Xcel Energy First Quarter 2016 Earnings Report

Xcel Energy Inc. (NYSE: XEL) today reported 2016 first quarter GAAP and ongoing earnings of $241 million, or $0.47 per share, compared with GAAP earnings of $152 million, or $0.30 per share, and ongoing earnings of $231 million, or $0.46 per share, in the same period in 2015.

Electric and gas margins rose in the first quarter of 2016 primarily due to an increase in retail electric and natural gas rates across various jurisdictions, non-fuel riders and a reduction in operating and maintenance expenses. These positive factors were partially offset by higher depreciation, interest charges, property taxes and the negative impact of weather.

“While we experienced unfavorable weather and lower than anticipated sales in the first quarter, lower O&M expenses allowed us to deliver solid quarterly results. We will continue our disciplined approach to managing costs and continue to expect to achieve ongoing earnings within our 2016 guidance range,” said Chairman, President and Chief Executive Officer Ben Fowke.

“I’m excited about the proposal we are planning to submit to construct, own and operate 600 megawatts of wind generation in Colorado. This $1 billion investment should deliver significant value to our customers and is structured to greatly enhance the local economy and the environment.”

“We continue to develop and execute our capital investment plans that will organically grow the company,” stated Fowke. “I’m looking forward to the rest of 2016 and beyond.”

Earnings Adjusted for Certain Items (Ongoing Earnings)

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

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.

The conference call also will be simultaneously broadcast and archived on Xcel Energy’s website at www.xcelenergy.com. To access the presentation, click on Investor Relations. If you are unable to participate in the live event, the call will be available for replay from 12:00 p.m. CDT on May 9 through 10:59 p.m. CDT on May 10.

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 2016 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, 2015, and subsequent securities filings, could cause actual results to differ materially from management expectations as suggested by such forward-looking information: general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures and the ability of Xcel Energy Inc. and its subsidiaries (collectively, Xcel Energy) to obtain financing on favorable terms; business conditions in the energy industry; including the risk of a slow down in the U.S. economy or delay in growth, recovery, trade, fiscal, taxation and environmental policies in areas where Xcel Energy has a financial interest; customer business conditions; actions of credit rating agencies; competitive factors including the extent and timing of the entry of additional competition in the markets served by Xcel Energy; unusual weather; effects of geopolitical events, including war and acts of terrorism; cyber security threats and data security breaches; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates or have an impact on asset operation or ownership or impose environmental compliance conditions; structures that affect the speed and degree to which competition enters the electric and natural gas markets; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; financial or regulatory accounting policies imposed by regulatory bodies; availability of cost of capital; and employee work force factors.

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

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

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

The only common equity securities that are publicly traded are common shares of Xcel Energy Inc. The diluted earnings and EPS of each subsidiary discussed below do not represent a direct legal interest in the assets and liabilities allocated to such subsidiary but rather represent a direct interest in our assets and liabilities as a whole. Ongoing diluted EPS for Xcel Energy and by subsidiary is a financial measure not recognized under GAAP. Ongoing diluted EPS is calculated by dividing the net income or loss attributable to the controlling interest of each subsidiary, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period. We use this non-GAAP financial measure to evaluate and provide details of Xcel Energy’s core earnings and underlying performance. We believe this measurement is useful to investors in facilitating period over period comparisons and evaluating or projecting financial results. This non-GAAP financial measure should not be considered as an alternative to measures calculated and reported in accordance with GAAP.

Note 1. Earnings Per Share Summary

The following table summarizes the diluted EPS for Xcel Energy:

PSCo — PSCo’s ongoing earnings increased $0.01 per share for the first quarter of 2016. Ongoing earnings were positively impacted by higher natural gas margins, primarily due to natural gas rate increases, as well as lower operating and maintenance (O&M) expenses, partially offset by higher depreciation.

NSP-Minnesota — NSP-Minnesota’s ongoing earnings increased $0.03 per share for the first quarter of 2016. Higher electric revenue, primarily due to an electric rate increase in Minnesota (interim, subject to refund), and electric non-fuel riders were partially offset by higher depreciation, property taxes and unfavorable weather. The negative impact of weather was partially mitigated by an electric weather decoupling mechanism, approved in the 2014 Minnesota Multi-Year Electric Rate Case.

SPS — SPS’ ongoing earnings were flat for the first quarter of 2016. Lower O&M expenses were offset by higher depreciation.

NSP-Wisconsin — NSP-Wisconsin’s ongoing earnings per share decreased $0.02 for the first quarter of 2016. Electric and natural gas rate increases were more than offset by higher O&M expenses and depreciation.

The following table summarizes significant components contributing to the changes in 2016 EPS compared with the same period in 2015:

Note 2. Regulated Utility Results

Estimated Impact of Temperature Changes on Regulated Earnings — Unusually hot summers or cold winters increase electric and natural gas sales, while mild weather reduces electric and natural gas sales. The estimated impact of weather on earnings is based on the number of customers, temperature variances and the amount of natural gas or electricity the average customer historically uses per degree of temperature. Accordingly, deviations in weather from normal levels can affect Xcel Energy’s financial performance.

Degree-day or Temperature-Humidity Index (THI) data is used to estimate amounts of energy required to maintain comfortable indoor temperature levels based on each day’s average temperature and humidity. Heating degree-days (HDD) is the measure of the variation in the weather based on the extent to which the average daily temperature falls below 65° Fahrenheit. Cooling degree-days (CDD) is the measure of the variation in the weather based on the extent to which the average daily temperature rises above 65° Fahrenheit. Each degree of temperature above 65° Fahrenheit is counted as one cooling degree-day, and each degree of temperature below 65° Fahrenheit is counted as one heating degree-day. In Xcel Energy’s more humid service territories, a THI is used in place of CDD, which adds a humidity factor to CDD. HDD, CDD and THI are most likely to impact the usage of Xcel Energy’s residential and commercial customers. Industrial customers are less sensitive to weather.

Normal weather conditions are defined as either the 20-year or 30-year average of actual historical weather conditions. The historical period of time used in the calculation of normal weather differs by jurisdiction, based on regulatory practice. To calculate the impact of weather on demand, a demand factor is applied to the weather impact on sales as defined above to derive the amount of demand associated with the weather impact.

There was no impact on sales in the first quarter of 2016 due to THI or CDD. The percentage decrease in normal and actual HDD is provided in the following table:

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

Sales Growth (Decline) — The following tables summarize Xcel Energy and its subsidiaries’ sales growth (decline) for actual and weather-normalized sales in 2016:

Weather-normalized Electric Growth (Decline) — Excluding Leap Day

• PSCo’s residential growth was primarily the result of an increased number of customers. The commercial and industrial (C&I) decline was mainly due to lower sales to certain large customers that primarily support the mining industry.
• NSP-Minnesota’s residential sales decrease was due to lower use per customer, partially offset by an increase in customer additions. C&I electric sales decreased as a result of lower use by large customers primarily in the manufacturing industry. The sales decline was partially reduced by an increase in the number of customers within the small customer class.
• SPS’ residential sales decline reflects lower use per customer, partially offset by customer additions. Electric sales decreased as a result of reduced activity within the oil and gas industries for the small customer class. The decline was partially reduced by customer additions in both the large and small customer classes.
• NSP-Wisconsin’s residential sales decline was primarily attributable to lower use per customer, partially offset by customer additions. C&I electric sales decreased due to lower use by small customers in the sand mining industry. The overall decrease was partially offset by large C&I sales as a result of greater use per customer in the oil and gas industries.

Weather-normalized Natural Gas Decline — Excluding Leap Day

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

Electric Margin — Electric revenues and fuel and purchased power expenses are largely impacted by the fluctuation in the price of natural gas, coal and uranium used in the generation of electricity, but as a result of the design of fuel recovery mechanisms to recover current expenses, these price fluctuations have minimal impact on electric margin. The following table details the electric revenues and margin:

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

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:

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

O&M Expenses — O&M expenses decreased $8.4 million, or 1.4 percent, for the first quarter of 2016. The decrease was mainly due to the timing of plant outages and discovery work along with lower nuclear outage and outage amortization costs, which were partially offset by higher gas survey and damage prevention costs.

Conservation and DSM Program Expenses — Conservation and DSM program expenses increased $3.6 million, or 6.7 percent, for the first quarter of 2016. The increase was primarily attributable to higher electric and gas recovery rates at NSP-Minnesota, partially offset by lower electric recovery rates at PSCo. Higher conservation and DSM program expenses are generally offset by higher revenues.

Depreciation and Amortization — Depreciation and amortization increased $46.9 million, or 17.2 percent, for the first quarter of 2016 primarily attributable to capital investments, including Pleasant Valley and Border Wind Farms, which were placed into service in late 2015.

Taxes (Other Than Income Taxes) — Taxes (other than income taxes) increased $8.7 million, or 6.4 percent, for the first quarter of 2016. The increase was due to higher property taxes primarily in Colorado and Minnesota.

Interest Charges — Interest charges increased $11.5 million, or 7.9 percent, for the first quarter of 2016. The increase was related to higher long-term debt levels, partially offset by refinancings at lower interest rates.

Income Taxes — Income tax expense increased $45.1 million for the first quarter of 2016 compared with the same period in 2015. The increase was primarily due to higher pretax earnings in 2016, partially offset by increased wind production tax credits. The ETR was 34.8 percent for the first quarter of 2016 compared with 35.5 percent for the same period in 2015. The lower ETR in 2016 is primarily due to increased wind production tax credits.

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

Following is the capital structure of Xcel Energy:

Credit Facilities — As of May 4, 2016, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available to meet liquidity needs:

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 May 4, 2016, the following represents the credit ratings assigned to Xcel Energy Inc. and its utility subsidiaries:

Xcel Energy Inc.’s and its utility subsidiaries’ 2016 financing plans reflect the following:

• In March, Xcel Energy Inc. issued $400 million of 2.4 percent senior notes due March 15, 2021 and $350 million of 3.3 percent senior notes due June 1, 2025;
• NSP-Minnesota plans to issue approximately $350 million of first mortgage bonds in the second quarter;
• PSCo plans to issue approximately $250 million of first mortgage bonds in the second quarter; and
• SPS plans to issue approximately $300 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. The request is detailed in the table below:

NSP-Minnesota also proposed a five-year alternative plan that would extend the rate plan two additional years.

In addition, NSP-Minnesota has requested the MPUC encourage parties to engage in a formal mediation type procedure as outlined by Minnesota’s rate case statute which may streamline the settlement process.

In December 2015, the MPUC approved interim rates for 2016. The MPUC deferred making a decision on incremental interim rates for 2017 and indicated that NSP-Minnesota could bring back its request in the fourth quarter of 2016.

The next steps in the procedural schedule are expected to be as follows:

• Intervenors’ direct testimony — June 14, 2016;
• Rebuttal testimony — Aug. 9, 2016;
• Surrebuttal testimony — Sept. 16, 2016;
• Settlement conference — Sept. 26, 2016;
• Evidentiary hearing — Oct. 4-7, 2016;
• Administrative Law Judge report — Feb. 21, 2017; and
• MPUC order — June 1, 2017.

NSP-Wisconsin – Wisconsin 2017 Electric and Gas Rate Case —On April 1, 2016, NSP-Wisconsin filed a request with the Public Service Commission of Wisconsin (PSCW) for an increase in annual electric rates of $17.4 million, or 2.4 percent, and an increase in natural gas rates by $4.8 million, or 3.9 percent, effective January 2017.

The electric rate request is for the limited purpose of recovering increases in (i) generation and transmission fixed charges and fuel and purchased power expenses related to the interchange agreement with NSP-Minnesota, and (ii) costs associated with forecasted average rate base of $1.188 billion in 2017.

The natural gas rate request is for the limited purpose of recovering expenses related to the ongoing environmental remediation of a former manufactured gas plant site and adjacent area in Ashland, Wis.

No changes are being requested to the capital structure or the 10.0 percent ROE authorized by the PSCW in the 2016 rate case. As part of an agreement with stakeholders to limit the size and scope of the case, NSP-Wisconsin also agreed to an earnings cap, solely for 2017, in which 100 percent of the earnings in excess of the authorized ROE would be refunded to customers.

A PSCW decision is anticipated in the fourth quarter of 2016.

PSCo – Wind Ownership Proposal — Colorado legislation allows for utilities to own up to 50 percent of new renewable resources without a competitive bidding process if the project can be developed at a reasonable price and demonstrate economic benefit. In April 2016, the Colorado Public Utilities Commission (CPUC) determined that the amount of renewable resources PSCo is eligible to develop under the state legislation is based on renewable resources added to the PSCo system since March 2007.

As a result, in May 2016, PSCo expects to submit a proposal to build, own and operate a 600 MW wind facility at a cost of approximately $1 billion, including transmission investment. PSCo believes its proposed facility can be constructed at a reasonable cost compared to the cost of similar renewable resources available on the market, and that it will be able to demonstrate to the CPUC and the independent evaluator that the proposed wind project meets the reasonable price standard. PSCo plans to request approval of its application by November 2016, in order to commence the project timely and capture the full production tax credit benefit for customers. If approved by the CPUC, the new facility is projected to go into service in December 2018.

PSCo – Natural Gas Reserves Investments — In January 2016, PSCo filed a request with the CPUC for approval of a long-term natural gas procurement and price hedging framework. Under the proposal a wholly-owned subsidiary of PSCo, PSCo Gas Reserves Company (PGRCo), will be formed to partner with Wexpro Development Company (Wexpro), a subsidiary of Questar Corporation, to acquire, develop and operate natural gas producing properties on a 50/50 joint basis, with production recovered under cost of service pricing through PSCo’s Gas Cost Adjustment. If approved, PGRCo could potentially invest up to $500 million in natural gas properties over 10 years.

The requested cost of service pricing formula for PGRCo would include all costs of property acquisition and development. The ROE would be based on PSCo’s allowed ROE, adjusted up or down a maximum of 100 basis points, based on the price of gas produced relative to market prices.

If the CPUC approves the framework, PSCo and Wexpro will seek to identify and acquire specific natural gas producing properties that would be beneficial to PSCo’s gas customers and seek CPUC approval of these specific investments.

Key dates in the procedural schedule are as follows:

• Supplemental direct testimony — June 27, 2016;
• Intervenor testimony — Aug. 26, 2016;
• Rebuttal testimony — Oct. 25, 2016;
• Hearings — Dec. 5-9, 2016;
• Statement of position — Jan. 6, 2017; and
• A CPUC decision is anticipated in 2017.

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

On May 2, 2016, SPS, the NMPRC Staff and all other parties filed a unanimous black-box stipulation that resolves all issues in the case. Under the stipulation, SPS will implement a non-fuel base rate increase of $23.5 million and a decrease in base fuel revenue of approximately $21.1 million. The decrease in base fuel revenue will be reflected in adjustments collected through the FPPCAC. The stipulation places no restriction on when SPS may file its next base rate case.

The stipulation is subject to approval by the NMPRC. A decision by the NMPRC on the settlement and implementation of final rates is expected by August 2016.

SPS – Texas 2016 Electric Rate Case — In February 2016, SPS filed a retail electric, non-fuel rate case in Texas with each of its Texas municipalities and the Public Utility Commission of Texas (PUCT) requesting an overall increase in annual base rate revenue of approximately $71.9 million, or 14.4 percent. The filing is based on a HTY ended Sept. 30, 2015, a requested ROE of 10.25 percent, an electric rate base of approximately $1.7 billion, and an equity ratio of 53.97 percent. In April 2016, SPS revised its request to $68.6 million. The modification reflects actual results for the period of Oct. 1, 2015 through Dec. 31, 2015.

The following table summarizes the revised net request:

Key dates in the procedural schedule are as follows:

• Intervenor direct testimony — Aug. 16, 2016;
• PUCT Staff direct testimony — Aug. 23, 2016;
• PUCT Staff and Intervenors’ cross-rebuttal testimony — Sept. 7, 2016;
• SPS’ Rebuttal testimony — Sept. 9, 2016; and
• Hearings — Sept. 27 - Oct. 7, 2016.

The final rates established at the end of the case will be made effective relating back to July 20, 2016. A PUCT decision is expected in the first quarter of 2017.

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

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

• Constructive outcomes in all rate case and regulatory proceedings.

• Normal weather patterns are experienced for the year.

• Weather-normalized retail electric utility sales are projected to increase approximately 0.5 percent.

• Weather normalized retail firm natural gas sales are projected to be relatively flat.

• Capital rider revenue is projected to increase by $55 million to $65 million over 2015 levels. The change in the capital rider assumption reflects the transfer of recovery of pipeline system integrity adjustment revenue from the rider to base rates per the CPUC decision in the Colorado natural gas case in late January 2016.

• The change in O&M expenses is projected to be within a range of 0 percent to 1 percent from 2015 levels.

• Depreciation expense is projected to increase approximately $200 million over 2015 levels. Approximately $20 million of the increased depreciation expense and amortization will be recovered through the RDF rider (not included in the capital rider) in Minnesota.

• Property taxes are projected to increase approximately $40 million to $50 million over 2015 levels.

• Interest expense (net of allowance for funds used during construction (AFUDC) — debt) is projected to increase $40 million to $50 million over 2015 levels.

• AFUDC — equity is projected to increase approximately $0 million to $5 million from 2015 levels.

• The ETR is projected to be approximately 34 percent to 36 percent.

• Average common stock and equivalents are projected to be approximately 509 million shares.

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

• Deliver long-term annual EPS growth of 4 percent to 6 percent, based on ongoing 2015 EPS of $2.10, which was the mid-point of Xcel Energy’s 2015 ongoing guidance range;

• Deliver annual dividend increases of 5 percent to 7 percent;

• Target a dividend payout ratio of 60 percent to 70 percent; and

• Maintain senior unsecured debt credit ratings in the BBB+ to A range.

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

Note 6. Non-GAAP Reconciliation

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

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

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

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