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 October 29, 2015 - 6:00 AM EDT
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Xcel Energy Third Quarter 2015 Earnings Report

  • GAAP (generally accepted accounting principles) and ongoing 2015 third quarter earnings per share were $0.84 compared with $0.73 per share in 2014.
  • Xcel Energy revises its 2015 ongoing earnings guidance range to $2.05 to $2.15 per share, compared to the previous range of $2.00 to $2.15 per share.
  • Xcel Energy initiates 2016 ongoing earnings guidance of $2.12 to $2.27 per share.

Xcel Energy Inc. (NYSE: XEL) today reported 2015 third quarter GAAP and ongoing earnings of $426 million, or $0.84 per share, compared with $369 million, or $0.73 per share, in the same period in 2014.

Electric and gas margins rose in the third quarter of 2015 primarily due to an increase in retail electric rates, non-fuel riders, the impact of favorable weather and a lower earnings test refund in Colorado. These positive factors were partially offset by higher depreciation and interest charges, lower allowance for funds used during construction and increased property taxes.

“Third quarter and year-to-date results demonstrate the ongoing, successful execution of our regulatory initiatives along with continued cost management efforts,” said Chairman, President and Chief Executive Officer Ben Fowke.

“During the quarter, the EPA issued the final Clean Power Plan. Although the regulations are groundbreaking and complex, Xcel Energy is well positioned to meet the requirements and remains committed to delivering the clean energy options our customers want while maintaining safety and reliability and keeping costs affordable.”

“Specifically, in Minnesota we recently filed a revised resource plan that will enable us to adapt to and embrace the rapid pace of change in our industry. Our proposal calls for a 60 percent reduction in carbon emissions from 2005 levels by 2030 and will result in 63 percent of NSP System energy being carbon free by 2030. In addition to supporting our effort to establish a long-term regulatory compact, this proposal will advance our shift to renewable energy, add cleaner natural gas-powered generation to our system and allow us to protect reliability, jobs and community investments.”

Earnings Adjusted for Certain Items (Ongoing Earnings)

The following table provides a reconciliation of ongoing earnings per share (EPS) to GAAP EPS:

   
Three Months Ended Sept. 30 Nine Months Ended Sept. 30
Diluted Earnings (Loss) Per Share 2015   2014 2015   2014
Ongoing diluted EPS $ 0.84 $ 0.73 $ 1.69 $ 1.64
Loss on Monticello life cycle management/extended power uprate project (a)           (0.16 )    
GAAP diluted EPS $ 0.84   $ 0.73   $ 1.53   $ 1.64  
 

(a) See Note 6.

 

At 9:00 a.m. CDT today, Xcel Energy will host a conference call to review financial results. To participate in the call, please dial in 5 to 10 minutes prior to the start and follow the operator’s instructions.

     
US Dial-In: (888) 539-3613
International Dial-In: (719) 457-2600
Conference ID: 4416633
 

The conference call also will be simultaneously broadcast and archived on Xcel Energy’s website at www.xcelenergy.com. To access the presentation, click on Investor Relations. If you are unable to participate in the live event, the call will be available for replay from 12:00 p.m. CDT on October 29 through 10:59 p.m. CDT on October 30.

     
Replay Numbers
US Dial-In: (888) 203-1112
International Dial-In: (719) 457-0820
Access Code: 4416633
 

Except for the historical statements contained in this release, the matters discussed herein, are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements, including our 2015 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 expressly disclaim any obligation to update any forward-looking information. The following factors, in addition to those discussed in Xcel Energy's Annual Report on Form 10-K for the fiscal year ended Dec. 31, 2014, and Quarterly Reports on Form 10-Q for the quarters ended March 31, 2015 and June 30, 2015, and subsequent securities filings, could cause actual results to differ materially from management expectations as suggested by such forward-looking information: 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 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; unusual weather; effects of geopolitical events, including war and acts of terrorism; cyber security threats and data security breaches; 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; financial or regulatory accounting policies imposed by regulatory bodies; availability of cost of capital; and employee work force factors.

This information is not given in connection with any sale, offer for sale or offer to buy any security.

 

XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME (Unaudited)
(amounts in thousands, except per share data)

   
Three Months Ended Sept. 30 Nine Months Ended Sept. 30
2015   2014 2015   2014
Operating revenues
Electric $ 2,667,480 $ 2,616,351 $ 7,105,803 $ 7,215,699
Natural gas 216,019 236,649 1,216,146 1,485,464
Other   17,813     16,807     56,716     56,344  
Total operating revenues 2,901,312 2,869,807 8,378,665 8,757,507
 
Operating expenses
Electric fuel and purchased power 1,014,726 1,079,855 2,869,563 3,188,498
Cost of natural gas sold and transported 66,071 99,344 665,109 934,073
Cost of sales — other 8,203 8,012 26,416 24,783
Operating and maintenance expenses 565,984 568,391 1,746,093 1,714,138
Conservation and demand side management program expenses 57,314 75,172 165,260 223,552
Depreciation and amortization 280,121 255,395 827,821 756,645
Taxes (other than income taxes) 123,081 117,958 389,438 358,938

Loss on Monticello life cycle management/extended power uprate project

          129,463      
Total operating expenses   2,115,500     2,204,127     6,819,163     7,200,627  
 
Operating income 785,812 665,680 1,559,502 1,556,880
 
Other income, net 1,626 1,404 5,748 4,687
Equity earnings of unconsolidated subsidiaries 8,162 7,401 24,360 22,650
Allowance for funds used during construction — equity 15,427 23,337 40,728 68,852
 
Interest charges and financing costs

Interest charges — includes other financing costs of $6,260, $5,737, $17,819 and $17,144, respectively

152,566 143,219 441,728 421,713
Allowance for funds used during construction — debt   (7,031 )   (9,948 )   (19,340 )   (29,609 )
Total interest charges and financing costs 145,535 133,271 422,388 392,104
 
Income before income taxes 665,492 564,551 1,207,950 1,260,965
Income taxes   239,029     195,969     432,490     435,998  
Net income $ 426,463   $ 368,582   $ 775,460   $ 824,967  
 
Weighted average common shares outstanding:
Basic 508,031 506,082 507,585 502,983
Diluted 508,427 506,365 507,976 503,213
 
Earnings per average common share:
Basic $ 0.84 $ 0.73 $ 1.53 $ 1.64
Diluted 0.84 0.73 1.53 1.64
 
Cash dividends declared per common share $ 0.32 $ 0.30 $ 0.96 $ 0.90
 

XCEL ENERGY INC. AND SUBSIDIARIES
Notes to Investor Relations Earnings Release (Unaudited)

Due to the seasonality of Xcel Energy’s operating results, quarterly financial results are not an appropriate base from which to project annual results.

The only common equity securities that are publicly traded are common shares of Xcel Energy Inc. The diluted earnings and 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. Ongoing diluted EPS for Xcel Energy and by subsidiary is a financial measure not recognized under GAAP. Ongoing diluted EPS is calculated by dividing the net income or loss attributable to the controlling interest of each subsidiary, adjusted for certain items, 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 Xcel Energy’s core earnings and underlying performance. We believe this measurement is useful to investors in facilitating period over period comparisons and evaluating or projecting financial results. This non-GAAP financial measure should not be considered as an alternative to measures calculated and reported in accordance with GAAP.

Note 1. Earnings Per Share Summary

The following table summarizes the diluted EPS for Xcel Energy:

   
Three Months Ended Sept. 30 Nine Months Ended Sept. 30
Diluted Earnings (Loss) Per Share 2015   2014 2015   2014
Public Service Company of Colorado (PSCo) $ 0.34 $ 0.30 $ 0.75 $ 0.72
NSP-Minnesota 0.35 0.27 0.65 0.63
Southwestern Public Service Company (SPS) 0.12 0.13 0.21 0.23
NSP-Wisconsin 0.05 0.04 0.13 0.11
Equity earnings of unconsolidated subsidiaries   0.01     0.01     0.03     0.03  
Regulated utility 0.87 0.75 1.77 1.72
Xcel Energy Inc. and other   (0.03 )   (0.02 )   (0.08 )   (0.08 )
Ongoing diluted EPS 0.84 0.73 1.69 1.64

Loss on Monticello life cycle management (LCM)/extended power uprate (EPU) project (a)

          (0.16 )    
GAAP diluted EPS $ 0.84   $ 0.73   $ 1.53   $ 1.64  
 

(a) See Note 6.

 

PSCo — PSCo’s ongoing earnings increased $0.04 per share for the third quarter of 2015 and $0.03 year-to-date. Higher revenue primarily due to the Clean Air Clean Jobs Act (CACJA) rider (partially offset by an electric base rate decrease), lower estimated electric earnings test refunds and the impact of favorable weather were partially offset by lower allowance for funds used during construction (AFUDC), higher property taxes, depreciation and operating and maintenance (O&M) expenses.

NSP-Minnesota — NSP-Minnesota’s ongoing earnings increased $0.08 per share for the third quarter of 2015 and $0.02 year-to-date. Revenues increased primarily due to electric rate cases in Minnesota, North Dakota and South Dakota and were partially offset by higher depreciation, higher O&M expenses, lower gas margins, higher interest charges, unfavorable weather and weather-normalized sales decline.

SPS — SPS’ ongoing earnings decreased $0.01 per share for the third quarter of 2015 and $0.02 year-to-date. Higher electric rates in Texas were more than offset by higher O&M expenses, increased depreciation, lower AFUDC and higher interest charges and unfavorable weather.

NSP-Wisconsin — NSP-Wisconsin’s ongoing earnings per share increased $0.01 for the third quarter of 2015 and $0.02 year-to-date. Higher electric margins, primarily due to an electric rate increase and weather-normalized sales growth and lower O&M expenses were partially offset by higher depreciation and unfavorable weather.

The following table summarizes significant components contributing to the changes in 2015 EPS compared with the same period in 2014:

   
Diluted Earnings (Loss) Per Share

Three Months
Ended Sept. 30

Nine Months
Ended Sept. 30

2014 GAAP and ongoing diluted EPS $ 0.73 $ 1.64
 
Components of change — 2015 vs. 2014
Higher electric margins 0.14 0.25
Lower conservation and demand side management (DSM) program expenses (offset by lower revenues) 0.02 0.07
Higher depreciation and amortization (0.03 ) (0.09 )
Lower AFUDC — equity (0.02 ) (0.06 )
Higher O&M expenses (0.04 )
Higher taxes (other than income taxes) (0.01 ) (0.04 )
Higher effective tax rate (ETR) (0.01 ) (0.03 )
Higher interest charges (0.01 ) (0.02 )
Dilution from equity issued through the direct stock purchase plan and benefit plans (0.02 )
Higher natural gas margins 0.02
Other, net   0.01     0.03  
2015 ongoing diluted EPS 0.84 1.69
Loss on Monticello LCM/EPU project (a)       (0.16 )
2015 GAAP diluted EPS $ 0.84   $ 1.53  
 

(a) See Note 6.

 

Note 2. Regulated Utility Results

Estimated Impact of Temperature Changes on Regulated Earnings — Unusually hot summers or cold winters increase electric and natural gas sales, while 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.

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. 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 regulatory practice. 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 decrease in normal and actual HDD, CDD and THI is provided in the following table:

   
Three Months Ended Sept. 30 Nine Months Ended Sept. 30
2015 vs.
Normal
  2014 vs.
Normal
  2015 vs.
2014
2015 vs.
Normal
  2014 vs.
Normal
  2015 vs.
2014
HDD (57.9 )% (11.2 )% (54.8 )% (4.2 )% 11.5 % (14.4 )%
CDD 15.1 (4.0 ) 20.0 5.4 (2.5 ) 8.3
THI 4.3 (17.3 ) 29.2 (1.6 ) (11.2 ) 13.7
 

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
2015 vs.
Normal
  2014 vs.
Normal
  2015 vs.
2014
2015 vs.
Normal
  2014 vs.
Normal
  2015 vs.
2014
Retail electric $ 0.010 $ (0.024 ) $ 0.034 $ (0.004 ) $ 0.010 $ (0.014 )
Firm natural gas   (0.002 )       (0.002 )   (0.007 )   0.018   (0.025 )
Total $ 0.008   $ (0.024 ) $ 0.032   $ (0.011 ) $ 0.028 $ (0.039 )
 

Sales Growth (Decline) — The following tables summarize Xcel Energy and its subsidiaries’ sales growth (decline) for actual and weather-normalized sales in 2015:

 
Three Months Ended Sept. 30
Xcel Energy   PSCo   NSP-Minnesota   NSP-Wisconsin   SPS
Actual
Electric residential (a) 4.3 % 4.2 % 3.3 % 6.2 % 6.6 %
Electric commercial and industrial 1.1 1.3 0.8 1.9 1.0
Total retail electric sales 1.9 2.2 1.4 3.0 1.4
Firm natural gas sales (5.7 ) (7.9 ) (1.4 ) (3.1 ) N/A
 
Three Months Ended Sept. 30
Xcel Energy PSCo NSP-Minnesota NSP-Wisconsin SPS
Weather-normalized
Electric residential (a) 0.6 % 1.5 % (0.2 )% (0.6 )% 1.3 %
Electric commercial and industrial (0.7 ) 0.2 0.2 0.4
Total retail electric sales 0.1 (0.1 ) 0.5
Firm natural gas sales (0.3 ) (1.3 ) 1.6 0.8 N/A
 
Nine Months Ended Sept. 30
Xcel Energy PSCo NSP-Minnesota NSP-Wisconsin SPS
Actual
Electric residential (a) (1.4 )% 0.5 % (2.9 )% (4.6 )% (0.3 )%
Electric commercial and industrial (0.3 ) 1.3
Total retail electric sales (0.5 ) 0.2 (1.1 ) (0.4 ) (0.2 )
Firm natural gas sales (11.2 ) (9.0 ) (14.7 ) (12.5 ) N/A
 
Nine Months Ended Sept. 30
Xcel Energy PSCo NSP-Minnesota NSP-Wisconsin SPS
Weather-normalized
Electric residential (a) (0.6 )% (0.1 )% (1.2 )% (2.5 )% 1.0 %
Electric commercial and industrial (0.7 ) 0.1 1.5 0.3
Total retail electric sales (0.2 ) (0.5 ) (0.3 ) 0.3 0.3
Firm natural gas sales (1.8 ) (2.3 ) (1.1 ) 0.1 N/A
 

(a) Extreme weather variations and additional factors such as windchill and cloud cover may not be reflected in weather-normalized and actual growth estimates.

 

Weather-normalized Electric Year-to-Date Growth (Decline)

  • SPS’ commercial and industrial (C&I) growth was driven by continued expansion from oil and gas exploration and production in the Southeastern New Mexico, Permian Basin area. This was partially offset by the impact of wet weather which resulted in less irrigation by agricultural customers. Residential growth reflects an increased number of customers as well as greater use per customer.
  • NSP-Wisconsin’s electric sales growth was largely due to strong sales to large C&I customers primarily in the oil, gas and sand mining industries. Residential decline was primarily attributable to lower use per customer.
  • PSCo’s C&I decline was primarily due to reduced sales to certain large manufacturing customers and/or those that support the fracking industry. Residential decrease was primarily the result of weaker use per customer, partially offset by customer growth.
  • NSP-Minnesota’s C&I electric sales were flat as a result of higher use for large customer class (particularly due to greater usage in the petroleum industry), and an increase in the number of customers in both the small and large classes, offset by lower use for the remaining large and small customers in various industries. The residential decrease was due to less use per customer, partially offset by an increase in customer growth.

Weather-normalized Natural Gas Decline

  • Across natural gas service territories, lower natural gas sales reflect a decline in customer use.

Electric 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 minimal 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) 2015   2014 2015   2014
Electric revenues $ 2,667 $ 2,616 $ 7,106 $ 7,216
Electric fuel and purchased power   (1,015 )   (1,080 )   (2,870 )   (3,188 )
Electric margin $ 1,652   $ 1,536   $ 4,236   $ 4,028  
 

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

(Millions of Dollars)   Three Months
Ended Sept. 30
2015 vs. 2014
  Nine Months
Ended Sept. 30
2015 vs. 2014
Non-fuel riders (a) (b) $ 20 $ 87
Retail rate increases (b) 31 80
PSCo earnings test refund 26 61
Transmission revenue, net of costs 22 28
Conservation and DSM program revenues (offset by expenses) (17 ) (46 )
Estimated impact of weather 26 (11 )
Other, net   8     9  
Total increase in electric margin $ 116   $ 208  
 

(a) Primarily related to the new CACJA rider in Colorado ($23 million and $74 million, respectively).

 

(b) Increase due to rate proceedings in Minnesota, South Dakota, North Dakota, Texas, New Mexico and Wisconsin. These increases were partially offset by a decline in Colorado retail base rates, which was more than offset by increased CACJA rider revenue as approved by the Colorado Public Utilities Commission (CPUC) in the first quarter of 2015.

 

Natural Gas Margin — Total natural gas expense 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 for sales to retail customers, fluctuations in the cost of natural gas has minimal impact 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) 2015   2014 2015   2014
Natural gas revenues $ 216 $ 237 $ 1,216 $ 1,485
Cost of natural gas sold and transported   (66 )   (99 )   (665 )   (934 )
Natural gas margin $ 150   $ 138   $ 551   $ 551  
 

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

   
(Millions of Dollars)

Three Months
Ended Sept. 30
2015 vs. 2014

Nine Months
Ended Sept. 30
2015 vs. 2014

Non-fuel riders, partially offset by expenses $ 7 $ 25
Gas transport - Cherokee pipeline 2 4
Estimated impact of weather (1 ) (20 )
Conservation and DSM program revenues (offset by expenses) (11 )
Other, net   4     2  
Total increase in natural gas margin $ 12   $  
 

O&M Expenses — O&M expenses decreased $2.4 million, or 0.4 percent, for the third quarter of 2015 and increased $32.0 million, or 1.9 percent, for the nine months ended Sept. 30, 2015. The year-to-date increase in O&M is primarily due to the timing of planned maintenance and overhauls at a number of our generation facilities as well as an increase in contractor costs.

   
(Millions of Dollars)

Three Months
Ended Sept. 30
2015 vs. 2014

Nine Months
Ended Sept. 30
2015 vs. 2014

Plant generation costs $ (8 ) $ 13
Labor and contract labor 5 11
Electric and natural gas distribution expenses 7 7
Nuclear plant operations (11 ) (7 )
Other, net   5     8  
Total (decrease) increase in O&M expenses $ (2 ) $ 32  
 

For the third quarter of 2015, O&M expenses decreased due to the following:

  • Plant generation costs were related to the timing of overhauls and discovery work; and
  • Nuclear expense decreases were primarily due to reduced costs driven by operational initiatives and efficiencies.

Conservation and DSM Program Expenses — Conservation and DSM program expenses decreased $17.9 million for the third quarter of 2015 and $58.3 million for the nine months ended Sept. 30, 2015. The decreases were primarily attributable to lower electric and gas recovery rates at NSP-Minnesota and PSCo. Lower conservation and DSM program expenses are generally offset by lower revenues.

Depreciation and Amortization — Depreciation and amortization increased $24.7 million, or 9.7 percent, for the third quarter of 2015 and $71.2 million, or 9.4 percent, year-to-date. Increases were primarily attributed to normal system expansion and lower amortization of the excess depreciation reserve in Minnesota, partially offset by Minnesota’s amortization of the Department of Energy settlement.

Taxes (Other Than Income Taxes) — Taxes (other than income taxes) increased $5.1 million, or 4.3 percent, for the third quarter of 2015 and $30.5 million, or 8.5 percent, for the nine months ended Sept. 30, 2015. Increases were due to higher property taxes primarily in Colorado and Minnesota.

AFUDC, Equity and Debt — AFUDC decreased $10.8 million for the third quarter of 2015 and $38.4 million year-to-date. Decreases were primarily due to the implementation of the CACJA rider on Jan. 1, 2015, facilitating earlier and alternative recovery of construction costs.

Interest Charges — Interest charges increased $9.3 million, or 6.5 percent, for the third quarter of 2015 and $20.0 million, or 4.7 percent, for the nine months ended Sept. 30, 2015. Increases were primarily due to higher long-term debt levels, partially offset by refinancings at lower interest rates.

Income Taxes Income tax expense increased $43.1 million for the third quarter of 2015 compared with the same period in 2014. The increase was primarily due to higher pretax earnings and decreased permanent plant-related adjustments in 2015. The ETR was 35.9 percent for the third quarter of 2015 compared with 34.7 percent for the same period in 2014. The higher ETR for 2015 was primarily due to the plant-related adjustments referenced above.

Income tax expense decreased $3.5 million for the first nine months of 2015 compared with the same period in 2014. The decrease was primarily due to lower pretax earnings, partially offset by decreased permanent plant-related adjustments and the successful resolution of a 2010-2011 IRS audit issue in 2014. The ETR was 35.8 percent for the first nine months of 2015, compared to 34.6 percent for the first nine months of 2014 primarily due to these adjustments.

Note 3. Xcel Energy Capital Structure, Financing and Credit Ratings

Following is the capital structure of Xcel Energy:

   
(Billions of Dollars) Sept. 30, 2015

Percentage of
Total Capitalization

Current portion of long-term debt $ 0.5 2 %
Short-term debt 0.1 1
Long-term debt   12.7 53  

Total debt

13.3 56
Common equity   10.5 44  
Total capitalization $ 23.8 100 %
 

Credit Facilities As of Oct. 26, 2015, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available to meet liquidity needs:

         
(Millions of Dollars) Credit Facility (a) Drawn (b) Available Cash Liquidity
Xcel Energy Inc. $ 1,000 $ $ 1,000 $ 6 $ 1,006
PSCo 700 4 696 1 697
NSP-Minnesota 500 23 477 156 633
SPS 400 10 390 1 391
NSP-Wisconsin   150   15   135   1   136
Total $ 2,750 $ 52 $ 2,698 $ 165 $ 2,863
 

(a) These credit facilities expire in October 2019.

(b) Includes outstanding commercial paper and letters of credit.

 

Credit Ratings — Access to the capital market at reasonable terms is dependent in part on credit ratings. The following ratings reflect the views of Moody’s Investors Service (Moody’s), Standard & Poor’s Rating Services (Standard & Poor’s), and Fitch Ratings (Fitch).

As of Oct. 26, 2015, the following represents the credit ratings assigned to Xcel Energy Inc. and its utility subsidiaries:

       
Company Credit Type Moody’s Standard & Poor’s Fitch
Xcel Energy Inc. Senior Unsecured Debt A3 BBB+ BBB+
Xcel Energy Inc. Commercial Paper P-2 A-2 F2
NSP-Minnesota Senior Unsecured Debt A2 A- A
NSP-Minnesota Senior Secured Debt Aa3 A A+
NSP-Minnesota Commercial Paper P-1 A-2 F2
NSP-Wisconsin Senior Unsecured Debt A2 A- A
NSP-Wisconsin Senior Secured Debt Aa3 A A+
NSP-Wisconsin Commercial Paper P-1 A-2 F2
PSCo Senior Unsecured Debt A3 A- A
PSCo Senior Secured Debt A1 A A+
PSCo Commercial Paper P-2 A-2 F2
SPS Senior Unsecured Debt Baa1 A- BBB+
SPS Senior Secured Debt A2 A A-
SPS Commercial Paper P-2 A-2 F2
 

The highest credit rating for debt is Aaa/AAA and the lowest investment grade rating is Baa3/BBB-. The highest rating for commercial paper is P-1/A-1/F-1 and the lowest rating is P-3/A-3/F-3. A security rating is not a recommendation to buy, sell or hold securities. Ratings are subject to revision or withdrawal at any time by the credit rating agency and each rating should be evaluated independently of any other rating.

During 2016, Xcel Energy Inc. and its utility subsidiaries anticipate issuing the following:

  • Xcel Energy Inc. plans to issue approximately $600 million of senior unsecured bonds;
  • NSP-Minnesota plans to issue approximately $250 million of first mortgage bonds; and
  • SPS plans to issue approximately $350 million of first mortgage bonds.

During 2015, Xcel Energy Inc. and its utility subsidiaries completed the following bond issuances:

  • In May, PSCo issued $250 million of 2.9 percent first mortgage bonds due May 15, 2025;
  • In June, Xcel Energy Inc. issued $250 million of 1.2 percent senior notes due June 1, 2017 and $250 million of 3.3 percent senior notes due June 1, 2025;
  • In June, NSP-Wisconsin issued $100 million of 3.3 percent first mortgage bonds due June 15, 2024;
  • In August, NSP-Minnesota issued $300 million of 2.2 percent first mortgage bonds due Aug. 15, 2020 and $300 million of 4.0 percent first mortgage bonds due Aug. 15, 2045; and
  • In September, SPS issued $200 million of 3.3 percent first mortgage bonds due June 15, 2024.

Financing plans are subject to change, depending on capital expenditures, internal cash generation, market conditions and other factors.

Dividend Reinvestment and Stock Purchase Plan and Stock Compensation Settlements — In October 2015, the Xcel Energy Inc. Board of Directors authorized open market purchases by the plan administrator as the source of shares for the dividend reinvestment program as well as market purchases of up to 3.0 million shares for stock compensation plan settlements.

Note 4. Rates and Regulation

NSP System Resource Plans — In January 2015, NSP-Minnesota filed its 2016-2030 Integrated Resource Plan (the Plan) with the MPUC.

On Oct. 2, 2015, NSP-Minnesota filed revisions to the Plan. The revised proposal addressed stakeholder recommendations as well as the final Clean Power Plan (CPP) recently issued by the Environmental Protection Agency. The revised Plan is based on four primary elements: (1) accelerate the transition from coal energy to renewables, (2) preserve regional system reliability, (3) pursue energy efficiency gains and grid modernization, and (4) ensure customer benefits. The provisions included in the Plan would allow for a 60 percent reduction in carbon emissions from 2005 levels by 2030 and will result in 63 percent of NSP System energy being carbon-free by 2030. Specific terms of the proposal include:

  • The addition of 800 megawatts (MW) of wind and 400 MW of utility scale solar to the pre-2020 time-frame;
  • The addition of 1000 MW wind and 1000 MW utility scale solar between 2020-2030;
  • The retirement of Sherco Unit 2 in 2023 and Sherco Unit 1 in 2026;
  • The addition of a 230 MW (approximate capacity, actual size to be determined) natural gas combustion turbine in North Dakota by 2025;
  • Replacement of Sherco coal generation with a 780 MW (approximate capacity, actual size to be determined) natural gas combined cycle unit at the Sherco site no later than 2026; and
  • Operation of the Monticello and Prairie Island nuclear plants through their current license periods in the early 2030’s.

We believe this will provide substantial opportunities for the ownership of replacement and renewable generation. The Plan is currently being reviewed by the MPUC.

NSP-Wisconsin – Wisconsin 2016 Electric and Gas Rate Case In May 2015, NSP-Wisconsin filed a request with the Public Service Commission of Wisconsin (PSCW) to increase rates for electric and natural gas service effective Jan. 1, 2016. NSP-Wisconsin requested an overall increase in annual electric rates of $27.4 million, or 3.9 percent, and an increase in natural gas rates of $5.9 million, or 5.0 percent.

The rate filing is based on a 2016 forecast test year, a return on equity (ROE) of 10.2 percent, an equity ratio of 52.5 percent and a forecasted average net investment rate base of approximately $1.2 billion for the electric utility and $111.2 million for the natural gas utility.

On Oct. 1, 2015, the PSCW Staff and other intervenors, including the Citizens Utility Board, filed their direct testimony in the case. The PSCW Staff recommended an electric rate increase of $10.4 million, or 1.5 percent and a gas rate increase of $3.0 million, or 2.5 percent, based on a ROE of 10.0 percent and an equity ratio of 52.5 percent. The Citizens Utility Board recommended a ROE of 8.75 percent. None of the intervenors presented a complete revenue requirements analysis. The majority of the PSCW Staff adjustments relate to ROE, compensation issues and capital related forecast disputes.

Key dates in the procedural schedule are as follows:

  • Initial Brief — Nov. 12, 2015;
  • Reply Brief — Nov. 19, 2015;
  • A PSCW decision is anticipated in December 2015; and
  • New rates effective on or about Jan. 1, 2016.

PSCo – Colorado 2015 Multi-Year Gas Rate Case — In March 2015, PSCo filed a multi-year request with the CPUC to increase Colorado retail natural gas base rates by $40.5 million, or 3.5 percent, in 2015, with subsequent step increases of $7.6 million, or 0.7 percent, in 2016 and $18.1 million, or 1.5 percent, in 2017.

The request is based on a historic test year (HTY) ended June 30, 2014 adjusted for known and measurable expenses and capital additions for each of the subsequent periods in the multi-year plan and an equity ratio of 56 percent. The rate case requests a ROE of 10.1 percent for 2015 and 2016 and 10.3 percent for 2017, and a rate base of $1.26 billion for 2015, $1.31 billion for 2016 and $1.36 billion for 2017.

PSCo also proposed a stay-out provision, in which PSCo would not request implementation of new rates prior to January 2018, and implementation of an earnings test for 2016 through 2017.

In addition, PSCo requested an extension of its pipeline system integrity adjustment (PSIA) rider through 2020 to recover costs associated with its pipeline integrity efforts. The request to extend and modify the PSIA rider has an expected negative revenue impact of approximately $0.1 million in 2015 and would provide incremental revenue of $21.7 million for 2016 and $21.2 million for 2017. The following table summarizes the request:

     
(Millions of Dollars) 2015 2016 Step 2017 Step
Total base rate increase $ 40.5 $ 7.6 $ 18.1
Incremental PSIA rider revenues   (0.1 )   21.7     21.2  
Total revenue impact $ 40.4   $ 29.3   $ 39.3  
 

In June 2015, the CPUC Staff (Staff) and the Office of Consumer Counsel (OCC) issued their 2015 base rate recommendations. The following table reflects the current positions of Staff and OCC:

   
(Millions of Dollars) Staff OCC
PSCo’s filed 2015 base rate request $ 40.5 $ 40.5
ROE (12.8 ) (13.7 )
Capital structure and cost of debt (12.8 ) (4.8 )
Cherokee pipeline adjustment (11.2 ) 4.8
Move to 2014 HTY (10.5 ) (16.4 )
O&M expenses (3.5 ) (2.7 )
Other, net   (4.4 )   (1.9 )
Total adjustments $ (55.2 ) $ (34.7 )
   
Recommended (decrease) increase $ (14.7 ) $ 5.8  
 

The Staff’s recommendation for the PSIA rider is as follows:

   
(Millions of Dollars) 2016 2017
PSCo’s filed incremental PSIA request $ 21.7 $ 21.2
Transfer PSIA O&M to base rates (24.1 ) (2.0 )
ROE and capital structure (8.2 ) (3.6 )
Transfer meter replacement program from base rates to PSIA   1.7     1.7  
Total $ (8.9 ) $ 17.3  
 

In July 2015, PSCo filed rebuttal testimony, maintaining its request for a multi-year plan and requested ROEs and reflecting the most recent sales forecast. PSCo’s rebuttal testimony, compared to its initial filed base rate and rider request are summarized as follows:

     
(Millions of Dollars) 2015 2016 Step 2017 Step
PSCo’s filed base rate request $ 40.5 $ 7.6 $ 18.1
Shift O&M expenses between PSIA and base rates 7.0 6.4
Rebuttal corrections and adjustments         (7.7 )
Total base rate request $ 40.5 $ 14.6 $ 16.8
Incremental PSIA rider revenues   (0.1 )   14.7   21.7  
Total revenue impact from rebuttal $ 40.4   $ 29.3 $ 38.5  
 

If PSCo’s revised request is accepted, PSIA revenue is projected to be $67.0 million in 2015, $81.7 million in 2016 and $103.4 million in 2017.

Interim rates, subject to refund, were also implemented, effective Oct. 1, 2015, based on PSCo’s direct testimony. PSCo is expecting the ALJ’s Recommended Decision in November 2015. The final CPUC decision is expected no later than January 2016.

SPS – New Mexico 2015 Electric Rate Case — In October 2015, SPS filed an electric rate case with the New Mexico Public Regulation Commission (NMPRC) for a net increase in base rates of approximately $24.3 million for the New Mexico retail jurisdiction. The proposed net amount reflects an increase in non-fuel base rates of $45.4 million and a decrease in base fuel revenue of approximately $21.1 million. The decrease in base fuel revenue will be reflected in adjustments collected through the fuel and purchased power adjustment clause. The rate filing is based on a June 30, 2015 HTY adjusted for known and measurable changes, a requested ROE of 10.25 percent, an electric jurisdictional rate base of approximately $734 million and an equity ratio of 53.97 percent.

The major components of the requested rate increase are summarized below:

 
(Millions of Dollars) Request
2015 base period deficiency $ 19.7
Capital expenditures post-test year adjustments 12.3
Depreciation, higher rates reflecting changes in depreciable lives, interim retirements and net salvage 3.7
Transmission revenue and expense, including charges paid to Southwest Power Pool for construction of regionally shared transmission projects 2.0
ROE, reflecting an increase from 9.96 percent to 10.25 percent 1.6
Rider revenue adjustments - gross receipts tax 1.3
Other, net   4.8  
Requested rate increase $ 45.4  
 

A NMPRC decision and implementation of final rates is anticipated in the second half of 2016. In June 2015, the NMPRC dismissed a rate case filing using a FTY based on new precedent. SPS has appealed that decision to the New Mexico Supreme Court.

SPS – Texas 2015 Electric Rate Case — In December 2014, SPS filed a retail electric rate case in Texas seeking an overall increase in annual revenue of approximately $64.8 million, or 6.7 percent. The filing was based on a HTY ending June 2014, adjusted for known and measurable changes, a ROE of 10.25 percent, an electric rate base of approximately $1.6 billion and an equity ratio of 53.97 percent. In March 2015, SPS revised its requested increase to $58.9 million based on updated information.

SPS is seeking a waiver of the Public Utility Commission of Texas (PUCT) post-test year adjustment rule which would allow for inclusion of $392 million (SPS total company) additional capital investment for the period July 1, 2014 through Dec. 31, 2014.

In June 2015, SPS filed rebuttal testimony supporting a revised rate increase of approximately $42.1 million, or 4.4 percent.

On Oct. 12, 2015, the administrative law judges (ALJs) issued their Proposal for Decision (PFD) and recommended a rate increase of approximately $1.2 million, based on a ROE of 9.70 percent and an equity ratio of 53.97 percent.

The following table reflects the current positions of Alliance of Xcel Municipalities (AXM), the Office of Public Utility Counsel (OPUC), the PUCT Staff (Staff), SPS as well as the estimated recommendation of the ALJs:

         

(Millions of Dollars)

AXM

OPUC

Staff

SPS
Rebuttal
Testimony

ALJs’ PFD (a)

SPS’ revised rate request $ 58.9 $ 58.9 $ 58.9 $ 58.9 $ 42.1
Investment for capital expenditures — post-test year adjustments (11.3 ) (23.8 ) (23.8 ) (16.7 )
Lower ROE (10.9 ) (13.5 ) (12.1 ) (6.3 )
Rate base adjustments (largely the removal of the prepaid pension asset) (6.2 ) (6.8 )
O&M expense adjustments (13.7 ) (11.0 ) (7.9 ) (1.6 ) (5.3 )
Depreciation expense (13.3 ) (3.9 )
Property taxes (1.2 ) (4.4 ) (1.8 ) (3.7 )
Revenue adjustments (2.2 ) (0.2 )
Wholesale load reductions (13.2 ) (11.1 )
Southwest Power Pool transmission expansion plan (7.3 ) (4.2 )
Other, net   (1.7 )   (0.6 )   (2.2 )   (1.8 )   (0.6 )
Total recommendation $ (13.6 ) $ 1.8 $ (2.6 ) $ 46.4 $ 1.4
Adjustment to move rate case expenses to a separate docket               (4.3 )   (0.2 )
Recommendation, excluding rate case expenses $ (13.6 ) $ 1.8   $ (2.6 ) $ 42.1   $ 1.2  
 

(a) The ALJs’ recommendation reflects proposed adjustments to SPS’ rebuttal testimony which supports a $42.1 million rate increase.

 

SPS believes the ALJs’ recommended decision contains discrepancies and a revised calculation will result in a higher recommended rate increase. On Oct. 21, 2015, SPS filed a letter notifying the PUCT of its concerns regarding the calculation.

New rates will be made effective retroactive to June 11, 2015 as established by the PUCT. A PUCT decision is expected in December 2015.

Note 5. Xcel Energy Earnings Guidance and Long-Term EPS and Dividend Growth Rate Objectives

Xcel Energy Earnings Guidance — Xcel Energy’s revised 2015 ongoing earnings guidance to $2.05 to $2.15 per share, compared with the previous issued guidance of $2.00 to $2.15 per share. Key assumptions related to 2015 earnings are detailed below:

  • Constructive outcomes in all rate case and regulatory proceedings.
  • Normal weather patterns are experienced for the remainder of the year.
  • Weather-normalized retail electric utility sales are projected to be relatively flat.
  • Weather-normalized retail firm natural gas sales are projected to decline approximately 2 percent.
  • Capital rider revenue is projected to increase by $150 million to $160 million over 2014 levels.
  • The change in O&M expenses is projected to be within a range of 0 percent to 2 percent from 2014 levels.
  • Depreciation expense is projected to increase $110 million to $120 million over 2014 levels. The change in the depreciation assumption reflects an adjustment for eliminations and will not have any impact on earnings.
  • Property taxes are projected to increase approximately $50 million to $60 million over 2014 levels.
  • Interest expense (net of AFUDC — debt) is projected to increase $40 million to $50 million over 2014 levels.
  • AFUDC — equity is projected to decline approximately $30 million to $40 million from 2014 levels.
  • The ETR is projected to be approximately 34 percent to 36 percent.
  • Average common stock and equivalents are projected to be approximately 508 million shares.

Xcel Energy’s 2016 ongoing earnings guidance is $2.12 to $2.27 per share. Key assumptions related to 2016 earnings are detailed below:

  • Constructive outcomes in all rate case and regulatory proceedings, including the implementation of interim rates in Minnesota consistent with historical precedent.
  • Normal weather patterns are experienced for the year.
  • Weather-normalized retail electric utility sales are projected to increase approximately 0.5 percent to 1.0 percent.
  • Weather normalized retail firm natural gas sales are projected to be relatively flat.
  • Capital rider revenue is projected to increase by $70 million to $80 million over 2015 levels.
  • The change in O&M expenses is projected to be within a range of 0 percent to 2 percent from 2015 levels.
  • Depreciation expense is projected to increase approximately $200 million over 2015 levels.
  • Property taxes are projected to increase approximately $40 million to $50 million over 2015 levels.
  • Interest expense (net of AFUDC — debt) is projected to increase $40 million to $50 million over 2015 levels.
  • AFUDC — equity is projected to decline approximately $5 million to $10 million from 2015 levels.
  • The ETR is projected to be approximately 34 percent to 36 percent.
  • Average common stock and equivalents are projected to be approximately 509 million shares.

Long-Term EPS and Dividend Growth Rate Objectives Xcel Energy expects to deliver an attractive total return to our shareholders through a combination of earnings growth and dividend yield, based on the following long-term objectives:

  • Deliver long-term annual EPS growth of 4 percent to 6 percent, based on weather-normalized, ongoing 2014 EPS of $2.00;
  • Deliver annual dividend increases of 5 percent to 7 percent;
  • Target a dividend payout ratio of 60 percent to 70 percent; and
  • Maintain senior unsecured debt credit ratings in the BBB+ to A range.

Ongoing earnings is calculated using net income and adjusting for certain nonrecurring or infrequent items that are, in management’s view, not reflective of ongoing operations.

Note 6. Non-GAAP Reconciliation

Xcel Energy’s reported earnings are prepared in accordance with GAAP. Xcel Energy’s management believes that ongoing earnings, or GAAP earnings adjusted for certain items, reflect management’s performance in operating the company and provides a meaningful representation of the underlying performance of Xcel Energy’s core business. In addition, Xcel Energy’s management uses ongoing earnings internally for financial planning and analysis, for reporting of results to the Board of Directors and when communicating its earnings outlook to analysts and investors. This non-GAAP financial measure should not be considered as an alternative to measures calculated and reported in accordance with GAAP.

The following table provides a reconciliation of ongoing earnings to GAAP earnings (net income):

   
Three Months Ended Sept. 30 Nine Months Ended Sept. 30
(Thousands of Dollars) 2015   2014 2015  

2014

Ongoing earnings $ 426,463 $ 368,582 $ 854,610 $ 824,967
Loss on Monticello LCM/EPU project           (79,150 )    
GAAP earnings $ 426,463   $ 368,582   $ 775,460   $ 824,967  
 

Loss on Monticello LCM/EPU Project — In March 2015, the MPUC approved full recovery, including a return, on $415 million of the project costs, inclusive of AFUDC, but only allow recovery of the remaining $333 million of costs with no return on this portion of the investment for years 2015 and beyond. As a result of this decision, Xcel Energy recorded a pre-tax charge of approximately $129 million, or $79 million net of tax, in the first quarter of 2015. Given the nature of this specific item, it has been excluded from ongoing earnings.

 

XCEL ENERGY INC. AND SUBSIDIARIES
EARNINGS RELEASE SUMMARY (Unaudited)
(amounts in thousands, except per share data)

 
  Three Months Ended Sept. 30
2015   2014
Operating revenues:
Electric and natural gas $ 2,883,499 $ 2,853,000
Other   17,813     16,807  
Total operating revenues 2,901,312 2,869,807
 
Net income $ 426,463 $ 368,582
 
Weighted average diluted common shares outstanding 508,427 506,365
 

Components of EPS — Diluted

Regulated utility $ 0.87 $ 0.75
Xcel Energy Inc. and other costs   (0.03 )   (0.02 )
Ongoing diluted EPS 0.84 0.73
Loss on Monticello LCM/EPU project (a)        
GAAP diluted EPS $ 0.84   $ 0.73  
 
Nine Months Ended Sept. 30
2015 2014
Operating revenues:
Electric and natural gas $ 8,321,949 $ 8,701,163
Other   56,716     56,344  
Total operating revenues 8,378,665 8,757,507
 
Net income $ 775,460 $ 824,967
 
Weighted average diluted common shares outstanding 507,976 503,213
 

Components of EPS — Diluted

Regulated utility $ 1.77 $ 1.72
Xcel Energy Inc. and other costs   (0.08 )   (0.08 )
Ongoing diluted EPS 1.69 1.64
Loss on Monticello LCM/EPU project (a)   (0.16 )    
GAAP diluted EPS $ 1.53   $ 1.64  
Book value per share $ 20.79 $ 20.09
 

(a) See Note 6.

 

Xcel Energy
Paul Johnson, 612-215-4535
Vice President, Investor Relations
or
News media inquiries:
Xcel Energy Media Relations, 612-215-5300
Xcel Energy internet address: www.xcelenergy.com


Source: Business Wire (October 29, 2015 - 6:00 AM EDT)

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