Xcel Energy First Quarter 2012 Earnings Report

  • 2012 first quarter earnings per share were $0.38 compared with $0.42 per share in 2011.
  • Xcel Energy expects 2012 earnings will be in the lower half of the guidance range of $1.75 to $1.85 per share.

MINNEAPOLIS--()--Xcel Energy Inc. (NYSE: XEL) today reported 2012 first quarter earnings of $184 million, or $0.38 per share compared with 2011 earnings of $204 million, or $0.42 per share.

As expected, first quarter 2012 earnings declined largely due to warmer than normal weather, which reduced electric and natural gas sales. In addition, earnings were negatively impacted by higher depreciation expense, property taxes and interest expense largely driven by continued investment in our utility business. These impacts were partially offset by a lower effective tax rate.

“During the first quarter, we experienced one of the warmest winters on record which had a significant adverse impact on our financial results,” said Ben Fowke, Chairman, President and Chief Executive Officer. “In response, we’ve implemented an extensive cost management program to offset the negative impact of the unfavorable weather as well as lower than expected weather-normalized sales. As a result, our operating and maintenance expenses were relatively flat for the quarter while our customers continue to benefit from lower fuel prices and high reliability.”

“On the regulatory front, the Minnesota Commission approved our settlement agreement in our 2011 electric rate case. In addition, we were successful in reaching a comprehensive and constructive multi-year settlement with the majority of the parties in our Colorado electric rate case, which should allow new rates to go into effect in May. The settlement establishes a first time precedent of a three-year rate plan in Colorado, providing regulatory certainty and transparency for our customers and shareholders.”

“We continue to expect 2012 earnings per share to be in the lower half of our $1.75 to $1.85 guidance range. It is important to note that delivering earnings within our guidance range is based on a series of assumptions. One of the key assumptions is constructive outcomes in all regulatory proceedings, including the Colorado Commission approval of our electric rate case settlement as proposed and the Minnesota Commission approval of our request to defer incremental property tax increases in 2012,” stated Fowke.

At 10 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:       (800) 762-8779
International Dial-In: (480) 629-9645
Conference ID: 4527264
 

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 Information. If you are unable to participate in the live event, the call will be available for replay from 2:00 p.m. CDT on April 26 through 11:59 p.m. CDT on April 27.

Replay Numbers      
US Dial-In: (800) 406-7325
International Dial-In: (303) 590-3030
Access Code: 4527264#
 

Except for the historical statements contained in this release, the matters discussed herein, including our 2012 full year earnings per share guidance and assumptions, are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made, and we do not undertake any obligation to update them to reflect changes that occur after that date. Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures and the ability of Xcel Energy Inc. and its subsidiaries (collectively, Xcel Energy) to obtain financing on favorable terms; business conditions in the energy industry, including the risk of a slow down in the U.S. economy or delay in growth recovery; trade, fiscal, taxation and environmental policies in areas where Xcel Energy 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 Nuclear Regulatory Commission; financial or regulatory accounting policies imposed by regulatory bodies; availability or cost of capital; employee work force factors; and the other risk factors listed from time to time by Xcel Energy in reports filed with the Securities and Exchange Commission (SEC), including Risk Factors in Item 1A and Exhibit 99.01 of Xcel Energy Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, 2011.

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  
2012   2011  
Operating revenues
Electric $ 1,936,782 $ 2,029,972
Natural gas 621,035 765,349
Other   20,262     21,219  
Total operating revenues

 

2,578,079

 

2,816,540

 
Operating expenses
Electric fuel and purchased power 863,980 931,828
Cost of natural gas sold and transported 417,946 543,376
Cost of sales — other 7,304 8,055
Operating and maintenance expenses 510,684 510,027
Conservation and demand side management program expenses 63,707 75,298
Depreciation and amortization 228,672 224,723
Taxes (other than income taxes)   105,624     96,570  
Total operating expenses   2,197,917     2,389,877  
 
Operating income 380,162 426,663
 
Other income, net 3,737 4,766
Equity earnings of unconsolidated subsidiaries 7,158 7,713
Allowance for funds used during construction — equity 13,450 13,244
 
Interest charges and financing costs

Interest charges — includes other financing costs of $6,080 and $5,260, respectively

151,830 144,354
Allowance for funds used during construction — debt   (6,607 )   (7,436 )
Total interest charges and financing costs 145,223 136,918
 
Income from continuing operations before income taxes 259,284 315,468
Income taxes   75,515     112,001  
Income from continuing operations 183,769 203,467
Income from discontinued operations, net of tax   124     102  
Net income 183,893 203,569
Dividend requirements on preferred stock   -     1,060  
Earnings available to common shareholders $ 183,893   $ 202,509  
 
Weighted average common shares outstanding:
Basic 487,360 483,641
Diluted 487,995 484,301
Earnings per average common share:
Basic $ 0.38 $ 0.42
Diluted 0.38 0.42
 
Cash dividends declared per common share $ 0.26 $ 0.25
 

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 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. EPS by subsidiary is a financial measure not recognized under GAAP that 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 our consolidated fully diluted EPS determined in accordance with GAAP as an indicator of operating performance.

Note 1. Earnings Per Share Summary

The following table summarizes the diluted earnings per share for Xcel Energy:

  Three Months Ended March 31
Diluted Earnings (Loss) Per Share 2012   2011
Public Service Company of Colorado (PSCo) $ 0.19 $ 0.20
NSP-Minnesota 0.16 0.19
NSP-Wisconsin 0.03 0.03
Southwestern Public Service Company (SPS) 0.02 0.02
Equity earnings of unconsolidated subsidiaries   0.01     0.01  
Regulated utility — continuing operations (a) 0.41 0.45
Xcel Energy Inc. and other costs   (0.03 )   (0.03 )
GAAP diluted earnings per share $ 0.38   $ 0.42  
 
(a)   See Note 2.
 

PSCo — PSCo earnings decreased $0.01 per share for the first quarter of 2012. The decrease is mainly due to lower electric and gas sales due to warmer weather, decreased wholesale revenue due to the expiration of a long-term wholesale power agreement with Black Hills Corp., higher depreciation expense and interest charges, partially offset by higher gas revenues, primarily due to new rates effective in September 2011.

NSP-Minnesota — NSP-Minnesota earnings decreased $0.03 per share for the first quarter of 2012. The decrease is primarily the result of warmer weather impacting electric and gas sales, differences between rates effective in the first quarter of 2012 as compared to interim rates in the first quarter of 2011, higher property taxes and higher operating and maintenance (O&M) expenses. The decreases were partially offset by a lower effective tax rate.

NSP-Wisconsin — NSP-Wisconsin earnings per share were flat for the first quarter of 2012. Higher electric and gas rates implemented in January 2012 and lower O&M expenses were offset by lower electric and gas sales due to warmer weather.

SPS — SPS earnings per share were flat for the first quarter of 2012. Higher electric margins in Texas and New Mexico, primarily due to rate increases effective in January 2012, were offset by the negative impact of warmer weather, higher depreciation expense, property taxes and interest charges.

The following table summarizes significant components contributing to the changes in the 2012 EPS compared with the same period in 2011, which are discussed in more detail later in the release.

 

Three Months

Diluted Earnings (Loss) Per Share

Ended March 31

2011 GAAP diluted earnings per share $ 0.42
 
Components of change — 2012 vs. 2011
Lower electric margins (0.03 )
Lower natural gas margins (0.02 )
Higher interest charges (0.01 )
Higher taxes (other than income taxes) (0.01 )
Lower effective tax rate 0.03
Lower conservation and DSM expenses (generally offset in revenues) 0.01
Other, net   (0.01 )
2012 GAAP diluted earnings per share $ 0.38  
 

Note 2. Regulated Utility Results — Continuing Operations

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.

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 weather sensitive.

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.

There was no impact on sales in the first quarter due to THI or CDD. The percentage increase (decrease) in normal and actual HDD is provided in the following table:

  Three Months Ended March 31

 

2012 vs.
Normal

 

2011 vs.
Normal

 

2012 vs.
2011

HDD (18.7 ) % 5.2 % (22.1 ) %
 

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

  Three Months Ended March 31

2012 vs.

 

2011 vs.

 

2012 vs.

Normal

Normal

2011

Retail electric $ (0.023 ) $ 0.007 $ (0.030 )
Firm natural gas   (0.021 )   0.007   (0.028 )
Total $ (0.044 ) $ 0.014 $ (0.058 )
 

Sales Growth (Decline) — The following table summarizes Xcel Energy’s sales growth (decline) for actual and weather-normalized sales in 2012:

        Three Months Ended March 31
Three Months Ended March 31 (Without Leap Day)
 

 

Weather

 

Weather

 

Actual

Normalized

Actual

Normalized

Electric residential (5.1 ) % 0.5

 %

(6.1 ) % (0.6 ) %
Electric commercial and industrial (0.7 ) 0.2 (1.8 ) (0.9 )
Total retail electric sales (2.0 ) 0.3 (3.1 ) (0.8 )
Firm natural gas sales (14.7 ) 1.3 (15.7 ) 0.2
 

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 March 31
(Millions of Dollars) 2012   2011
Electric revenues $ 1,937 $ 2,030
Electric fuel and purchased power   (864 )   (932 )
Electric margin $ 1,073   $ 1,098  
 

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

 

Three Months

Ended March 31,

(Millions of Dollars)

2012 vs. 2011

Estimated impact of weather $ (22 )
Firm wholesale (a) (11 )
Conservation and DSM revenue (offset by expenses) (4 )
Transmission revenue, net of costs 5
Retail rate increases (Minnesota, Texas, New Mexico, South Dakota interim, North Dakota, Wisconsin and Michigan) (b) 5
Sales mix and demand revenue 2
Conservation and DSM incentive 2
Other, net   (2 )
Total decrease in electric margin $ (25 )
 
(a)   Decrease is primarily due to the expiration of a long-term wholesale power agreement with Black Hills Corp.
 
(b) NSP-Minnesota reduced depreciation expense and revenues by approximately $8 million in the first quarter of 2012 to reflect the settlement in the Minnesota electric rate case.
 

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 March 31
(Millions of Dollars) 2012   2011
Natural gas revenues $ 621 $ 765
Cost of natural gas sold and transported   (418 )   (543 )
Natural gas margin $ 203   $ 222  
 

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

 

Three Months

Ended March 31,

(Millions of Dollars)

2012 vs. 2011

Estimated impact of weather $ (21 )
Conservation and DSM revenue (offset by expenses) (9 )
Retail rate increase (Colorado, Wisconsin) 3
Pipeline system integrity adjustment rider (Colorado) 3
Return on PSCo gas in storage 2
Conservation and DSM incentive 1
Other, net   2  
Total decrease in natural gas margin $ (19 )
 

O&M Expenses — O&M expenses increased $0.7 million, or 0.1 percent, for the first quarter of 2012, compared with the same period in 2011. The following table summarizes the changes in O&M expenses:

 

Three Months

Ended March 31,

(Millions of Dollars)

2012 vs. 2011

Higher plant generation costs $ 6
Pipeline system integrity costs 3
Lower consulting costs (3 )
Lower employee benefit expense (2 )
Other, net   (3 )
Total increase in O&M expenses $ 1  
 
  • Higher plant generation costs are attributable to a higher level of scheduled overhaul work.
  • Higher pipeline system integrity costs were for verification and testing natural gas pipeline integrity. These costs are recovered through a rider in Colorado.
  • Lower employee benefit expenses were driven by lower compensation and incentive expenses, partially offset by higher pension expense.

Conservation and DSM Program Expenses — Conservation and demand side management (DSM) program expenses decreased $11.6 million, or 15.4 percent for the first quarter of 2012, compared with the same period in 2011. The lower expense is primarily attributable to lower sales volumes and lower rider rates, as well as a change in the cost allocation formula used to account for electric conservation improvement program expenses at NSP-Minnesota. Conservation and DSM program expenses are generally recovered in our major jurisdictions concurrently through riders and base rates.

Depreciation and Amortization — Depreciation and amortization increased $3.9 million, or 1.8 percent for the first quarter of 2012, compared with the same period in 2011. This increase is primarily due to a portion of the Monticello extended power uprate going into service in May 2011 at NSP-Minnesota, the Jones Unit 3 going into service in June 2011 at SPS and normal system expansion across Xcel Energy’s service territories. The increase was partially offset by a change in depreciation lives for certain assets to reflect the settlement in the Minnesota recent electric rate case, which resulted in a reduction in depreciation expense of approximately $8 million.

Taxes (Other Than Income Taxes) — Taxes (other than income taxes) increased $9.1 million, or 9.4 percent for the first quarter of 2012, compared with the same period in 2011. The increase is primarily due to an increase in property taxes in Minnesota. NSP-Minnesota has requested to defer incremental property taxes in Minnesota, effective as of Jan. 1, 2012. However, until the Minnesota Public Utilities Commission (MPUC) rules on this issue, NSP-Minnesota will continue to expense the incremental property taxes. Assuming MPUC approval of NSP-Minnesota’s request, which is currently expected in the second quarter of 2012, NSP-Minnesota would reflect the deferral retroactive to Jan.1, 2012. For more information, see Note 4.

Allowance for Funds Used During Construction, Equity and Debt (AFUDC) — AFUDC decreased $0.6 million, or 3.0 percent for the first quarter of 2012, compared with the same period in 2011. The decrease is primarily due to lower average construction work in progress balances.

Interest Charges — Interest charges increased $7.5 million, or 5.2 percent for the first quarter of 2012, compared with the same period in 2011. The increase is due to higher long-term debt levels to fund investments in utility operations, partially offset by lower interest rates.

Income Taxes — Income tax expense for continuing operations decreased $36.5 million for the first quarter of 2012, compared with the same period in 2011. The decrease in income tax expense was primarily due to lower pretax earnings and a tax benefit associated with a carryback. The effective tax rate for continuing operations was 29.1 percent for the first quarter of 2012 compared with 35.5 percent for the same period in 2011. The lower effective tax rate for 2012 was primarily due to the completion of an analysis in the first quarter on the eligibility of certain expenses that qualified for an extended carryback beyond the typical two-year carryback period. As a result, Xcel Energy recognized a discrete tax benefit of approximately $15 million. Without this tax benefit, the effective tax rate for continuing operations for the first quarter of 2012 would have been 34.9 percent.

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

Following is the capital structure of Xcel Energy:

    Percentage  
(Billions of Dollars) of Total
  March 31, 2012 Capitalization
Current portion of long-term debt $ 1.3 7 %
Short-term debt 0.3 2
Long-term debt   8.6 46
Total debt 10.2 55
Common equity   8.5 45
Total capitalization $ 18.7 100 %
 

Financing Plans Xcel Energy issues debt and equity securities to refinance retiring maturities, reduce short-term debt, fund construction programs, infuse equity in subsidiaries, fund asset acquisitions and for other general corporate purposes. Xcel Energy Inc. and its utility subsidiaries anticipate issuing the following:

  • NSP-Minnesota may issue approximately $800 million of first mortgage bonds in the third quarter of 2012.
  • PSCo may issue approximately $750 million of first mortgage bonds in the third quarter of 2012.
  • SPS may issue approximately $100 million of first mortgage bonds in the first half of 2012.
  • NSP-Wisconsin may issue approximately $100 million of first mortgage bonds in the second half of 2012.

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

Credit Facilities — As of April 23, 2012, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available to meet its liquidity needs:

(Millions of Dollars)   Facility   Drawn(a)   Available   Cash   Liquidity   Maturity
Xcel Energy Inc. $ 800.0 $ 227.0 $ 573.0 $ 1.0 $ 574.0 March 2015
PSCo 700.0 3.0 697.0 0.2 697.2 March 2015
NSP-Minnesota 500.0 22.7 477.3 1.1 478.4 March 2015
SPS 300.0 53.0 247.0 1.1 248.1 March 2015
NSP-Wisconsin   150.0   80.0   70.0   0.7   70.7 March 2015
Total $ 2,450.0 $ 385.7 $ 2,064.3 $ 4.1 $ 2,068.4
 

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

Credit Ratings — Access to reasonably priced capital markets is dependent in part on credit and 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 April 25, 2012, 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 Baa1 BBB+ BBB+
Xcel Energy Inc. Commercial Paper P-2 A-2 F2
NSP-Minnesota Senior Unsecured Debt A3 A- A
NSP-Minnesota Senior Secured Debt A1 A A+
NSP-Minnesota Commercial Paper P-2 A-2 F1
NSP-Wisconsin Senior Unsecured Debt A3 A- A
NSP-Wisconsin Senior Secured Debt A1 A A+
NSP-Wisconsin Commercial Paper P-2 A-2 F1
PSCo Senior Unsecured Debt Baa1 A- A-
PSCo Senior Secured Debt A2 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 ratings 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.

Note 4. Rates and Regulation

NSP-Minnesota – Minnesota Electric Rate Case — In November 2010, NSP-Minnesota filed a request with the MPUC to increase electric rates in Minnesota for 2011 by approximately $150 million, or an increase of 5.62 percent, and an additional increase of $48.3 million, or 1.81 percent, in 2012. The rate filing was based on a 2011 forecast test year, a requested return on equity (ROE) of 11.25 percent, an electric rate base of $5.6 billion and an equity ratio of 52.56 percent. The MPUC approved an interim rate increase of $123 million, subject to refund, effective Jan. 2, 2011. In August 2011, NSP-Minnesota submitted supplemental testimony, revising its requested rate increase to approximately $122 million for 2011 and an additional increase of approximately $29 million in 2012. The revisions were due to delays in the Monticello nuclear plant extended power uprate.

In November 2011, NSP-Minnesota reached a settlement agreement with various parties, which resolved all financial issues and several rate design issues. The settlement agreement includes:

  • A rate increase of approximately $58 million in 2011 and an incremental rate increase of $14.8 million in 2012 based on an ROE of 10.37 percent and an equity ratio of 52.56 percent.
  • A reduction to depreciation expense and NSP-Minnesota’s rate request by $30 million.
  • The ability for NSP-Minnesota to seek deferred accounting for incremental property tax increases associated with electric and natural gas businesses in 2012.
  • The stipulation that NSP-Minnesota will not file an electric rate case prior to Nov. 1, 2012, provided that both the settlement agreement and the property tax filing are approved by the MPUC.

In February 2012, NSP-Minnesota filed to reduce the interim rate request to $72.8 million to align with the settlement agreement. On March 29, 2012, the MPUC approved the settlement and a written order is pending. As of March 31, 2012 and Dec. 31, 2011, NSP-Minnesota has recorded a provision for revenue subject to refund of approximately $78 million and $67 million, respectively, to align with the settlement agreement.

NSP-Minnesota – Minnesota Property Tax Deferral Request —As part of the settlement agreement in the Minnesota electric rate case, the settling parties acknowledged that NSP-Minnesota would be filing a petition seeking deferred accounting for 2012 property tax expense in excess of the level approved in the rate case. The settling parties waived any right to object to the petition, but reserved the right to review and comment on the petition. In December 2011, NSP-Minnesota filed the petition to request deferral of approximately $28 million of incremental 2012 property taxes that will not be recovered in base rates. The estimate of 2012 incremental property taxes has been subsequently revised to approximately $24 million.

In April 2012, the Minnesota Department of Commerce (DOC) filed comments on the petition. The DOC concluded that NSP-Minnesota had not made a reasonable case for deferred accounting and recommended that the MPUC deny NSP-Minnesota’s request to defer incremental 2012 property taxes and also opposed the proposed rider mechanism. The Xcel Large Industrials and the Minnesota Chamber of Commerce filed comments in support of the deferred accounting treatment as preferable to a rider mechanism, with the understanding that all costs will be reviewed in NSP-Minnesota’s next rate case. Until the MPUC rules on the issue, NSP-Minnesota will continue to expense the incremental property taxes. An MPUC decision is expected in the second quarter of 2012.

NSP-Minnesota – North Dakota Electric Rate Case — In December 2010, NSP-Minnesota filed a request with the North Dakota Public Service Commission (NDPSC) to increase 2011 electric rates in North Dakota by approximately $19.8 million, or an increase of 12 percent, and a step increase of $4.2 million, or 2.6 percent, in 2012. The rate filing was based on a 2011 forecast test year and included a requested ROE of 11.25 percent, an electric rate base of approximately $328 million and an equity ratio of 52.56 percent. The NDPSC approved an interim rate increase of approximately $17.4 million, subject to refund, effective Feb. 18, 2011.

In May 2011, NSP-Minnesota revised its rate request to approximately $18.0 million, or an increase of 11 percent, for 2011 and $2.4 million, or 1.4 percent, for the additional step increase in 2012.

In September 2011, NSP-Minnesota reached a settlement with the NDPSC Advocacy Staff, which provided for a rate increase of $13.7 million in 2011 and an additional step increase of $2.0 million in 2012, based on a 10.4 percent ROE and black box settlement for all other issues. To address 2012 sales coming in below forecast revenue projections, the settlement includes a true-up to 2012 non-fuel revenues plus the settlement rate increase. In February 2012, the NDPSC approved the settlement agreement.

NSP-Minnesota – South Dakota Electric Rate Case In June 2011, NSP-Minnesota filed a request with the South Dakota Public Utility Commission (SDPUC) to increase South Dakota electric rates by $14.6 million annually, effective in 2012. The proposed increase included $0.7 million in revenues currently recovered through automatic recovery mechanisms. The request is based on a 2010 historic test year adjusted for known and measurable changes, a requested ROE of 11 percent, a rate base of $323.4 million and an equity ratio of 52.48 percent. NSP-Minnesota also requested approval of a nuclear cost recovery rider to recover the actual investment cost of the Monticello nuclear plant life cycle management and extended power uprate project that is not reflected in the test year. On Jan. 2, 2012, interim rates of $12.7 million were implemented.

In April 2012, the SDPUC Staff filed their direct testimony, which recommended an ROE of approximately 9 percent (ranging from 8.5 percent to 9.5 percent) and a lower cost of debt than the request (6.02 percent compared to the original request of 6.13 percent). The Staff also recommended disallowance of the Nobles wind project costs unless the SDPUC determines there is energy value in which case the Staff’s recommendation would be to disallow a portion of the costs. NSP-Minnesota’s rebuttal testimony is due by April 27, 2012 and a final SDPUC decision is expected in the summer of 2012.

PSCo 2011 Wholesale Electric Rate Case — In February 2011, PSCo filed with the Federal Energy Regulatory Commission (FERC) to change Colorado wholesale electric rates to formula based rates with an expected annual increase of $16.1 million for 2011. The request was based on a 2011 forecast test year, a 10.9 percent ROE, a rate base of $407.4 million and an equity ratio of 57.1 percent. The formula rate would be estimated each year for the following year and then trued-up to actual costs after the conclusion of the calendar year. In September 2011, PSCo implemented an interim rate increase of $7.8 million, subject to refund.

In April 2012, PSCo filed an unopposed settlement agreement with wholesale customers for an annual rate increase of $7.8 million. The primary reasons for the decrease from the original request were a reduction to depreciation expense of $5.8 million and a lower ROE (ranging from 10.1 percent to 10.4 percent). The reduction of depreciation expense is associated with the early retirement of plants related to PSCo’s compliance with the Colorado Clean Air Clean Jobs Act (CACJA). The depreciation expense will be deferred and amortized over the original life of the plants.

PSCo 2011 Electric Rate Case In November 2011, PSCo filed a request with the Colorado Public Utilities Commission (CPUC) to increase Colorado retail electric rates by $141.9 million. The request was based on a 2012 forecast test year, a 10.75 percent ROE, an electric rate base of $5.4 billion and an equity ratio of 56 percent.

In April 2012, PSCo and various parties filed a comprehensive multi-year settlement agreement, which covers 2012 through 2014, resolving all financial issues between the signing parties. Key terms of the agreement include the following:

  • PSCo will implement an annual electric rate increase of $73 million in 2012. The rate increase will be effective on May 1, 2012, subject to refund. In addition, PSCo will implement incremental electric rate increases of $16 million on Jan. 1, 2013 and $25 million on Jan. 1, 2014. These rate increases are net of the shift of the costs from the purchased capacity cost adjustment (PCCA) and the transmission cost adjustment (TCA) clauses to base rates.
  • The settlement reflects an authorized ROE of 10 percent and an equity ratio of 56 percent.
  • PSCo will forego the opportunity allowed under the Clean Air Clean Jobs Act (CACJA) to seek additional rate mechanisms to recover approved CACJA plan costs through 2014. PSCo will instead recover the carrying costs of CACJA related expenditures through the recording of AFUDC.
  • For 2012 through 2014, incremental property taxes in excess of $76.7 million (2010-2011 historic test year property taxes) will be deferred over a three-year period with the amortization effective the first year after the deferral. To the extent that PSCo is successful in gaining the manufacturer’s sales tax refund as a result of the sales tax lawsuit currently pending in the Colorado Supreme Court, PSCo shall credit such refunds first against legal fees incurred to obtain the refund and then against the deferred property tax balances outstanding at the end of the 2014.
  • The rates that take effect include no incremental recovery of deferred costs associated with the expiration of the Black Hills contract. However, the jurisdictional allocator used to determine the increase in base rates and for all rider calculations will reflect the expiration of the Black Hills contract as of Dec. 31, 2011. The rates that would take effect also include no change in depreciation rates.
  • The signing parties agree to implement an earnings test, in which customers and shareholders will share earnings above an ROE of 10 percent. The sharing mechanism is as follows:
ROE   Shareholders   Customers
> 10.0% ≤ 10.2% 40 % 60 %
> 10.2% ≤ 10.5% 50 50
> 10.5% - 100
 
  • PSCo agrees that it will not file for an electric rate increase that would take effect prior to Jan. 1, 2015, provided that net revenue requirements increases or decreases in excess of $10 million caused by changes in tax law, government mandates, or natural disasters may be deferred or recovered through a modified rate adjustment. In the event normalized base revenues in either 2012 or 2013 are 2.0 percent below 2011 actual levels adjusted to reflect the rate increases allowed for 2012 and 2013, PSCo has the right to an additional rate adjustment in the next year for 50 percent of the shortfall. The parties acknowledge that PSCo may file an electric rate increase as early as May 1, 2014, so long as no rate increase takes effect on either an interim or permanent basis prior to Jan. 1, 2015.

Note 5. Xcel Energy Earnings Guidance

Xcel Energy’s 2012 earnings is expected to be in the lower half of the guidance range of $1.75 to $1.85 per share. Key assumptions related to earnings are detailed below:

  • Constructive outcomes in all rate case and regulatory proceedings, including the CPUC’s approval of our electric rate case settlement as proposed and the MPUC’s approval of our request to defer incremental property tax increases in 2012.
  • Normal weather patterns are experienced for the remainder of the year.
  • Weather-adjusted retail electric utility sales are projected to be relatively flat.
  • Weather-adjusted retail firm natural gas sales are projected to be relatively flat.
  • Rider revenue recovery is projected to increase approximately $35 million to $45 million over 2011 levels.
  • O&M expenses are projected to increase up to 1.0 percent over 2011 levels.
  • Depreciation expense is projected to increase $50 million to $60 million over 2011 levels.
  • Property taxes are projected to be relatively flat. This assumes the CPUC approves PSCo’s rate case settlement, which includes a provision to defer incremental 2012 property taxes in Colorado and the MPUC approves NSP-Minnesota’s request to defer incremental 2012 property taxes in Minnesota.
  • Interest expense (net of AFUDC debt) is projected to increase approximately $10 million.
  • AFUDC equity is projected to increase approximately $10 million to $20 million over 2011 levels.
  • The effective tax rate is projected to be approximately 34 percent to 35 percent.
  • Average common stock and equivalents are projected to be approximately 488 million shares.
  Three Months Ended March 31
2012   2011
Operating revenues:
Electric and natural gas revenues $ 2,557,817 $ 2,795,321
Other   20,262     21,219  
Total operating revenues 2,578,079 2,816,540
 
Income from continuing operations 183,769 203,467
Income from discontinued operations   124     102  
Net income $ 183,893   $ 203,569  
 
Earnings available to common shareholders $ 183,893 $ 202,509
Weighted average diluted common shares outstanding 487,995 484,301
 

Components of Earnings per Share — Diluted

Regulated utility — continuing operations $ 0.41 $ 0.45
Xcel Energy Inc. and other costs (0.03 )   (0.03 )
GAAP diluted earnings per share $ 0.38   $ 0.42  
 
Book value per share $ 17.53 $ 16.90

Contacts

Xcel Energy Inc.
Paul Johnson, 612-215-4535
Vice President, Investor Relations and Financial Management
or
Jack Nielsen, 612-215-4559
Director, Investor Relations
or
Cindy Hoffman, 612-215-4536
Senior Investor Relations Analyst
or
For news media inquiries only:
Xcel Energy media relations, 612-215-5300
Xcel Energy internet address: www.xcelenergy.com

Sharing

Contacts

Xcel Energy Inc.
Paul Johnson, 612-215-4535
Vice President, Investor Relations and Financial Management
or
Jack Nielsen, 612-215-4559
Director, Investor Relations
or
Cindy Hoffman, 612-215-4536
Senior Investor Relations Analyst
or
For news media inquiries only:
Xcel Energy media relations, 612-215-5300
Xcel Energy internet address: www.xcelenergy.com