,541 | ) | (30,577 | ) | ||||
| Transition obligation | 2 | 35 | ||||||
| Total | $ | 29,360 | $ | 44,611 | ||||
| (Thousands of Dollars) | 2013 | 2012 | ||||||
| Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates: | ||||||||
| Current regulatory assets | $ | 1,679 | $ | 1,134 | ||||
| Noncurrent regulatory assets | 25,800 | 40,722 | ||||||
| Deferred income taxes | 768 | 1,127 | ||||||
| Net-of-tax accumulated OCI | 1,113 | 1,628 | ||||||
| Total | $ | 29,360 | $ | 44,611 | ||||
| Measurement date | Dec. 31, 2013 | Dec. 31, 2012 | ||
| 2013 | 2012 | |||||
| Significant Assumptions Used to Measure Benefit Obligations: | ||||||
| Discount rate for year-end valuation | 4.82 | % | 4.10 | % | ||
| Mortality table | RP 2000 | RP 2000 | ||||
| Health care costs trend rate — initial | 7.00 | % | 7.50 | % | ||
Effective Jan. 1, 2014, the initial medical trend rate was decreased from 7.5 percent to 7.0 percent. The ultimate trend assumption remained at 4.5 percent. The period until the ultimate rate is reached is five years. Xcel Energy Inc. and NSP-Minnesota base the 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 the retiree medical plan.
A one-percent change in the assumed health care cost trend rate would have the following effects on NSP-Minnesota:
| One Percentage Point | ||||||||
| (Thousands of Dollars) | Increase | Decrease | ||||||
| APBO | $ | 11,189 | $ | (9,376 | ) | |||
| Service and interest components | 496 | (392 | ) | |||||
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, which includes NSP-Minnesota, contributed $17.6 million, $47.1 million and $49.0 million during 2013, 2012 and 2011, respectively, of which $7.0 million, $12.0 million and $12.5 million were attributable to NSP-Minnesota. Xcel Energy expects to contribute approximately $13.3 million during 2014, of which $9.3 million is attributable to NSP-Minnesota.
Plan Amendments — The 2012 decrease of the projected Xcel Energy and NSP-Minnesota postretirement health and welfare benefit obligation for plan amendments is due to the expected transition of certain participant groups to an external plan administrator.
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Benefit Costs — The components of NSP-Minnesota’s net periodic postretirement benefit cost were:
| (Thousands of Dollars) | 2013 | 2012 | 2011 | |||||||||
| Service cost | $ | 120 | $ | 96 | $ | 87 | ||||||
| Interest cost | 4,901 | 7,129 | 7,372 | |||||||||
| Expected return on plan assets | (417 | ) | (438 | ) | (576 | ) | ||||||
| Amortization of transition obligation | 33 | 1,346 | 1,346 | |||||||||
| Amortization of prior service credit | (3,036 | ) | (117 | ) | (117 | ) | ||||||
| Amortization of net loss | 5,272 | 3,204 | 2,348 | |||||||||
| Net periodic postretirement benefit cost | $ | 6,873 | $ | 11,220 | $ | 10,460 | ||||||
| 2013 | 2012 | 2011 | |||||||
| Significant Assumptions Used to Measure Costs: | |||||||||
| Discount rate | 4.10 | % | 5.00 | % | 5.50 | % | |||
| Expected average long-term rate of return on assets | 7.11 | 6.75 | 7.50 | ||||||
In addition to the benefit costs in the table above, for the postretirement health care plans sponsored by Xcel Energy, Inc., costs are allocated to NSP-Minnesota based on Xcel Energy Services Inc. employees’ labor costs.
Projected Benefit Payments
The following table lists NSP-Minnesota’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 | ||||||||||||
| 2014 | $ | 129,101 | $ | 9,359 | $ | 70 | $ | 9,289 | ||||||||
| 2015 | 93,988 | 9,108 | 75 | 9,033 | ||||||||||||
| 2016 | 95,716 | 9,018 | 77 | 8,941 | ||||||||||||
| 2017 | 96,798 | 8,728 | 79 | 8,649 | ||||||||||||
| 2018 | 93,542 | 8,595 | 77 | 8,518 | ||||||||||||
| 2019-2023 | 432,905 | 39,271 | 351 | 38,920 | ||||||||||||
Multiemployer Plans
NSP-Minnesota contributes 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 sponsored pension and postretirement health care plans. Contributing to these types of plans creates risk that differs from providing benefits under NSP-Minnesota 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, 2013, 2012 and 2011. The average number of NSP-Minnesota union employees covered by the multiemployer pension plans increased to approximately 1,100 in 2013 from approximately 800 in 2012. There were no other significant changes to the nature or magnitude of the participation of NSP-Minnesota in multiemployer plans for the years presented:
| (Thousands of Dollars) | 2013 | 2012 | 2011 | |||||||||
| Multiemployer plan contributions: | ||||||||||||
| Pension | $ | 23,515 | $ | 14,984 | $ | 17,811 | ||||||
| Other postretirement benefits | 390 | 197 | 336 | |||||||||
| Total | $ | 23,905 | $ | 15,181 | $ | 18,147 | ||||||
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| 8. | Other (Expense) Income, Net |
Other (expense) income, net for the years ended Dec. 31 consisted of the following:
| (Thousands of Dollars) | 2013 | 2012 | 2011 | |||||||||
| Interest income | $ | 4,869 | $ | 5,364 | $ | 4,663 | ||||||
| Other nonoperating income | 174 | 825 | 969 | |||||||||
| Insurance policy expense | (5,696 | ) | (5,210 | ) | (3,915 | ) | ||||||
| Other (expense) income, net | $ | (653 | ) | $ | 979 | $ | 1,717 | |||||
| 9. | 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 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 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. Proper notice varies by fund and can range from daily with one or two days notice to annually with 90 days 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, which is typically quarterly with 45-90 days notice; however, withdrawals from real estate investments may be delayed or discounted as a result of fund illiquidity. Based on NSP-Minnesota’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.
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.
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Electric commodity derivatives held by NSP-Minnesota include transmission congestion instruments purchased from MISO, PJM, ERCOT and NYISO, generally referred to as FTRs. FTRs purchased from an RTO are financial instruments that entitle or obligate the holder to 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 energy congestion, which is caused by overall transmission load and other transmission constraints. In addition to overall transmission load, 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. Non-trading monthly FTR settlements are included in fuel and purchased energy cost recovery mechanisms, and therefore changes in the fair value of the yet to be settled portions of most 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 NSP-Minnesota.
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 uses the MPUC approved asset allocation for the escrow and investment targets by asset class for both the escrow and qualified trust.
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 nuclear decommissioning fund were $240.3 million and $135.8 million at Dec. 31, 2013 and 2012, respectively, and unrealized losses and amounts recorded as other-than-temporary impairments were $58.5 million and $46.4 million at Dec. 31, 2013 and 2012, respectively.
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The following tables present the cost and fair value of NSP-Minnesota’s non-derivative instruments with recurring fair value measurements in the nuclear decommissioning fund at Dec. 31, 2013 and 2012:
| Dec. 31, 2013 | ||||||||||||||||||||
| Fair Value | ||||||||||||||||||||
| (Thousands of Dollars) | Cost | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Nuclear decommissioning fund (a) | ||||||||||||||||||||
| Cash equivalents | $ | 33,281 | $ | 33,281 | $ | — | $ | — | $ | 33,281 | ||||||||||
| Commingled funds | 457,986 | — | 452,227 | — | 452,227 | |||||||||||||||
| International equity funds | 78,812 | — | 81,671 | — | 81,671 | |||||||||||||||
| Private equity investments | 52,143 | — | — | 62,696 | 62,696 | |||||||||||||||
| Real estate | 45,564 | — | — | 57,368 | 57,368 | |||||||||||||||
| Debt securities: | ||||||||||||||||||||
| Government securities | 34,304 | — | 27,628 | — | 27,628 | |||||||||||||||
| U.S. corporate bonds | 80,275 | — | 83,538 | — | 83,538 | |||||||||||||||
| International corporate bonds | 15,025 | — | 15,358 | — | 15,358 | |||||||||||||||
| Municipal bonds | 241,112 | — | 232,016 | — | 232,016 | |||||||||||||||
| Equity securities: | ||||||||||||||||||||
| Common stock | 406,695 | 581,243 | — | — | 581,243 | |||||||||||||||
| Total | $ | 1,445,197 | $ | 614,524 | $ | 892,438 | $ | 120,064 | $ | 1,627,026 | ||||||||||
(a) | Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $28.3 million of miscellaneous investments. |
| Dec. 31, 2012 | ||||||||||||||||||||
| Fair Value | ||||||||||||||||||||
| (Thousands of Dollars) | Cost | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||
Nuclear decommissioning fund (a) | ||||||||||||||||||||
| Cash equivalents | $ | 246,904 | $ | 237,938 | $ | 8,966 | $ | — | $ | 246,904 | ||||||||||
| Commingled funds | 396,681 | — | 417,583 | — | 417,583 | |||||||||||||||
| International equity funds | 66,452 | — | 69,481 | — | 69,481 | |||||||||||||||
| Private equity investments | 27,943 | — | — | 33,250 | 33,250 | |||||||||||||||
| Real estate | 32,561 | — | — | 39,074 | 39,074 | |||||||||||||||
| Debt securities: | ||||||||||||||||||||
| Government securities | 21,092 | — | 21,521 | — | 21,521 | |||||||||||||||
| U.S. corporate bonds | 162,053 | — | 169,488 | — | 169,488 | |||||||||||||||
| International corporate bonds | 15,165 | — | 16,052 | — | 16,052 | |||||||||||||||
| Municipal bonds | 21,392 | — | 23,650 | — | 23,650 | |||||||||||||||
| Asset-backed securities | 2,066 | — | — | 2,067 | 2,067 | |||||||||||||||
| Mortgage-backed securities | 28,743 | — | — | 30,209 | 30,209 | |||||||||||||||
| Equity securities: | ||||||||||||||||||||
| Common stock | 379,093 | 420,263 | — | — | 420,263 | |||||||||||||||
| Total | $ | 1,400,145 | $ | 658,201 | $ | 726,741 | $ | 104,600 | $ | 1,489,542 | ||||||||||
(a) | Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $24.6 million of miscellaneous investments. |
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The following tables present the changes in Level 3 nuclear decommissioning fund investments:
| (Thousands of Dollars) | Jan. 1, 2013 | Purchases | Settlements | Gains Recognized as Regulatory Assets and Liabilities | Transfers Out of Level 3 (a) | Dec. 31, 2013 | ||||||||||||||||||
| Private equity investments | $ | 33,250 | $ | 24,201 | $ | — | $ | 5,245 | $ | — | $ | 62,696 | ||||||||||||
| Real estate | 39,074 | 31,626 | (18,622 | ) | 5,290 | — | 57,368 | |||||||||||||||||
| Asset-backed securities | 2,067 | — | — | — | (2,067 | ) | — | |||||||||||||||||
| Mortgage-backed securities | 30,209 | — | — | — | (30,209 | ) | — | |||||||||||||||||
| Total | $ | 104,600 | $ | 55,827 | $ | (18,622 | ) | $ | 10,535 | $ | (32,276 | ) | $ | 120,064 | ||||||||||
(a) | Transfers out of Level 3 into Level 2 were principally due to diminished use of unobservable inputs that were previously significant to these fair value measurements and were subsequently sold during 2013. |
| (Thousands of Dollars) | Jan. 1, 2012 | Purchases | Settlements | Gains (Losses) Recognized as Regulatory Assets and Liabilities | Transfers Out of Level 3 | Dec. 31, 2012 | ||||||||||||||||||
| Private equity investments | $ | 9,203 | $ | 20,671 | $ | (1,931 | ) | $ | 5,307 | $ | — | $ | 33,250 | |||||||||||
| Real estate | 26,395 | 9,777 | (3,611 | ) | 6,513 | — | 39,074 | |||||||||||||||||
| Asset-backed securities | 16,501 | — | (14,450 | ) | 16 | — | 2,067 | |||||||||||||||||
| Mortgage-backed securities | 78,664 | 33,016 | (79,899 | ) | (1,572 | ) | — | 30,209 | ||||||||||||||||
| Total | $ | 130,763 | $ | 63,464 | $ | (99,891 | ) | $ | 10,264 | $ | — | $ | 104,600 | |||||||||||
| (Thousands of Dollars) | Jan. 1, 2011 | Purchases | Settlements | Gains (Losses) Recognized as Regulatory Assets and Liabilities | Transfers Out of Level 3 | Dec. 31, 2011 | ||||||||||||||||||
| Private equity investments | $ | — | $ | 9,203 | $ | — | $ | — | $ | — | $ | 9,203 | ||||||||||||
| Real estate | — | 24,768 | — | 1,627 | — | 26,395 | ||||||||||||||||||
| 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 | ||||||||||||||||
| Total | $ | 105,763 | $ | 219,177 | $ | (193,694 | ) | $ | (483 | ) | $ | — | $ | 130,763 | ||||||||||
The following table summarizes the final contractual maturity dates of the debt securities in the nuclear decommissioning fund, by asset class, at Dec. 31, 2013:
| 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 | $ | — | $ | — | $ | — | $ | 27,628 | $ | 27,628 | ||||||||||
| U.S. corporate bonds | 780 | 17,850 | 63,089 | 1,819 | 83,538 | |||||||||||||||
| International corporate bonds | — | 2,222 | 13,136 | — | 15,358 | |||||||||||||||
| Municipal bonds | 3,554 | 25,663 | 33,109 | 169,690 | 232,016 | |||||||||||||||
| Debt securities | $ | 4,334 | $ | 45,735 | $ | 109,334 | $ | 199,137 | $ | 358,540 | ||||||||||
Derivative Instruments Fair Value Measurements
NSP-Minnesota enters into derivative instruments, including forward contracts, futures, swaps and options, for trading purposes and to manage risk in connection with changes in interest rates, utility commodity prices and vehicle fuel prices.
Interest Rate Derivatives — NSP-Minnesota enters into various instruments that effectively fix the interest payments on certain floating rate debt obligations or effectively fix the yield or price on a specified benchmark interest rate for an anticipated debt issuance for a specific period. These derivative instruments are generally designated as cash flow hedges for accounting purposes.
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At Dec. 31, 2013, accumulated other comprehensive losses related to interest rate derivatives included $0.8 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings, including forecasted amounts for unsettled hedges, as applicable.
In conjunction with the NSP-Minnesota debt issuance in August 2012, NSP-Minnesota settled interest rate hedging instruments with a notional amount of $225 million with cash payments of $45.0 million. This loss is classified as a component of accumulated other comprehensive loss on the consolidated balance sheet, net of tax, and is being reclassified to earnings over the term of the hedged interest payments. See Note 4 for further discussion of long-term borrowings.
Wholesale and Commodity Trading Risk — NSP-Minnesota conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and energy-related instruments. NSP-Minnesota’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 — NSP-Minnesota 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, natural gas for resale, and vehicle fuel.
At Dec. 31, 2013, NSP-Minnesota had various vehicle fuel contracts designated as cash flow hedges extending through December 2016. NSP-Minnesota 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. NSP-Minnesota recorded immaterial amounts to income related to the ineffectiveness of cash flow hedges for the years ended Dec. 31, 2013 and 2012.
At Dec. 31, 2013, net gains related to commodity derivative cash flow hedges recorded as a component of accumulated other comprehensive losses included an immaterial amount of net gains expected to be reclassified into earnings during the next 12 months as the hedged transactions occur.
Additionally, NSP-Minnesota 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 revenue, 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, 2013 and 2012:
(Amounts in Thousands) (a)(b) | Dec. 31, 2013 | Dec. 31, 2012 | ||||
| MWh of electricity | 52,107 | 55,163 | ||||
| MMBtu of natural gas | 2,470 | 26 | ||||
| Gallons of vehicle fuel | 265 | 375 | ||||
(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. |
Consideration of Credit Risk and Concentrations — NSP-Minnesota continuously monitors the creditworthiness of the counterparties to its interest rate derivatives and commodity derivative contracts prior to settlement, 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 NSP-Minnesota’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 unsettled commodity derivatives presented in the consolidated balance sheets.
NSP-Minnesota employs additional credit risk control mechanisms when appropriate, such as letters of credit, parental guarantees, standardized master netting agreements and termination provisions that allow for offsetting of positive and negative exposures. Credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided.
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NSP-Minnesota’s most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to its wholesale, trading and non-trading commodity activities. At Dec. 31, 2013, six of NSP-Minnesota’s 10 most significant counterparties for these activities, comprising $26.3 million or 27 percent of this credit exposure, had investment grade credit ratings from Standard & Poor’s, Moody’s or Fitch Ratings. The remaining four significant counterparties, comprising $18.4 million or 19 percent of this credit exposure at Dec. 31, 2013, were not rated by these agencies, but based on NSP-Minnesota’s internal analysis, had credit quality consistent with investment grade. All 10 of these significant counterparties are municipal or cooperative electric entities, or other utilities.
Financial Impact of Qualifying Cash Flow Hedges — The impact of qualifying interest rate and vehicle fuel cash flow hedges on NSP-Minnesota’s accumulated other comprehensive loss, included in the consolidated statements of common stockholder’s equity and in the consolidated statements of comprehensive income, is detailed in the following table:
| (Thousands of Dollars) | 2013 | 2012 | 2011 | |||||||||
| Accumulated other comprehensive (loss) income related to cash flow hedges at Jan. 1 | $ | (21,393 | ) | $ | (11,729 | ) | $ | 4,977 | ||||
| After-tax net unrealized gains (losses) related to derivatives accounted for as hedges | 5 | (9,889 | ) | (16,578 | ) | |||||||
| After-tax net realized losses (gains) on derivative transactions reclassified into earnings | 779 | 225 | (128 | ) | ||||||||
| Accumulated other comprehensive loss related to cash flow hedges at Dec. 31 | $ | (20,609 | ) | $ | (21,393 | ) | $ | (11,729 | ) | |||
The following tables detail the impact of derivative activity during the years ended Dec. 31, 2013, 2012 and 2011 on accumulated other comprehensive loss, regulatory assets and liabilities, and income:
| Year Ended Dec. 31, 2013 | |||||||||||||||||||||
Pre-Tax Fair Value Gains (Losses) Recognized During the Period in: | Pre-Tax (Gains) Losses Reclassified into Income During the Period from: | ||||||||||||||||||||
| (Thousands of Dollars) | Accumulated Other Comprehensive Loss | Regulatory (Assets) and Liabilities | Accumulated Other Comprehensive Loss | Regulatory Assets and (Liabilities) | Pre-Tax Gains (Losses) Recognized During the Period in Income | ||||||||||||||||
| Derivatives designated as cash flow hedges | |||||||||||||||||||||
| Interest rate | $ | — | $ | — | $ | 1,388 | (a) | $ | — | $ | — | ||||||||||
| Vehicle fuel and other commodity | 15 | — | (49 | ) | (b) | — | — | ||||||||||||||
| Total | $ | 15 | $ | — | $ | 1,339 | $ | — | $ | — | |||||||||||
| Other derivative instruments | |||||||||||||||||||||
| Commodity trading | $ | — | $ | — | $ | — | $ | — | $ | 11,220 | (c) | ||||||||||
| Electric commodity | — | 65,884 | — | (52,796 | ) | (d) | — | ||||||||||||||
| Natural gas commodity | — | 1,039 | — | 368 | (e) | (393 | ) | (d) | |||||||||||||
| Total | $ | — | $ | 66,923 | $ | — | $ | (52,428 | ) | $ | 10,827 | ||||||||||
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| Year Ended Dec. 31, 2012 | |||||||||||||||||||||
Pre-Tax Fair Value Gains (Losses) Recognized During the Period in: | Pre-Tax (Gains) Losses Reclassified into Income During the Period from: | ||||||||||||||||||||
| (Thousands of Dollars) | Accumulated Other Comprehensive Loss | Regulatory (Assets) and Liabilities | Accumulated Other Comprehensive Loss | Regulatory Assets and (Liabilities) | Pre-Tax Gains Recognized During the Period in Income | ||||||||||||||||
| Derivatives designated as cash flow hedges | |||||||||||||||||||||
| Interest rate | $ | (16,832 | ) | $ | — | $ | 490 | (a) | $ | — | $ | — | |||||||||
| Vehicle fuel and other commodity | 58 | — | (109 | ) | (b) | — | — | ||||||||||||||
| Total | $ | (16,774 | ) | $ | — | $ | 381 | $ | — | $ | — | ||||||||||
| Other derivative instruments | |||||||||||||||||||||
| Commodity trading | $ | — | $ | — | $ | — | $ | — | $ | 12,224 | (c) | ||||||||||
| Electric commodity | — | 44,162 | — | (39,999 | ) | (d) | — | ||||||||||||||
| Natural gas commodity | — | (2,662 | ) | — | 16,158 | (e) | — | ||||||||||||||
| Total | $ | — | $ | 41,500 | $ | — | $ | (23,841 | ) | $ | 12,224 | ||||||||||
| Year Ended Dec. 31, 2011 | |||||||||||||||||||||
Pre-Tax Fair Value Gains (Losses) Recognized During the Period in: | Pre-Tax (Gains) Losses Reclassified into Income During the Period from: | ||||||||||||||||||||
| (Thousands of Dollars) | Accumulated Other Comprehensive Loss | Regulatory (Assets) and Liabilities | Accumulated Other Comprehensive Loss | Regulatory Assets and(Liabilities) | Pre-Tax Gains Recognized During the Period in Income | ||||||||||||||||
| Derivatives designated as cash flow hedges | |||||||||||||||||||||
| Interest rate | $ | (28,119 | ) | $ | — | $ | (109 | ) | (a) | $ | — | $ | — | ||||||||
| Vehicle fuel and other commodity | 119 | — | (113 | ) | (b) | — | — | ||||||||||||||
| Total | $ | (28,000 | ) | $ | — | $ | (222 | ) | $ | — | $ | — | |||||||||
| Other derivative instruments | |||||||||||||||||||||
| Commodity trading | $ | — | $ | — | $ | — | $ | — | $ | 6,330 | (c) | ||||||||||
| Electric commodity | — | 49,818 | — | (40,492 | ) | (d) | — | ||||||||||||||
| Natural gas commodity | — | (22,581 | ) | — | 18,021 | (e) | — | ||||||||||||||
| Total | $ | — | $ | 27,237 | $ | — | $ | (22,471 | ) | $ | 6,330 | ||||||||||
(a) | Amounts are recorded to interest charges. |
(b) | Amounts are recorded to O&M expenses. |
(c) | Amounts are recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate. |
(d) | Amounts are 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. |
(e) | Amounts are 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. |
NSP-Minnesota had no derivative instruments designated as fair value hedges during the years ended Dec. 31, 2013, 2012 and 2011. Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods.
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Credit Related Contingent Features — Contract provisions for derivative instruments that NSP-Minnesota enters into, including those recorded to the consolidated balance sheet at fair value, as well as those accounted for as normal purchase-normal sale contracts and therefore not reflected on the balance sheet, may require the posting of collateral or settlement of the contracts for various reasons, including if NSP-Minnesota is unable to maintain its credit ratings. At Dec. 31, 2013 and 2012, no derivative instruments in a liability position would have required the posting of collateral or settlement of outstanding contracts if the credit ratings of NSP-Minnesota were downgraded below investment grade.
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 NSP-Minnesota’s ability to fulfill its contractual obligations is reasonably expected to be impaired. NSP-Minnesota had no collateral posted related to adequate assurance clauses in derivative contracts as of Dec. 31, 2013 and 2012.
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Recurring Fair Value Measurements — The following table presents for each of the fair value hierarchy levels, NSP-Minnesota’s derivative assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2013:
| Dec. 31, 2013 | ||||||||||||||||||||||||
| Fair Value | ||||||||||||||||||||||||
| (Thousands of Dollars) | Level 1 | Level 2 | Level 3 | Fair Value Total | Counterparty Netting (b) | Total | ||||||||||||||||||
| Current derivative assets | ||||||||||||||||||||||||
| Derivatives designated as cash flow hedges: | ||||||||||||||||||||||||
| Vehicle fuel and other commodity | $ | — | $ | 48 | $ | — | $ | 48 | $ | — | $ | 48 | ||||||||||||
| Other derivative instruments: | ||||||||||||||||||||||||
| Commodity trading | — | 17,854 | 1,167 | 19,021 | (6,718 | ) | 12,303 | |||||||||||||||||
| Electric commodity | — | — | 30,692 | 30,692 | (1,723 | ) | 28,969 | |||||||||||||||||
| Natural gas commodity | — | 1,986 | — | 1,986 | — | 1,986 | ||||||||||||||||||
| Total current derivative assets | $ | — | $ | 19,888 | $ | 31,859 | $ | 51,747 | $ | (8,441 | ) | 43,306 | ||||||||||||
PPAs (a) | 23,420 | |||||||||||||||||||||||
| Current derivative instruments | $ | 66,726 | ||||||||||||||||||||||
| Noncurrent derivative assets | ||||||||||||||||||||||||
| Derivatives designated as cash flow hedges: | ||||||||||||||||||||||||
| Vehicle fuel and other commodity | $ | — | $ | 16 | $ | — | $ | 16 | $ | (16 | ) | $ | — | |||||||||||
| Other derivative instruments: | ||||||||||||||||||||||||
| Commodity trading | — | 32,074 | 3,395 | 35,469 | (9,071 | ) | 26,398 | |||||||||||||||||
| Total noncurrent derivative assets | $ | — | $ | 32,090 | $ | 3,395 | $ | 35,485 | $ | (9,087 | ) | 26,398 | ||||||||||||
PPAs (a) | 10,483 | |||||||||||||||||||||||
| Noncurrent derivative instruments | $ | 36,881 | ||||||||||||||||||||||
| Current derivative liabilities | ||||||||||||||||||||||||
| Derivatives designated as cash flow hedges: | ||||||||||||||||||||||||
| Other derivative instruments: | ||||||||||||||||||||||||
| Commodity trading | $ | — | $ | 8,108 | $ | 1,804 | $ | 9,912 | $ | (9,912 | ) | $ | — | |||||||||||
| Electric commodity | — | — | 1,723 | 1,723 | (1,723 | ) | — | |||||||||||||||||
| Total current derivative liabilities | $ | — | $ | 8,108 | $ | 3,527 | $ | 11,635 | $ | (11,635 | ) | — | ||||||||||||
PPAs (a) | 13,066 | |||||||||||||||||||||||
| Current derivative instruments | $ | 13,066 | ||||||||||||||||||||||
| Noncurrent derivative liabilities | ||||||||||||||||||||||||
| Other derivative instruments: | ||||||||||||||||||||||||
| Commodity trading | $ | — | $ | 14,382 | $ | — | $ | 14,382 | $ | (10,137 | ) | $ | 4,245 | |||||||||||
| Total noncurrent derivative liabilities | $ | — | $ | 14,382 | $ | — | $ | 14,382 | $ | (10,137 | ) | 4,245 | ||||||||||||
PPAs (a) | 147,406 | |||||||||||||||||||||||
| Noncurrent derivative instruments | $ | 151,651 | ||||||||||||||||||||||
(a) | In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, NSP-Minnesota began recording several long-term PPAs 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, NSP-Minnesota 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) | NSP-Minnesota nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2013. At Dec. 31, 2013, derivative assets and liabilities include no obligations to return cash collateral and rights to reclaim cash collateral of $4.2 million. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. |
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The following table presents for each of the fair value hierarchy levels, NSP-Minnesota’s derivative assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2012:
| Dec. 31, 2012 | ||||||||||||||||||||||||
| Fair Value | ||||||||||||||||||||||||
| (Thousands of Dollars) | Level 1 | Level 2 | Level 3 | Fair Value Total | Counterparty Netting (b) | Total | ||||||||||||||||||
| Current derivative assets | ||||||||||||||||||||||||
| Derivatives designated as cash flow hedges: | ||||||||||||||||||||||||
| Vehicle fuel and other commodity | $ | — | $ | 52 | $ | — | $ | 52 | $ | — | $ | 52 | ||||||||||||
| Other derivative instruments: | ||||||||||||||||||||||||
| Commodity trading | — | 19,871 | 692 | 20,563 | (3,374 | ) | 17,189 | |||||||||||||||||
| Electric commodity | — | — | 16,724 | 16,724 | (843 | ) | 15,881 | |||||||||||||||||
| Total current derivative assets | $ | — | $ | 19,923 | $ | 17,416 | $ | 37,339 | $ | (4,217 | ) | 33,122 | ||||||||||||
PPAs (a) | 23,110 | |||||||||||||||||||||||
| Current derivative instruments | $ | 56,232 | ||||||||||||||||||||||
| Noncurrent derivative assets | ||||||||||||||||||||||||
| Derivatives designated as cash flow hedges: | ||||||||||||||||||||||||
| Vehicle fuel and other commodity | $ | — | $ | 47 | $ | — | $ | 47 | $ | (47 | ) | $ | — | |||||||||||
| Other derivative instruments: | ||||||||||||||||||||||||
| Commodity trading | — | 37,513 | 76 | 37,589 | (2,616 | ) | 34,973 | |||||||||||||||||
| Total noncurrent derivative assets | $ | — | $ | 37,560 | $ | 76 | $ | 37,636 | $ | (2,663 | ) | 34,973 | ||||||||||||
PPAs (a) | 31,507 | |||||||||||||||||||||||
| Noncurrent derivative instruments | $ | 66,480 | ||||||||||||||||||||||
| Current derivative liabilities | ||||||||||||||||||||||||
| Other derivative instruments: | ||||||||||||||||||||||||
| Commodity trading | $ | — | $ | 12,664 | $ | — | $ | 12,664 | $ | (6,400 | ) | $ | 6,264 | |||||||||||
| Electric commodity | — | — | 843 | 843 | (843 | ) | — | |||||||||||||||||
| Natural gas commodity | — | 2 | — | 2 | — | 2 | ||||||||||||||||||
| Total current derivative liabilities | $ | — | $ | 12,666 | $ | 843 | $ | 13,509 | $ | (7,243 | ) | 6,266 | ||||||||||||
PPAs (a) | 13,851 | |||||||||||||||||||||||
| Current derivative instruments | $ | 20,117 | ||||||||||||||||||||||
| Noncurrent derivative liabilities | ||||||||||||||||||||||||
| Other derivative instruments: | ||||||||||||||||||||||||
| Commodity trading | $ | — | $ | 17,966 | $ | — | $ | 17,966 | $ | (2,664 | ) | $ | 15,302 | |||||||||||
| Total noncurrent derivative liabilities | $ | — | $ | 17,966 | $ | — | $ | 17,966 | $ | (2,664 | ) | 15,302 | ||||||||||||
PPAs (a) | 159,169 | |||||||||||||||||||||||
| Noncurrent derivative instruments | $ | 174,471 | ||||||||||||||||||||||
(a) | In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, NSP-Minnesota began recording several long-term PPAs 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, NSP-Minnesota 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) | NSP-Minnesota nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2012. At Dec. 31, 2012, derivative assets and liabilities include no obligations to return cash collateral and rights to reclaim cash collateral of $3.0 million. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. |
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The following table present the changes in Level 3 commodity derivatives for the years ended Dec. 31, 2013, 2012 and 2011:
| Year Ended Dec. 31 | ||||||||||||
| (Thousands of Dollars) | 2013 | 2012 | 2011 | |||||||||
| Balance at Jan. 1 | $ | 16,649 | $ | 12,417 | $ | 2,392 | ||||||
| Purchases | 51,541 | 37,595 | 33,609 | |||||||||
| Settlements | (45,199 | ) | (44,950 | ) | (36,552 | ) | ||||||
| Net transactions recorded during the period: | ||||||||||||
Gains recognized in earnings (a) | 3,947 | 463 | 66 | |||||||||
| Gains recognized as regulatory assets and liabilities | 4,789 | 11,124 | 12,902 | |||||||||
| Balance at Dec. 31 | $ | 31,727 | $ | 16,649 | $ | 12,417 | ||||||
(a) | These amounts relate to commodity derivatives held at the end of the period. |
NSP-Minnesota recognizes transfers between levels as of the beginning of each period. There were no transfers of amounts between levels for derivative instruments for the years ended Dec. 31, 2013, 2012 and 2011.
Fair Value of Long-Term Debt
As of Dec. 31, 2013 and 2012, other financial instruments for which the carrying amount did not equal fair value were as follows:
| 2013 | 2012 | |||||||||||||||
| (Thousands of Dollars) | Carrying Amount | Fair Value | Carrying Amount | Fair Value | ||||||||||||
| Long-term debt, including current portion | $ | 3,888,732 | $ | 4,099,745 | $ | 3,488,640 | $ | 4,181,580 | ||||||||
The fair value of NSP-Minnesota’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. The fair value estimates are based on information available to management as of Dec. 31, 2013 and 2012, and given the observability of the inputs to these estimates, the fair values presented for long-term debt have been assigned a Level 2.
| 10. | Rate Matters |
Pending and Recently Concluded Regulatory Proceedings — MPUC
Minnesota 2014 Multi-Year Electric Rate Case — On Nov. 4, 2013, NSP-Minnesota filed a two-year, electric rate case with the MPUC. The rate case is based on a requested ROE of 10.25 percent, a 52.5 percent equity ratio, a 2014 average electric rate base of $6.67 billion and an additional average rate base of $412 million in 2015.
The NSP-Minnesota electric rate case reflects an overall increase in revenues of approximately $193 million or 6.9 percent in 2014 and an additional $98 million or 3.5 percent in 2015. The request includes a proposed rate moderation plan for 2014 and 2015. After reflecting interim rate adjustments, the impact of NSP-Minnesota’s request on customer bills would result in a 4.6 percent increase in 2014 and an additional 5.6 percent in 2015.
NSP-Minnesota’s moderation plan includes the acceleration of the eight-year amortization of the excess theoretical depreciation reserve which the MPUC approved in NSP-Minnesota’s last electric rate case and the use of expected funds from the DOE for settlement of certain claims. These DOE refunds would be in excess of amounts needed to fund its decommissioning expense. The interim rate adjustments are primarily associated with ROE, Monticello LCM/EPU project costs and NSP-Minnesota’s request to amortize amounts associated with the canceled Prairie Island EPU project. NSP-Minnesota plans to file a petition for deferred accounting regarding these Monticello costs in the first quarter of 2014.
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The rate request, moderation plan, interim rate adjustments, customer bill impacts and certain impacts on expenses are detailed in the table below:
| (Millions of Dollars) | 2014 | Percentage Increase | 2015 | Percentage Increase | ||||||||
| Pre-moderation deficiency | $ | 274 | $ | 81 | ||||||||
| Moderation change compared to prior year: | ||||||||||||
| Excess theoretical depreciation reserve | (81 | ) | 53 | |||||||||
| DOE settlement proceeds | — | (36 | ) | |||||||||
| Filed rate request | 193 | 6.9% | 98 | 3.5% | ||||||||
| Interim rate adjustments | (66 | ) | 66 | |||||||||
| Impact on customer bill | 127 | 4.6% | 164 | 5.6% | ||||||||
| Potential expense deferral (Monticello/Prairie Island EPU projects) | 16 | — | ||||||||||
| Depreciation expense - reduction/(increase) | 81 | (46 | ) | |||||||||
| Recognition of DOE settlement proceeds | — | 36 | ||||||||||
| Pre-tax impact on operating income | $ | 224 | $ | 154 | ||||||||
On Dec. 12, 2013, the MPUC approved interim rates of $127 million as requested, effective Jan. 3, 2014, subject to refund. The MPUC determined that the costs of Sherco Unit 3 would be allowed in interim rates, and that NSP-Minnesota’s request to accelerate the theoretical depreciation reserve amortization was a permissible adjustment to its interim rate request even though it differed from the MPUC’s 2013 Minnesota rate case order.
The next steps in the procedural schedule are expected to be as follows:
| • | Direct Testimony — June 5, 2014; |
| • | Rebuttal Testimony — July 7, 2014; |
| • | Surrebuttal Testimony — Aug. 4, 2014; |
| • | Evidentiary Hearing — Aug. 11-18, 2014; |
| • | Reply Brief — Oct. 14, 2014; and |
| • | ALJ Report — Dec. 22, 2014. |
A final MPUC decision is anticipated in March 2015.
Minnesota 2013 Electric Rate Case — In November 2012, NSP-Minnesota filed a request with the MPUC for an increase in annual revenues of approximately $285 million, or 10.7 percent. The rate filing was based on a 2013 FTY, a requested ROE of 10.6 percent, an average electric rate base of approximately $6.3 billion and an equity ratio of 52.56 percent. In January 2013, interim rates of approximately $251 million became effective, subject to refund.
In May 2013, NSP-Minnesota subsequently revised the requested annual revenue increase to approximately $209 million, or 7.8 percent, based on an ROE of 10.6 percent, a rate base of approximately $6.3 billion an equity ratio of 52.56 percent. The revenue requirement reflected a requested deficiency of $259 million combined with $50 million of rate mitigation through deferral mechanisms.
In September 2013, the MPUC issued an order approving a rate increase of approximately $103 million, or 3.8 percent, based on a 9.83 percent ROE and 52.56 percent equity ratio. In addition, the MPUC authorized approximately $20 million in deferrals, as well as a $24 million reduction in revenue and depreciation expense.
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The table below reconciles NSP-Minnesota’s original request to the final MPUC order:
| (Millions of Dollars) | MPUC Order | |||
| NSP-Minnesota original request | $ | 285 | ||
| ROE | (43 | ) | ||
| Sherco Unit 3 | (34 | ) | ||
| Reduced recovery for nuclear plants | (15 | ) | ||
| Incentive compensation | (4 | ) | ||
| Sales forecast | (26 | ) | ||
| Pension | (13 | ) | ||
| Employee benefits | (6 | ) | ||
| Black Dog remediation | (5 | ) | ||
| Estimated impact of the theoretical depreciation reserve | (24 | ) | ||
| NSP-Wisconsin wholesale allocation | (7 | ) | ||
| Other, net | (5 | ) | ||
| Recommended rate increase | 103 | |||
| Estimated impact of cost deferrals | 20 | |||
| Estimated impact of the theoretical depreciation reserve | 24 | |||
| Impact on pre-tax income | $ | 147 | ||
NSP-Minnesota filed its final rate implementation and interim rate refund compliance filing on Sept. 19, 2013, requesting final rates be implemented Dec. 1, 2013, with interim rate refunds of approximately $132.2 million, including interest, to begin by January 2014. On Nov. 19, 2013, the MPUC approved the final rate implementation plan, new rates began Dec. 1, 2013 and interim rate refunds were applied to customer accounts starting Dec. 16, 2013.
Nuclear Project Prudence Investigation — The MPUC has initiated an investigation to determine whether the costs in excess of those included in the CON for NSP-Minnesota’s Monticello LCM/EPU project were prudent. In October 2013, NSP-Minnesota filed a summary report to further support the change and prudence of the incurred costs. The filing indicated the increase in costs was primarily attributable to three factors: (1) the original estimate was based on a high level conceptual design and the project scope increased as the actual conditions of the plant were incorporated into the design; (2) implementation difficulties, including the amount of work that occurred in confined and radioactive or electrically sensitive spaces and NSP-Minnesota’s and its vendors’ ability to attract and retain experienced workers; and (3) additional NRC licensing related requests over the five-plus year application process. NSP-Minnesota has provided information that the cost deviation is in line with similar upgrade projects undertaken by other utilities and the project remains economically beneficial to customers. The results and any recommendations from the conclusion of this prudence proceeding are expected to be considered by the MPUC in NSP-Minnesota’s 2014 Minnesota electric rate case.
The next steps in the procedural schedule are expected to be as follows:
| • | Direct Testimony — July 2, 2014; |
| • | Rebuttal Testimony — Aug. 26, 2014; |
| • | Surrebuttal Testimony — Sept. 19, 2014; |
| • | Hearing — Sept. 29-Oct. 3, 2014; |
| • | Reply Brief — Nov. 21, 2014; and |
| • | ALJ Report — Dec. 31, 2014. |
A final MPUC decision is anticipated in the first quarter of 2015.
2012 Transmission Cost Recovery Rate Filing — In January 2012, the 2012 NSP-Minnesota TCR filing was submitted to the MPUC, requesting recovery of $29.6 million of transmission investment costs. As project costs have decreased and certain transmission project costs have been removed and included in base rates, the anticipated revenue requirement for 2012 was modified to approximately $22.9 million. In December 2013, the MPUC approved the 2012 TCR filing, with a few adjustments, for approximately $22.7 million.
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2013/14 Transmission Cost Recovery Rate Filing — In December 2013, the 2013/14 NSP-Minnesota TCR filing was filed with the MPUC, requesting recovery of $20.7 million of 2013 transmission investment costs and $37.3 million of 2014 transmission investment costs not previously included in electric base rates. An MPUC decision is anticipated in late 2014, with implementation of new rates soon after approval.
Prairie Island Nuclear Plant EPU — In 2009, the MPUC granted NSP-Minnesota a CON for an EPU project at the Prairie Island nuclear generating plant. The total estimated cost of the EPU was $294 million, of which approximately $78.9 million had been incurred, including AFUDC of approximately $12.8 million. Subsequently, NSP-Minnesota made a change of circumstances filing notifying the MPUC that there were changes in the size, timing and cost estimates for this project, revisions to economic and project design analysis and changes due to the estimated impact of revised scheduled outages. The information indicated reductions to the estimated benefit of the uprate project. As a result, NSP-Minnesota concluded that further investment in this project would not benefit customers. In February 2013, the MPUC issued an order terminating the CON for the Prairie Island EPU project.
NSP-Minnesota plans to address recovery of incurred costs in rate cases for each of the NSP-Minnesota jurisdictions and to file a request with the FERC for approval to recover a portion of the costs from NSP-Wisconsin through the Interchange Agreement. NSP-Wisconsin plans to seek cost recovery in a future rate case. Based on the outcome of the December 2012 MPUC decision, EPU costs incurred to date were compared to the discounted value of the estimated future rate recovery based on past jurisdictional precedent, resulting in a $10.1 million pretax charge in December 2012 which is included in O&M expense for that year.
Pending and Recently Concluded Regulatory Proceedings — NDPSC
North Dakota 2013 Electric Rate Case — In December 2012, NSP-Minnesota filed a request with the NDPSC to increase annual retail electric rates approximately $16.9 million, or 9.25 percent. The rate filing was based on a 2013 FTY, a requested ROE of 10.6 percent, an electric rate base of approximately $377.6 million and an equity ratio of 52.56 percent. In January 2013, the NDPSC approved an interim electric increase of $14.7 million, effective Feb. 16, 2013, subject to refund.
In August 2013, NSP-Minnesota filed rebuttal testimony revising the requested increase in retail electric rates to approximately $14.9 million, based on a revised ROE of 10.25 percent and incorporating updated information.
In December 2013, a comprehensive settlement agreement between NSP-Minnesota and the NDPSC Staff was filed for approval, proposing resolution to the rate case and resolution of various regulatory proceedings for wind and natural gas generating resources pending before the NDPSC. The settlement agreement provided for a four-year rate plan including a 5.0 percent annual increase in retail revenues in North Dakota, effective Feb. 16, 2013 through Dec. 31, 2015, with no increase in 2016. As filed, the estimated 2013 settlement impact was $11.6 million. On Feb. 18, 2014, NSP-Minnesota filed an amended settlement agreement revising the annual increase to 4.9 percent, effective Feb. 16, 2013 through Dec. 31, 2015, with no increase in 2016.
The table below reflects the amended settlement’s 2013 impact.
| (Millions of Dollars) | Amended Settlement Impact | |||
| Proposed 12 month settlement base rate increase | $ | 9.0 | ||
| Pre-effective period impact (Jan. 1, 2013 - Feb. 15, 2013) | (1.6 | ) | ||
| Proposed settlement base rate increase | 7.4 | |||
| Retention of DOE settlement proceeds | 3.9 | |||
| Other, net | (0.3 | ) | ||
| Amended settlement’s 2013 impact | $ | 11.0 | ||
Additional settlement terms include:
| • | An approval of two new rate rider tariff mechanisms to recover transmission and North Dakota renewable costs; |
| • | An authorized ROE of 9.75, 10.0, 10.0 and 10.25 percent in 2013 through 2016, respectively; |
| • | A 50 percent earnings sharing mechanism for amounts earned in excess of the authorized ROEs during the term of the settlement; |
| • | The continued use of a 12 month coincident peak demand allocator for certain rate base and operating expenses; |
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| • | A commitment to develop a generation cost allocation mechanism over the next 16 months that reflects North Dakota energy policy; providing for the exclusion of resources deemed inconsistent with North Dakota energy policy beginning in 2016 (such as certain Minnesota wind and biomass purchase power agreements) and reflecting replacement of those costs based on either system average costs or like resource costs (base load for base load generation, etc.) and recognizing the time needed to address complexity among multiple jurisdictions by providing that a plan for this mechanism be filed by June 2015; |
| • | The commitment to construct up to 400 MW of thermal generation in North Dakota by 2036 subject to least-cost resource planning principles; and |
| • | The retention of DOE settlement proceeds received in 2012, 2013 and expected in 2014. |
A final NDPSC decision on the case is anticipated in the first quarter of 2014.
Recently Concluded Regulatory Proceedings — SDPUC
South Dakota 2012 Electric Rate Case — In March 2013, NSP-Minnesota and the SDPUC Staff reached a settlement agreement that provides for a base rate increase of approximately $11.6 million and the implementation of a new rider. On Oct. 1, 2013, NSP-Minnesota filed its compliance report consistent with the settlement to recover the revenue requirement on the specific major capital additions and incremental property tax resulting in recovery of $8.7 million for 2014. In December 2013, the SDPUC approved recovery of $8.5 million, reflecting updates made during review of the compliance filing.
Electric, Purchased Gas and Resource Adjustment Clauses
CIP and CIP Rider — In December 2012, the MPUC approved reductions to the CIP financial incentive mechanisms effective for the 2013 through 2015 program years. Based on the approved savings goals, the estimated average annual electric and natural gas incentives are $30.6 million and $3.6 million, respectively.
CIP expenses are recovered through base rates and a rider that is adjusted annually. In November 2013, the MPUC approved NSP-Minnesota’s 2012 CIP electric financial incentives totaling $54.0 million, as well as NSP-Minnesota’s proposed 2013 to 2014 electric CIP rider. In October 2013, the MPUC approved NSP-Minnesota’s 2012 CIP natural gas financial incentive of $2.7 million, as well as NSP-Minnesota’s proposed 2013 to 2014 natural gas CIP rider. NSP-Minnesota estimates 2014 recovery of $83.9 million of electric CIP expenses and $11.7 million of natural gas CIP expenses. This proposed recovery through the riders is in addition to an estimated $87.2 million and $3.1 million through electric and gas base rates, respectively.
11. Commitments and Contingencies
Commitments
Capital Commitments — NSP-Minnesota has made commitments in connection with a portion of its projected capital expenditures. NSP-Minnesota’s capital commitments primarily relate to the following major projects:
CapX2020 — CapX2020 is an alliance of electric cooperatives, municipals and investor-owned utilities in the upper Midwest, including the NSP System that has 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 and on the allocation of costs borne by other participating utilities in the upper Midwest.
NSP-Minnesota Wind Projects — In October 2013, the MPUC approved two projects totaling 350 MW that will be owned by NSP-Minnesota. A NDSPC decision is anticipated in early 2014. The Pleasant Valley wind farm in Minnesota and the Border Winds wind farm projects in North Dakota are anticipated to be operational by 2015.
Fuel Contracts — NSP-Minnesota has entered into various long-term commitments 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 2014 and 2033. NSP-Minnesota is required to pay additional amounts depending on actual quantities shipped under these agreements.
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The estimated minimum purchases for NSP-Minnesota under these contracts as of Dec. 31, 2013, are as follows:
| (Millions of Dollars) | Coal | Nuclear fuel | Natural gas supply | Natural gas storage and transportation | ||||||||||||
| 2014 | $ | 337.3 | $ | 128.8 | $ | 74.5 | $ | 99.4 | ||||||||
| 2015 | 262.5 | 79.9 | 6.1 | 96.2 | ||||||||||||
| 2016 | 123.4 | 121.5 | 6.0 | 96.8 | ||||||||||||
| 2017 | 30.0 | 127.5 | 3.2 | 82.5 | ||||||||||||
| 2018 | 29.9 | 69.4 | — | 35.6 | ||||||||||||
| Thereafter | — | 697.6 | — | 244.6 | ||||||||||||
Total (a) | $ | 783.1 | $ | 1,224.7 | $ | 89.8 | $ | 655.1 | ||||||||
(a) | Includes amounts allocated to NSP-Wisconsin through intercompany charges. |
Additional expenditures for fuel and natural gas storage and transportation will be required to meet expected future electric generation and natural gas needs. NSP-Minnesota’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.
PPAs — NSP-Minnesota has entered into PPAs with other utilities and energy suppliers with expiration dates through 2033 for purchased power to meet system load and energy requirements and to meet operating reserve obligations. In general, these agreements provide for energy payments, based on actual energy delivered and capacity payments. Certain PPAs accounted for as executory contracts also contain minimum energy purchase commitments. Capacity and energy 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. The effects of price adjustments on our financial results are mitigated through purchased energy cost recovery mechanisms.
Included in electric fuel and purchased power expenses for PPAs, accounted for as executory contracts, were payments for capacity of $106.0 million, $106.2 million and $106.8 million in 2013, 2012 and 2011, respectively. At Dec. 31, 2013, the estimated future payments for capacity and energy that NSP-Minnesota is obligated to purchase pursuant to these executory contracts, subject to availability, are as follows:
| (Millions of Dollars) | Capacity | Energy (a) | ||||||
| 2014 | $ | 119.5 | $ | 78.3 | ||||
| 2015 | 115.5 | 83.7 | ||||||
| 2016 | 100.3 | 81.6 | ||||||
| 2017 | 92.6 | 87.3 | ||||||
| 2018 | 55.8 | 93.2 | ||||||
| Thereafter | 429.1 | 866.7 | ||||||
Total (b) | $ | 912.8 | $ | 1,290.8 | ||||
(a) | Excludes contingent energy payments for renewable energy PPAs. |
(b) | Includes amounts allocated to NSP-Wisconsin through intercompany charges. |
Additional energy payments under these PPAs and PPAs accounted for as operating leases will be required to meet expected future electric demand.
Leases — NSP-Minnesota leases a variety of equipment and facilities used in the normal course of business. These 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 were approximately $79.6 million, $78.5 million and $72.9 million for 2013, 2012 and 2011, respectively. These expenses include capacity payments for PPAs accounted for as operating leases of $59.1 million, $59.0 million and $58.2 million in 2013, 2012 and 2011, respectively, recorded to electric fuel and purchased power expenses.
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Under certain railcar lease agreements accounted for as operating leases, NSP-Minnesota guarantees the lessor’s proceeds from sale of the leased assets at the end of the lease term will at least equal the guaranteed residual value. NSP-Minnesota’s maximum potential loss under these residual value guarantees is $9.2 million assuming the fair market value of the assets is zero at the end of the lease term; however, NSP-Minnesota expects sale proceeds to exceed the guaranteed amounts. These lease agreements expire in 2014 and 2015.
Included in the future commitments under operating leases are estimated future capacity payments under PPAs that have been accounted for as operating leases in accordance with the applicable accounting guidance. Future commitments under all operating leases are:
| (Millions of Dollars) | Operating Leases | PPA Operating Leases (a) (b) | Total Operating Leases | |||||||||
| 2014 | $ | 7.4 | $ | 61.1 | $ | 68.5 | ||||||
| 2015 | 6.6 | 62.1 | 68.7 | |||||||||
| 2016 | 6.4 | 63.1 | 69.5 | |||||||||
| 2017 | 6.9 | 64.2 | 71.1 | |||||||||
| 2018 | 6.6 | 65.2 | 71.8 | |||||||||
| Thereafter | 72.7 | 489.2 | 561.9 | |||||||||
(a) | Amounts do not include PPAs accounted for as executory contracts. |
(b) | PPA operating leases contractually expire through 2026. |
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.
PPAs — Under certain PPAs, NSP-Minnesota purchases power from independent power producing entities that own natural gas or biomass fueled power plants for which NSP-Minnesota is required to reimburse natural gas or biomass fuel costs, or to participate in tolling arrangements under which NSP-Minnesota procures the natural gas required to produce the energy that it purchases. These specific PPAs create a variable interest in the associated independent power producing entity.
NSP-Minnesota has determined that certain independent power producing entities are variable interest entities. NSP-Minnesota 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 PPAs.
NSP-Minnesota 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. NSP-Minnesota 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. NSP-Minnesota had approximately 1,069 MW and 1,064 MW of capacity under long-term PPAs as of Dec. 31, 2013, and 2012, respectively, with entities that have been determined to be variable interest entities. These agreements have expiration dates through the year 2028.
Environmental Contingencies
NSP-Minnesota has been or is currently involved with the cleanup of contamination from certain hazardous substances at several sites. In many situations, NSP-Minnesota believes it will recover some portion of these costs through insurance claims. Additionally, where applicable, NSP-Minnesota 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 NSP-Minnesota, which are normally recovered through the regulated rate process. To the extent any costs are not recovered through the options listed above, NSP-Minnesota would be required to recognize an expense.
Site Remediation — Various federal and state environmental laws impose liability, without regard to the legality of the original conduct, where hazardous substances or other regulated materials have been released to the environment. NSP-Minnesota may sometimes pay all or a portion of the cost to remediate sites where past activities of NSP-Minnesota or other parties have caused environmental contamination. Environmental contingencies could arise from various situations, including sites of former MGPs operated by NSP-Minnesota, its predecessors, or other entities; and third-party sites, such as landfills, for which NSP-Minnesota is alleged to be a PRP that sent hazardous materials and wastes to that site.
MGP Sites — NSP-Minnesota is currently involved in investigating and/or remediating several MGP sites where hazardous or other regulated materials may have been deposited. NSP-Minnesota has identified three sites, where former MGP activities have or may have resulted in 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 remediation. NSP-Minnesota anticipates that the majority of the remediation at these sites will continue through at least 2014. NSP-Minnesota had accrued $0.1 million for all of these sites at Dec. 31, 2012 and an immaterial amount as of Dec. 31, 2013. There may be insurance recovery and/or recovery from other PRPs that will offset any costs incurred. NSP-Minnesota anticipates that any amounts spent will be fully recovered from customers.
Environmental Requirements
Water and waste
Asbestos Removal — Some of NSP-Minnesota’s facilities contain asbestos. Most asbestos will remain undisturbed until the facilities that contain it are demolished or removed. NSP-Minnesota has recorded an estimate for final removal of the asbestos as an ARO. 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.
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Federal Clean Water Act (CWA) Effluent Limitations Guidelines (ELG) — In June 2013, the EPA published a proposed ELG rule for power plants that use coal, natural gas, oil or nuclear materials as fuel and discharge treated effluent to surface waters as well as utility-owned landfills that receive coal combustion residuals. Refuse derived fuel, biomass and other alternatively fueled power plants are not addressed by the proposed revisions. The proposed rule identifies four potential regulatory options and invites comments on those regulatory approaches. The options differ in the number of waste streams covered, size of the units controlled and stringency of controls. It is not yet known when the EPA will issue a finalized rule. Under the current proposed rule, facilities would need to comply as soon as possible after July 2017 but no later than July 2022. The impact of this rule on NSP-Minnesota is uncertain at this time.
Federal 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 2011, the EPA published the proposed rule that sets standards for minimization of aquatic species impingement, but leaves entrainment reduction requirements at the discretion of the permit writer and the regional EPA office. A final rule is anticipated in April 2014. It is not possible to provide an accurate estimate of the overall cost of this rulemaking at this time due to the uncertainty of the final regulatory requirements.
NSP-Minnesota submitted its Black Dog CWA compliance plan for the MPCA’s review and approval in 2010. The MPCA is currently reviewing the proposal in consultation with the EPA.
Proposed Coal Ash Regulation — NSP-Minnesota’s operations are subject to federal and state laws that impose requirements for handling, storage, treatment and disposal of hazardous waste. In 2010, the EPA published a proposed rule on whether to regulate coal combustion byproducts (coal ash) as hazardous or nonhazardous waste. Coal ash is currently exempt from hazardous waste regulation. NSP-Minnesota’s costs for the management and disposal of coal ash would significantly increase and the beneficial reuse of coal ash would be negatively impacted if the EPA ultimately issues a rule under which coal ash is regulated as hazardous waste. The EPA has entered into a consent decree to act on final regulations by December 2014. The timing, scope and potential cost of any final rule that might be implemented are not determinable at this time.
Air
EPA GHG Regulation — In 2009, the EPA issued its “endangerment” finding that GHG emissions pose a threat to public health and welfare. This finding required the EPA to adopt GHG emission standards for mobile sources. In 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. These rules were upheld on appeal to the D.C. Circuit. The U.S. Supreme Court has granted review on one issue related to these rules, specifically whether the EPA’s regulation of GHG emissions from mobile sources triggered, by operation of law, new source review permitting requirements for stationary sources, which was the EPA’s basis for adopting the 2011 permitting rules. The Court is scheduled to hear arguments in February 2014. A ruling is anticipated by June 2014. NSP-Minnesota is unable to determine the cost of compliance with these new EPA requirements as it is not clear whether these requirements will apply to future changes at NSP-Minnesota’s power plants.
GHG Emission Standard for Existing Sources and NSPS Proposal — In June 2013, President Obama issued a memorandum directing the EPA to develop GHG emission standards for existing power plants. The memorandum anticipates the EPA will issue a proposed GHG emission standard for existing power plants in June 2014. It is not possible to evaluate the impact of existing source standards until the upcoming proposal and final requirements are known.
In January 2014, the EPA re-proposed a GHG NSPS for newly constructed power plants which seeks to establish CO2 emission rates for coal-fired power plants that reflect emission reductions using partial carbon capture and storage technology (CCS). The EPA’s proposed CO2 emission limits for gas-fired power plants reflect emissions levels from combined cycle technology with no CCS. The EPA continues to propose that the NSPS not apply to modified or reconstructed existing power plants. In addition, installation of control equipment on existing plants would not constitute a “modification” to those plants under the NSPS program. It is not possible to evaluate the impact of the re-proposed NSPS until its final requirements are known.
CSAPR — In 2011, the EPA issued the CSAPR to address long range transport of PM and ozone by requiring reductions in SO2 and NOx from utilities in the eastern half of the United States, including Minnesota. The CSAPR would have set more stringent requirements than the proposed Clean Air Transport Rule. The rule also would have created an emissions trading program.
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In August 2012, the D.C. Circuit vacated the CSAPR and remanded it back to the EPA. The D.C. Circuit stated that the EPA must continue administering the CAIR pending adoption of a valid replacement. In December 2013, the U.S. Supreme Court heard oral arguments on the D.C. Circuit’s 2012 decision to vacate the CSAPR. A decision is anticipated by June 2014. It is not yet known whether the D.C. Circuit’s decision will be upheld, or how the EPA might approach a replacement rule. Therefore, it is not known what requirements may be imposed in the future.
CAIR — In 2005, the EPA issued the CAIR to further regulate SO2 and NOx emissions. The CAIR does not currently apply to Minnesota.
EGU Mercury and Air Toxics Standards (MATS) Rule — The final EGU MATS rule became effective in 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. NSP-Minnesota expects to comply with the EGU MATS rule through a combination of mercury and other emission control projects. NSP-Minnesota believes EGU MATS costs will be recoverable through regulatory mechanisms and does not expect a material impact on results of operations, financial position or cash flows.
Minnesota Mercury Legislation — NSP-Minnesota installed sorbent control systems at the Sherco Unit 3 and A.S. King generating plants and has obtained MPUC approval to install mercury controls on Sherco Units 1 and 2 by the end of 2014. NSP-Minnesota projects installation costs of $12.0 million for the mercury controls on the units and believes these costs will be recoverable through regulatory mechanisms.
Regional Haze Rules — In 2005, the EPA amended the BART requirements of its regional haze rules, which require the installation and operation of emission controls for industrial facilities emitting air pollutants that reduce visibility in certain national parks and wilderness areas. In its first regional haze SIP, Minnesota identified the NSP-Minnesota facilities that will have to reduce SO2, NOx and PM emissions under BART and set emissions limits for those facilities.
In 2009, the MPCA approved a SIP and submitted it to the EPA for approval. The MPCA’s source-specific BART limits for Sherco Units 1 and 2 require combustion controls for NOx and scrubber upgrades for SO2. The MPCA concluded SCRs should not be required because the minor visibility benefits derived from SCRs do not outweigh the substantial costs. The combustion controls have been installed and the scrubber upgrades, to be completed by January 2015, are underway. These emission controls are projected to cost approximately $50 million, of which $40.3 million has already been spent. NSP-Minnesota anticipates these costs will be fully recoverable in rates.
After the CSAPR was adopted in 2011, the MPCA supplemented its SIP, determining that CSAPR meets BART requirements, but also implementing its source-specific BART determination for Sherco Units 1 and 2 from the 2009 SIP. In June 2012, the EPA approved the SIP for EGUs and also approved the source-specific emission limits for Sherco Units 1 and 2 as strengthening the SIP, but avoided characterizing them as BART limits.
In August 2012, the National Parks Conservation Association, Sierra Club, Voyageurs National Park Association, Friends of the Boundary Waters Wilderness, Minnesota Center for Environmental Advocacy and Fresh Energy appealed the EPA’s approval of the Minnesota SIP to the U.S. Court of Appeals for the Eighth Circuit. NSP-Minnesota and other regulated parties were denied intervention. In June 2013, the Court ordered this case to be held in abeyance until the U.S. Supreme Court decides on the CSAPR. If this litigation results in further EPA proceedings concerning the SIP, such proceedings may consider whether SCRs should be required for Sherco Units 1 and 2.
Reasonably Attributable Visibility Impairment (RAVI) — Additional visibility rules relate to a program called the RAVI program. In 2009, the DOI certified that a portion of the visibility impairment in Voyageurs and Isle Royale National Parks is reasonably attributable to emissions from 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 has stated it 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.
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In December 2012, a lawsuit against the EPA was filed in the U.S. District Court for the District of Minnesota by the following organizations: National Parks Conservation Association, Minnesota Center for Environmental Advocacy, Friends of the Boundary Waters Wilderness, Voyageurs National Park Association, Fresh Energy and Sierra Club. The lawsuit alleges the EPA has failed to perform a nondiscretionary duty to determine BART for Sherco Units 1 and 2 under the RAVI program. The EPA filed an answer denying the allegations. The Court denied NSP-Minnesota’s motion to intervene in July 2013. NSP-Minnesota appealed this decision to the U.S. Court of Appeals for the Eighth Circuit. Oral arguments have been scheduled for March 2014.
Revisions to National Ambient Air Quality Standards (NAAQS) for PM — In December 2012, the EPA lowered the primary health-based NAAQS for annual average fine PM and retained the current daily standard for fine PM. In areas where NSP-Minnesota operates power plants, current monitored air concentrations are below the level of the final annual primary standard. The EPA is expected to designate non-compliant locations by December 2014. 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 the final designations have been made.
Notice of Violation (NOV) — In 2011, NSP-Minnesota received an NOV from the EPA alleging violations of the New Source Review (NSR) requirements of the CAA at the Sherco plant and Black Dog plant in Minnesota. The NOV alleges that various maintenance, repair and replacement projects 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.
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Asset Retirement Obligations
Recorded AROs — AROs have been recorded for property related to the following: electric production (nuclear, steam, wind, other and hydro), electric distribution and transmission, natural gas transmission and distribution, and general property. The electric production obligations include asbestos, ash-containment facilities, radiation sources, storage tanks, control panels and decommissioning. The asbestos recognition associated with the steam production includes certain plants. 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 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. NSP-Minnesota has also recorded AROs for the retirement and removal of assets at certain wind production facilities for which the land is leased and removal is required by contract, with the origination dates being the in-service date of the various facilities.
NSP-Minnesota has recognized AROs for the retirement costs of natural gas mains and for the removal of electric transmission and distribution equipment, which consists of many small potential obligations associated with PCBs, mineral oil, storage tanks, treated poles, lithium batteries, mercury and street lighting lamps. The common general AROs include small obligations related to storage tanks, radiation sources and office buildings. These assets have numerous 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 AROs 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 12 for further discussion of nuclear obligations.
A reconciliation of NSP-Minnesota’s AROs is shown in the tables below for the years ended Dec. 31, 2013 and 2012, respectively:
| (Thousands of Dollars) | Beginning Balance Jan. 1, 2013 | Accretion | Revisions to Prior Estimates | Ending Balance Dec. 31, 2013 (a) | ||||||||||||
| Electric plant | ||||||||||||||||
| Nuclear production decommissioning | $ | 1,546,358 | $ | 81,940 | $ | — | $ | 1,628,298 | ||||||||
| Steam and other production ash containment | 47,926 | 1,361 | (340 | ) | 48,947 | |||||||||||
| Steam and other production asbestos | 12,789 | 514 | — | 13,303 | ||||||||||||
| Wind production | 32,936 | 1,575 | — | 34,511 | ||||||||||||
| Electric distribution | 12,443 | 358 | (7,930 | ) | 4,871 | |||||||||||
| Other | 1,137 | 118 | 135 | 1,390 | ||||||||||||
| Natural gas plant | ||||||||||||||||
| Gas transmission and distribution | 339 | 23 | (29 | ) | 333 | |||||||||||
| Common and other property | ||||||||||||||||
| Common general plant asbestos | 1,197 | 66 | (783 | ) | 480 | |||||||||||
| Common miscellaneous | 277 | 27 | 326 | 630 | ||||||||||||
| Total liability | $ | 1,655,402 | $ | 85,982 | $ | (8,621 | ) | $ | 1,732,763 | |||||||
(a) | There were no new ARO liabilities recognized or settled during the 12 months ended Dec. 31, 2013. |
The aggregate fair value of NSP-Minnesota’s legally restricted assets, for purposes of funding future nuclear decommissioning, was $1.6 billion as of Dec. 31, 2013, consisting of external investment funds.
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In 2013, NSP-Minnesota revised asbestos, ash containment facilities, radiation sources, miscellaneous electric production, electric transmission and distribution, natural gas transmission and distribution and common general AROs due to revised estimated cash flows.
| (Thousands of Dollars) | Beginning Balance Jan. 1, 2012 | Accretion | Revisions to Prior Estimates | Ending Balance Dec. 31, 2012 (a) | ||||||||||||
| Electric plant | ||||||||||||||||
| Nuclear production decommissioning | $ | 1,482,741 | $ | 75,301 | $ | (11,684 | ) | $ | 1,546,358 | |||||||
| Steam and other production ash containment | 30,989 | 1,065 | 15,872 | 47,926 | ||||||||||||
| Steam and other production asbestos | 10,479 | 459 | 1,851 | 12,789 | ||||||||||||
| Wind production | 40,515 | 2,068 | (9,647 | ) | 32,936 | |||||||||||
| Electric distribution | 14,372 | 522 | (2,451 | ) | 12,443 | |||||||||||
| Other | 1,078 | 40 | 19 | 1,137 | ||||||||||||
| Natural gas plant | ||||||||||||||||
| Gas transmission and distribution | 320 | 19 | — | 339 | ||||||||||||
| Common and other property | ||||||||||||||||
| Common general plant asbestos | 1,135 | 62 | — | 1,197 | ||||||||||||
| Common miscellaneous | 267 | 10 | — | 277 | ||||||||||||
| Total liability | $ | 1,581,896 | $ | 79,546 | $ | (6,040 | ) | $ | 1,655,402 | |||||||
(a) | There were no new ARO liabilities recognized or settled during the 12 months ended Dec. 31, 2012. |
The aggregate fair value of NSP-Minnesota’s legally restricted assets, for purposes of funding future nuclear decommissioning, was $1.5 billion as of Dec. 31, 2012, consisting of external investment funds.
In 2012, NSP-Minnesota incurred revisions for nuclear decommissioning, asbestos, ash-containment facilities, wind facilities and electric transmission and distribution AROs due to revised estimated cash flows.
Removal Costs — NSP-Minnesota records a regulatory liability for the plant removal costs of steam and other generation, transmission and distribution facilities. 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, NSP-Minnesota has estimated the amount of removal costs accumulated through historic depreciation expense based on current factors used in the existing depreciation rates. Removal costs as of Dec. 31, 2013 and 2012 were $378 million and $377 million, respectively.
Nuclear Insurance
NSP-Minnesota’s public liability for claims resulting from any nuclear incident is limited to $13.6 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 $13.2 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 $127.3 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 $19.0 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 September 2013.
NSP-Minnesota purchases insurance for property damage and site decontamination cleanup costs from Nuclear Electric Insurance Ltd. (NEIL). The coverage limits are $2.3 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 $16.1 million for business interruption insurance and $40.2 million for property damage insurance if losses exceed accumulated reserve funds.
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Legal Contingencies
NSP-Minnesota is involved in various litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss. For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on NSP-Minnesota’s financial statements. Unless otherwise required by GAAP, legal fees are expensed as incurred.
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 the U.S. District Court in Minnesota to obtain a determination that it acted properly in terminating the agreements. enXco also filed a separate lawsuit in the same court seeking approximately $240 million for an alleged breach of contract. NSP-Minnesota believes enXco’s lawsuit is without merit. In October 2012, NSP-Minnesota filed a motion for summary judgment. In April 2013, the U.S. District Court granted NSP-Minnesota’s motion and entered judgment in its favor. In April 2013, enXco filed a notice of appeal to the Eighth Circuit. It is uncertain when the Eighth Circuit will decide this appeal. Although Xcel Energy believes the likelihood of loss is remote based on existing case law and the U.S. District Court’s April 2013 decision, it is not possible to estimate the amount or range of reasonably possible loss in the event of an adverse outcome of this matter. No accrual has been recorded for this matter.
Nuclear Power Operations and Waste Disposal
Nuclear Waste Disposal Litigation — In 1998, NSP-Minnesota filed a complaint in the U.S. Court of Federal Claims against the United States requesting breach of contract damages for the DOE’s failure to begin accepting spent nuclear fuel by Jan. 31, 1998, as required by the contract between the United States and NSP-Minnesota. NSP-Minnesota sought contract damages in this lawsuit through Dec. 31, 2004. In September 2007, the court awarded NSP-Minnesota $116.5 million in damages. In August 2007, NSP-Minnesota filed a second complaint; this lawsuit claimed damages for the period Jan. 1, 2005 through Dec. 31, 2008.
In July 2011, the United States and NSP-Minnesota executed a settlement agreement resolving both lawsuits, providing an initial $100 million payment from the United States to NSP-Minnesota, and providing a method by which NSP-Minnesota can recover its spent fuel storage costs through 2013, estimated to be an additional $100 million. In January 2014, the United States proposed, and NSP-Minnesota accepted, an extension to the settlement agreement which will allow NSP-Minnesota to recover spent fuel storage costs through 2016. The extension does not address costs for used fuel storage after 2016; such costs could be the subject of future litigation. NSP-Minnesota received the initial $100 million payment in August 2011, the second installment of $18.6 million in March 2012, the third installment of $20.7 million in October 2012, and the fourth installment of $42.6 million in November 2013. Amounts received from the installments were subsequently credited to customers, except for approved reductions such as legal costs, customer credits still in process at Dec. 31, 2013, and amounts set aside to be credited through another regulatory mechanism.
Other Contingencies
See Note 10 for further discussion.
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12. | 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. In January 2014, the DOE sent its court mandated proposal to adjust the current fee to zero. The Nuclear Waste Policy Act provides that a proposal by the Secretary of Energy to adjust the fee shall be effective after a period of 90 days of continuous session unless either House of Congress adopts a resolution disapproving the Secretary’s proposed adjustment.
Fuel expense includes the DOE fuel disposal assessments of approximately $10 million in 2013, $12 million in 2012 and $11 million in 2011. In total, NSP-Minnesota had paid approximately $444.8 million to the DOE through Dec. 31, 2013. See Note 11 — Nuclear Waste Disposal Litigation for further discussion.
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 2091, assuming the prompt dismantlement method. NSP-Minnesota is currently recording the costs for decommissioning over the MPUC-approved cost-recovery period. 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. The Monticello dry-cask storage facility currently stores 15 of the 30 canisters authorized by the MPUC.
Prairie Island Units 1 and 2 received their initial operating license and began commercial operations in 1973 and 1974. With its renewed operating license from the NRC, Prairie Island Units 1 and 2 can operate until 2033 and 2034, respectively. The MPUC approved depreciation life for Prairie Island is consistent with the remaining life of the NRC approved operating license. The Prairie Island dry-cask storage facility currently stores 35 of the 64 casks authorized by the MPUC
NSP-Minnesota previously recorded annual decommissioning accruals based on periodic site-specific cost studies and a presumed level of dedicated funding consistent with cost-recovery in utility customer rates. Cost studies quantify decommissioning costs in current dollars. This study presumed that costs will escalate in the future at a rate of 3.63 percent per year during operations and radiological portion of decommissioning and 2.63 percent during the independent spent fuel storage installation and site restoration portion of decommissioning. 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 an after-tax return between 4.57 percent and 5.53 percent, depending on production unit and time frame for external funding. The net unrealized gain or loss on nuclear decommissioning investments is deferred as a regulatory asset or liability.
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 external funds are held in trust and in escrow. The portion in escrow is subject to refund if approved by the various commissions. In November 2012, the MPUC approved NSP-Minnesota’s most recent nuclear decommissioning study which used 2011 cost data. The MPUC approved the use of a 60-year decommissioning scenario. This resulted in an approved annual accrual of $14.2 million for Minnesota retail customers, to be held in our external escrow fund.
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As of Dec. 31, 2013, NSP-Minnesota has accumulated $1.6 billion of assets held in external decommissioning trusts. 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) | 2013 | 2012 | |||||||
| Estimated decommissioning cost obligation from most recently approved study (2011 dollars) | $ | 2,694,079 | $ | 2,694,079 | |||||
| Effect of escalating costs (to 2013 and 2012 dollars, respectively, at 3.63/2.63 percent) | 189,924 | 93,327 | |||||||
| Estimated decommissioning cost obligation (in current dollars) | 2,884,003 | 2,787,406 | |||||||
| Effect of escalating costs to payment date (3.63/2.63 percent) | 5,697,285 | 5,793,882 | |||||||
| Estimated future decommissioning costs (undiscounted) | 8,581,288 | 8,581,288 | |||||||
| Effect of discounting obligation (using risk-free interest rate) | (6,215,050 | ) | (6,243,332 | ) | |||||
| Discounted decommissioning cost obligation | $ | 2,366,238 | $ | 2,337,956 | |||||
| Assets held in external decommissioning trust | $ | 1,627,026 | $ | 1,489,542 | |||||
| Underfunding of external decommissioning fund compared to the discounted decommissioning obligation | $ | 739,212 | $ | 848,414 | |||||
Decommissioning expenses recognized as a result of regulation include the following components:
| (Thousands of Dollars) | 2013 | 2012 | 2011 | |||||||||
Annual decommissioning recorded as depreciation expense: (a) | ||||||||||||
| Externally funded | $ | 6,402 | $ | — | $ | — | ||||||
| Internally funded (including interest costs) | — | (1,251 | ) | (456 | ) | |||||||
| Net decommissioning expense recorded | $ | 6,402 | $ | (1,251 | ) | $ | (456 | ) | ||||
(a) | Decommissioning expense does not include depreciation of the capitalized nuclear asset retirement costs. |
Reductions to expense for internally-funded portions in 2012 and 2011 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). Due to the immaterial amount remaining in the internal fund, the entire remaining amount was unwound for Prairie Island 1 and 2 in 2012. As of December 2013, there is no balance remaining in the internally funded decommissioning account. The 2011 nuclear decommissioning filing approved in 2012 has been used for the regulatory presentation.
13. | Regulatory Assets and Liabilities |
NSP-Minnesota’s consolidated financial statements are prepared 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 the business that is not rate regulated cannot establish regulatory assets and liabilities. If changes in the utility industry or the business of NSP-Minnesota no longer allow for the application of regulatory accounting guidance under GAAP, NSP-Minnesota would be required to recognize the write-off of regulatory assets and liabilities in net income or OCI.
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The components of regulatory assets shown on the consolidated balance sheets of NSP-Minnesota at Dec. 31, 2013 and 2012 are:
| (Thousands of Dollars) | See Note(s) | Remaining Amortization Period | Dec. 31, 2013 | Dec. 31, 2012 | |||||||||||||||||
| Regulatory Assets | Current | Noncurrent | Current | Noncurrent | |||||||||||||||||
Pension and retiree medical obligations (a) | 7 | Various | $ | 29,381 | $ | 286,088 | $ | 23,131 | $ | 367,578 | |||||||||||
| Recoverable deferred taxes on AFUDC recorded in plant | 1 | Plant lives | — | 198,698 | — | 183,572 | |||||||||||||||
Net AROs (c) | 1, 11, 12 | Plant lives | — | 98,419 | — | 115,877 | |||||||||||||||
Contract valuation adjustments (b) | 1, 9 | Term of related contract | — | 136,919 | 2 | 127,661 | |||||||||||||||
Conservation programs (d) | 1 | One to two years | 38,850 | 36,092 | 41,644 | 46,524 | |||||||||||||||
| Nuclear refueling outage costs | 1 | One to two years | 86,333 | 36,477 | 56,035 | 22,647 | |||||||||||||||
| Renewable resources and environmental initiatives | 11 | One to two years | 20,323 | 20,187 | 12,777 | 21,228 | |||||||||||||||
| Purchased power contracts costs | 11 | Term of related contract | — | 38,113 | — | 34,971 | |||||||||||||||
| Losses on reacquired debt | 4 | Term of related debt | 1,928 | 17,296 | 1,927 | 19,224 | |||||||||||||||
| Recoverable purchased natural gas and electric energy costs | 1 | One to two years | 23,101 | 15,495 | 15,860 | 8,340 | |||||||||||||||
| Gas pipeline inspection and remediation costs | Pending rate case | — | 18,907 | — | 12,340 | ||||||||||||||||
| State commission adjustments | 1 | Plant lives | — | 4,278 | — | 4,283 | |||||||||||||||
| Sherco Unit 3 deferral | Twenty-one years | 503 | 10,063 | — | — | ||||||||||||||||
Prairie Island EPU (e) | 10 | Pending rate cases | — | 69,668 | — | 67,590 | |||||||||||||||
| Other | Various | 7,048 | 3,504 | 4,847 | 7,840 | ||||||||||||||||
| Total regulatory assets | $ | 207,467 | $ | 990,204 | $ | 156,223 | $ | 1,039,675 | |||||||||||||
(a) | Includes $303.3 million and $330.3 million for the regulatory recognition of pension expense of which $23.2 million and $24.3 million is included in the current asset at Dec. 31, 2013 and 2012, respectively. Also included are $2.3 million and $2.1 million of regulatory assets related to the non-qualified pension plan of which $0.3 million and $0.2 million is included in the current asset at Dec. 31, 2013 and 2012, respectively. |
(b) | Includes the fair value of certain long-term purchase power agreements used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases. |
(c) | Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments. |
(d) | Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. |
(e) | For the canceled Prairie Island EPU project, NSP-Minnesota plans to address recovery of incurred costs in the pending multi-year rate case. |
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The components of regulatory liabilities shown on the consolidated balance sheets of NSP-Minnesota at Dec. 31, 2013 and 2012 are:
| (Thousands of Dollars) | See Note(s) | Remaining Amortization Period | Dec. 31, 2013 | Dec. 31, 2012 | |||||||||||||||||
| Regulatory Liabilities | Current | Noncurrent | Current | Noncurrent | |||||||||||||||||
| Plant removal costs | 1, 11 | Plant lives | $ | — | $ | 377,716 | $ | — | $ | 377,107 | |||||||||||
| DOE Settlement | 11 | One to two years | 37,395 | 1,131 | 17,071 | 1,131 | |||||||||||||||
| Deferred income tax adjustment | 1, 6 | Various | — | 28,100 | — | 29,715 | |||||||||||||||
Conservation programs (b) | 1 | Less than one year | 4,690 | — | 1,823 | — | |||||||||||||||
| Investment tax credit deferrals | 1, 6 | Various | — | 21,898 | — | 22,821 | |||||||||||||||
Contract valuation adjustments (a) | 1, 9 | Term of related contract | 39,632 | — | 25,139 | — | |||||||||||||||
| Deferred electric energy costs | 1 | Less than one year | 6,390 | — | 6,424 | — | |||||||||||||||
| Renewable resources and environmental initiatives | 10, 11 | Less than one year | 2,499 | — | 256 | — | |||||||||||||||
| Other | Various | 11,189 | 2,154 | 2,446 | 1,697 | ||||||||||||||||
| Total regulatory liabilities | $ | 101,795 | $ | 430,999 | $ | 53,159 | $ | 432,471 | |||||||||||||
(a) | Includes the fair value of certain long-term purchase power agreements used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases. |
(b) | Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. |
At Dec. 31, 2013 and 2012, approximately $140 million and $115 million of NSP-Minnesota’s regulatory assets represented past expenditures not currently earning a return, respectively. This amount primarily includes Prairie Island EPU costs and recoverable purchased natural gas and electric energy costs.
14. Other Comprehensive Income
Changes in accumulated other comprehensive loss, net of tax, for the year ended Dec. 31, 2013 were as follows:
| (Thousands of Dollars) | Gains and Losses on Cash Flow Hedges | Unrealized Gains and Losses on Marketable Securities | Defined Benefit Pension and Postretirement Items | Total | ||||||||||||
| Accumulated other comprehensive loss at Jan. 1 | $ | (21,393 | ) | $ | (99 | ) | $ | (1,707 | ) | $ | (23,199 | ) | ||||
| Other comprehensive gain before reclassifications | 5 | 172 | 423 | 600 | ||||||||||||
| Losses reclassified from net accumulated other comprehensive loss | 779 | — | 91 | 870 | ||||||||||||
| Net current period OCI | 784 | 172 | 514 | 1,470 | ||||||||||||
| Accumulated other comprehensive gain (loss) at Dec. 31 | $ | (20,609 | ) | $ | 73 | $ | (1,193 | ) | $ | (21,729 | ) | |||||
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Reclassifications from accumulated other comprehensive loss for the year ended Dec. 31, 2013 were as follows:
| (Thousands of Dollars) | Amounts Reclassified from Accumulated Other Comprehensive Loss | ||||
| (Gains) losses on cash flow hedges: | |||||
| Interest rate derivatives | $ | 1,388 | (a) | ||
| Vehicle fuel derivatives | (49 | ) | (b) | ||
| Total, pre-tax | 1,339 | ||||
| Tax benefit | (560 | ) | |||
| Total, net of tax | 779 | ||||
| Defined benefit pension and postretirement (gains) losses: | |||||
| Amortization of net loss | 340 | (c) | |||
| Prior service cost | (188 | ) | (c) | ||
| Transition obligation | 2 | (c) | |||
| Total, pre-tax | 154 | ||||
| Tax benefit | (63 | ) | |||
| Total, net of tax | 91 | ||||
| Total amounts reclassified, net of tax | $ | 870 | |||
(a) | Included in interest charges. |
(b) | Included in O&M expenses. |
(c) | Included in the computation of net periodic pension and post retirement benefit costs. See Note 7 for details regarding these benefit plans. |
| 15. | Segments and Related Information |
Operating results from the regulated electric utility and regulated natural gas utility are each separately and regularly reviewed by NSP-Minnesota’s chief operating decision maker. NSP-Minnesota evaluates performance 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.
NSP-Minnesota has the following reportable segments: regulated electric utility, regulated natural gas utility and all other.
| • | NSP-Minnesota’s regulated electric utility segment generates electricity which is transmitted and distributed in Minnesota, North Dakota and South Dakota. 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 NSP-Minnesota’s commodity trading operations. |
| • | NSP-Minnesota’s regulated natural gas utility segment transports, stores and distributes natural gas in portions of Minnesota and North Dakota. |
| • | 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 appliance repair services, nonutility real estate activities and revenues associated with processing solid waste into refuse-derived fuel. |
Asset and capital expenditure information is not provided for NSP-Minnesota’s reportable segments because as an integrated electric and natural gas utility, NSP-Minnesota 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 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.
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| (Thousands of Dollars) | Regulated Electric | Regulated Natural Gas | All Other | Reconciling Eliminations | Consolidated Total | |||||||||||||||
| 2013 | ||||||||||||||||||||
Operating revenues (a) | $ | 4,062,440 | $ | 591,017 | $ | 26,153 | $ | — | $ | 4,679,610 | ||||||||||
| Intersegment revenues | 680 | 640 | — | (1,320 | ) | — | ||||||||||||||
| Total revenues | $ | 4,063,120 | $ | 591,657 | $ | 26,153 | $ | (1,320 | ) | $ | 4,679,610 | |||||||||
| Depreciation and amortization | $ | 373,747 | $ | 40,163 | $ | 678 | $ | — | $ | 414,588 | ||||||||||
| Interest charges and financing costs | 162,084 | 11,572 | 154 | — | 173,810 | |||||||||||||||
| Income tax expense (benefit) | 183,854 | 17,416 | (19,413 | ) | — | 181,857 | ||||||||||||||
| Net income | 338,900 | 29,891 | 24,555 | — | 393,346 | |||||||||||||||
| (Thousands of Dollars) | Regulated Electric | Regulated Natural Gas | All Other | Reconciling Eliminations | Consolidated Total | |||||||||||||||
| 2012 | ||||||||||||||||||||
Operating revenues (a) | $ | 3,842,529 | $ | 471,765 | $ | 23,045 | $ | — | $ | 4,337,339 | ||||||||||
| Intersegment revenues | 532 | 608 | — | (1,140 | ) | — | ||||||||||||||
| Total revenues | $ | 3,843,061 | $ | 472,373 | $ | 23,045 | $ | (1,140 | ) | $ | 4,337,339 | |||||||||
| Depreciation and amortization | $ | 360,224 | $ | 38,776 | $ | 432 | $ | — | $ | 399,432 | ||||||||||
| Interest charges and financing cost | 167,080 | 13,471 | 158 | — | 180,709 | |||||||||||||||
| Income tax expense | 161,450 | 9,516 | 4,558 | — | 175,524 | |||||||||||||||
| Net income | 314,853 | 17,389 | 7,899 | — | 340,141 | |||||||||||||||
| (Thousands of Dollars) | Regulated Electric | Regulated Natural Gas | All Other | Reconciling Eliminations | Consolidated Total | |||||||||||||||
| 2011 | ||||||||||||||||||||
Operating revenues (a) | $ | 3,772,628 | $ | 604,723 | $ | 21,170 | $ | — | $ | 4,398,521 | ||||||||||
| Intersegment revenues | 547 | 535 | — | (1,082 | ) | — | ||||||||||||||
| Total revenues | $ | 3,773,175 | $ | 605,258 | $ | 21,170 | $ | (1,082 | ) | $ | 4,398,521 | |||||||||
| Depreciation and amortization | $ | 342,570 | $ | 38,056 | $ | 399 | $ | — | $ | 381,025 | ||||||||||
| Interest charges and financing cost | 170,884 | 16,168 | 134 | — | 187,186 | |||||||||||||||
| Income tax expense (benefit) | 183,704 | 13,529 | (5,584 | ) | — | 191,649 | ||||||||||||||
| Net income | 317,458 | 25,447 | 10,076 | — | 352,981 | |||||||||||||||
(a) | Operating revenues include $459 million, $450 million and $441 million of intercompany revenue for the years ended Dec. 31, 2013, 2012 and 2011, respectively. See Note 16 for further discussion of related party transactions by operating segment. |
16. | Related Party Transactions |
Xcel Energy Services Inc. provides management, administrative and other services for the subsidiaries of Xcel Energy Inc., including NSP-Minnesota. The services are provided and billed to each subsidiary in accordance with service agreements executed by each subsidiary. NSP-Minnesota uses the services provided by Xcel Energy Services Inc. whenever possible. Costs are charged directly to the subsidiary and are allocated if they cannot be directly assigned.
Xcel Energy Inc., NSP-Minnesota, PSCo and SPS have established a utility money pool arrangement. See Note 4 for further discussion.
The electric production and transmission costs of the entire NSP System are shared by NSP-Minnesota and NSP-Wisconsin. The Interchange Agreement provides for the sharing of all costs of generation and transmission facilities of the system, including capital costs.
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The table below contains significant affiliate transactions among the companies and related parties including billings under the Interchange Agreement for the years ended Dec. 31:
| (Thousands of Dollars) | 2013 | 2012 | 2011 | |||||||||
| Operating revenues: | ||||||||||||
| Electric | $ | 458,633 | $ | 449,958 | $ | 440,519 | ||||||
| Gas | 97 | 116 | 98 | |||||||||
| Operating expenses: | ||||||||||||
| Purchased power | 68,518 | 65,426 | 68,379 | |||||||||
| Transmission expense | 68,398 | 59,918 | 55,955 | |||||||||
| Other operating expenses — paid to Xcel Energy Services Inc. | 387,912 | 345,529 | 351,470 | |||||||||
| Interest expense | 288 | 333 | 192 | |||||||||
| Interest income | 22 | 18 | 92 | |||||||||
Accounts receivable and payable with affiliates at Dec. 31 were:
| 2013 | 2012 | |||||||||||||||
| (Thousands of Dollars) | Accounts Receivable | Accounts Payable | Accounts Receivable | Accounts Payable | ||||||||||||
| NSP-Wisconsin | $ | 18,584 | $ | — | $ | 26,632 | $ | — | ||||||||
| PSCo | — | 18,065 | — | 23,214 | ||||||||||||
| SPS | — | 3,462 | — | 3,820 | ||||||||||||
| Other subsidiaries of Xcel Energy Inc. | 1,185 | 44,414 | 28 | 42,705 | ||||||||||||
| $ | 19,769 | $ | 65,941 | $ | 26,660 | $ | 69,739 | |||||||||
| 17. | Summarized Quarterly Financial Data (Unaudited) |
| Quarter Ended | ||||||||||||||||
| (Thousands of Dollars) | March 31, 2013 | June 30, 2013 | Sept. 30, 2013 | Dec. 31, 2013 | ||||||||||||
| Operating revenues | $ | 1,193,235 | $ | 1,084,845 | $ | 1,217,476 | $ | 1,183,638 | ||||||||
| Operating income | 175,290 | 142,046 | 264,520 | 127,244 | ||||||||||||
| Net income | 101,965 | 77,701 | 155,106 | 58,277 | ||||||||||||
| Quarter Ended | ||||||||||||||||
| (Thousands of Dollars) | March 31, 2012 | June 30, 2012 | Sept. 30, 2012 | Dec. 31, 2012 | ||||||||||||
| Operating revenues | $ | 1,076,773 | $ | 972,536 | $ | 1,185,400 | $ | 1,102,630 | ||||||||
| Operating income | 132,676 | 139,478 | 259,747 | 126,385 | ||||||||||||
| Net income | 76,986 | 64,312 | 136,011 | 62,832 | ||||||||||||
Item 9 — Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A — Controls and Procedures
Disclosure Controls and Procedures
NSP-Minnesota maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in 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, 2013, based on an evaluation carried out under the supervision and with the participation of NSP-Minnesota’s management, including the CEO and CFO, of the effectiveness of its disclosure controls and the procedures, the CEO and CFO have concluded that NSP-Minnesota’s disclosure controls and procedures were effective.
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Internal Control Over Financial Reporting
No change in NSP-Minnesota’s internal control over financial reporting has occurred during the most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, NSP-Minnesota’s internal control over financial reporting. NSP-Minnesota maintains internal control over financial reporting to provide reasonable assurance regarding the reliability of the financial reporting. NSP-Minnesota 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, 2013 on internal controls under section 404 of the Sarbanes-Oxley Act of 2002, NSP-Minnesota conducted testing and monitoring of its internal control over financial reporting. Based on the control evaluation, testing and remediation performed, NSP-Minnesota 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.
This annual report does not include an attestation report of NSP-Minnesota’s independent registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by NSP-Minnesota’s independent registered public accounting firm pursuant to the rules of the SEC that permit NSP-Minnesota to provide only management’s report in this annual report.
Item 9B — Other Information
None.
PART III
Items 10, 11, 12 and 13 of Part III of Form 10-K have been omitted from this report for NSP-Minnesota in accordance with conditions set forth in general instructions I (1) (a) and (b) of Form 10-K for wholly-owned subsidiaries.
Item 10 — Directors, Executive Officers and Corporate Governance
Item 11 — Executive Compensation
Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Item 13 — Certain Relationships and Related Transactions, and Director Independence
Item 14 — Principal Accountant Fees and Services
Information required under this Item is contained in Xcel Energy Inc.’s Proxy Statement for its 2014 Annual Meeting of Shareholders, which is incorporate
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PART IV
Item 15 — Exhibits, Financial Statement Schedules
| 1. | Consolidated Financial Statements: |
Management Report on Internal Controls Over Financial Reporting — For the year ended Dec. 31, 2013. | |
| Report of Independent Registered Public Accounting Firm — Financial Statements | |
Consolidated Statements of Income — For the three years ended Dec. 31, 2013, 2012 and 2011. | |
Consolidated Statements of Comprehensive Income — For the three years ended Dec. 31, 2013, 2012 and 2011. | |
Consolidated Statements of Cash Flows — For the three years ended Dec. 31, 2013, 2012 and 2011. | |
Consolidated Balance Sheets — As of Dec. 31, 2013 and 2012. | |
Consolidated Statements of Common Stockholder’s Equity — For the three years ended Dec. 31, 2013, 2012 and 2011. | |
| Consolidated Statements of Capitalization — As of Dec. 31, 2013 and 2012. | |
| 2. | Schedule II — Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2013, 2012 and 2011. |
| 3. | Exhibits |
| * | Indicates incorporation by reference |
| + | Executive Compensation Arrangements and Benefit Plans Covering Executive Officers and Directors |
| 3.01* | Articles of Incorporation and Amendments of Northern Power Corp. (renamed Northern States Power Co. (a Minnesota corporation) on Aug. 21, 2000) (Exhibit 3.01 to Form 10-12G (file no. 000-31709) dated Oct. 5, 2000). |
| 3.02* | By-Laws of Northern States Power Co. (a Minnesota corporation) as Amended and Restated on Sept. 26, 2013 (Exhibit 3.02 to Form 10-Q/A for the quarter ended Sept. 30, 2013 (file no. 000-31387)). |
| 4.01* | 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). | |
| 4.02* | Supplemental Indenture dated 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). |
| 4.03* | 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). |
| 4.04* | 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). |
| 4.05* | 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. 001-31387) dated Sept. 30, 2002). |
| 4.06* | 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. 001-31387) dated Aug. 22, 2002). |
| 4.07* | 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. 001-31387) dated July 14, 2005). |
| 4.08* | 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. 001-31387) dated May 18, 2006). |
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| 4.09* | 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). |
| 4.10* | Supplemental Indenture dated March 1, 2008 between NSP-Minnesota and The Bank of New York Trust Company, NA, as successor Trustee (Exhibit 4.01 to Form 8-K (file no. 001-31387) dated March 11, 2008. |
| 4.11* | 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)). |
| 4.12* | 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)). |
| 4.13* | Supplemental Indenture dated as of Aug. 1, 2012 between NSP-Minnesota and The Bank of New York Mellon Trust Company, NA, as successor Trustee, creating $300 million principal amount of 2.15 percent First Mortgage Bonds, Series due Aug. 15, 2022 and $500 million principal amount of 3.40 percent First Mortgage Bonds, Series due Aug. 15, 2042 (Exhibit 4.01 to NSP-Minnesota’s Form 8-K dated Aug. 13, 2012 (file no. 001-31387)). |
| 4.14* | Supplemental Trust Indenture dated as of May 1, 2013 between NSP-Minnesota and The Bank of New York Mellon Trust Company, N.A., as successor Trustee, creating $400 million principal amount of 2.60 percent First Mortgage Bonds, Series due May 15, 2023. (Exhibit 4.01 to NSP-Minnesota’s Form 8-K dated May 20, 2013 (file no. 001-31387)) |
| 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 (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* | 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). |
| 10.07* | 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). |
| 10.08*+ | 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). |
| 10.09*+ | Xcel Energy 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). |
| 10.10*+ | 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 (file no. 001-03034) dated April 6, 2010). |
| 10.11*+ | 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). |
| 10.12*+ | 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 (file no. 001-03034) dated April 6, 2010). |
| 10.13*+ | 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). |
| 10.14*+ | Xcel Energy 2005 Long-Term Incentive Plan Form of Bonus Stock Agreement (as amended and restated effective Feb. 17, 2010) (Exhibit 10.24 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2010). |
| 10.15*+ | 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). |
| 10.16a*+ | 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). |
| 10.16b*+ | Xcel Energy 2005 Long-Term Incentive Plan Form of Time-Based Restricted Stock Unit Agreement (Exhibit 10.14b to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2012). |
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| 10.17*+ | 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 Apr. 5, 2011). |
| 10.18*+ | Xcel Energy Inc. Nonqualified Deferred Compensation Plan (2009 Restatement) (as amended and restated effective Nov. 29, 2011) (Exhibit 10.17 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2011). |
| 10.19*+ | Second Amendment dated Oct. 26, 2011 to the Xcel Energy Senior Executive Severance and Change-in-Control Policy (Exhibit 10.18 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2011). |
| 10.20* | Amended and Restated Credit Agreement, dated as of July 27, 2012 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 Bank Plc, as Syndication Agents, and Wells Fargo Bank, National Association, as Documentation Agent (Incorporated by reference to Exhibit 99.02 to Form 8-K, dated July 27, 2012 (file no. 001-03034)). |
| 10.21*+ | First Amendment dated Feb. 20, 2013 to the Xcel Energy Executive Annual Incentive Award Plan (as amended and restated effective Feb. 17, 2010) (Exhibit 10.01 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended March 31, 2013). |
| 10.22*+ | Fourth Amendment dated Feb. 20, 2013 to the Xcel Energy Senior Executive Severance and Change-in-Control Policy (Exhibit 10.02 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended March 31, 2013). |
| 10.23*+ | First Amendment dated May 21, 2013 to the Xcel Energy Inc. Long-Term Incentive Plan (as amended and restated effective Feb. 17, 2010) (Exhibit 10.21 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2013). |
| 10.24*+ | Second Amendment dated May 21, 2013 to the Xcel Energy Inc. Non-Qualified Deferred Compensation Plan (2009 Restatement) (Exhibit 10.22 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2013). |
| 10.25*+ | Xcel Energy 2005 Long-Term Incentive Plan Form of Long-Term Incentive Award Agreement (Exhibit 10.23 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2013). |
| Statement of Computation of Ratio of Earnings to Fixed Charges. | |
| Consent of Independent Registered Public Accounting Firm. | |
| 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 NSP-Minnesota’s Annual Report on Form 10-K for the year ended Dec. 31, 2013 are formatted in XBRL (eXtensible Business Reporting Language): (i) the Consolidated Statements of Income, (ii) the Consolidated Statements of Comprehensive Income, (iii) the Consolidated Statements of Cash Flows, (iv) the Consolidated Balance Sheets, (v) the Consolidated Statements of Stockholder’s Equity, (vi) the Consolidated Statements of Capitalization, (vii) Notes to Consolidated Financial Statements, (viii) document and entity information, and (ix) Schedule II. |
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SCHEDULE II
NSP-MINNESOTA AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS
YEARS ENDED DEC. 31, 2013, 2012 AND 2011
(amounts in thousands)
| Additions | |||||||||||||||||||
Balance at Jan. 1 | Charged to Costs and Expenses | Charged to Other Accounts (a) | Deductions from Reserves (b) | Balance at Dec. 31 | |||||||||||||||
| Allowance for bad debts: | |||||||||||||||||||
| 2013 | $ | 20,420 | $ | 13,418 | $ | 5,190 | $ | 18,812 | $ | 20,216 | |||||||||
| 2012 | 23,004 | 11,241 | 5,874 | 19,699 | 20,420 | ||||||||||||||
| 2011 | 20,996 | 15,936 | 5,833 | 19,761 | 23,004 | ||||||||||||||
(a) | Recovery of amounts previously written off. |
(b) | Principally bad debts written off. |
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SIGNATURES
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.
NORTHERN STATES POWER COMPANY (A MINNESOTA CORPORATION) | ||
| Feb. 24, 2014 | /s/ TERESA S. MADDEN | |
| Teresa S. Madden | ||
| Senior Vice President, Chief Financial Officer and Director | ||
| (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/ DAVID M. SPARBY | /s/ BENJAMIN G.S. FOWKE III | |
| David M. Sparby | Benjamin G.S. Fowke III | |
| President, Chief Executive Officer and Director | Chairman and Director | |
| (Principal Executive Officer) | ||
| /s/ TERESA S. MADDEN | /s/ JEFFREY S. SAVAGE | |
| Teresa S. Madden | Jeffrey S. Savage | |
| Senior Vice President, Chief Financial Officer and Director | Vice President and Controller | |
| (Principal Financial Officer) | (Principal Accounting Officer) | |
| /s/ JUDY M. POFERL | ||
| Judy M. Poferl | ||
| Director | ||
SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION 15(D) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO SECTION 12 OF THE ACT
NSP-Minnesota has not sent, and does not expect to send, an annual report or proxy statement to its security holder.
104