Xcel Energy Inc. (NYSE: XEL) today reported 2017 first quarter GAAP and ongoing earnings of $239 million, or $0.47 per share, compared with $241 million, or $0.47 per share, in the same period in 2016.

Higher electric and natural gas margins to recover infrastructure investments, along with a lower effective tax rate were offset by higher depreciation and interest expenses.

"We've made excellent progress on our steel for fuel strategy this quarter, with proposals for new wind farms that would add almost 3,400 megawatts of wind generation to our system. With wind energy at historic low prices in our operating territories, we can secure savings that will benefit customers for decades to come. Our plan offers impressive economic and environmental benefits that appeal to our customers, stakeholders and shareholders and strengthens our position as an affordable, reliable, clean energy provider," said Ben Fowke, chairman, president and CEO of Xcel Energy.

"First quarter earnings were generally in line with our internal plan, despite the unfavorable impact of warmer temperatures. We are on track to keep our operating costs flat for the full year and deliver earnings within our 2017 guidance range," concluded Fowke.

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: (877) 681-3378
International Dial-In: (719) 325-4791
Conference ID: 3101434
 

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 1:00 p.m. CDT on April 27 through 12:00 p.m. CDT on April 29.
   
Replay Numbers
US Dial-In: (888) 203-1112
International Dial-In: (719) 457-0820
Access Code: 3101434
 

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 2017 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, 2016 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; outcomes of regulatory proceedings; availability or 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 March 31
2017     2016
Operating revenues
Electric $ 2,299,060 $ 2,185,119
Natural gas 625,703 565,689
Other   21,659     21,465  
Total operating revenues 2,946,422 2,772,273
 
Operating expenses
Electric fuel and purchased power 925,221 861,852
Cost of natural gas sold and transported 365,134 312,117
Cost of sales — other 8,587 8,245
Operating and maintenance expenses 586,430 577,410
Conservation and demand side management program expenses 67,533 57,436
Depreciation and amortization 365,204 320,020
Taxes (other than income taxes)   142,094     145,323  
Total operating expenses   2,460,203     2,282,403  
 
Operating income 486,219 489,870
 
Other income, net 6,446 4,250
Equity earnings of unconsolidated subsidiaries 7,875 13,182
Allowance for funds used during construction — equity 14,313 13,113
 
Interest charges and financing costs

Interest charges — includes other financing costs of $5,858 and $6,336, respectively
165,934 156,443
Allowance for funds used during construction — debt   (7,022 )   (5,990 )
Total interest charges and financing costs 158,912 150,453
 
Income before income taxes 355,941 369,962
Income taxes   116,664     128,650  
Net income $ 239,277   $ 241,312  
 
Weighted average common shares outstanding:
Basic 508,278 508,667
Diluted 508,774 509,150
 
Earnings per average common share:
Basic $ 0.47 $ 0.47
Diluted 0.47 0.47
 
Cash dividends declared per common share $ 0.36 $ 0.34
 

XCEL ENERGY INC. AND SUBSIDIARIESNotes 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 earnings per share (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 generally accepted accounting principles (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 diluted EPS for Xcel Energy:
   
Three Months Ended March 31
Diluted Earnings (Loss) Per Share 2017     2016
Public Service Company of Colorado (PSCo) $ 0.22 $ 0.23
NSP-Minnesota 0.19 0.19
Southwestern Public Service Company (SPS) 0.05 0.04
NSP-Wisconsin 0.04 0.03
Equity earnings of unconsolidated subsidiaries   0.01     0.02  
Regulated utility 0.51 0.51
Xcel Energy Inc. and other   (0.04 )   (0.03 )
GAAP diluted EPS (a) $ 0.47   $ 0.47  
 

(a) Amounts may not add due to rounding.
 

PSCo — Earnings decreased $0.01 per share for the first quarter of 2017, primarily due to higher operating and maintenance (O&M) expenses and depreciation.

NSP-Minnesota — Earnings were flat for the first quarter of 2017. Higher electric margins driven by interim electric rates in Minnesota (subject to refund), non-fuel riders and lower O&M expenses were offset by an increase in depreciation.

SPS — Earnings increased $0.01 per share for the first quarter of 2017. Higher electric margins primarily due to rate increases in Texas and New Mexico were partially offset by increased depreciation and timing of O&M expenses.

NSP-Wisconsin — Earnings increased $0.01 per share for the first quarter of 2017, primarily attributable to higher electric margins driven by rate increases.

The following table summarizes significant components contributing to the changes in 2017 EPS compared with the same period in 2016:
 
Diluted Earnings (Loss) Per Share

Three Months Ended March 31
2016 GAAP diluted EPS $ 0.47
 
Components of change — 2017 vs. 2016
Higher electric margins 0.06
Lower effective tax rate (ETR) 0.02
Higher natural gas margins 0.01
Higher depreciation and amortization (0.05 )
Higher O&M expenses (0.01 )
Higher interest charges (0.01 )
Other, net   (0.02 )
2017 GAAP diluted EPS $ 0.47  
 

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 CDD, and each degree of temperature below 65° Fahrenheit is counted as one HDD. 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.

There was no impact on sales for the first quarter of 2017 due to THI or CDD. The percentage decrease in normal and actual HDD is provided in the following table:
       
Three Months Ended March 31
2017 vs.     2016 vs.     2017 vs.
Normal Normal 2016
HDD (14.4 )% (13.3 )% (2.2 )%
 

Weather — The following table summarizes the estimated impact of temperature variations on EPS compared with sales under normal weather conditions:
   
Three Months Ended March 31
2017 vs.     2016 vs.     2017 vs.
Normal Normal 2016
Retail electric $ (0.025 ) $ (0.016 ) $ (0.009 )
Firm natural gas   (0.018 )   (0.013 )   (0.005 )
Total (excluding decoupling) $ (0.043 ) $ (0.029 ) $ (0.014 )
Decoupling - Minnesota   0.008     0.006     0.002  
Total (adjusted for recovery from decoupling) $ (0.035 ) $ (0.023 ) $ (0.012 )
 

Sales Growth (Decline) — The following tables summarize Xcel Energy and its subsidiaries' sales growth (decline) for actual and weather-normalized sales in 2017 compared to the same period in 2016:
   
Three Months Ended March 31
PSCo     NSP-Minnesota     SPS     NSP-Wisconsin     Xcel Energy
Actual
Electric residential (a) (1.7 )% (1.0 )% (9.5 )% (1.5 )% (2.5 )%
Electric commercial and industrial (1.6 ) (1.0 ) 0.7 (0.5 ) (0.8 )
Total retail electric sales (1.6 ) (1.1 ) (1.6 ) (0.9 ) (1.3 )
Firm natural gas sales (6.1 ) 4.1 N/A 3.5 (2.2 )
 
Three Months Ended March 31
PSCo NSP-Minnesota SPS NSP-Wisconsin Xcel Energy
Weather-normalized
Electric residential (a) (0.8 )% (0.5 )% (3.4 )% (0.3 )% (1.0 )%
Electric commercial and industrial (1.6 ) (0.6 ) 0.5 (0.6 ) (0.6 )
Total retail electric sales (1.2 ) (0.6 ) (0.6 ) (0.6 ) (0.8 )
Firm natural gas sales 4.1 N/A 3.3 1.5
 
Three Months Ended March 31 (Excluding Leap Day) (b)
PSCo NSP-Minnesota SPS NSP-Wisconsin Xcel Energy
Weather-normalized - adjusted for

leap day
Electric residential (a) 0.3 % 0.6 % (2.4 )% 0.8 % 0.1 %
Electric commercial and industrial (0.5 ) 0.5 1.6 0.5 0.5
Total retail electric sales (0.2 ) 0.5 0.5 0.5 0.3
Firm natural gas sales 1.1 5.2 N/A 4.5 2.7
 

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

(b) The estimated impact of the 2016 leap day is excluded to present a more comparable year-over-year presentation. The estimated impact on the first quarter of the additional day of sales in 2016 was approximately 100 basis points.
 

Weather-normalized Electric Sales Growth (Decline) - Excluding Leap Day
  • PSCo's residential growth reflects an increased number of customers and lower use per customer. The commercial and industrial (C&I) decline was mainly due to lower use per customer, particularly to certain large customers that support the mining, oil and gas industries. The decline was partially offset by an increase in the number of C&I customers.
  • NSP-Minnesota's residential sales growth reflects customer additions, partially offset by lower use per customer. C&I sales increased mostly as a result of increased sales to large customers in manufacturing, which offset declines in oil and gas, air transportation, and services.
  • SPS' residential sales decline was primarily the result of lower use per customer. The increase in C&I sales was driven by oil and natural gas production in the Southeastern New Mexico, Permian Basin area.
  • NSP-Wisconsin's residential sales increase was primarily attributable to higher use per customer and customer additions. The C&I growth was largely due to higher use per customer and an increase in small customers in the sand mining industry. The overall increase was partially offset by a decrease in the number of large C&I customers as well as lower use per customer in the large C&I class for the oil and gas industries.

Weather-normalized Natural Gas Sales Growth - Excluding Leap Day
  • Across natural gas service territories, higher natural gas sales reflect an increase in the number of customers, partially offset by 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 March 31
(Millions of Dollars)       2017     2016
Electric revenues $ 2,299 $ 2,185
Electric fuel and purchased power   (925 )   (862 )
Electric margin $ 1,374   $ 1,323  
 

The following table summarizes the components of the changes in electric margin:
   
Three Months
Ended March 31
(Millions of Dollars) 2017 vs. 2016
Retail rate increases (a) $ 41
Non-fuel riders 12
Conservation and DSM revenues, offset by expenses 7
Decoupling (weather portion) - Minnesota 2
Wholesale transmission revenue, net of costs (7 )
Estimated impact of weather (6 )
Other, net   2  
Total increase in electric margin $ 51  
 

(a) Increase is primarily due to interim rates in Minnesota (subject to and net of estimated provision for refund) and final rates in Wisconsin, New Mexico and Texas.
 

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 March 31
(Millions of Dollars) 2017     2016
Natural gas revenues $ 626 $ 566
Cost of natural gas sold and transported   (365 )   (312 )
Natural gas margin $ 261   $ 254  
 

The following table summarizes the components of the changes in natural gas margin:
     
Three Months
Ended March 31
(Millions of Dollars)     2017 vs. 2016
Infrastructure and integrity riders $ 7
Retail sales growth, excluding weather impact 2
Estimated impact of weather (4 )
Other, net   2  
Total increase in natural gas margin $ 7  
 

O&M Expenses — O&M expenses increased $9.0 million, or 1.6 percent, for the first quarter of 2017 compared with 2016. The increase was driven by the impact of previously deferred 2016 expenses associated with the Texas 2016 electric rate case (approximately $8 million) recognized in 2017 in connection with the settlement, offset by revenue recovery.

Conservation and DSM Program Expenses — Conservation and DSM program expenses increased $10.1 million, or 17.6 percent, for the first quarter of 2017 compared with 2016. Increases were primarily attributable to both higher recovery rates, as well as additional customer participation in electric conservation programs, mostly in Minnesota. Conservation and DSM program expenses are generally recovered in our major jurisdictions concurrently through riders and base rates. Timing of recovery may not correspond to the period in which costs were incurred.

Depreciation and Amortization — Depreciation and amortization increased $45.2 million, or 14.1 percent, for the first quarter of 2017 compared with 2016. The increase was primarily attributable to capital investments, including the Courtenay Wind Farm, and a reduction of the excess depreciation reserve in Minnesota.

Allowance for Funds Used During Construction (AFUDC), Equity and Debt — AFUDC increased $2.2 million, or 11.7 percent, for the first quarter of 2017 compared with 2016. The increase was primarily attributable to higher average capital investments.

Interest Charges — Interest charges increased $9.5 million, or 6.1 percent, for the first quarter of 2017 compared with 2016. The increase was related to higher long-term debt levels to fund capital investments, partially offset by refinancings at lower interest rates.

Income Taxes Income tax expense decreased $12.0 million for the first quarter of 2017 compared with 2016. The decrease was primarily due to lower pretax earnings in 2017 and an increase in wind production tax credits in 2017. The ETR was 32.8 percent for the first quarter of 2017 compared with 34.8 percent for 2016. The lower ETR in 2017 is primarily due to the increased wind production tax credits referenced above.

The wind production tax credits flow back to customers through NSP-Minnesota's fuel clause and riders.

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

Following is the capital structure of Xcel Energy:
               
(Billions of Dollars) March 31, 2017

Percentage of Total Capitalization
Dec. 31, 2016

Percentage of Total Capitalization
Current portion of long-term debt $ 0.7 3 % $ 0.3 1 %
Short-term debt 0.6 2 0.4 2
Long-term debt   13.7 52     14.2 55  
Total debt 15.0 57 14.9 58
Common equity   11.1 43     11.0 42  
Total capitalization $ 26.1 100 % $ 25.9 100 %
 

Credit Facilities   As of April 24, 2017, 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 $ 285 $ 715 $ $ 715
PSCo 700 91 609 609
NSP-Minnesota 500 76 424 1 425
SPS 400 157 243 1 244
NSP-Wisconsin   150   46   104   1   105
Total $ 2,750 $ 655 $ 2,095 $ 3 $ 2,098
 

(a) These credit facilities expire in June 2021.

(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).

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.

As of April 24, 2017, the following represents the credit ratings assigned to Xcel Energy Inc. and its utility subsidiaries:

               
Credit Type     Company

   Moody's   

 Standard & Poor's 

    Fitch    
Senior Unsecured Debt Xcel Energy Inc. A3 BBB+ BBB+
NSP-Minnesota A2 A- A
NSP-Wisconsin A2 A- A
PSCo A3 A- A
SPS Baa1 A- BBB+
Senior Secured Debt NSP-Minnesota Aa3 A A+
NSP-Wisconsin Aa3 A A+
PSCo A1 A A+
SPS A2 A A-
Commercial Paper Xcel Energy Inc. P-2 A-2 F2
NSP-Minnesota P-1 A-2 F2
NSP-Wisconsin P-1 A-2 F2
PSCo P-2 A-2 F2
SPS P-2 A-2 F2
 

2017 Planned Financing Activity — Xcel Energy Inc. and its utility subsidiaries' 2017 financing plans reflect the following:
  • Xcel Energy Inc. plans to issue approximately $300 million of senior unsecured bonds in the fourth quarter;
  • NSP-Minnesota plans to issue approximately $600 million of first mortgage bonds in the fourth quarter;
  • NSP-Wisconsin plans to issue approximately $100 million of first mortgage bonds in the third quarter;
  • PSCo plans to issue approximately $400 million of first mortgage bonds in the second quarter; and
  • SPS plans to issue approximately $250 million of first mortgage bonds in the third quarter.

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

Note 4. Rates and Regulation

NSP-Minnesota - Minnesota 2016 Multi-Year Electric Rate Case — In November 2015, NSP-Minnesota filed a three-year electric rate case with the Minnesota Public Utilities Commission (MPUC). The rate case is based on a requested return on equity (ROE) of 10.0 percent and a 52.50 percent equity ratio. In December 2015, the MPUC approved interim rates for 2016. The request is detailed in the table below:
           
Request (Millions of Dollars) 2016 2017 2018
Rate request $ 194.6 $ 52.1 $ 50.4
Increase percentage 6.4 % 1.7 % 1.7 %
Interim request $ 163.7 $ 44.9 N/A
Rate base $ 7,800 $ 7,700 $ 7,700
 

Settlement Agreement

In August 2016, NSP-Minnesota and various parties reached a settlement which resolves all revenue requirement issues in dispute. The settlement agreement requires the approval of the MPUC.

Key terms of the settlement are listed below:

  • Four-year period covering 2016-2019;
  • Annual sales true-up;
  • ROE of 9.2 percent and an equity ratio of 52.5 percent;
  • Nuclear related costs will not be considered provisional;
  • Continued use of all existing riders, however no new riders may be utilized during the four-year term;
  • Deferral of incremental 2016 property tax expense above a fixed threshold to 2018 and 2019;
  • Four-year stay out provision for rate cases;
  • Property tax true-up mechanism for 2017-2019; and
  • Capital expenditure true-up mechanism for 2016-2019.
                   
(Millions of Dollars, incremental) 2016 2017

  2018  

  2019  
Total
Settlement revenues $ 74.99 $ 59.86 $ $ 50.12 $ 184.97
NSP-Minnesota's sales true-up   59.95       (0.20 )   59.75
Total rate impact $ 134.94 $ 59.86 $ $ 49.92   $ 244.72
 

In March 2017, the Administrative Law Judge (ALJ) recommended that the MPUC approve the settlement as it will contribute to just and reasonable rates and that no objections to the settlement are sufficient to merit rejection. The ALJ also provided recommendations for a majority of the revenue requirement issues in the event the MPUC decides to reject the settlement.

The MPUC is anticipated to hold deliberations on the rate case in May 2017 and issue an order in June 2017.

PSCo - Decoupling Filing — In July 2016, PSCo filed a request with the Colorado Public Utilities Commission (CPUC) to approve a partial decoupling mechanism for a five-year period, effective Jan. 1, 2017. The proposed decoupling adjustment would adjust annual revenues based on changes in weather normalized average use per customer for the residential and small C&I classes. The proposed decoupling mechanism is symmetric and may result in potential refunds to customers if there were an increase in average use per customer. PSCo did not request that revenue be adjusted as a result of weather related sales fluctuations.

In January 2017, the CPUC Staff and various intervenors, including the Office of Consumer Counsel (OCC), filed testimony.
  • The CPUC Staff recommended a portion of PSCo's request be approved and suggested the CPUC should lower PSCo's ROE by 30 basis points to account for lower risk, if the full proposal were approved;
  • The OCC opposed PSCo's decoupling request; and
  • Other intervening parties generally supported PSCo's proposal, but recommended various modifications, such as the use of actual sales data instead of weather-normalized sales.

A CPUC decision is expected by May 2017.

SPS - New Mexico 2016 Electric Rate Case — In November 2016, SPS filed an electric rate case with the New Mexico Public Regulatory Commission (NMPRC) seeking an increase in base rates of approximately $41.4 million, representing a total revenue increase of approximately 10.9 percent. The rate filing is based on a requested ROE of 10.1 percent, an equity ratio of 53.97 percent, an electric rate base of approximately $832 million and a future test year ending June 30, 2018.

On April 10, 2017, the hearing examiner determined that SPS' rate filing was deficient, and recommended the NMPRC extend the procedural schedule by one month and restart the suspension period once it is determined that the deficiencies are resolved. On April 19, 2017, the NMPRC ruled to dismiss SPS' rate case and required SPS to refile a future test year rate case. SPS filed a motion for reconsideration on April 21, 2017 and the NMPRC is expected to consider that motion May 10, 2017.

Note 5. Wind Development

During the first quarter of 2017, Xcel Energy announced plans to significantly expand its wind capacity by adding 1,550 megawatts (MW) of new wind generation at NSP-Minnesota and 1,230 MW at SPS. Previously, Xcel Energy received regulatory approval to build a 600 MW wind farm at PSCo.

In total, Xcel Energy has proposed adding 3,380 MW of wind capacity by the end of 2020. Xcel Energy has filed to own and place in rate base 2,750 MW of these wind projects, while 630 MW would be through purchased power agreements (PPAs). If approved by the commissions, these wind projects would qualify for 100 percent of the production tax credit (PTC) and are intended to provide billions of dollars of savings to our customers and substantial environmental benefits. Projected savings/benefits assume fuel costs and generation mix consistent with those included in various commission approved resource plans and generation need filings.

The following table details these wind projects:
                   
Project Name

Capacity (MW)

  State  

Estimated Year of Completion
Ownership/PPA Regulatory Status
Rush Creek 600 CO 2018 PSCo Approved by CPUC
Freeborn 200 MN 2020 NSP-Minnesota Pending MPUC Approval
Blazing Star 1 200 MN 2019 NSP-Minnesota Pending MPUC Approval
Blazing Star 2 200 MN 2020 NSP-Minnesota Pending MPUC Approval
Lake Benton 100 MN 2019 NSP-Minnesota Pending MPUC Approval
Foxtail 150 ND 2019 NSP-Minnesota Pending MPUC Approval
Crowned Ridge 300 SD 2019 NSP-Minnesota Pending MPUC Approval
Hale 478 TX 2019 SPS Pending PUCT & NMPRC Approval
Sagamore 522 NM 2020 SPS Pending PUCT & NMPRC Approval
Total Ownership 2,750
 
Crowned Ridge 300 SD 2019 PPA Pending MPUC Approval
Clean Energy 1 100 ND 2019 PPA Pending MPUC Approval
Bonita 230 TX 2019 PPA Pending PUCT & NMPRC Approval
Total PPA 630
 
  • NSP-Minnesota has requested that the MPUC approve the proposed wind projects by July 2017;
  • SPS has requested that the PUCT and NMPRC approve the proposed wind projects by December 2017; and
  • Xcel Energy's total capital investment for the proposed wind ownership projects is approximately $4.2 billion for 2017-2021.

Note 6. Xcel Energy Earnings Guidance and Long-Term EPS and Dividend Growth Rate Objectives

Xcel Energy 2017 Earnings Guidance — Xcel Energy's 2017 GAAP and ongoing earnings guidance is $2.25 to $2.35 per share. (a) Key assumptions related to 2017 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 increase 0 percent to 0.5 percent.
  • Weather-normalized retail firm natural gas sales are projected to increase 0 percent to 0.5 percent.
  • Capital rider revenue is projected to increase by $60 million to $70 million over 2016 levels.
  • O&M expenses are projected to be flat.
  • Depreciation expense is projected to increase approximately $165 million to $175 million over 2016 levels.
  • Property taxes are projected to increase approximately $0 million to $10 million over 2016 levels.
  • Interest expense (net of AFUDC — debt) is projected to increase $20 million to $30 million over 2016 levels.
  • AFUDC — equity is projected to increase approximately $0 million to $10 million from 2016 levels.
  • The ETR is projected to be approximately 32 percent to 34 percent.
  • Average common stock and equivalents are projected to be approximately 509 million shares.

(a) Ongoing earnings could differ from those prepared in accordance with GAAP for unplanned and/or unknown adjustments. Xcel Energy is unable to forecast if any of these items will occur or provide a quantitative reconciliation of the guidance for ongoing diluted EPS to corresponding GAAP diluted EPS.

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;

• 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.
 
XCEL ENERGY INC. AND SUBSIDIARIES
EARNINGS RELEASE SUMMARY (UNAUDITED)

(amounts in thousands, except per share data)
   
Three Months Ended March 31
2017     2016
Operating revenues:
Electric and natural gas $ 2,924,763 $ 2,750,808
Other   21,659     21,465  
Total operating revenues 2,946,422 2,772,273
 
Net income $ 239,277 $ 241,312
 
Weighted average diluted common shares outstanding 508,774 509,150
 

Components of EPS — Diluted
Regulated utility $ 0.51 $ 0.51
Xcel Energy Inc. and other costs   (0.04 )   (0.03 )
GAAP diluted EPS (a) $ 0.47   $ 0.47  
Book value per share $ 21.80 $ 21.01
 

(a) Amounts may not add due to rounding.
 

View source version on businesswire.com: http://www.businesswire.com/news/home/20170427005154/en/

Copyright Business Wire 2010

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