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XCEL ENERGY : MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (form 10-Q)

08/01/2014 | 05:13pm US/Eastern
The following discussion and analysis by management focuses on those factors
that had a material effect on Xcel Energy'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 the related notes to
consolidated financial statements. Due to the seasonality of Xcel Energy's
operating results, quarterly financial results are not an appropriate base from
which to project annual results.


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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, including the 2014 earnings per share guidance
and assumptions, 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 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 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 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 or cost of capital; employee work
force factors; the items described under Factors Affecting Results of Continuing
Operations in Item 7 of Xcel Energy Inc.'s Form 10-K for the year ended Dec. 31,
2013; and the other risk factors listed from time to time by Xcel Energy Inc. in
reports filed with the SEC, including "Risk Factors" in Item 1A of Xcel Energy
Inc.'s Form 10-K for the year ended Dec. 31, 2013, and Item 1A and Exhibit 99.01
to this Quarterly Report on Form 10-Q for the quarter ended June 30, 2014.

Financial Review


The following discussion and analysis by management focuses on those factors
that had a material effect on Xcel Energy'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 the related notes to
consolidated financial statements.

The only common equity securities that are publicly traded are common shares of
Xcel Energy Inc. The diluted EPS of each subsidiary discussed below do not
represent a direct legal interest in the assets and liabilities allocated to
such subsidiary but rather represent a direct interest in our assets and
liabilities as a whole. Diluted EPS by subsidiary is a financial measure not
recognized under GAAP and is calculated by dividing the net income or loss
attributable to the controlling interest of each subsidiary by the weighted
average fully diluted Xcel Energy Inc. common shares outstanding for the period.
We use this non-GAAP financial measure to evaluate and provide details of
earnings results. We believe that this measurement is useful to investors to
evaluate the actual and projected financial performance and contribution of our
subsidiaries. This non-GAAP financial measure should not be considered as an
alternative to measures calculated and reported in accordance with GAAP.

Results of Operations

The following table summarizes the diluted EPS for Xcel Energy:

                                              Three Months Ended June 30         Six Months Ended June 30
Diluted Earnings (Loss) Per Share               2014              2013             2014             2013
PSCo                                       $      0.18$      0.20$      0.41$      0.43
NSP-Minnesota                                     0.15              0.16             0.37              0.37
SPS                                               0.06              0.05             0.09              0.08
NSP-Wisconsin                                     0.02              0.02             0.07              0.06
Equity earnings of unconsolidated
subsidiaries                                      0.01              0.01             0.02              0.02
Regulated utility                                 0.42              0.44             0.96              0.96
Xcel Energy Inc. and other                       (0.03 )           (0.04 )          (0.05 )           (0.08 )
GAAP diluted EPS                           $      0.39$      0.40$      0.91$      0.88




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Xcel Energy - Overall, earnings decreased $0.01 per share for the second quarter
of 2014. Electric and gas margins rose in the second quarter of 2014 primarily
driven by new rates in various jurisdictions. This positive factor, along with
lower interest expense, was more than offset by higher O&M expenses, property
taxes, and depreciation and amortization expense as well as less favorable
weather.

PSCo - PSCo's earnings decreased $0.02 per share for the second quarter and six
months ended June 30, 2014. Higher electric and natural gas rates and
weather-normalized sales growth were offset by increased property taxes,
depreciation, accruals associated with electric earnings test refund obligations
as well as the impact of weather. See Note 5 to the consolidated financial
statements for further discussion of rate matters.

NSP-Minnesota - NSP-Minnesota's earnings decreased $0.01 per share for the
second quarter of 2014 and were flat year-to-date. Electric rate increases in
Minnesota (interim, subject to refund) and North Dakota, lower depreciation
expense, weather-normalized sales growth and the favorable year-over-year impact
of weather were offset by higher O&M expenses, lower AFUDC and higher property
taxes.

SPS - SPS' earnings increased $0.01 per share for the second quarter and six
months ended June 30, 2014. The positive impact of higher electric rates in
Texas and New Mexico and weather-normalized sales growth were partially offset
by increased O&M expenses and depreciation.

NSP-Wisconsin - NSP-Wisconsin's earnings were flat for the second quarter of
2014 and increased $0.01 per share year-to-date. Higher electric and natural gas
margins, due to an electric rate increase effective in January 2014, and
weather-normalized sales growth were partially offset by higher O&M expenses.

Changes in Diluted EPS

The following table summarizes significant components contributing to the changes in 2014 diluted EPS compared with the same period in 2013. See further discussion below.

                                                             Three Months Ended     Six Months Ended
Diluted Earnings (Loss) Per Share                                 June 30               June 30
2013 GAAP diluted EPS                                       $         0.40  

$ 0.88


Components of change - 2014 vs. 2013
Higher electric margins                                               0.06                  0.14
Higher natural gas margins                                            0.01                  0.04
Lower interest charges                                                0.01                  0.01
Higher AFUDC - equity                                                    -                  0.01
Higher O&M expenses                                                  (0.03 )               (0.07 )
Higher taxes (other than income taxes)                               (0.02 )               (0.03 )

Higher conservation and demand side management (DSM) program expenses

                                                     (0.01 )               (0.03 )
Higher depreciation and amortization                                 (0.01 )               (0.01 )

Dilution from equity issued through the ATM program, direct stock purchase plan and benefit plans

                             -                 (0.01 )
Other, net                                                           (0.02 )               (0.02 )
2014 GAAP diluted EPS                                       $         0.39         $        0.91

The following tables summarize the earnings contributions of Xcel Energy's business segments:

                                              Three Months Ended June 30          Six Months Ended June 30
(Millions of Dollars)                           2014               2013             2014             2013
GAAP income (loss) by segment
Regulated electric income                  $      185.7$      201.1$     371.1$     375.2
Regulated natural gas income                       15.3               16.0            92.6              80.9
Other income (a)                                    8.7                1.0            20.1              17.1
Xcel Energy Inc. and other (a)                    (14.5 )            (21.2 )         (27.4 )           (39.8 )
Total net income                           $      195.2$      196.9$     456.4$     433.4



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                                              Three Months Ended June 30         Six Months Ended June 30
Contributions to Diluted Earnings (Loss)
Per Share                                       2014              2013             2014             2013
GAAP earnings (loss) by segment
Regulated electric                         $      0.37$      0.41$      0.74$      0.76
Regulated natural gas                             0.03              0.03             0.18              0.16
Other (a)                                         0.02                 -             0.04              0.04
Xcel Energy Inc. and other (a)                   (0.03 )           (0.04 )          (0.05 )           (0.08 )
Total diluted EPS                          $      0.39$      0.40$      0.91$      0.88

(a) Not a reportable segment. Included in all other segment results in Note 10

to the consolidated financial statements.

Statement of Income Analysis

The following discussion summarizes the items that affected the individual revenue and expense items reported in the consolidated statements of income.


Estimated Impact of Temperature Changes on Regulated Earnings - Unusually hot
summers or cold winters increase electric and natural gas sales while,
conversely, mild weather reduces electric and natural gas sales. The estimated
impact of weather on earnings is based on the number of customers, temperature
variances and the amount of natural gas or electricity the average customer
historically uses per degree of temperature. Accordingly, deviations in weather
from normal levels can affect Xcel Energy's financial performance, from both an
energy and demand perspective.

Degree-day or Temperature-Humidity Index (THI) data is used to estimate amounts
of energy required to maintain comfortable indoor temperature levels based on
each day's average temperature and humidity. Heating degree-days (HDD) is the
measure of the variation in the weather based on the extent to which the average
daily temperature falls below 65° Fahrenheit, and cooling degree-days (CDD) is
the measure of the variation in the weather based on the extent to which the
average daily temperature rises above 65° Fahrenheit. Each degree of temperature
above 65° Fahrenheit is counted as one cooling degree-day, and each degree of
temperature below 65° Fahrenheit is counted as one heating degree-day. In Xcel
Energy's more humid service territories, a THI is used in place of CDD, which
adds a humidity factor to CDD. HDD, CDD and THI are most likely to impact the
usage of Xcel Energy's residential and commercial customers. Industrial
customers are less sensitive to weather.

Normal weather conditions are defined as either the 20-year or 30-year average
of actual historical weather conditions. The historical period of time used in
the calculation of normal weather differs by jurisdiction based on the time
period used by the regulator in establishing estimated volumes in the rate
setting process. To calculate the impact of weather on demand, a demand factor
is applied to the weather impact on sales as defined above to derive the amount
of demand associated with the weather impact.

The percentage increase (decrease) in normal and actual HDD, CDD and THI are provided in the following table:

          Three Months Ended June 30             Six Months Ended June 30
      2014 vs.     2013 vs.     2014 vs.    2014 vs.     2013 vs.    2014 vs.
       Normal       Normal        2013       Normal       Normal       2013
HDD      4.5 %       22.5 %      (16.6 )%     12.3 %         7.2 %      3.7  %
CDD      0.6         52.2        (29.6 )       1.0          51.8      (28.9 )
THI      9.3          6.6          7.1         8.4           6.5        7.1


Weather - The following table summarizes the estimated impact of temperature variations on EPS compared with sales under normal weather conditions:

                                               Three Months Ended June 30                     Six Months Ended June 30
                                          2014 vs.        2013 vs.      2014 vs.       2014 vs.        2013 vs.       2014 vs.
                                           Normal          Normal         2013          Normal          Normal          2013
Retail electric                        $   0.002$    0.027$ (0.025 )$   0.034$    0.031$    0.003
Firm natural gas                           0.001             0.007       (0.006 )       0.019             0.016          0.003
Total                                  $   0.003$    0.034$ (0.031 )$   0.053$    0.047$    0.006




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Sales Growth (Decline) - The following tables summarize Xcel Energy and its
subsidiaries' sales growth (decline) for actual and weather-normalized sales in
2014:
                                                        Three Months Ended June 30
                                NSP-Minnesota     NSP-Wisconsin       PSCo           SPS        Xcel Energy
Actual
Electric residential                 0.2  %            1.7  %          (5.0 )%       (2.8 )%       (2.0 )%
Electric commercial and
industrial                          (0.4 )             4.3             (1.5 )         3.1           0.4
Total retail electric sales         (0.3 )             3.6             (2.5 )         1.9          (0.2 )
Firm natural gas sales               0.3              (0.8 )           (6.0 )         N/A          (3.7 )


                                                       Three Months Ended June 30
                                NSP-Minnesota     NSP-Wisconsin       PSCo         SPS        Xcel Energy
Weather-normalized
Electric residential                 2.0  %              0.8 %          1.1 %        1.0 %         1.4 %
Electric commercial and
industrial                          (0.1 )               4.0            1.1          3.7           1.5
Total retail electric sales          0.4                 3.1            1.1          3.2           1.4
Firm natural gas sales               7.5                14.6            8.5          N/A           8.6


                                                         Six Months Ended June 30
                                NSP-Minnesota     NSP-Wisconsin       PSCo          SPS        Xcel Energy
Actual
Electric residential                   3.2 %             5.4 %         (1.8 )%        3.7 %         1.6 %
Electric commercial and
industrial                             1.1               5.4           (0.1 )         3.8           1.7
Total retail electric sales            1.7               5.4           (0.5 )         3.6           1.7
Firm natural gas sales                12.7              13.8           (1.9 )         N/A           3.7


                                                        Six Months Ended June 30
                                NSP-Minnesota     NSP-Wisconsin       PSCo         SPS        Xcel Energy
Weather-normalized
Electric residential                  1.2 %             0.7 %           1.2 %        2.0 %         1.3 %
Electric commercial and
industrial                            0.7               4.3             1.1          4.1           1.9
Total retail electric sales           0.8               3.2             1.2          3.6           1.7
Firm natural gas sales                3.7               4.7             5.7          N/A           5.0



Weather-normalized Electric Growth

• NSP-Minnesota's electric residential sales growth is primarily related to

       outages from severe storms experienced during the second quarter of 2013,
       which served to lower sales in that period and, in turn, increased
       year-over-year sales.


• NSP-Wisconsin's electric C&I sales growth was primarily related to certain

       energy sector and manufacturing customers.


• PSCo's electric residential sales growth reflects an increased number of

       customers. Several large mining and manufacturing customers drove C&I
       growth.



•      SPS' C&I growth was the result of continued expansion of oilfield
       development in southeast New Mexico.


Weather-normalized Gas Growth

• Across the gas service territories, strong sales were experienced during

the first half of the year, which continued the trend that began in the

last half of 2013. As normal weather conditions are typically defined as a

       30-year average of actual historical weather conditions, significant
       weather fluctuations in periods of low demand may result in large
       percentage changes on small volumes. Extreme weather variations and
       additional factors such as windchill and cloud cover may not be fully
       reflected.




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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:
                                              Three Months Ended June 30          Six Months Ended June 30
(Millions of Dollars)                           2014               2013             2014             2013
Electric revenues                          $      2,298$      2,220$     4,599$     4,312
Electric fuel and purchased power                (1,041 )           (1,011 )        (2,109 )          (1,936 )
Electric margin                            $      1,257$      1,209$     2,490$     2,376

The following tables summarize the components of the changes in electric revenues and electric margin:

Electric Revenues
                                                                Three Months         Six Months
                                                               Ended June 30       Ended June 30
(Millions of Dollars)                                          2014 vs. 2013       2014 vs. 2013
Fuel and purchased power cost recovery                       $           -        $        103
Retail rate increases (a)                                               38                  73
Trading                                                                 23                  45
Transmission revenue                                                    13                  39
Conservation and DSM program revenues (offset by expenses)              12                  25
Retail sales growth, excluding weather impact                            7                  20
Non-fuel riders                                                         17                  19
Estimated impact of weather                                            (19 )                 3
PSCo earnings test refund obligations                                   (9 )               (20 )
Firm wholesale                                                          (9 )               (13 )
Other, net                                                               5                  (7 )
Total increase in electric revenues                          $          78        $        287



Electric Margin
                                                                Three Months         Six Months
                                                               Ended June 30       Ended June 30
(Millions of Dollars)                                          2014 vs. 2013       2014 vs. 2013
Retail rate increases (a)                                    $          38        $         73
Conservation and DSM program revenues (offset by expenses)              12                  25
Transmission revenue, net of costs                                      10                  21
Retail sales growth, excluding weather impact                            7                  20
Non-fuel riders                                                         17                  19
Estimated impact of weather                                            (19 )                 3
PSCo earnings test refund obligations                                   (9 )               (20 )
Firm wholesale                                                          (9 )               (13 )
Other, net                                                               1                 (14 )
Total increase in electric margin                            $          48        $        114

(a) Retail rates implemented in 2014 include interim rates in Minnesota, subject

to refund, and final rates for Colorado, Wisconsin, New Mexico and North

Dakota. In addition, retail rates in Texas were implemented in the second

     quarter of 2013. See Note 5 to the consolidated financial statements for
     further discussion.




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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:
                                               Three Months Ended June 30           Six Months Ended June 30
(Millions of Dollars)                            2014                2013             2014             2013
Natural gas revenues                       $        369$        341$     1,249$     1,011
Cost of natural gas sold and transported           (211 )               (189 )          (835 )            (628 )
Natural gas margin                         $        158$        152$       414$       383

The following tables summarize the components of the changes in natural gas revenues and natural gas margin:

Natural Gas Revenues
                                                     Three Months         Six Months
                                                     Ended June 30      Ended June 30
(Millions of Dollars)                                2014 vs. 2013      2014 vs. 2013
Purchased natural gas adjustment clause recovery   $         22        $    

204

Retail rate increase, net of refund (Colorado)                7                     16
Retail sales growth                                           3                      6
PSIA rider (Colorado)                                         -                      4
Estimated impact of weather                                  (5 )           

3

Other, net                                                    1             

5

Total increase in natural gas revenues             $         28        $           238



Natural Gas Margin
                                                                 Three Months          Six Months
                                                                Ended June 30         Ended June 30
(Millions of Dollars)                                           2014 vs. 2013         2014 vs. 2013
Retail rate increase, net of refund (Colorado)               $            7         $            16
Retail sales growth                                                       3                       6
PSIA rider (Colorado), partially offset in O&M expenses                   -                       4
Estimated impact of weather                                              (5 )                     3
Other, net                                                                1                       2
Total increase in natural gas margin                         $            6         $            31



Non-Fuel Operating Expenses and Other Items


O&M Expenses - O&M expenses increased $23.0 million, or 4.1 percent, for the
second quarter of 2014 and $54.0 million, or 4.9 percent, for the six months
ended June 30, 2014. The year-to-date increase in O&M expense is partially due
to the timing of a prior year nuclear outage (i.e., amortization of the 2013
Monticello outage began in July 2013). Xcel Energy continues to project annual
O&M expenses will increase 2 percent to 3 percent for 2014.
                                              Three Months         Six Months
                                              Ended June 30      Ended June 30
(Millions of Dollars)                         2014 vs. 2013      2014 vs. 2013

Nuclear plant operations and amortization $ 15 $

27

Electric and gas distribution expenses                 3                     13
Plant generation costs                                 6                      6
Transmission costs                                     3                      6
Other, net                                            (4 )                    2
Total increase in O&M expenses              $         23        $            54


• Nuclear plant operations and amortization cost increases were primarily

       related to the amortization of the 2013 Monticello outage costs, as well
       as initiatives designed to improve the operational efficiencies of the
       plants;

• Electric and gas distribution expenses were primarily driven by increased

       maintenance activities (e.g., vegetation management) and repairs and
       amounts related to pipeline system integrity;



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• Plant generation costs were driven by the timing of overhauls; and

• Transmission costs increased as a result of higher substation maintenance

       and repairs.



Conservation and DSM Program Expenses - Conservation and DSM program expenses
increased $10.4 million, or 17.2 percent, for the second quarter of 2014 and
$23.9 million, or 19.2 percent, for the six months ended June 30, 2014. These
increases were primarily attributable to higher electric recovery rates at
NSP-Minnesota and PSCo. Conservation costs are recovered from customers and
expensed on a kilowatt hour (KWh) basis. As such, increased sales due to cold
winter temperatures or hot summer temperatures will increase revenues and
expenses.

Depreciation and Amortization - Depreciation and amortization increased $11.4
million, or 4.7 percent, for the second quarter of 2014 and $8.6 million, or 1.7
percent, year-to-date. The increases were primarily attributed to normal system
expansion, partially offset by additional accelerated amortization of the excess
depreciation reserve associated with certain Minnesota assets. See further
discussion within Note 5 to the consolidated financial statements.

Taxes (Other Than Income Taxes) - Taxes (other than income taxes) increased $14.2 million, or 13.9 percent, for the second quarter of 2014 and $25.5 million, or 11.8 percent, for the six months ended June 30, 2014. The increases were due to higher property taxes primarily in Minnesota and Colorado.

AFUDC, Equity and Debt - AFUDC increased $1.3 million for the second quarter of 2014 and $4.2 million year-to-date. The increases were due to construction related to the CACJA project and the expansion of transmission facilities, partially offset by the reduction caused by the portion of the Monticello LCM/EPU placed in service in July 2013.


Interest Charges - Interest charges decreased $7.5 million, or 5.1 percent, for
the second quarter of 2014 and $8.0 million, or 2.8 percent, for the six months
ended June 30, 2014. The decreases were primarily due to refinancings at lower
interest rates and the write off of $6.3 million of unamortized debt expense
associated with the calling of junior subordinated notes in May 2013. These
positive factors were partially offset by higher long-term debt levels in the
current period.

Income Taxes - Income tax expense increased $5.4 million for the second quarter
of 2014. The increase in income tax expense was primarily due to higher pretax
earnings in 2014, decreased permanent plant-related adjustments in 2014,
recognition of research and experimentation credits in 2013 and a tax benefit
for a carryback claim related to 2013. These were partially offset by a tax
benefit for an income exclusion in 2014. The ETR was 34.8 percent for the second
quarter of 2014, compared to 33.4 percent for the second quarter of 2013 due to
these adjustments.

Income tax expense increased $22.7 million for the first six months of 2014. The
increase in income tax expense was primarily due to higher pretax earnings in
2014, recognition of research and experimentation credits in 2013 and a tax
benefit for a carryback claim related to 2013. These were partially offset by
the successful resolution of a 2010-2011 IRS audit issue in 2014. The ETR was
34.5 percent for the first six months of 2014, compared to 33.4 percent for the
first six months of 2013 due to these adjustments.

Public Utility Regulation

NSP-Minnesota


NSP System Resource Plans - In March 2013, the MPUC approved NSP-Minnesota's
Resource Plan and ordered a competitive acquisition process with the goal of
adding approximately 500 MW of generation to the NSP System by 2019.

In May 2014, the MPUC issued its order directing NSP-Minnesota to negotiate a
100 MW solar PPA with Geronimo Energy, a natural gas, combined-cycle PPA with
Calpine, a natural gas, combustion turbine PPA with Invenergy and to file these
agreements later this fall. The MPUC also directed NSP-Minnesota to present its
final pricing terms for its 215 MW natural gas combustion turbine, self-build
option at the Black Dog site. The MPUC is expected to rule on the four options
later this year.

In early 2013, NSP-Minnesota also issued a request for proposal (RFP) for wind
generation and subsequently sought commission approval of the following four
wind projects:
• A 200 MW ownership project for the Pleasant Valley wind farm in Minnesota;


• A 150 MW ownership project for the Border Winds wind farm in North Dakota;


•      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.




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In October 2013, the MPUC approved the four wind projects. In 2014, the North
Dakota Public Service Commission (NDPSC) approved the prudence of the Border
Winds project as part of the rate case settlement and determined it will address
the Pleasant Valley project at a later date. In June and July of 2014,
NSP-Minnesota finalized agreements with Renewable Energy Systems Americas, Inc.
for the Pleasant Valley and Border Winds projects and anticipates both projects
going into service in 2015.

In April 2014, NSP-Minnesota issued a RFP for up to 100 MWs of solar generation
resources. Proposals were received in June 2014. NSP-Minnesota is evaluating
such bids and plans to submit recommendations regarding selected bids with the
MPUC in October 2014.

CapX2020 - In 2009, the MPUC granted CONs to construct one 230 kilovolt (KV)
electric transmission line and three 345 KV electric transmission lines as part
of the CapX2020 project. The estimated cost of the five major CapX2020
transmission projects listed below is $2.1 billion. NSP-Minnesota and
NSP-Wisconsin are responsible for approximately $1.2 billion of the total
investment. As of June 30, 2014, Xcel Energy has invested $821 million of its
$1.2 billion share of the five CapX2020 transmission projects.

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 certificate of public convenience and necessity
(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.

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. In April 2014, the St.
Cloud, Minn. to Alexandria, Minn. portion of the project was placed in service.
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 final phase of the project, Alexandria, Minn. to Fargo, N.D. is
expected to go into service in 2015.

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 multi-value project (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.


Big Stone South to Brookings County, S.D. 345 KV transmission line
In December 2011, MISO granted final approval of the project as a MVP. In March
2014, the SDPUC approved a permit for construction of the project's southern
portion. Construction is anticipated to begin in late 2015, with completion in
2017.

Minnesota Solar - Minnesota legislation requires 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. There are two new solar programs approved: a
community solar garden program that will provide bill credits to participating
subscribers and a production incentive program for solar energy systems equal to
or less than 20 kilowatts with authorized payments of $5.0 million over five
years. The legislation also provides for an alternative tariff based on a
distributed solar value or Value of Solar (VOS) methodology.


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In March 2014, the DOC's proposed VOS methodology was approved by the MPUC
however, NSP-Minnesota disagrees with including the VOS in the community solar
garden program. In June 2014, NSP-Minnesota submitted reply comments and a
recalculation of the VOS rate to recognize lower costs and incorporate DOC
assumptions. If the MPUC requires the VOS rate, and NSP-Minnesota's VOS rate
calculation is approved, production from solar gardens would earn 9.4 cents per
KWh, adjusted annually for inflation. If the VOS rate is not required by the
MPUC, it may approve a retail rate based credit ranging from 9.5 to 15 cents per
KWh. The actual bill credit amount is dependent on tariff service the customer
receives as well as their willingness to transfer the REC to NSP-Minnesota. An
MPUC decision on community solar gardens, including the bill credit rate, is
expected in the third quarter of 2014.

Nuclear Power Operations


NSP-Minnesota owns two nuclear generating plants: the Monticello plant and the
PI plant. See Note 14 of Xcel Energy Inc.'s Annual Report on Form 10-K for the
year ended Dec. 31, 2013 for further discussion regarding the nuclear generating
plants.

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 regarding plant readiness to
safely manage severe events, which is expected to require additional capital
expenditures and operating expenses.

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 $80 to $100 million at the Monticello and PI 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.

The NRC continues to review its requirements for mitigating the risks of external events on nuclear plants. In April 2014, the NRC issued a draft of proposed regulatory guidance for risk mitigation of tornado missiles (projectiles impacting the plant). This draft guidance is subject to public comments, further NRC review and possibly public meetings prior to finalization. NSP-Minnesota expects the costs associated with compliance with new NRC regulatory guidance for missile protection to be capital in nature and recoverable from customers. However, at this time NSP-Minnesota is still evaluating the proposed new requirements and has not yet estimated their financial impact.

NSP-Wisconsin


NSP-Wisconsin CapX2020 CPCN - The PSCW issued a CPCN for the Wisconsin portion
of the Hampton, Minn. to La Crosse, Wis. project in May 2012. The Wisconsin
route is approximately 50 miles of new transmission line with an estimated cost
of $211 million. Construction on the Wisconsin terminus of the line, the Briggs
Road Substation, began in mid-2013 and construction on the Wisconsin portion of
the line began in June 2014. The line is expected to go into service in 2015.


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NSP-Wisconsin / American Transmission Company, LLC (ATC) - La Crosse, Wis. to
Madison, Wis. Transmission Line - In October 2013, NSP-Wisconsin and ATC jointly
filed an application with the PSCW for a CPCN for a new 345 KV transmission line
that would extend from La Crosse, Wis. to Madison, Wis. The proposed line, known
as the Badger Coulee line, would run between 159 and 182 miles. Updated
information was provided to the PSCW in April 2014 showing an estimated project
cost, including AFUDC, of between $540 and $580 million, depending upon the
route ultimately approved by the PSCW. NSP-Wisconsin's share of the investment
is estimated to be between $190 and $207 million. The cost estimates are based
on a projected 2018 in-service year. In December 2011, MISO determined the line
to be a MVP project, and as such, eligible for cost sharing under MISO's MVP
tariff.

On April 30, 2014, the PSCW determined the CPCN application was complete. The
next step is an extensive regulatory review by the PSCW, the Wisconsin
Department of Natural Resources and the Department of Agriculture. By statute,
the PSCW has 360 days from the determination of completeness to issue a decision
on the project. If approved, NSP-Wisconsin and ATC anticipate beginning
construction on the line in mid-2016, with completion by late-2018.

PSCo


Brush, Colo. to Castle Pines, Colo. 345 KV Transmission Line - In March 2014,
PSCo filed with the CPUC for a CPCN to construct a new 345 KV transmission line
originating from Pawnee Station, near Brush, Colo. and terminating at the
Daniels Park substation, near Castle Pines, Colo. The estimated cost of the
project is $178 million. Evidentiary hearings are scheduled for September 2014.
A CPUC decision is expected in early 2015.

Renewable Energy Standard (RES) Compliance Plan - Colorado law mandates that at
least 30 percent of PSCo's energy sales be supplied by renewable energy by 2020
and includes a distributed generation standard. In July 2013, PSCo filed its
2014 RES compliance plan that included the continuation of both the
Solar*Rewards and Solar*Rewards Community programs. Hearings for the 2014 RES
compliance plan were held in May 2014. A decision is anticipated in the third
quarter of 2014.

Net Metering Standard - In conjunction with its 2014 RES compliance plan filing,
PSCo proposed to track and quantify the system costs that are not avoided by
distributed solar generation, which PSCo has defined as a "net metering
incentive," for purposes of equitably recovering costs between customers who
participate in distributed generation and customers that do not. In December
2013, parties including the OCC filed answer testimony supporting PSCo's net
metering proposal. However, rooftop solar advocates opposed it and also argued
for higher solar installation levels and a slower reduction in incentives over
time. The CPUC has assigned the net metering issue to its own docket and
established key dates to evaluate this matter. A CPUC decision is expected in
the fourth quarter of 2014.

Solar*Connect Program - In April 2014, PSCo filed an application with the CPUC
seeking approval for a program that would allow customers the option to purchase
a portion or all of their electricity from a utility scale solar facility
approximately 50 MW in size. Customer contracts under the program would run a
minimum of one year. Hearings have been set for November 2014.

Boulder, Colo. Municipalization - PSCo's franchise agreement with the City of
Boulder (Boulder) expired on Dec. 31, 2010. In November 2011, a ballot measure
was passed by the citizens of Boulder, which authorized the formation and
operation of a municipal light and power utility and the issuance of enterprise
revenue bonds, subject to certain restrictions, including the level of initial
rates and debt service coverage.

In May 2014, the Boulder City Council passed an ordinance to establish an
electric utility. In June 2014, PSCo filed a complaint in the Boulder District
Court seeking a declaratory ruling that this ordinance violates Boulder's
charter requirements. Subsequently, Boulder filed a motion to dismiss PSCo's
complaint, which is still pending.

Boulder sent PSCo its final offer of $128 million for certain portions of PSCo's
transmission and distribution business, which includes Boulder and certain areas
outside city limits. PSCo has notified Boulder that its offer has deficiencies
related to property descriptions as well as other relevant information impacting
the remainder of PSCo's system. Under Colorado law, a condemning entity must pay
the owner fair market value for the taking of and damages to the remainder of
the property. In July 2014, Boulder filed a petition for condemnation in the
Boulder District Court.

The CPUC has previously ruled that it has jurisdiction under Colorado law to
determine the utility that will serve customers outside Boulder's city limits,
and will determine certain system separation matters as well as what facilities
need to be constructed to ensure reliable service. The CPUC has declared that it
should make its determinations prior to any eminent domain actions. In January
2014, Boulder appealed this ruling to the Boulder District Court. PSCo and the
CPUC filed briefs in June 2014 in opposition of Boulder's appeal. This matter is
currently pending.


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If Boulder were to succeed in the eminent domain proceeding, PSCo would seek to
obtain full compensation for the business and its associated property taken by
Boulder, as well as for all damages resulting to PSCo and its system. PSCo would
also seek appropriate compensation for stranded costs with the FERC.

SPS


SPP Integrated Market (IM) - SPP has operated a regional energy imbalance market
since 2007. SPS has recovered related charges and revenues in its retail and
wholesale rates. In 2012 and 2013, the FERC approved proposed revisions to the
SPP tariff to allow SPP to operate a day ahead and real time energy and
ancillary services market similar to the regional market operated by MISO. The
SPP IM began operations on March 1, 2014. SPS submitted filings to the FERC to
modify its wholesale power sales contracts to allow recovery of SPP IM charges
and revenues through the SPP wholesale fuel clause adjustment (FCA). SPS also
requested approval to make sales to the SPP IM at market-based rates, which the
FERC approved in February 2014. The FERC approved the FCA tariff filings in
April 2014. SPS has also filed changes to its QF tariffs in Texas and New Mexico
to revise the pricing applied to QF purchases to be consistent with the new
market. In February 2014, SPS was granted interim approval of the revised QF
tariff in Texas to coincide with the start of the IM. The New Mexico revised QF
tariff was approved in March 2014.

SPS Transmission Notifications to Construct (NTCs) - In April 2014, the SPP
Board of Directors approved the High Priority Incremental Load Study Report, a
reliability assessment that evaluated the anticipated transmission needs of
certain parts of the SPP resulting from expected load growth in the area. As a
result of this study, SPS has received NTCs and conditional NTCs for 44 new
transmission projects to be placed into service by 2020. SPS is in the process
of evaluating these projects and their costs internally before submitting
certificates of convenience and necessity (CCNs) to the PUCT and the NMPRC.
These projects are intended to provide regional reliability benefits as well as
the ability to serve the increase in load in Southeast New Mexico.

In April 2014, SPS filed a CCN with the NMPRC for a new 345 KV transmission line
from the Potash Junction substation to the Roadrunner substation, both near
Carlsbad, N.M. The proposed line would run 40 miles and cost an estimated $53
million. Approval for the CCN is pending.

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, accounting practices and certain other activities of
Xcel Energy Inc.'s utility subsidiaries, including enforcement of North American
Electric Reliability Corporation (NERC) mandatory electric reliability
standards. State and local agencies have jurisdiction over many of Xcel Energy
Inc.'s utility subsidiaries' activities, including regulation of retail rates
and environmental matters. See additional discussion in the summary of recent
federal regulatory developments and public utility regulation sections of the
Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 2013. In
addition to the matters discussed below, see Note 5 to the consolidated
financial statements for a discussion of other regulatory matters.

FERC Order 1000, Transmission Planning and Cost Allocation (Order 1000) - In
2011, the FERC issued Order 1000 adopting new requirements for transmission
planning, cost allocation and development to be effective prospectively. In
Order 1000, the FERC required utilities to develop 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 Right of First Refusal (ROFR)
to build certain types of transmission projects in its service area.

The removal of a federal ROFR would eliminate rights that NSP-Minnesota,
NSP-Wisconsin and SPS currently have under the MISO and SPP tariffs to build
certain transmission projects within their footprints. In Order 1000, FERC
instead required that the opportunity to build such projects would extend to
competitive transmission developers. MISO, SPP, and PSCo all made their initial
compliance filings to incorporate new provisions into their tariffs regarding
regional planning and cost allocation. Various parties appealed Order 1000 final
rules to the D.C. Circuit. The date for a Court decision in the appeal is
uncertain.

The FERC ruled on the initial regional compliance filings for MISO, SPP and
PSCo, directing further compliance changes and thus the SPP and PSCo regional
compliance filings remain pending action by the FERC. The FERC ruling prohibits
ROFR provisions in the MISO tariff and Transmission Owners Agreement (TOA),
except for consideration of state statutes. The MISO Transmission Owners filed
an appeal of this decision. Initial filings to address interregional planning
and cost allocation requirements with other regions were made by PSCo, MISO and
SPP and are pending action by the FERC.


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Transmission-only subsidiaries (TransCo)
Xcel Energy has formed two TransCos that could bid for projects subject to a
competitive bidding process in MISO and SPP. The MISO Board of Directors
accepted a membership application for Xcel Energy Transmission Development
Company, LLC (XETD) in April 2014. In May 2014, Xcel Energy formed Xcel Energy
Southwest Transmission Company, LLC (XEST), which could bid for projects subject
to a competitive bidding process in SPP.

NSP System
Minnesota, North Dakota and South Dakota legislation preserves ROFR rights.
Wisconsin has not developed such legislation. The FERC's initial order on MISO's
compliance filing 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. Xcel Energy requested rehearing of this
issue. The FERC has also accepted changes to MISO's transmission cost allocation
procedures that will protect the ROFR for projects needed for system
reliability. MISO has proposed that the Order 1000 compliance tariffs be
effective for projects approved in December 2014.

PSCo

Colorado does not have legislation protecting ROFR rights for incumbent
utilities. PSCo submitted its FERC compliance filing proposing that PSCo would
join the WestConnect region, a consortium of utilities in the Western
Interconnection and the FERC issued its initial order. In April 2013, PSCo and
other WestConnect members requested rehearing. PSCo and other WestConnect
jurisdictional utilities made their compliance filings to address directives in
the March 2013 order. The FERC is expected to rule in 2014 on the compliance
filing and the requests for rehearing. PSCo and other WestConnect members filed
the interregional compliance filings in May 2013 and action on those filings is
pending. The WestConnect members proposed that the regional and inter-regional
compliance tariffs be effective prospectively after the final FERC orders, and
not earlier than Jan. 1, 2015.

SPS

Xcel Energy believes that Texas statutes protect the ROFR of incumbent utilities
operating outside of the ERCOT region to construct and own transmission
interconnected to their systems, though this view is disputed by some parties.
The State of New Mexico does not have legislation establishing ROFR rights for
incumbent utilities. The FERC issued its initial order on SPP's Order 1000
regional compliance filing in July 2013. The FERC identified several areas that
required a further compliance filing by SPP to address regional compliance
issues. Among other things, the FERC rejected SPP's proposal to retain a ROFR
for new transmission projects with operational voltages between 100 KV and 300
KV. Requests for rehearing of the FERC's July 2013 order were filed in August
2013 and are pending the FERC's action. The SPP regional compliance filing was
filed in November 2013 and is currently pending. The SPP regional compliance
tariffs went into effect March 1, 2014, subject to the outcome of the additional
FERC proceedings. The SPP interregional compliance filing was submitted in July
2013 and is pending the FERC's action.

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 was requested. In March 2014, the U.S.
Supreme Court denied the appeal. Appeals of the regional allocation issue have
thus been exhausted. The FERC has not yet taken action on the remand of the PJM
allocation issue. 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.

NERC Critical Infrastructure Protection (CIP) Requirements - The FERC has
approved version 5 of NERC's CIP standards. Requirements must be applied to high
and medium impact assets by April 1, 2016 and to low impact assets by April 1,
2017. Xcel Energy is currently in the process of evaluating the new requirements
and identifying initiatives needed to meet the compliance deadlines.


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NERC Physical Security Requirements - In July 2014, the FERC issued a notice of
proposed rulemaking (NOPR) generally proposing to adopt NERC's proposed CIP
standard related to physical security for bulk electric system facilities.
However, the FERC proposed a modification to the standard that would allow
certain governmental authorities, including FERC, to revise an entity's list of
critical facilities. The new standard would likely be effective in 2015. Xcel
Energy is currently in the process of evaluating and identifying the critical
facilities impacted to better determine the cost of protections necessary to
meet the standard. The additional cost for compliance is anticipated to be
recoverable through rates.

SPP and MISO Complaints Regarding RTO Joint Operating Agreement (JOA) - SPP and
MISO have a longstanding dispute regarding the interpretation of their JOA,
which is intended to coordinate RTO operations along the MISO/SPP system
boundary. SPP and MISO disagree over MISO's authority to transmit power over SPP
transmission facilities between the traditional MISO region in the Midwest and
the Entergy system. Several cases have been filed with the FERC by MISO and SPP.
In March 2014, FERC issued an order setting all of the cases for settlement
judge proceedings, or hearings if settlement fails. The Xcel Energy utilities
have intervened in the various dockets, arguing that non-firm use by MISO should
not be subject to SPP transmission charges. If SPP is successful in charging
MISO for use of the SPP system, the NSP System would experience higher costs
from MISO, which could be material, but SPS would collect revenues from SPP. The
outcome of the JOA disputes, and the potential impact on Xcel Energy, are
uncertain at this time. In June 2014, the FERC accepted a proposed tariff change
by MISO to recover transmission charges imposed by SPP retroactive to Jan. 29,
2014, and set the issues for settlement judge and hearing procedures.

Wind Integration Tariff Filing - In May 2014, PSCo filed proposed amendments to
its Open Access Transmission Tariff with FERC designed to better allocate
ancillary services costs associated with renewable generation to those customers
on the PSCo system that use renewable resources to serve load. The proposed
amendments include changes to the mechanism used to recover the cost of capacity
associated with balancing of loads and resources and a new charge designed to
recover the cost of additional capacity needed to respond to situations where
the output of wind generators decreases significantly over a short period of
time. PSCo proposed an effective date of Aug. 1, 2014 with rates suspended until
Jan. 1, 2015. The FERC is required to take action on the filing within 60 days.
The proposed tariff changes would not materially affect 2014 revenues, but would
provide more appropriate cost allocation as additional renewable generation is
connected to PSCo.

FERC Order 745 Vacated, Demand Response Compensation in Organized Wholesale
Energy Markets (Order 745) - In 2011, the FERC issued a final rule requiring
that demand resources participating in organized wholesale markets (such as MISO
or SPP) be paid the locational marginal price for avoided energy consumption.
Numerous parties objected to the rule. On appeal, the D.C. Circuit Court of
Appeals vacated and remanded FERC's order. The Court found that the order was an
impermissible intrusion by the FERC into retail electric matters reserved to the
states. The FERC has requested rehearing en banc (review by the entire appeals
court panel) and that request remains pending. After issuance of the Court's
decision, FirstEnergy Service Company (FirstEnergy) filed a complaint requesting
FERC to require PJM to remove all portions of the PJM Tariff allowing or
requiring PJM to include demand response as suppliers to PJM's wholesale
markets. This complaint also remains pending. Neither the Court's vacatur of
Order 745 nor FirstEnergy's complaint against PJM have material implications for
NSP-Minnesota, NSP-Wisconsin or SPS at this time. However, these actions create
uncertainty regarding future participation of demand resources in the MISO and
SPP wholesale organized markets.

Environmental, Legal and Other Matters

See a discussion of environmental, legal and other matters in Note 6 to the consolidated financial statements.

Critical Accounting Policies and Estimates


Preparation of the consolidated financial statements and related disclosures in
compliance with GAAP requires the application of accounting rules and guidance,
as well as the use of estimates. The application of these policies involves
judgments regarding future events, including the likelihood of success of
particular projects, legal and regulatory challenges and anticipated recovery of
costs. These judgments could materially impact the consolidated financial
statements and disclosures, based on varying assumptions. In addition, the
financial and operating environment also may have a significant effect on the
operation of the business and on the results reported even if the nature of the
accounting policies applied have not changed. Item 7 - Management's Discussion
and Analysis, in Xcel Energy Inc.'s Annual Report on Form 10-K for the year
ended Dec. 31, 2013, includes a discussion of accounting policies and estimates
that are most significant to the portrayal of Xcel Energy's financial condition
and results, and that require management's most difficult, subjective or complex
judgments. Each of these has a higher likelihood of resulting in materially
different reported amounts under different conditions or using different
assumptions. As of June 30, 2014, there have been no material changes to
policies set forth in Xcel Energy Inc.'s Annual Report on Form 10-K for the year
ended Dec. 31, 2013.


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Derivatives, Risk Management and Market Risk


In the normal course of business, Xcel Energy Inc. and its subsidiaries are
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 8 to the
consolidated financial statements for further discussion of market risks
associated with derivatives.

Xcel Energy 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 Xcel Energy expects that the counterparties will perform under
the contracts underlying its derivatives, the contracts expose Xcel Energy to
some credit and non-performance risk.

Though no material non-performance risk currently exists with the counterparties
to Xcel Energy'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 Xcel Energy's ability to earn a return on short-term investments of
excess cash.

Commodity Price Risk - Xcel Energy Inc.'s utility subsidiaries are exposed to
commodity price risk in their 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.
Xcel Energy'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 - Xcel Energy Inc.'s utility subsidiaries
conduct various wholesale and commodity trading activities, including the
purchase and sale of electric capacity, energy and energy-related instruments.
Xcel Energy's risk management policy allows management to conduct these
activities within guidelines and limitations as approved by its risk management
committee, which is made up of management personnel not directly involved in the
activities governed by this policy.

At June 30, 2014, the fair values by source for net commodity trading contract
assets were as follows:
                                                                 Futures / Forwards
                                                                                                              Total
                               Source      Maturity                                         Maturity         Futures/
                              of Fair    Less Than 1     Maturity 1    Maturity 4 to     Greater Than 5      Forwards
(Thousands of Dollars)         Value         Year        to 3 Years       5 Years            Years          Fair Value
NSP-Minnesota                      (a)   $    9,368$   11,046$      1,445$      (448 )$   21,411
NSP-Minnesota                      (b)        5,107              -                -             368             5,475
                                         $   14,475$   11,046$      1,445$       (80 )$   26,886


                                                                                  Options
                               Source                                                                         Maturity         Total Futures/
                              of Fair          Maturity          Maturity 1 to 3      Maturity 4 to 5      Greater Than 5      Forwards Fair
(Thousands of Dollars)         Value       Less Than 1 Year           Years                Years                Years              Value
NSP-Minnesota                      (b)   $               50     $              -     $              -     $             -     $           50

(a) - Prices actively quoted or based on actively quoted prices. (b) - Prices based on models and other valuation methods.

Changes in the fair value of commodity trading contracts before the impacts of margin-sharing mechanisms were as follows:

                                                                  Six Months Ended June 30
(Thousands of Dollars)                                              2014    

2013

Fair value of commodity trading net contract assets outstanding at Jan. 1

                                          $     30,514$   28,314
Contracts realized or settled during the period                      (7,278 

) (3,863 ) Commodity trading contract additions and changes during period

                                                                3,700            2,003
Fair value of commodity trading net contract assets
outstanding at June 30                                         $     26,936$   26,454




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At June 30, 2014, a 10 percent increase in market prices for commodity trading
contracts would increase pretax income by approximately $1.1 million, whereas a
10 percent decrease would decrease pretax income from continuing operations by
approximately $1.1 million. At June 30, 2013, a 10 percent increase in market
prices for commodity trading contracts would increase pretax income from
continuing operations by approximately $1.2 million, whereas a 10 percent
decrease would decrease pretax income from continuing operations by
approximately $1.2 million.

Xcel Energy Inc.'s utility subsidiaries' 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:

                                       Three Months
(Millions of Dollars)                  Ended June 30       VaR Limit       Average        High         Low
2014                                 $          0.42     $      3.00$    0.77$   1.69$   0.06
2013                                            0.43            3.00          0.70         1.47         0.21



Nuclear Fuel Supply - In December 2014, NSP-Minnesota is scheduled to take
delivery of 69 percent of its 2014 enriched nuclear material requirements and in
December 2015 approximately 13 percent of its 2015 enriched nuclear material
requirements that could be impacted by events in Ukraine and sanctions against
Russia. NSP-Minnesota has arranged for deliveries of material from alternate
sources in 2014 and 2015 that would not be impacted by these world events and
provide the flexibility to manage its nuclear fuel supply to ensure that plant
availability and reliability will not be negatively impacted in the near term.
Long term through 2024, NSP-Minnesota is scheduled to take delivery of
approximately 34 percent of its average enriched nuclear material requirements
that could be impacted by events in Ukraine and extended sanctions against
Russia. NSP-Minnesota is closely following the progression of these events and
will periodically assess if further actions are required to assure security of
supply of enriched nuclear material beyond 2015.

Interest Rate Risk - Xcel Energy is subject to the risk of fluctuating interest
rates in the normal course of business. Xcel Energy'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.

At June 30, 2014 and 2013, a 100-basis-point change in the benchmark rate on
Xcel Energy's variable rate debt would impact pretax interest expense annually
by approximately $7.8 million and $4.4 million, respectively. See Note 8 to the
consolidated financial statements for a discussion of Xcel Energy Inc. and its
subsidiaries' 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 June 30, 2014, 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 - Xcel Energy Inc. and its subsidiaries are also exposed to credit
risk. Credit risk relates to the risk of loss resulting from counterparties'
nonperformance on their contractual obligations. Xcel Energy Inc. and its
subsidiaries maintain credit policies intended to minimize overall credit risk
and actively monitor these policies to reflect changes and scope of operations.

At June 30, 2014, a 10 percent increase in commodity prices would have resulted
in an increase in credit exposure of $35.9 million, while a decrease in prices
of 10 percent would have resulted in a decrease in credit exposure of $22.2
million. At June 30, 2013, a 10 percent increase in commodity prices would have
resulted in a decrease in credit exposure of $5.2 million, while a decrease in
prices of 10 percent would have resulted in an increase in credit exposure of
$13.7 million.


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Xcel Energy Inc. and its subsidiaries conduct standard credit reviews for all
counterparties. Xcel Energy 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 the financial markets could increase Xcel
Energy's credit risk.

Fair Value Measurements

Xcel Energy 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 8 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 - Xcel Energy continuously monitors the creditworthiness
of the counterparties to its commodity derivative contracts and assesses each
counterparty's ability to perform on the transactions set forth in the
contracts. Given this assessment 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 June 30, 2014. Xcel Energy 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 June 30, 2014.

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 7.1 percent and
61.8 percent of total assets and liabilities, respectively, measured at fair
value at June 30, 2014.

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 $133.1 million and $28.6 million of estimated
fair values, respectively, for FTRs held at June 30, 2014.

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
included $1.0 million of estimated fair values, and no liabilities, for forwards
held at June 30, 2014. There were no Level 3 options held at June 30, 2014.

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 $146.8 million in the nuclear
decommissioning fund at June 30, 2014 (approximately 7.8 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.

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