Exhibit 99.01
| 414 Nicollet Mall | |
| Minneapolis, MN 55401 |
May 2, 2013
XCEL ENERGY
FIRST QUARTER 2013 EARNINGS REPORT
| · | 2013 first quarter earnings per share were $0.48 compared with $0.38 per share in 2012. |
| · | Xcel Energy reaffirms 2013 earnings guidance of $1.85 to $1.95 per share. |
MINNEAPOLIS — Xcel Energy Inc. (NYSE: XEL) today reported 2013 first quarter earnings of $237 million, or $0.48 per share compared with 2012 earnings of $184 million, or $0.38 per share.
First quarter 2013 earnings were favorably impacted by increased electric and natural gas margins and lower interest expense. Winter weather in the first quarter of 2013 was not only colder than normal, but significantly different from the abnormally warm first quarter of 2012. This contrast in weather primarily drove the positive impact when comparing the two periods. The increase in electric and natural gas margins also reflects the implementation of rate increases in Colorado, South Dakota and Wisconsin, along with interim rate increases, subject to refund, in Minnesota and North Dakota. These positive drivers were partially offset by higher operating and maintenance expenses, depreciation and property taxes.
“We had a good first quarter delivering solid earnings, while maintaining quality service and reliability,” said Ben Fowke, Chairman, President and Chief Executive Officer. “We are reaffirming our 2013 earnings guidance of $1.85 to $1.95 per share, which is dependent on several key assumptions, including constructive outcomes in all rate case and regulatory proceedings.”
“We recently reached settlements in South Dakota and Texas. However, several parties filed adverse recommendations in our electric rate case in Minnesota and our natural gas rate case in Colorado. We believe our requested rate increases in both states are necessary to continue to provide excellent customer service and reliability, recover our costs of investments in our utility business, maintain strong credit ratings and access the capital markets. We will continue to work with the various parties and commissions to reach constructive outcomes,” stated 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: | (800) 762-8779 |
| International Dial-In: | (480) 629-9818 |
| Conference ID: | 4611871 |
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 2:00 p.m. CDT on May 2 through 11:59 p.m. CDT on May 3.
| Replay Numbers | |
| US Dial-In: | (800) 406-7325 |
| International Dial-In: | (303) 590-3030 |
| Access Code: | 4611871# |
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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 2013 earnings per share guidance and assumptions, are intended to be identified in this document by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made, and we do not undertake any obligation to update them to reflect changes that occur after that date. Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures and the ability of Xcel Energy Inc. and its subsidiaries (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, 2012.
For more information, contact:
| Paul Johnson, Vice President, Investor Relations and Financial Management | (612) 215-4535 |
| Jack Nielsen, Director, Investor Relations | (612) 215-4559 |
| Cindy Hoffman, Senior Investor Relations Analyst | (612) 215-4536 |
| For news media inquiries only, please call Xcel Energy Media Relations | (612) 215-5300 |
Xcel Energy internet address: www.xcelenergy.com |
This information is not given in connection with any
sale, offer for sale or offer to buy any security.
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XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME (Unaudited)
(amounts in thousands, except per share data)
| Three Months Ended March 31 | ||||||||
| 2013 | 2012 | |||||||
| Operating revenues | ||||||||
| Electric | $ | 2,092,196 | $ | 1,936,782 | ||||
| Natural gas | 669,596 | 621,035 | ||||||
| Other | 21,057 | 20,262 | ||||||
| Total operating revenues | 2,782,849 | 2,578,079 | ||||||
| Operating expenses | ||||||||
| Electric fuel and purchased power | 925,043 | 863,980 | ||||||
| Cost of natural gas sold and transported | 439,375 | 417,946 | ||||||
| Cost of sales — other | 8,411 | 7,304 | ||||||
| Operating and maintenance expenses | 529,231 | 510,684 | ||||||
| Conservation and demand side management program expenses | 64,032 | 63,707 | ||||||
| Depreciation and amortization | 248,706 | 228,672 | ||||||
| Taxes (other than income taxes) | 113,427 | 105,624 | ||||||
| Total operating expenses | 2,328,225 | 2,197,917 | ||||||
| Operating income | 454,624 | 380,162 | ||||||
| Other income, net | 3,922 | 3,737 | ||||||
| Equity earnings of unconsolidated subsidiaries | 7,577 | 7,158 | ||||||
| Allowance for funds used during construction — equity | 19,754 | 13,450 | ||||||
| Interest charges and financing costs | ||||||||
| Interest charges — includes other financing costs of $5,809 and $6,080, respectively | 139,613 | 151,830 | ||||||
| Allowance for funds used during construction — debt | (8,758 | ) | (6,607 | ) | ||||
| Total interest charges and financing costs | 130,855 | 145,223 | ||||||
| Income from continuing operations before income taxes | 355,022 | 259,284 | ||||||
| Income taxes | 118,434 | 75,515 | ||||||
| Income from continuing operations | 236,588 | 183,769 | ||||||
| (Loss) income from discontinued operations, net of tax | (18 | ) | 124 | |||||
| Net income | $ | 236,570 | $ | 183,893 | ||||
| Weighted average common shares outstanding: | ||||||||
| Basic | 489,781 | 487,360 | ||||||
| Diluted | 490,531 | 487,995 | ||||||
| Earnings per average common share: | ||||||||
| Basic | $ | 0.48 | $ | 0.38 | ||||
| Diluted | 0.48 | 0.38 | ||||||
| Cash dividends declared per common share | $ | 0.27 | $ | 0.26 | ||||
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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 | 2013 | 2012 | ||||||
| Public Service Company of Colorado (PSCo) | $ | 0.24 | $ | 0.19 | ||||
| NSP-Minnesota | 0.21 | 0.16 | ||||||
| NSP-Wisconsin | 0.04 | 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) | 0.52 | 0.41 | ||||||
| Xcel Energy Inc. and other costs | (0.04 | ) | (0.03 | ) | ||||
| GAAP diluted earnings per share | $ | 0.48 | $ | 0.38 | ||||
| (a) | See Note 2. |
PSCo — PSCo’s earnings increased $0.05 per share for the first quarter of 2013. The increase is mainly due to the electric rate increases in May 2012 and January 2013, cooler weather impacting electric and gas margins and lower interest charges. The increase is partially offset by higher depreciation expense and operating and maintenance (O&M) expenses.
NSP-Minnesota — NSP-Minnesota’s earnings increased $0.05 per share for the first quarter of 2013. The increase is primarily the result of interim electric rate increases, effective in January 2013 subject to refund, in Minnesota and North Dakota, an electric rate increase in South Dakota, cooler weather and lower interest charges. These increases were partially offset by higher O&M expenses, depreciation expense and property taxes.
NSP-Wisconsin — NSP-Wisconsin’s earnings increased $0.01 per share for the first quarter of 2013. The increase is the result of higher electric and gas rates implemented in January 2013 and the effect of cooler weather, which were partially offset by higher O&M expenses and depreciation expense.
SPS — SPS’ earnings were flat for the first quarter of 2013. Earnings were positively impacted by higher electric margin due to cooler weather, offset by higher depreciation expense, O&M expenses and interest charges.
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The following table summarizes significant components contributing to the changes in 2013 EPS compared with the same period in 2012, which are discussed in more detail later in the release:
| Diluted Earnings (Loss) Per Share | Three Months Ended March 31 | |||
| 2012 GAAP diluted earnings per share | $ | 0.38 | ||
| Components of change — 2013 vs. 2012 | ||||
| Higher electric margins | 0.12 | |||
| Higher natural gas margins | 0.03 | |||
| Lower interest charges | 0.01 | |||
| Higher AFUDC - Equity | 0.01 | |||
| Higher depreciation and amortization | (0.03 | ) | ||
| Higher operating and maintenance expenses | (0.02 | ) | ||
| Higher effective tax rate | (0.01 | ) | ||
| Higher taxes (other than income taxes) | (0.01 | ) | ||
| 2013 GAAP diluted earnings per share | $ | 0.48 | ||
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, from both an energy and demand perspective.
Degree-day or Temperature-Humidity Index (THI) data is used to estimate amounts of energy required to maintain comfortable indoor temperature levels based on each day’s average temperature and humidity. Heating degree-days (HDD) is the measure of the variation in the weather based on the extent to which the average daily temperature falls below 65° Fahrenheit, and cooling degree-days (CDD) is the measure of the variation in the weather based on the extent to which the average daily temperature rises above 65° Fahrenheit. Each degree of temperature above 65° Fahrenheit is counted as one cooling degree-day, and each degree of temperature below 65° Fahrenheit is counted as one heating degree-day. In Xcel Energy’s more humid service territories, a THI is used in place of CDD, which adds a humidity factor to CDD. HDD, CDD and THI are most likely to impact the usage of Xcel Energy’s residential and commercial customers. Industrial customers are less sensitive to weather.
Normal weather conditions are defined as either the 20-year or 30-year average of actual historical weather conditions. The historical period of time used in the calculation of normal weather differs by jurisdiction based on the time period used by the regulator in establishing estimated volumes in the rate setting process. To calculate the impact of weather on demand, a demand factor is applied to the weather impact on sales as defined above to derive the amount of demand associated with the weather impact.
There was no impact on sales in the first quarter of 2013 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 | ||||||||||||
2013 vs. Normal | 2012 vs. Normal | 2013 vs. 2012 | ||||||||||
| HDD | 3.6 | % | (18.7 | )% | 26.5 | % | ||||||
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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 | ||||||||||||
2013 vs. Normal | 2012 vs. Normal | 2013 vs. 2012 | ||||||||||
| Retail electric | $ | 0.004 | $ | (0.025 | ) | $ | 0.029 | |||||
| Firm natural gas | 0.009 | (0.021 | ) | 0.030 | ||||||||
| Total | $ | 0.013 | $ | (0.046 | ) | $ | 0.059 | |||||
In 2012, Xcel Energy refined its estimate to incorporate the impact of weather on demand charges. As a result, the estimated weather impact on earnings per share for prior periods has been adjusted for comparison purposes.
Sales Growth (Decline) — The following table summarizes Xcel Energy’s sales growth (decline) for actual and weather-normalized sales in 2013:
| Three Months Ended March 31 | ||||||||||||||||
| Three Months Ended March 31 | (Without Leap Day) | |||||||||||||||
| Actual | Weather Normalized | Actual | Weather Normalized | |||||||||||||
| Electric residential | 5.1 | % | 0.0 | % | 6.3 | % | 1.1 | |||||||||
| Electric commercial and industrial | 0.1 | (0.8 | ) | 1.2 | 0.4 | |||||||||||
| Total retail electric sales | 1.4 | (0.6 | ) | 2.6 | 0.5 | |||||||||||
| Firm natural gas sales | 21.7 | (0.4 | ) | 23.0 | 0.7 | |||||||||||
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) | 2013 | 2012 | ||||||
| Electric revenues | $ | 2,092 | $ | 1,937 | ||||
| Electric fuel and purchased power | (925 | ) | (864 | ) | ||||
| Electric margin | $ | 1,167 | $ | 1,073 | ||||
The following table summarizes the components of the changes in electric margin:
| (Millions of Dollars) | Three Months Ended March 31 2013 vs. 2012 | |||
Retail rate increases (Minnesota interim, Colorado, Wisconsin, South Dakota and North Dakota interim) | $ | 75 | ||
| Estimated impact of weather | 22 | |||
| Transmission revenue, net of costs | 11 | |||
| Retail sales increase, excluding weather impact | 1 | |||
| 2012 leap day impact | (7 | ) | ||
| Firm wholesale | (4 | ) | ||
| Other, net | (4 | ) | ||
| Total increase in electric margin | $ | 94 | ||
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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) | 2013 | 2012 | ||||||
| Natural gas revenues | $ | 670 | $ | 621 | ||||
| Cost of natural gas sold and transported | (439 | ) | (418 | ) | ||||
| $ | 231 | $ | 203 | |||||
The following table summarizes the components of the changes in natural gas margin:
| (Millions of Dollars) | Three Months Ended March 31 2013 vs. 2012 | |||
| Estimated impact of weather | $ | 22 | ||
| Conservation and demand side management program revenues (offset by expenses) | 3 | |||
| Other, net | 3 | |||
| Total increase in natural gas margin | $ | 28 | ||
O&M Expenses — O&M expenses increased $18.5 million, or 3.6 percent, for the first quarter of 2013 compared with the same period in 2012. The following table summarizes the changes in O&M expenses:
| (Millions of Dollars) | Three Months Ended March 31 2013 vs. 2012 | |||
| Employee benefits | $ | 9 | ||
| Nuclear outage amortization costs | 5 | |||
| Nuclear plant operations costs | 3 | |||
| Other, net | 2 | |||
| Total increase in O&M expenses | $ | 19 | ||
Depreciation and Amortization — Depreciation and amortization increased $20.0 million, or 8.8 percent, for the first quarter of 2013 compared with the same period in 2012. The increase is primarily attributable to normal system expansion and additional amortization as a result of regulatory outcomes.
Taxes (Other Than Income Taxes) — Taxes (other than income taxes) increased $7.8 million, or 7.4 percent, for the first quarter of 2013 compared with the same period in 2012. The increase is due to higher property taxes primarily in Minnesota. Increased property taxes in Colorado related to the electric retail business are being deferred based on the multi-year rate settlement approved by the Colorado Public Utilities Commission (CPUC) in May 2012.
Allowance for Funds Used During Construction, Equity and Debt (AFUDC) — AFUDC increased $8.5 million for the first quarter of 2013 compared with the same period in 2012. The increase is due to construction related to the Clean Air Clean Jobs Act, nuclear generation projects, the expansion of transmission facilities and other capital investments.
Interest Charges — Interest charges decreased $12.2 million, or 8.0 percent, for the first quarter of 2013 compared with the same period in 2012. The decrease is due to lower interest rates, primarily related to refinancings completed in the second half of 2012, partially offset by higher long-term debt levels to fund investments in utility operations.
Income Taxes — Income tax expense for continuing operations increased $42.9 million for the first quarter of 2013 compared with the same period in 2012. The increase in income tax expense was primarily due to higher pretax earnings in 2013 and a discrete tax benefit of approximately $15.0 million for a carryback in 2012. These were partially offset by recognition of prior year research and experimentation credits in 2013 due to the passage of the American Taxpayer Relief Act of 2012 in 2013.
The effective tax rate for continuing operations was 33.4 percent for the first quarter of 2013 compared with 29.1 percent for the same period in 2012. The lower effective tax rate for 2012 was primarily due to the carryback adjustment referenced above. The effective tax rate for the first quarter of 2012 would have been 34.9 percent without this tax benefit.
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Note 3. Xcel Energy Capital Structure, Financing and Credit Ratings
Following is the capital structure of Xcel Energy:
| (Billions of Dollars) | March 31, 2013 | Percentage of Total Capitalization | ||||||
| Short-term debt | $ | 0.4 | 2 | % | ||||
| Long-term debt | 10.6 | 52 | ||||||
| Total debt | 11.0 | 54 | ||||||
| Common equity | 9.2 | 46 | ||||||
| Total capitalization | $ | 20.2 | 100 | % | ||||
Credit Facilities — As of April 30, 2013, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available to meet its liquidity needs:
| (Millions of Dollars) | Credit Facility (a) | Drawn (b) | Available | Cash | Liquidity | |||||||||||||||
| Xcel Energy Inc. | $ | 800.0 | $ | 311.0 | $ | 489.0 | $ | 0.6 | $ | 489.6 | ||||||||||
| PSCo | 700.0 | 4.0 | 696.0 | 0.9 | 696.9 | |||||||||||||||
| NSP-Minnesota | 500.0 | 96.1 | 403.9 | 0.3 | 404.2 | |||||||||||||||
| SPS | 300.0 | - | 300.0 | 0.3 | 300.3 | |||||||||||||||
| NSP-Wisconsin | 150.0 | 19.0 | 131.0 | 0.8 | 131.8 | |||||||||||||||
| Total | $ | 2,450.0 | $ | 430.1 | $ | 2,019.9 | $ | 2.9 | $ | 2,022.8 | ||||||||||
| (a) | These credit facilities expire in July 2017. |
| (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 April 30, 2013, 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 | F2 | ||||
| NSP-Wisconsin | Senior Unsecured Debt | A3 | A- | A | ||||
| NSP-Wisconsin | Senior Secured Debt | A1 | A | A+ | ||||
| NSP-Wisconsin | Commercial Paper | P-2 | A-2 | F2 | ||||
| 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 | Baa2 | A- | BBB+ | ||||
| SPS | Senior Secured Debt | A3 | 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.
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Financing — 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.
In March 2013, PSCo issued $250 million of 2.50 percent first mortgage bonds due March 15, 2023 and $250 million of 3.95 percent first mortgage bonds due March 15, 2043.
In March 2013, Xcel Energy Inc. filed a prospectus supplement under which it may sell up to $400 million of its common stock through an at-the-market offering program. As of March 31, 2013, Xcel Energy Inc. had entered into sales transactions for 7.7 million shares of common stock with net proceeds of $223 million.
On April 15, 2013, Xcel Energy Inc. notified the trustee of its intent to redeem the entire $400 million principal amount of the 7.60 percent junior subordinated notes on May 31, 2013.
During the remainder of 2013, Xcel Energy Inc. and its utility subsidiaries anticipate issuing the following:
| · | Xcel Energy Inc. may issue approximately $400 million of unsecured bonds in the first half of 2013. |
| · | NSP-Minnesota may issue approximately $400 million of first mortgage bonds in the first half of 2013. |
| · | SPS may issue approximately $100 million of first mortgage bonds in the first half of 2013. |
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 2012 Electric Rate Case — In November 2012, NSP-Minnesota filed a request with the Minnesota Public Utilities Commission (MPUC) to increase electric rates approximately $285 million, or 10.7 percent. The rate filing was based on a 2013 forecast test year, a requested return on equity (ROE) of 10.6 percent, an average electric rate base of approximately $6.3 billion and an equity ratio of 52.56 percent. In January 2013, interim rates of approximately $251 million became effective, subject to refund.
On Feb. 28, 2013, intervening parties filed direct testimony proposing modifications to NSP-Minnesota’s rate request. The Minnesota Department of Commerce (DOC) recommended an increase of approximately $93.6 million, based on a recommended ROE of 10.24 percent and an equity ratio of 52.56 percent. Seven other intervenors filed testimony recommending various adjustments, some similar to the DOC, but no other party made a comprehensive analysis of all rate case elements. See the summary of DOC recommendations below.
On March 25, 2013, NSP-Minnesota filed rebuttal testimony and revised the requested annual revenue increase to approximately $219.7 million, or 8.23 percent, based on an ROE of 10.6 percent, a rate base of approximately $6.3 billion and an equity ratio of 52.56 percent. The updated request reflects alternate proposals in several key areas including deferral and removal of certain costs related to Sherco 3 and to Monticello, as well as removal of costs for cancellation of the Prairie Island Extended Power Uprate (EPU) project. Additional adjustments were made for compensation and benefits, amortization of pension market losses and Black Dog remediation costs. NSP-Minnesota’s updated request also reflects more recent information on property taxes and sales forecast, as well as data corrections to the original filing.
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On April 12, 2013, intervenors including the DOC, Office of Attorney General (OAG), Minnesota Chamber (MCC), Xcel Large Industrials (XLI), Commercial Group, Industrial, Commercial and Institutional Customers, and Energy Cents Coalition filed surrebuttal testimony. The DOC recommended a revenue increase of $89.6 million, based on a 9.83 percent ROE, an average electric rate base of approximately $6.1 billion and an equity ratio of 52.56 percent. The following table summarizes the effect of the DOC’s recommendations on NSP-Minnesota’s original request:
(Millions of Dollars) | DOC Direct Testimony February 2013 | DOC Surrebuttal Testimony April 2013 | ||||||
| NSP-Minnesota's original request | $ | 285 | $ | 285 | ||||
| ROE | (20 | ) | (44 | ) | ||||
| Sherco Unit 3 | (39 | ) | (44 | ) | ||||
| Reduced recovery for the nuclear plants | (9 | ) | (5 | ) | ||||
| Elimination of certain incentive compensation | (25 | ) | (20 | ) | ||||
| Increase to the sales forecast | (24 | ) | (26 | ) | ||||
| Reduced recovery of pension | (25 | ) | (25 | ) | ||||
| Employee benefits | (11 | ) | (6 | ) | ||||
| Other, net | (38 | ) | (25 | ) | ||||
| DOC recommendation | $ | 94 | $ | 90 | ||||
In its surrebuttal testimony, the OAG recommends, among other things, no recovery for the Prairie Island EPU project, stating it should have been written off in 2012 when cancellation was approved by the MPUC on Dec. 20, 2012. The DOC is also not supportive of recovery of the Prairie Island EPU cancelled plant costs, but identifies requirements for the next case if deferral is allowed. The OAG suggests pension recovery in rates exceeds benefit payout because of changes made to benefit plans and recommends correction for an alleged over-collection of funds to pay for future benefits which may never be paid out. The OAG supports the DOC in adjustments to recovery of annual incentive compensation and does not find NSP-Minnesota’s Sherco 3 proposal warranted. Other intervenors maintained their primary positions with various adjustments and recommendations for class responsibility and rate design. XLI and MCC opposed recovery of Sherco 3 costs and Monticello EPU costs.
Hearings were held in April and NSP-Minnesota revised its rate request to approximately $215.4 million to reflect updated property tax information and other adjustments. Also at the hearings, the DOC’s recommendation was revised to approximately $98.6 million, largely to reflect updated information. NSP-Minnesota has recognized a liability representing its best estimate of any refund obligation.
Next steps in the procedural schedule are expected to be as follows:
| · | Initial Brief – May 15, 2013 |
| · | Reply Brief and Findings of Fact – May 30, 2013 |
| · | Administrative Law Judge (ALJ) Report – July 3, 2013 |
| · | MPUC Order – Anticipated by September 2013 |
NSP-Minnesota – North Dakota 2012 Electric Rate Case — In December 2012, NSP-Minnesota filed a request with the North Dakota Public Service Commission (NDPSC) to increase annual retail electric rates approximately $16.9 million, or 9.25 percent. The rate filing is based on a 2013 forecast test year, a requested ROE of 10.6 percent, an electric rate base of approximately $377.6 million and an equity ratio of 52.56 percent. In January 2013, the NDPSC approved an interim electric increase of $14.7 million, effective Feb. 16, 2013, subject to refund.
Next steps in the procedural schedule are expected to be as follows:
| · | Staff/Intervenor Direct Testimony – July 12, 2013 |
| · | Rebuttal Testimony – Aug. 12, 2013 |
| · | Technical Hearings – Aug. 27-28, 2013 |
| · | Initial Briefs – Sept. 20, 2013 |
| · | Reply Briefs/Proposed Findings – October 2013 |
A final NDPSC decision on the case is expected in the fourth quarter of 2013.
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NSP-Minnesota – South Dakota 2012 Electric Rate Case — In June 2012, NSP-Minnesota filed a request with the South Dakota Public Utilities Commission (SDPUC) to increase electric rates by $19.4 million annually. The request was based on a 2011 historic test year adjusted for known and measurable changes, a requested ROE of 10.65 percent, an average rate base of $367.5 million and an equity ratio of 52.89 percent. Interim rates of $19.4 million went into effect on Jan. 1, 2013, subject to refund.
In March 2013, NSP-Minnesota and the SDPUC Staff reached a settlement agreement that provides for a base rate increase of approximately $11.6 million and the implementation of a new rider to recover an additional $3.7 million for certain capital projects and incremental property taxes. Combined, the overall revenue increase for 2013 is approximately $15.3 million, or 9.1 percent. The rider is subject to true-up for actual costs and is projected to provide incremental revenue of $2.6 million in 2014. The settlement agreement also includes a moratorium on base rate increases, effective until Jan. 1, 2015. The settlement was approved by the SDPUC on April 9, 2013. Implementation of new rates and the rider began on May 1, 2013.
NSP-Minnesota – Minnesota Resource Plan — In March 2013, the MPUC approved NSP-Minnesota’s 2011-2025 Resource Plan. The MPUC ordered that a competitive acquisition process be conducted with the goal of adding approximately 500 megawatts of natural gas-based generation to the NSP System between 2017 and 2019. In February 2013, NSP-Minnesota also issued a Request for Proposal (RFP) for up to 200 megawatts of wind generation, to the extent that cost effective opportunities can be identified. Proposals for both RFPs may be for purchase power agreements, self-build or contracts with a build-ownership transfer option. Bid proposals in response to the two RFPs were received in April 2013.
The natural gas-based generation procedural schedule is expected to be as follows:
| · | Natural gas-based generation bid evaluation and advocacy assigned to ALJ – April-October 2013 |
| · | ALJ will report to the MPUC which project should be selected – October 2013 |
| · | MPUC to make a final ruling – November 2013 |
The wind-based generation procedural schedule is expected to be as follows:
| · | Project review, selection and negotiation – April-June 2013 |
| · | Planned application for and receipt of regulatory approval – July-September 2013 |
PSCo – Colorado 2013 Gas Rate Case — In December 2012, PSCo filed a multi-year request with the CPUC to increase Colorado retail natural gas rates by $48.5 million in 2013 with subsequent step increases of $9.9 million in 2014 and $12.1 million in 2015. The request is based on a 2013 forecast test year, a 10.5 percent ROE, a rate base of $1.3 billion and an equity ratio of 56 percent. PSCo is requesting an extension of its Pipeline System Integrity Adjustment (PSIA) rider mechanism to collect the costs associated with its pipeline integrity efforts, including accelerated system renewal projects. PSCo estimates that the PSIA will increase by $26.8 million in 2014 with a subsequent step increase of $24.7 million in 2015 in addition to the proposed changes in base rate revenue. In conjunction with the multi-year base rate step increases, PSCo is proposing a stay-out provision and an earnings test through the end of 2015 with a commitment to file a rate case to implement revised rates on Jan. 1, 2016.
In January 2013, the CPUC suspended the tariff filing and set the case for hearing. In order to accommodate the procedural schedule, rates will go into effect as filed on Aug. 10, 2013, subject to refund for the difference between the filed rates and the rates approved in the final CPUC order in the case.
On April 3, 2013, four parties filed answer testimony in the natural gas case. The CPUC Staff and Office of Consumer Counsel (OCC) recommended changes to the level of integrity management costs moved from the PSIA rider to base rates. For clarity, PSCo will present base rate recommendations relative to deficiencies without the PSIA revenues to isolate the base rate impacts of the recommendations. PSCo’s 2013 deficiency based on a Forecasted Test Year (FTY) net of PSIA changes was $45 million for 2013 and the revenue deficiency was $28.3 million based on a Historic Test Year (HTY).
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The CPUC Staff recommended a rate reduction of $14.4 million, based on a HTY, an ROE of 9 percent and an equity ratio of 52 percent and other adjustments. The OCC recommended a rate increase of $0.5 million based on a HTY, an ROE of 9 percent and equity ratio of 51.03 percent and other adjustments. While the OCC did not recommend that the CPUC set rates using a FTY, they did calculate a revenue deficiency of $12.4 million for 2013. No other intervenor made ROE recommendations or specific recommendations regarding the revenue deficiency. The major adjustments to the test year proposed by the CPUC Staff and OCC are presented below.
| (Millions of Dollars) | CPUC Staff | OCC | ||||||
| PSCo deficiency based on a HTY | $ | 28.3 | $ | 28.3 | ||||
| ROE and capital structure adjustments | (20.8 | ) | (20.0 | ) | ||||
| Move to a 13 month average from year end rate base | (5.7 | ) | (3.2 | ) | ||||
| Remove pension asset | (5.9 | ) | - | |||||
| Remove incentive compensation | (3.5 | ) | (0.2 | ) | ||||
| Challenge known and measurable | - | (9.0 | ) | |||||
| Eliminate depreciation annualization | - | (1.8 | ) | |||||
| Revenue adjustments | (4.1 | ) | (1.4 | ) | ||||
| Resulting tax impacts | 1.5 | 4.7 | ||||||
| Other adjustments | (4.2 | ) | 3.1 | |||||
| Recommendation | $ | (14.4 | ) | $ | 0.5 | |||
On April 26, 2013, the CPUC Staff filed supplemental testimony recommending an additional net disallowance of $1.6 million for adjustments and corrections.
On April 29, 2013, PSCo filed rebuttal testimony and revised its requested annual rate increase to $44.8 million for 2013, $9.0 million for 2014 and $10.9 million for 2015, based on an ROE of 10.3 percent. PSCo refutes the recommendations of the CPUC Staff and the OCC to disallow known and measurable adjustments and otherwise change regulatory precedent including moving from end of year rate base to average rate base for a HTY, removing the pension asset, removing incentive compensation and moving to an imputed capital structure. PSCo agreed to recover approximately $3.5 million of revenue requirement in the PSIA, rather than through base rates and accepted the CPUC Staff’s recommendation to use deferred accounting to accommodate property tax increases.
Hearings are expected to start in May 2013 and a decision is expected in the third quarter of 2013.
PSCo – Colorado 2013 Steam Rate Case — In December 2012, PSCo filed a request to increase Colorado retail steam rates by $1.6 million in 2013 with subsequent step increases of $0.9 million in 2014 and $2.3 million in 2015. The request is based on a 2013 forecast test year, a 10.5 percent ROE, a rate base of $21 million for steam and an equity ratio of 56 percent. Final rates are expected to be effective in the third quarter of 2013.
Next steps in the procedural schedule are expected to be as follows:
| · | Staff/Intervenor Direct Testimony – Aug. 7, 2013 |
| · | Rebuttal Testimony and Reverse Cross-Answer Testimony – Aug. 28, 2013 |
| · | Evidentiary Hearings – Sept. 23-27, 2013 |
| · | Post-Hearing Statement Position – Oct. 11, 2013 |
| · | Proposed Findings – prior to Dec. 31, 2013 |
PSCo – Colorado 2011 Electric Resource Plan (ERP) and 2013 All-Source Solicitation — In January 2013, the CPUC approved with modifications the 2011 ERP. In March 2013, PSCo issued an All-Source RFP for 250 megawatts by the end of 2018. Proposals for the All-Source RFP may be for purchase power agreements, self-build or contracts with a build-ownership transfer option. PSCo also issued a separate wind RFP for purchase power agreements only. Bid proposals in response to the Wind RFP were received in April 2013.
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Next steps in the 2013 All-Source solicitation schedule are expected to be as follows:
| · | The deadline for All-Source generation bids – May 2013 |
| · | Delivery of the wind evaluation assessment report to CPUC – May 2013 |
| · | Delivery of the All-Source evaluation assessment report to CPUC – September 2013 |
| · | CPUC evaluation and regulatory approval of wind-based generation proposals – October 2013 |
| · | CPUC evaluation and regulatory approval of All-Source generation proposals – December 2013 |
Boulder, Colo. Franchise Agreement — In November 2011, two ballot measures were passed by the citizens of Boulder. The first measure increased the occupation tax to raise an additional $1.9 million annually for funding the exploration costs of forming a municipal utility and acquiring the PSCo electric distribution system in Boulder. The second measure authorized the formation and operation of a municipal light and power utility and the issuance of enterprise revenue bonds, subject to certain restrictions, including the level of initial rates and debt service coverage.
In December 2012, Boulder issued a white paper exploring opportunities for reaching its energy goals with PSCo, in lieu of condemnation. PSCo has advised Boulder that it is willing to discuss many of these opportunities. In February 2013, Boulder staff published a memorandum on the feasibility of creating a municipal utility. In April 2013, the Boulder City Council voted to proceed with the possible formation of a municipal electric utility, including considering authorization to commence legal actions needed to determine any potential rights or obligations of Boulder and means of separating from Xcel Energy’s system under state and federal law. Boulder City Council is not expected to make a final decision regarding a condemnation action until August 2013.
Should Boulder attempt to condemn PSCo facilities, PSCo would seek to obtain full compensation for the property and business taken by Boulder and for all damages resulting to PSCo and its system. PSCo would also seek appropriate compensation for stranded costs with the Federal Energy Regulatory Commission.
SPS – Texas 2012 Electric Rate Case — In November 2012, SPS filed an electric rate case in Texas with the Public Utility Commission of Texas (PUCT) for an increase in annual revenue of approximately $90.2 million. The rate filing is based on a historic twelve month test year ended June 30, 2012 (adjusted for known and measurable changes), a requested ROE of 10.65 percent, an electric rate base of $1.15 billion and an equity ratio of 52 percent.
In April 2013, the parties filed a settlement agreement in which SPS’ base rate will increase by $37 million, effective May 1, 2013, on an interim basis pending the PUCT’s approval of the settlement, and by an additional $13.8 million on Sept. 1, 2013. In addition, the settlement allows SPS to file a transmission cost recovery adjustment rider in the fourth quarter of 2013 and for those rates to become effective on an interim basis in January 2014. Under the settlement, SPS cannot file another base rate case in 2013, but there are no restrictions on SPS filing a base rate case in 2014. The PUCT is expected to act on the settlement during the second quarter of 2013.
SPS – New Mexico 2012 Electric Rate Case — In December 2012, SPS filed an electric rate case in New Mexico with the New Mexico Public Regulation Commission (NMPRC) for an increase in annual revenue of approximately $45.9 million. The rate filing is based on a 2014 forecast test year, a requested ROE of 10.65 percent, a jurisdictional electric rate base of $479.8 million and an equity ratio of 53.89 percent.
In March 2013, the NMPRC ruled that SPS’ case, as originally filed, was incomplete due to confidential exhibits to testimony and schedules being included in SPS’ direct case, and directed the hearing examiner to review SPS’ claims of confidentiality and to determine the date the filing is complete. After SPS made filings to address the NMPRC’s concern about the confidential documents, the hearing examiner determined that SPS’ application was completed on April 12, 2013. The NMPRC has suspended the tariffs for an initial nine month period beyond that date, or until Jan. 11, 2014. The NMPRC has authority to suspend the rates for an additional three months beyond the initial nine month period, or until April 11, 2014.
Next steps in the procedural schedule are expected to be as follows:
| · | Staff/Intervenor Direct Testimony – Aug. 8, 2013 |
| · | Rebuttal Testimony – Aug. 29, 2013 |
| · | Evidentiary Hearings – Sept. 16-27, 2013 |
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Note 5. Xcel Energy Earnings Guidance
Xcel Energy’s 2013 earnings guidance is $1.85 to $1.95 per share. Key assumptions related to 2013 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-adjusted retail electric utility sales are projected to grow approximately 0.5 percent. |
| · | Weather-adjusted retail firm natural gas sales are projected to decline by approximately 1 percent. |
| · | O&M expenses are projected to increase approximately 4 percent to 5 percent over 2012 levels. |
| · | Depreciation expense is projected to increase $75 million to $85 million over 2012 levels. |
| · | Property taxes are projected to increase approximately $35 million to $40 million over 2012 levels. |
| · | Interest expense (net of AFUDC — debt) is projected to decrease $30 million to $35 million from 2012 levels. |
| · | AFUDC — equity is projected to increase approximately $15 million to $20 million over 2012 levels. |
| · | The effective tax rate is projected to be approximately 34 percent to 36 percent. |
| · | Average common stock and equivalents are projected to be approximately 497 million shares. |
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XCEL ENERGY INC. AND SUBSIDIARIES
EARNINGS RELEASE SUMMARY (Unaudited)
(amounts in thousands, except per share data)
| Three Months Ended March 31 | ||||||||
| 2013 | 2012 | |||||||
| Operating revenues: | ||||||||
| Electric and natural gas revenues | $ | 2,761,792 | $ | 2,557,817 | ||||
| Other | 21,057 | 20,262 | ||||||
| Total operating revenues | 2,782,849 | 2,578,079 | ||||||
| Income from continuing operations | 236,588 | 183,769 | ||||||
| (Loss) income from discontinued operations | (18 | ) | 124 | |||||
| Net income | $ | 236,570 | $ | 183,893 | ||||
| Earnings available to common shareholders | $ | 236,570 | $ | 183,893 | ||||
| Weighted average diluted common shares outstanding | 490,531 | 487,995 | ||||||
| Components of Earnings per Share — Diluted | ||||||||
| Regulated utility — continuing operations | $ | 0.52 | $ | 0.41 | ||||
| Xcel Energy Inc. and other costs | (0.04 | ) | (0.03 | ) | ||||
| GAAP diluted earnings per share | $ | 0.48 | $ | 0.38 | ||||
| Book value per share | $ | 18.53 | $ | 17.53 | ||||
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