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Xcel Energy Third Quarter 2013 Earnings Report

Stocks in this article: XEL

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 Sept. 30 Nine Months Ended Sept. 30
2013 vs.     2012 vs.     2013 vs. 2013 vs.     2012 vs.     2013 vs.
Normal Normal 2012 Normal Normal 2012
HDD (44.6 )% (23.3 )% (30.7 )% 5.4 % (21.4 )% 33.4 %
CDD 15.6 33.1 (11.4 ) 25.3 46.9 (13.7 )
THI 28.0 34.3 (2.1 ) 23.0 37.2 (9.7 )
 

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

       
Three Months Ended Sept. 30 Nine Months Ended Sept. 30
2013 vs.     2012 vs.     2013 vs. 2013 vs.     2012 vs.     2013 vs.
Normal Normal 2012 Normal Normal 2012
Retail electric $ 0.048 $ 0.076 $ (0.028 ) $ 0.079 $ 0.083 $ (0.004 )
Firm natural gas (0.001 ) (0.001 )   0.015   (0.030 ) 0.045  
Total $ 0.047   $ 0.075   $ (0.028 ) $ 0.094   $ 0.053   $ 0.041  
 

Sales Growth (Decline) — The following tables summarize Xcel Energy’s sales growth (decline) for actual and weather-normalized sales in 2013:

   
Three Months Ended Sept. 30
    Weather
Actual     Normalized
Electric residential (2.4 )% 0.6 %
Electric commercial and industrial (0.5 ) 0.1
Total retail electric sales (1.1 ) 0.3
Firm natural gas sales (a) 4.9 5.2
 
       
Nine Months Ended Sept. 30
Nine Months Ended Sept. 30 (Without Leap Day)
    Weather     Weather
Actual     Normalized     Actual     Normalized
Electric residential 2.7 % 0.1 % 3.3 % 0.7 %
Electric commercial and industrial (0.4 ) (0.6 ) 0.1 (0.1 )
Total retail electric sales 0.4 (0.4 ) 0.9 0.1
Firm natural gas sales (a) 31.3 3.7 32.4 4.6
 

(a)

    As normal weather conditions are typically defined as a 30-year average of actual historical weather conditions, significant weather variations in periods of low demand may result in large percentage changes on small volumes.

Electric — 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 Sept. 30 Nine Months Ended Sept. 30
(Millions of Dollars) 2013     2012 2013     2012
Electric revenues $ 2,600 $ 2,533 $ 6,912 $ 6,506
Electric fuel and purchased power (1,098 ) (1,007 ) (3,034 ) (2,725 )
Electric margin $ 1,502   $ 1,526   $ 3,878   $ 3,781  
 

The following table summarizes the components of the changes in electric margin:

       
Three Months Nine Months
Ended Sept. 30 Ended Sept. 30
(Millions of Dollars) 2013 vs. 2012 2013 vs. 2012
Retail rate increases (a) $ 46 $ 177
Transmission revenue, net of costs 9 29
Non-fuel riders 7 10
Conservation and demand side management (DSM) program incentives (17 ) (26 )
PSCo earnings test refund obligation (11 ) (20 )
Firm wholesale (7 ) (20 )
SPS 2004 FERC complaint case orders (b) (5 ) (5 )
Estimated impact of weather (20 ) (1 )
Other, net   (21 )
Total increase in ongoing electric margin 2 123
SPS 2004 FERC complaint case orders (b) (26 ) (26 )
Total (decrease) increase in GAAP electric margin $ (24 ) $ 97  
 
   
(a) The retail rate increases include final rates in Minnesota, Colorado, Wisconsin, South Dakota and Texas and interim rates, subject to refund, in North Dakota. The Minnesota rate increase is net of a provision for customer refunds of $69 million for the third quarter of 2013 and $116 million for the nine months ended Sept. 30, 2013 based on the final rate order received for the 2013 electric rate case. In addition, revenues and expenses were reduced by approximately $30 million, primarily related to depreciation expense of $24 million and O&M expenses of $6 million in the third quarter of 2013 due to the order. See Note 4.

(b)

As a result of two orders issued by the Federal Energy Regulatory Commission (FERC), a pretax charge of approximately $35 million ($31 million in electric revenues, of which $5 million relates to 2013 and $26 million relates to periods prior to 2013, and $4 million in interest charges) was recorded in the third quarter of 2013. See Note 5.

 

Natural Gas — 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 Sept. 30 Nine Months Ended Sept. 30
(Millions of Dollars) 2013     2012 2013     2012
Natural gas revenues $ 205 $ 175 $ 1,216 $ 1,017
Cost of natural gas sold and transported (75 ) (50 ) (703 ) (557 )
Natural gas margin $ 130   $ 125   $ 513   $ 460  
 

The following table summarizes the components of the changes in natural gas margin:

       
Three Months Nine Months
Ended Sept. 30 Ended Sept. 30
(Millions of Dollars) 2013 vs. 2012 2013 vs. 2012
Estimated impact of weather $ $ 34
Retail rate increases (Colorado interim and Wisconsin) 7 8
Retail sales growth 1 7
Conservation and DSM program revenues (offset by expenses) (1 ) 4
Other, net (2 )
Total increase in natural gas margin $ 5   $ 53
 

O&M Expenses — O&M expenses increased $43.8 million, or 8.2 percent, for the third quarter of 2013 and $90.9 million, or 5.8 percent, for the nine months ended Sept. 30, 2013 compared with the same periods in 2012. The following table summarizes the changes in O&M expenses:

       
Three Months Nine Months
Ended Sept. 30 Ended Sept. 30
(Millions of Dollars) 2013 vs. 2012 2013 vs. 2012
Electric and gas distribution expenses $ 15 $ 32
Nuclear plant operations and amortization 13 28
Transmission costs 2 11
Employee benefits 5 4
Other, net 9   16
Total increase in O&M expenses $ 44   $ 91
 
  • Electric and gas distribution expenses were primarily driven by increased maintenance activities due to vegetation management, storms and outages;
  • Nuclear cost increases are related to the amortization of prior outages and initiatives designed to improve the operational efficiencies of the plants;
  • Increased transmission costs were related to higher substation maintenance expenditures and reliability costs; and
  • Higher employee benefits related primarily to increased pension expense.

Depreciation and Amortization — Depreciation and amortization decreased $10.6 million, or 4.4 percent, for the third quarter of 2013 and increased $26.8 million, or 3.9 percent, for the nine months ended Sept. 30, 2013 compared with the same periods in 2012. NSP-Minnesota reduced depreciation expense by $24 million in the third quarter of 2013 to reflect the final rate order received for the 2013 Minnesota electric rate case. This reduction was offset by increased depreciation related to normal system expansion.

Taxes (Other Than Income Taxes) — Taxes (other than income taxes) increased $4.7 million, or 4.6 percent, for the third quarter of 2013 and $14.9 million, or 4.9 percent, for the nine months ended Sept. 30, 2013 compared with the same periods in 2012. The increases are due to higher property taxes primarily in Minnesota, Colorado and Texas.

Allowance for Funds Used During Construction, Equity and Debt (AFUDC) — AFUDC increased $4.4 million for the third quarter of 2013 and $22.4 million for the nine months ended Sept. 30, 2013 compared with the same periods in 2012. The increases are primarily due to construction related to the Clean Air Clean Jobs Act (CACJA), the expansion of transmission facilities and other capital expenditures.

Interest Charges — Interest charges decreased $9.0 million, or 5.8 percent, for the third quarter of 2013 and $26.3 million, or 5.7 percent, for the nine months ended Sept. 30, 2013 compared with the same periods in 2012. The decreases are primarily due to refinancings at lower interest rates. This is partially offset by higher long-term debt levels, $4 million of interest associated with the customer refund at SPS based on the recent FERC orders and $3 million of interest associated with customer refunds in Minnesota based on the final rate order received for the 2013 Minnesota electric rate case. Also included for the nine months ended Sept. 30, 2013 was the write off of $6.3 million of unamortized debt expense related to the junior subordinated notes called in May 2013.

Income Taxes — Income tax expense for continuing operations decreased $9.5 million for the third quarter of 2013 compared with the same period in 2012. The decrease in income tax expense was primarily due to lower pretax earnings. The effective tax rate (ETR) for continuing operations was 34.7 percent for the third quarter of 2013 compared with 33.8 percent for the same period in 2012. The lower ETR for 2012 was primarily due to a one time tax benefit related to the restoration of a portion of the tax benefit written off in 2010 associated with federal subsidies for prescription drug plans. The ETR would have been 36.6 percent for the third quarter of 2012 without this tax benefit.

Income tax expense for continuing operations increased $30.5 million for the first nine months of 2013 compared with the same period in 2012. The increase in income tax expense was primarily due to higher pretax earnings. The ETR for continuing operations was 34.0 percent for the nine months ended Sept. 30, 2013 compared with 33.2 percent for the same period in 2012. The ETRs for 2013 reflect the benefits of research and experimentation credits, increased permanent plant-related adjustments and a 2013 carryback item. The lower ETR for the nine months ended Sept. 30, 2012 reflects a one time adjustment for a tax benefit associated with a carryback and a tax benefit related to the restoration of a portion of the tax benefit written off in 2010 associated with federal subsidies for prescription drug plans. As a result, Xcel Energy recognized discrete tax benefits of approximately $14.9 million for the carryback and $17 million for the tax benefit associated with the federal subsidies. The ETR would have been 36.0 percent for the nine months ended Sept. 30, 2012 without these tax benefits.

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