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XEL > SEC Filings for XEL > Form 8-K on 16-Dec-2013All Recent SEC Filings

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Other Events

Item 8.01. Other Events

NSP-Minnesota - Minnesota 2014 Multi-Year Electric Rate Case

Recent Events

On Dec. 12, 2013, the Minnesota Public Utilities Commission (MPUC) approved interim rates of $127 million, or 4.6 percent as requested, effective Jan. 3, 2014, subject to refund, and referred the case to the Office of Administrative Hearings for a contested case proceeding. The MPUC determined that the costs of Sherco Unit 3 will be allowed in interim rates, and that our request to accelerate the theoretical depreciation reserve amortization was a permissible adjustment to our interim rate request to be included in interim rates even though it differed from the schedule in their 2013 rate case order. A final MPUC decision is anticipated in the first quarter of 2015.

Background Information on the Minnesota 2014 Multi-Year Electric Rate Case

On Nov. 4, 2013, Northern States Power Company Minnesota (NSP-Minnesota) a Minnesota corporation, and a wholly owned subsidiary of Xcel Energy Inc., filed a two-year, electric rate case with the MPUC. The rate case is based on a requested return on equity (ROE) of 10.25 percent, a 52.5 percent equity ratio, a 2014 average electric rate base of $6.670 billion and an additional average rate base of $412 million in 2015.

The NSP-Minnesota electric rate case reflects an overall increase in present revenues of approximately $193 million or 6.9 percent in 2014 and an additional $98 million in 2015 or 3.5 percent. 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 theoretical depreciation reserve which the MPUC recently approved in NSP-Minnesota's last electric rate case and the use of expected funds from the Department of Energy (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 life cycle management/extended power uprate project costs and our request to amortize our abandoned plant costs associated with our Prairie Island EPU project. NSP-Minnesota currently plans to file a petition for deferred accounting regarding these Monticello costs later this year.

The rate request, moderation plan, interim rate adjustments, customer bill impacts and certain impacts on expenses are detailed in the table below.

                                                        Percentage             Percentage
(Millions of Dollars)                          2014      Increase      2015     Increase
Pre-moderation deficiency                     $ 274                   $  81
Moderation change compared to prior year:
 Theoretical depreciation reserve              (81)                      53
 DOE settlement proceeds                          -                    (36)
                                               (81)                      17
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                       16                       -
Depreciation expense - reduction/(increase)      81                    (46)
Recognition of DOE settlement proceeds            -                      36
Pre-tax impact on operating income            $ 224                   $ 154

Key drivers for the pre-moderation deficiency portion of our 2014 - 2015 rate request include:
Carbon free generation costs at our Prairie Island and Monticello generating plants ($128 million) and our new wind facilities ($23 million);

Investments and costs to support a diverse energy supply including recovery of Sherco Unit 3 costs not allowed in our last case ($34 million) and costs for other sources of generation ($24 million);

Reliability infrastructure costs in support of our transmission and distribution systems ($62 million) and technology ($26 million); and,

Other changes from our last rate case ($58 million).

NSP-Minnesota's final 2014 - 2015 rate moderation proposal:
Shortens the amortization period of the transmission, distribution and general plant theoretical depreciation reserve included in the MPUC's last general rate order from 8 years to 3 years, using 50 percent of the balance in 2014 ($111 million) and 30 percent of the balance in 2015 ($58 million). Rates are $81 million less in 2014 and $30 million less in 2015 than they otherwise would have been as approved in the MPUC's order in our last rate case. The reduction of the theoretical depreciation reserve would cause changes in our costs and likely rates, beyond the proposed multi-year period.

The impact of the change in the theoretical reserve amortization is shown in the table below (in millions of dollars).

                               Revenue Requirement
                 Proposed         for Proposed       Revenue Requirement
               Amortization       Amortization       for Current 8-Year      Impact Difference:
Year            Percentage         Percentage           Amortization        Proposed less 8-Year
2014               50%        $             (111 )  $               (30 ) $                (81 )
2015               30%                       (58 )                  (28 )                  (30 )
             2015 Step Amount $               53

As the 2015 theoretical depreciation reserve amortization is $53 million less than 2014, NSP-Minnesota proposes to use expected DOE settlement funds in excess of decommissioning accruals of $36 million to offset the 2015 increase.

The rate case request reduces the scope of costs recovered through riders. NSP-Minnesota also is proposing a weather-normalized decoupling mechanism for residential and small commercial classes.

NSP-Minnesota - North Dakota 2013 Electric Rate Case

Recent Events

On Dec. 13, 2013, NSP-Minnesota filed a settlement agreement that was reached
with the North Dakota Public Service Commission (NDPSC) Advocacy Staff, which
provides for a four-year rate plan. The settlement provides for a 5 percent
annual increase in retail revenues in North Dakota, effective Feb. 16, 2013
through Dec. 31, 2015, with no increase in 2016.

The table below reflects the proposed settlement's impact on 2013.
(Millions of Dollars)                                               2013 Settlement Impact
Proposed 12 month settlement base rate increase                    $                9.1
Pre-effective period impact (Jan. 1, 2013 - Feb. 15, 2013)                         (1.1 )
2013 proposed settlement base rate increase                                         8.0
Retention of DOE settlement proceeds                                                3.9
Other, net                                                                         (0.3 )
Estimated 2013 settlement impact                                   $               11.6

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 twelve month coincident peak demand allocator for certain rate base and operating expenses;

A commitment to develop a generation cost allocation mechanism over the next 18 months for serving North Dakota customers in a way 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 megawatts of thermal generation in North Dakota by 2036 subject to least-cost resource planning principles; and

The retention of DOE settlement proceeds received in 2013 and expected in 2014.

If approved, the settlement would resolve various regulatory proceedings for wind and natural gas generating resources currently pending before the NDPSC, and includes a commitment to build a natural gas plant in North Dakota by 2036, subject to resource planning principles.

The NDPSC is expected to schedule several hearings before taking action.

Background Information on the 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 is 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 June 2013, NSP-Minnesota revised its rate increase to $16 million, reflecting updated information.

On Aug. 12, 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 the updated information from June 2013.

On Aug. 22, 2013, NDPSC Staff filed supplemental testimony revising their recommendation by removing a positive adjustment for federal taxes and adjusting depreciation to reflect longer asset lives. In total, the NDPSC Staff's filed position was modified to a $10 million rate reduction. The recommendation reflects a 9.0 percent ROE.

Primary revenue requirement adjustments include:
                                                            NSP-Minnesota Rebuttal     NDPSC Position
(Millions of Dollars)                                              Testimony           as Supplemented
NSP-Minnesota revised request                               $           16.0          $          16.0
Use of a one month coincident peak demand allocator for
certain rate base and operation expenses                                   -                    (20.4 )
ROE                                                                     (1.2 )                   (5.2 )
Incentive compensation                                                     -                     (0.8 )
Adjustment for various O&M expenses                                        -                     (0.7 )
Modified cost of capital and increased capital structure
to 53.42 percent                                                         0.1                      1.3
Depreciation/remaining life study                                          -                     (1.1 )
Other, net                                                                 -                      0.9
Recommended rate increase (decrease)                        $           14.9          $         (10.0 )

Except for the historical statements contained in this 8-K, the matters discussed herein, including the expected impact of rate cases, 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 Xcel Energy Inc. and its subsidiaries (collectively, Xcel Energy) 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 Xcel Energy Inc. and NSP-Minnesota have 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 Xcel Energy Inc. 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 our 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 of cost of capital; employee work force factors; and the other risk factors listed from time to time by Xcel Energy Inc. and NSP-Minnesota in reports filed with the Securities and Exchange Commission, including Risk Factors in Item 1A and Exhibit 99.01 of Xcel Energy Inc.'s and NSP-Minnesota's Annual Reports on Form 10-K for the year ended Dec. 31, 2012 and Quarterly Reports on Form 10-Q for the quarters ended March 31, 2013, June 30, 2013, and Sept. 30, 2013 and NSP-Minnesota's Quarterly Report on Form 10-Q/A for the quarter ended Sept. 30, 2013.

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