# Xcel Energy Inc: Form 10-Q for the period ended Jun 30, 2024

- Company: [Xcel Energy Inc](/companies/xel.md) (CIK 72903)
- Form: 10-Q
- Filed: 2024-08-01
- Accepted by EDGAR: Aug 1, 2024, 15:38 ET
- Period: 2024-06-30
- Accession: 0000072903-24-000172
- Inline XBRL: yes
- Main document: https://www.sec.gov/Archives/edgar/data/72903/000007290324000172/xel-20240630.htm
- All documents and exhibits: https://www.sec.gov/Archives/edgar/data/72903/000007290324000172/

## Figures reported in this filing

Standardized XBRL line items for the period ended 2024-06-30.

| Line item | Period | Value | XBRL concept |
| --- | --- | ---: | --- |
| Operating income | 3 months, 2024-04-01 to 2024-06-30 | $449.0m | us-gaap:OperatingIncomeLoss |
| Operating income | 6 months, 2024-01-01 to 2024-06-30 | $1.13bn | us-gaap:OperatingIncomeLoss |
| Interest expense | 3 months, 2024-04-01 to 2024-06-30 | $319.0m | us-gaap:InterestExpense |
| Interest expense | 6 months, 2024-01-01 to 2024-06-30 | $610.0m | us-gaap:InterestExpense |
| Income tax | 3 months, 2024-04-01 to 2024-06-30 | −$88.0m | us-gaap:IncomeTaxExpenseBenefit |
| Income tax | 6 months, 2024-01-01 to 2024-06-30 | −$115.0m | us-gaap:IncomeTaxExpenseBenefit |
| Net income | 3 months, 2024-04-01 to 2024-06-30 | $302.0m | us-gaap:NetIncomeLoss |
| Net income | 6 months, 2024-01-01 to 2024-06-30 | $790.0m | us-gaap:NetIncomeLoss |
| Diluted EPS | 3 months, 2024-04-01 to 2024-06-30 | $0.54 | us-gaap:EarningsPerShareDiluted |
| Diluted EPS | 6 months, 2024-01-01 to 2024-06-30 | $1.42 | us-gaap:EarningsPerShareDiluted |
| Basic EPS | 3 months, 2024-04-01 to 2024-06-30 | $0.54 | us-gaap:EarningsPerShareBasic |
| Basic EPS | 6 months, 2024-01-01 to 2024-06-30 | $1.42 | us-gaap:EarningsPerShareBasic |
| Diluted shares (weighted) | 3 months, 2024-04-01 to 2024-06-30 | 557,000,000 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Diluted shares (weighted) | 6 months, 2024-01-01 to 2024-06-30 | 556,000,000 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Operating cash flow | 6 months, 2024-01-01 to 2024-06-30 | $2.24bn | us-gaap:NetCashProvidedByUsedInOperatingActivities |
| Capital expenditure | 6 months, 2024-01-01 to 2024-06-30 | $3.37bn | us-gaap:PaymentsToAcquireProductiveAssets |
| Dividends paid | 6 months, 2024-01-01 to 2024-06-30 | $575.0m | us-gaap:PaymentsOfDividends |
| Cash and equivalents | at 2024-06-30 | $1.60bn | us-gaap:CashAndCashEquivalentsAtCarryingValue |
| Current assets | at 2024-06-30 | $5.70bn | us-gaap:AssetsCurrent |
| Total assets | at 2024-06-30 | $67.93bn | us-gaap:Assets |
| Current liabilities | at 2024-06-30 | $5.90bn | us-gaap:LiabilitiesCurrent |
| Long-term debt | at 2024-06-30 | $28.57bn | us-gaap:LongTermDebt |
| Short-term borrowings | at 2024-06-30 | $802.0m | us-gaap:ShortTermBorrowings |
| Shareholders' equity | at 2024-06-30 | $17.95bn | us-gaap:StockholdersEquity |

## Management's discussion and analysis

As filed, 65,258 characters.

The following discussion and analysis by management focuses on those factors that had a material effect on Xcel Energy’s financial condition, results of operations and cash flows during the periods presented or are expected to have a material impact in the future. It should be read in conjunction with the accompanying unaudited consolidated financial statements and the related notes to consolidated financial statements. 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 demand for electric power and natural gas is affected by seasonal differences in the weather. In general, peak sales of electricity occur in the summer months, and peak sales of natural gas occur in the winter months. As a result, the overall operating results may fluctuate substantially on a seasonal basis. Additionally, Xcel Energy’s operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer.

### Non-GAAP Financial Measures

The following discussion includes financial information prepared in accordance with GAAP, as well as certain non-GAAP financial measures such as ongoing earnings and ongoing diluted EPS. Generally, a non-GAAP financial measure is a measure of a company’s financial performance, financial position or cash flows that adjusts measures calculated and presented in accordance with GAAP.

Xcel Energy’s management uses non-GAAP measures for financial planning and analysis, for reporting of results to the Board of Directors, in determining performance-based compensation and communicating its earnings outlook to analysts and investors. Non-GAAP financial measures are intended to supplement investors’ understanding of our performance and should not be considered alternatives for financial measures presented in accordance with GAAP. These measures are discussed in more detail below and may not be comparable to other companies’ similarly titled non-GAAP financial measures.

### Earnings Adjusted for Certain Items (Ongoing Earnings and Ongoing Diluted EPS)

GAAP diluted EPS reflects the potential dilution that could occur if securities or other agreements to issue common stock (i.e., common stock equivalents) were settled. The weighted average number of potentially dilutive shares outstanding used to calculate Xcel Energy Inc.’s diluted EPS is calculated using the treasury stock method.

Ongoing earnings reflect adjustments to GAAP earnings (net income) for certain items. Ongoing diluted EPS for Xcel Energy is calculated by dividing net income or loss, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period. Ongoing diluted EPS for each subsidiary is calculated by dividing the net income or loss for such subsidiary, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period.

We use these non-GAAP financial measures to evaluate and provide details of Xcel Energy’s core earnings and underlying performance. For instance, to present ongoing earnings and ongoing diluted earnings per share, we may adjust the related GAAP amounts for certain items that are non-recurring in nature. We believe these measurements are useful to investors to evaluate the actual and projected financial performance and contribution of our subsidiaries. These non-GAAP financial measures should not be considered as an alternative to measures calculated and reported in accordance with GAAP. For the three and six months ended June 30, 2024 and 2023, there were no such adjustments to GAAP earnings and therefore GAAP earnings equal ongoing earnings for these periods.

### Results of Operations

The only common equity securities that are publicly traded are common shares of Xcel Energy Inc. 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.

Summarized diluted EPS for Xcel Energy:

| Diluted Earnings (Loss) Per Share | Three Months Ended June 30 2024 | 2023 | Six Months Ended June 30 2024 | 2023 |
| --- | ---: | ---: | ---: | ---: |
| NSP-Minnesota | $0.24 | $0.23 | $0.61 | $0.48 |
| PSCo | 0.21 | 0.17 | 0.61 | 0.56 |
| SPS | 0.16 | 0.15 | 0.26 | 0.25 |
| NSP-Wisconsin | 0.04 | 0.05 | 0.12 | 0.13 |
| Earnings from equity method investments — WYCO | 0.01 | 0.01 | 0.02 | 0.02 |
| Regulated utility | 0.66 | 0.60 | 1.62 | 1.43 |
| Xcel Energy Inc. and Other | (0.12) | (0.08) | (0.20) | (0.15) |
| GAAP diluted EPS | $0.54 | $0.52 | $1.42 | $1.28 |

### Summary of Earnings

***Xcel Energy —*** Xcel Energy’s second quarter GAAP and ongoing diluted earnings were $0.54 per share, compared with $0.52 per share in the same period in 2023. The increase in earnings per share was primarily driven by increased recovery of infrastructure investments and warmer than normal weather, partially offset by higher depreciation, interest charges and O&M expenses. Fluctuations in electric and natural gas revenues associated with changes in fuel and purchased power and/or natural gas sold and transported generally do not significantly impact earnings (changes in costs are offset by the related variation in revenues).

***NSP-Minnesota —*** GAAP and ongoing earnings increased $0.01 per share for the second quarter and $0.13 year-to-date. Year-to-date earnings primarily reflect increased recovery of electric and natural gas infrastructure investments and lower O&M expenses, partially offset by higher depreciation.

***PSCo —*** GAAP and ongoing earnings increased $0.04 in the second quarter and $0.05 year-to-date. The year-to-date change was driven by increased recovery of electric infrastructure investments, which was partially offset by increased depreciation.

***SPS —*** GAAP and ongoing earnings increased $0.01 for the second quarter and year-to-date as regulatory rate outcomes and increased sales and demand were partially offset by increased depreciation.

***NSP-Wisconsin —*** GAAP and ongoing earnings decreased $0.01 in the second quarter and year-to-date, largely due to unfavorable weather and increased depreciation.

***Xcel Energy Inc. and Other —*** Primarily includes financing costs and interest income at the holding company and earnings from investment funds, which are accounted for as equity method investments. The decline in earnings is largely due to increased interest rates and higher debt levels.

### Changes in GAAP and Ongoing Diluted EPS

Components significantly contributing to changes in 2024 EPS compared to 2023:

| Diluted Earnings (Loss) Per Share | Three Months Ended June 30 | Six Months Ended June 30 |
| --- | ---: | ---: |
| **GAAP and ongoing diluted EPS — 2023** | **$0.52** | **$1.28** |
| Components of change - 2024 vs. 2023 |  |  |
| Electric regulatory rate outcomes (a) | 0.26 | 0.40 |
| Higher AFUDC | 0.04 | 0.08 |
| Natural gas regulatory rate outcomes (b) | 0.02 | 0.05 |
| (Higher) lower O&M expenses | (0.04) | 0.02 |
| Higher depreciation and amortization | (0.18) | (0.23) |
| Higher interest charges | (0.07) | (0.12) |
| Other, net | (0.01) | (0.06) |
| **GAAP and ongoing diluted EPS — 2024** | **$0.54** | **$1.42** |

(a) Includes the revenue impact of regulatory rate outcomes and non-fuel riders.

(b) Includes the revenue impact of natural gas regulatory rate outcomes and infrastructure and integrity riders.

### Statement of Income Analysis

The following summarizes the items that affected the individual revenue and expense items reported in the consolidated statements of income.

***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, the amount of natural gas or electricity historically used per degree of temperature and excludes any incremental related operating expenses that could result due to storm activity or vegetation management requirements.

As a result, weather deviations from normal levels can affect Xcel Energy’s financial performance. However, electric sales true-up and gas decoupling mechanism in Minnesota predominately mitigate the positive and adverse impacts of weather in that jurisdiction.

Degree-day or 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. HDD is the measure of the variation in the weather based on the extent to which the average daily temperature falls below 65° Fahrenheit. CDD is the measure of the variation in the weather based on the extent to which the average daily temperature rises above 65° Fahrenheit.

Each degree of temperature above 65° Fahrenheit is counted as one CDD, and each degree of temperature below 65° Fahrenheit is counted as one HDD. In Xcel Energy’s more humid service territories, a THI is used in place of CDD, which adds a humidity factor to CDD. HDD, CDD and THI are most likely to impact the usage of Xcel Energy’s residential and commercial customers. Industrial customers are less sensitive to weather. Typically, sales are not impacted in the first or fourth quarter due to THI or CDD.

Normal weather conditions are defined as either the 10, 20 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. Extreme weather variations, windchill and cloud cover may not be reflected in weather-normalized estimates.

Percentage increase (decrease) in normal and actual HDD, CDD and THI:

|  | Three Months Ended June 30 2024 vs. Normal | 2023 vs. Normal | 2024 vs. 2023 | Six Months Ended June 30 2024 vs. Normal | 2023 vs. Normal | 2024 vs. 2023 |
| --- | ---: | ---: | ---: | ---: | ---: | ---: |
| HDD | (21.4)% | (9.5)% | (15.3)% | (13.2)% | (0.7)% | (13.0)% |
| CDD | 36.8 | (26.3) | 84.6 | 36.5 | (27.1) | 85.3 |
| THI | (37.6) | 44.6 | (55.0) | (37.7) | 44.2 | (54.9) |

***Weather —*** Estimated impact of temperature variations on EPS compared with normal weather conditions:

|  | Three Months Ended June 30 2024 vs. Normal | 2023 vs. Normal | 2024 vs. 2023 | Six Months Ended June 30 2024 vs. Normal | 2023 vs. Normal | 2024 vs. 2023 |
| --- | ---: | ---: | ---: | ---: | ---: | ---: |
| Retail electric | $0.006 | $0.001 | $0.005 | $(0.023) | $0.003 | $(0.026) |
| Decoupling and sales true-up | 0.025 | (0.017) | 0.042 | 0.041 | (0.023) | 0.064 |
| Electric total | $0.031 | $(0.016) | $0.047 | $0.018 | $(0.020) | $0.038 |
| Firm natural gas | (0.011) | (0.003) | (0.008) | (0.038) | 0.026 | (0.064) |
| Decoupling | 0.002 | — | 0.002 | 0.019 | — | 0.019 |
| Natural gas total | $(0.009) | $(0.003) | $(0.006) | $(0.019) | $0.026 | $(0.045) |
| Total | $0.022 | $(0.019) | $0.041 | $(0.001) | $0.006 | $(0.007) |

***Sales —*** Sales growth (decline) for actual and weather-normalized sales in 2024 compared to 2023:

| Actual | Three Months Ended June 30 PSCo | NSP-Minnesota | SPS | NSP-Wisconsin | Xcel Energy |
| --- | ---: | ---: | ---: | ---: | ---: |
| Electric residential | 12.1% | (10.9)% | 11.7% | (6.2)% | 0.4% |
| Electric C&I | (0.8) | (5.8) | 6.9 | (3.4) | (0.4) |
| Total retail electric sales | 3.2 | (7.4) | 7.5 | (4.1) | (0.2) |
| Firm natural gas sales | (9.7) | (10.9) | N/A | (9.5) | (10.1) |

| Weather-Normalized | Three Months Ended June 30 PSCo | NSP-Minnesota | SPS | NSP-Wisconsin | Xcel Energy |
| --- | ---: | ---: | ---: | ---: | ---: |
| Electric residential | (0.3)% | 1.0% | (0.2)% | (1.2)% | 0.2% |
| Electric C&I | (4.1) | (3.6) | 6.2 | (2.5) | (0.8) |
| Total retail electric sales | (2.9) | (2.2) | 5.2 | (2.2) | (0.5) |
| Firm natural gas sales | (4.4) | (0.6) | N/A | (3.6) | (3.2) |

| Actual | Six Months Ended June 30 PSCo | NSP-Minnesota | SPS | NSP-Wisconsin | Xcel Energy |
| --- | ---: | ---: | ---: | ---: | ---: |
| Electric residential | 4.2% | (8.3)% | 4.2% | (6.8)% | (1.9)% |
| Electric C&I | (0.2) | (4.5) | 7.2 | (2.6) | 0.3 |
| Total retail electric sales | 1.2 | (5.7) | 6.6 | (3.8) | (0.3) |
| Firm natural gas sales | (9.3) | (13.6) | N/A | (13.4) | (10.9) |

*Weather-Normalized*

|  | Six Months Ended June 30 PSCo | NSP-Minnesota | SPS | NSP-Wisconsin | Xcel Energy |
| --- | ---: | ---: | ---: | ---: | ---: |
| Electric residential | 0.3% | —% | (1.7)% | (2.2)% | (0.3)% |
| Electric C&I | (1.5) | (2.9) | 6.8 | (2.0) | 0.4 |
| Total retail electric sales | (0.9) | (2.0) | 5.3 | (2.1) | 0.2 |
| Firm natural gas sales | 2.2 | 0.8 | N/A | (3.2) | 1.4 |

*Weather-Normalized*

|  | Six Months Ended June 30 (Leap Year Adjusted) PSCo | NSP-Minnesota | SPS | NSP-Wisconsin | Xcel Energy |
| --- | ---: | ---: | ---: | ---: | ---: |
| Electric residential | (0.3)% | (0.6)% | (2.4)% | (2.8)% | (0.9)% |
| Electric C&I | (2.1) | (3.5) | 6.2 | (2.5) | (0.1) |
| Total retail electric sales | (1.5) | (2.6) | 4.7 | (2.6) | (0.4) |
| Firm natural gas sales | 1.3 | (0.2) | N/A | (4.1) | 0.4 |

### Weather-normalized and leap-year adjusted electric sales growth (decline) — year-to-date

- PSCo — Residential sales decreased due to a 1.6% decrease in use per customer, partially offset by customer growth of 1.3%. The C&I sales decline was related to decreased use per customer, primarily in the manufacturing, information and real estate sectors.
- NSP-Minnesota — Residential sales decreased due to a 2.1% decrease in use per customer, partially offset by a 1.5% increase in customers. C&I sales declined due to decreased use per customer, largely in the manufacturing sector.
- SPS — Residential sales declined as a result of a 2.9% decrease in use per customer, partially offset by 0.5% customer growth. C&I sales increased due to higher use per customer, primarily driven by the energy sector.
- NSP-Wisconsin — Residential sales declined due to a 3.6% decrease in use per customer, partially offset by 0.8% increase in customers. C&I sales decline was associated with decreased use per customer, experienced largely in the professional services and manufacturing sectors.

***Weather-normalized and leap-year adjusted natural gas sales growth (decline) — year-to-date***

- Increase in natural gas sales was driven by residential and C&I customer growth in all jurisdictions and increased use per customer in PSCo. Overall residential and C&I customer growth was 1.1% and 0.6%, respectively.

### Electric Revenues

Electric revenues are impacted by fluctuations in the price of natural gas, coal and uranium, regulatory outcomes, market prices and seasonality. In addition, electric customers receive a credit for PTCs generated, which reduce electric revenue and income taxes.

| (Millions of Dollars) | Three Months Ended June 30, 2024 vs. 2023 | Six Months Ended June 30, 2024 vs. 2023 |
| --- | ---: | ---: |
| Recovery of lower cost of electric fuel and purchased power | $(155) | $(331) |
| Wholesale generation revenues | (13) | (31) |
| PTCs flowed back to customers (offset by lower ETR) | (3) | (12) |
| Sales and demand (a) | (25) | (10) |
| Regulatory rate outcomes (MN, CO, TX, NM, & WI) | 159 | 225 |
| Non-fuel riders | 36 | 70 |
| Conservation and demand side management (offset in expense) | 23 | 43 |
| Revenue recognition for the Texas rate case surcharge (b) | 37 | 37 |
| Estimated impact of weather (net of sales true-up) | 34 | 27 |
| Other, net | (35) | (38) |
| Total increase (decrease) | $58 | $(20) |

(a) Sales excludes weather impact, net of sales true-up mechanism in Minnesota.

(b) Recognition of revenue from the Texas rate case outcome is largely offset by recognition of previously deferred costs.

### Natural Gas Revenues

Natural gas revenues vary with changing sales, the cost of natural gas and regulatory outcomes.

| (Millions of Dollars) | Three Months Ended June 30, 2024 vs. 2023 | Six Months Ended June 30, 2024 vs. 2023 |
| --- | ---: | ---: |
| Recovery of lower cost of natural gas | $(51) | $(410) |
| Estimated impact of weather (net of decoupling) | (4) | (33) |
| Regulatory rate outcomes | 13 | 35 |
| Retail sales growth (net of decoupling) | (1) | 9 |
| Infrastructure and integrity riders | 2 | 5 |
| Other, net | 3 | 9 |
| Total decrease | $(38) | $(385) |

***Electric Fuel and Purchased Power —*** Expenses incurred for electric fuel and purchased power are impacted by fluctuations in market prices of natural gas, coal and uranium, as well as seasonality. These incurred expenses are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are largely offset in operating revenues and have minimal earnings impact.

Electric fuel and purchased power expenses decreased $175 million for the second quarter and $344 million year-to-date. The decrease is primarily due to timing of fuel recovery mechanisms and lower commodity prices.

***Cost of Natural Gas Sold and Transported —*** Expenses incurred for the cost of natural gas sold are impacted by market prices and seasonality. These costs are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are largely offset in operating revenues and have minimal earnings impact.

Natural gas sold and transported decreased $52 million for the second quarter and $413 million year-to-date. The decrease is primarily due to lower commodity prices and volumes.

### Non-Fuel Operating Expenses and Other Items

***O&M Expenses —*** O&M expenses increased $34 million for the second quarter and decreased $11 million year-to-date. The year-to-date decrease was primarily due to decreased labor and benefit costs, gain on a land sale in the first quarter and lower bad debt expenses, partially offset by recognition of previously deferred costs associated with the Texas Electric Rate Case and planned generation outages that both occurred in the second quarter, as well as increased wildfire mitigation costs.

***Depreciation and Amortization —*** Depreciation and amortization increased $138 million for the second quarter and $172 million year-to-date. The year-to-date increase was largely the result of system expansion as well as recognition of previously deferred costs and depreciation rate changes associated with the Texas Rate Case, partially offset by wind and nuclear life extensions implemented in 2023 in the Minnesota Electric Rate Case.

***Interest Charges —*** Interest charges increased $51 million for the second quarter and $89 million year-to-date, largely due to increased debt levels and higher interest rates.

***AFUDC, Equity and Debt —*** AFUDC increased $24 million for the second quarter and $46 million year-to-date, driven by increased investment in renewable and transmission projects.

### Public Utility Regulation and Other

The FERC and various state and local regulatory commissions regulate Xcel Energy Inc.’s utility subsidiaries and West Gas Interstate. Xcel Energy is subject to rate regulation by state utility regulatory agencies, which have jurisdiction with respect to the rates of electric and natural gas distribution companies in Minnesota, North Dakota, South Dakota, Wisconsin, Michigan, Colorado, New Mexico and Texas.

Rates are designed to recover plant investment, operating costs and an allowed return on investment. Our utility subsidiaries request changes in utility rates through commission filings. Changes in operating costs can affect Xcel Energy’s financial results, depending on the timing of rate cases and implementation of final rates. Other factors affecting rate filings are new investments, sales, conservation and demand side management efforts, and the cost of capital.

In addition, the regulatory commissions authorize the ROE, capital structure and depreciation rates in rate proceedings. Decisions by these regulators can significantly impact Xcel Energy’s results of operations.

Except to the extent noted below, the circumstances set forth in Public Utility Regulation included in Item 7 of Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2023 appropriately represent, in all material respects, the current status of public utility regulation and are incorporated herein by reference.

### NSP-Minnesota

### Pending and Recently Concluded Regulatory Proceedings

*2024 Minnesota Natural Gas Rate Case —* In November 2023, NSP-Minnesota filed a request with the MPUC for a natural gas rate increase of approximately $59 million, or 9.6%. The request is based on a ROE of 10.2%, a 52.5% equity ratio and a 2024 forward test year with rate base of approximately $1.27 billion. In December 2023, the MPUC approved NSP-Minnesota’s request for interim rates, subject to refund, of approximately $51 million (implemented on Jan. 1, 2024).

In June 2024, NSP-Minnesota and various parties filed an uncontested settlement, which includes the following terms:

- Natural gas rate increase of $46 million, or 7.5%.
- ROE of 9.6%.
- Equity ratio of 52.5%.
- Rate base of $1.25 billion.
- No change to Commission approved decoupling.

A MPUC decision and order is expected by the end of 2024.

*2024 North Dakota Natural Gas Rate Case —* In December 2023, NSP-Minnesota filed a request with the NDPSC seeking an increase in natural gas rates of $8.5 million (9.4%), based on a ROE of 10.20%, an equity ratio of 52.5%, 2024 test year and rate base of $168 million. In February 2024, the NDPSC approved interim rates of $8 million, effective March 1, 2024.

In June 2024, the North Dakota staff filed testimony and recommended a $6.3 million increase (7%), based on a ROE of 9.8% and a 50% equity ratio.

The procedural schedule is as follows:

- Surrebuttal testimony: Aug. 12-26, 2024
- Evidentiary hearings: Sept. 3-5, 2024

A NDPSC decision is expected by year-end.

*2022 Minnesota Electric Rate Case —* In October 2021, NSP-Minnesota filed a three-year electric rate case with the MPUC.

In July 2023, the MPUC approved a three-year rate increase of approximately $332 million for 2022-2024, based on a ROE of 9.25% and an equity ratio of 52.5%. The MPUC also approved a continuation of the sales true-up mechanism.

In November 2023, NSP-Minnesota filed an appeal of the decision to the Minnesota Court of Appeals. In June 2024, a group of Minnesota utilities filed an amicus brief supporting NSP-Minnesota’s position related to prepaid pension assets. The appeal is pending a court decision.

### Nuclear Power Operations

NSP-Minnesota owns two nuclear generating plants: the Monticello plant and the Prairie Island plant. See Note 12 to the consolidated financial statements of Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2023 for further information. The circumstances set forth in Nuclear Power Operations included in Item 7 of Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2023, appropriately represent, in all material respects, the current status of nuclear power operations.

### NSP-Wisconsin

### Pending Regulatory Proceedings

*Michigan Electric Rate Case —* In July 2024, NSP-Wisconsin filed a Michigan electric rate case, seeking a $2.9 million (16.7%) rate increase for 2025, based on a ROE of 10.0% and an equity ratio of 52%. In addition, NSP-Wisconsin proposed an Investment Recovery Mechanism which would result in increases of $2.0 million (9.8%) in 2026 and $0.8 million (3.7%) in 2027 for recovery of costs associated with distribution and generation investment. A decision is expected in the first half of 2025.

*Wisconsin 2025 Stay-Out Proposal —* In June 2024, NSP-Wisconsin filed a 2025 stay-out proposal with the PSCW. The filing proposes to offset $28 million and $3 million of the Company’s forecasted 2025 electric and natural gas revenue deficiency, respectively, by amortizing IRA deferrals, stopping a deferral related to IRA benefits ordered in a previous rate case, and deferring revenue requirement impacts of two gas capital projects. The Company expects to have a Commission decision before year-end 2024.

### NSP System

*2022 Upper Midwest IRP Resource Acquisition —* NSP-Minnesota and NSP-Wisconsin have been engaged in multiple resource acquisition processes and proceedings to meet the need identified in the approved Upper Midwest IRP.

- In the second quarter of 2023, NSP-Minnesota initiated the process with the MPUC for acquisition of 800 MW of firm dispatchable resources. In January 2024, NSP-Minnesota and other companies submitted proposed resources and filed for project approval with the MPUC. NSP-Minnesota expects a decision by the second quarter of 2025.
- In July 2023, NSP-Wisconsin issued an RFP seeking 650 MW of solar and/or solar plus storage development assets to replace the capacity from the retiring King Generating Station. NSP-Wisconsin did not accept any bids from the RFP and continues to pursue projects to meet this capacity need, including through the July 2024 RFP.
- In October 2023, NSP-Minnesota issued an RFP seeking 1,200 MW of wind assets to replace capacity and reutilize interconnection rights associated with the retiring Sherco coal facilities. The RFP closed in December 2023. NSP-Minnesota expects to file for approval of recommended projects by the fourth quarter of 2024.
- In June and July 2024, respectively, NSP-Minnesota and NSP-Wisconsin each issued an RFP collectively seeking up to 1,600 MW of wind, solar, storage or hybrid resources to interconnect to the NSP System. Among other things, the RFP will seek to reutilize interconnection rights associated with the retiring Sherco and King coal units in NSP-Minnesota. Dependent on the proposals received, NSP-Minnesota or NSP-Wisconsin plan to file for the requisite approvals of the selected resources with the MPUC and PSCW, respectively, in the second quarter of 2025.

*2024 Upper Midwest Resource Plan —* In February 2024, NSP filed its Upper Midwest Resource Plan with the MPUC which included the following key items:

- Reduced carbon emissions by more than 80%, potentially up to 88%, by 2030.
- Extends the operation of Prairie Island and Monticello through the early 2050s.
- Adds 3,600 MWs of new wind and solar resources by 2030.
- Adds 600 MWs of battery energy storage by 2030.
- Adds more than 2,200 MWs of dispatchable resources by 2030.

These proposed resources are in addition to projects already approved by the MPUC. NSP-Minnesota anticipates a MPUC decision in 2025 and will file related RFPs upon approval.

### PSCo

### Pending and Recently Concluded Regulatory Proceedings

*Colorado Natural Gas Rate Case —* In January 2024, PSCo filed a request with the CPUC seeking an increase to retail natural gas rates of $171 million (9.5%). The request is based on a 10.25% ROE, an equity ratio of 55%, a 2023 test year and a $4.2 billion retail rate base which includes projected capital additions through Dec. 31, 2023. PSCo has requested a proposed effective date of Nov. 1, 2024.

PSCo has proposed to defer collection of the increased rates until Feb. 15, 2025 (following expiration of the rider to recover Winter Storm Uri costs) to mitigate customer bill impacts, with revenues for the deferred period collected over a 12-month period beginning on that date.

In July 2024, three intervenors filed testimony, with Staff and the UCA filing comprehensive testimony. Staff and UCA opposed the deferral of collections until Feb. 15, 2025, instead proposing Nov. 1, 2024 as the effective date for new rates.

Proposed modifications:

| (Millions of Dollars) | Staff |  | UCA |
| --- | ---: | --- | ---: |
| **PSCo Direct Testimony** | $171 |  | $171 |
| **Recommended adjustments:** |  |  |  |
| ROE | (40) |  | (31) |
| Capital structure and cost of capital | (27) | (a) | (14) |
| Test year adjustments to reflect average vs. year-end balances | (19) |  | (17) |
| Capital adjustments (subject to separate review) | (3) |  | (1) |
| Depreciation expense | 15 |  | — |
| Other, net | (4) |  | (17) |
| **Total adjustments** | (78) |  | (80) |
| **Proposed revenue change** | $93 |  | $91 |
| ROE | 8.89% |  | 9.20% |
| Equity ratio | 52% |  | 51.4% |
| Test Year | Dec 2023 |  | Dec 2023 |
| Rate Base Convention | 13 month |  | 13 month |

(a) Revised estimate.

Procedural schedule:

- Rebuttal testimony: Aug. 15, 2024
- Settlement deadline: Aug. 27, 2024
- Evidentiary hearing: Sept. 4-12, 2024
- Statement of position: Sept. 26, 2024

A CPUC decision is expected in the fourth quarter of 2024.

*Colorado Resource Plan —* In December 2023, the CPUC approved a portfolio of 5,835 MW, which includes approximately 3,100 MW of company owned resources and 2,700 MW of PPAs.

In December 2023, the CPUC approved two PIMs associated with the generation projects in the portfolio, including a PIM related to capital construction costs and another related to ongoing levelized energy costs. These PIMs will be further defined in related proceedings throughout 2024.

PSCo filed or expects to file generation and transmission certificates of public convenience and necessity throughout 2024.

PSCo will file an interim resource plan, also referred to as the Just Transition Solicitation, by Oct. 15, 2024. The filing deadline was extended to Oct. 15, 2024 to allow for additional time to assess the impact of supply chain issues and solar tariffs on the Colorado Resource Plan portfolio.

*Transportation Electrification Plan —* In April 2024, the CPUC approved PSCo’s TEP with modification, including a three-year budget of $264 million and continued cost recovery through the TEP rider.

*Wildfire Mitigation Plan —* In June 2024, PSCo filed an Updated Wildfire Mitigation Plan (the Plan) and request for recovery of costs covering the years 2025 to 2027 with the CPUC. The estimated total cost for this plan is approximately $1.9 billion. A CPUC decision is expected in early 2025.

The Plan is a key component of keeping our customers and communities safe while providing reliable and affordable electric service. The Plan integrates industry experience; incorporates evolving risk assessment methodologies; adds new technology; and expands the scope, pace and scale of our work to reduce wildfire risk in a comprehensive and efficient manner under four core programs that include the following:

- Situational awareness – Meteorology, area risk mapping and modeling, artificial intelligence cameras and continuous monitoring.
- Operational mitigations – Enhanced powerline safety settings and PSPS.
- System resiliency – Asset assessment and remediations, pole replacements, line rebuilds, targeted undergrounding and vegetation management.
- Customer support – Coordination and real-time data sharing with customers and other stakeholders and PSPS resiliency rebates.

Total capital investments and O&M expenses associated with the proposed plan are estimated at the following:

| (Millions of Dollars) Capital investments | 2025 | 2026 | 2027 | Total |
| --- | ---: | ---: | ---: | ---: |
| Situational awareness | $24 | $17 | $10 | $51 |
| Operational mitigations | 58 | 66 | 83 | 207 |
| System resiliency | 368 | 411 | 565 | 1,344 |
| **Total capital investments** | $450 | $494 | $658 | $1,602 |
| **O&M expenses** |  |  |  |  |
| Situational awareness | $9 | $10 | $10 | $29 |
| Operational mitigations | 3 | 3 | 4 | 10 |
| System resiliency | 44 | 69 | 77 | 190 |
| Customer support | 7 | 8 | 9 | 24 |
| **Total O&M expenses** | 63 | 90 | 100 | 253 |
| **Total expenditures** | $513 | $584 | $758 | $1,855 |

*CPUC Proactive Line De-Energization Investigation —* In April 2024, PSCo proactively de-energized certain lines in Colorado due to winds that were over 90 MPH to reduce potential wildfire risk.

In May 2024, the CPUC held sessions to hear public comments and Commissioner Information Meetings on the impacts of the power shutoffs. PSCo has provided responses to CPUC information requests and will continue to respond to requests throughout 2024 as the investigation continues.

*Clean Heat Plan —* In August of 2023, PSCo filed a Clean Heat Plan to reduce natural gas local distribution company greenhouse gas emissions. PSCo proposed a diversified portfolio of electrification, efficiency and lower-carbon gas options that would create an emissions reduction pathway through 2028 consistent with achieving a 2030 target reduction of 22 percent.

In June 2024, the CPUC approved a portfolio weighted predominantly toward electrification and efficiency programs, based on a budget of $441 million through 2027. The CPUC’s approval included rider cost recovery. The CPUC directed PSCo to file the next Clean Heat Plan in 2026.

*Colorado Senate Bill 23-291 —* In May 2023, Colorado Senate Bill 23-291 was signed into law. The bill includes a number of topics including natural gas and electric fuel incentive mechanisms, natural gas planning rules, regulatory filing requirements, and non-recovery of certain expenses (e.g., certain organizational or membership dues, tax penalties or fines).

In November 2023, the CPUC approved PSCo’s natural gas price risk plan to manage customer bill volatility from commodity price changes, establishing upper and lower limits for changes in the GCA rate. As a result, costs above the upper limit are deferred for future recovery, with interest, and costs below the lower limit are deferred as a reserve against future cost increases.

The legislation also calls for the CPUC to adopt rules to establish fuel cost mechanisms to align the financial incentives of a utility with the interests of the utility’s customers by Jan. 1, 2025. The CPUC issued a written notice of the proposed rule in the second quarter of 2024 and held a hearing on comments in July 2024. A CPUC decision and final rule is expected later in 2024. The Commission's proposed rules for electric utilities are also expected later in 2024.

*Colorado Senate Bill 24-218 —* In May 2024, Colorado Senate Bill 24-218 was signed into law. The bill includes a suite of policy changes to accelerate investment in electric distribution, including a framework to develop distribution planning and performance requirements and the opportunity for current cost recovery for many distribution investments. In July 2024, the CPUC approved PSCo’s request to collect $17 million through a rider, over the remainder of 2024, subject to true-up, associated with forecasted capital investments covered by the new legislation.

*Cabin Creek Prudency Review —* In 2015, the CPUC granted a CPCN for an $88 million upgrade project to renew the FERC operating license and increase the generating and storage capacity of the Cabin Creek hydroelectric storage facility, which anticipated project completion in 2020. Due to significant and unforeseen challenges, the project was not completed until 2023 and cost approximately $110 million. In July 2024, PSCo filed a prudency review for the upgrade project, which reviews the project’s timelines, costs, benefits and challenges. A procedural schedule is expected in the third quarter of 2024 with a final CPUC decision in 2025.

### SPS

### Pending and Recently Concluded Regulatory Proceedings

*2023 Texas Electric Rate Case —* In 2023, SPS filed an electric rate case with the PUCT seeking an increase in base rate revenue of $158 million (14%). Interim rates went into effect on Feb. 1, 2024. In April 2024, the PUCT approved a black box settlement between SPS and intervening parties, which reflect the following terms:

- A base rate increase of $65 million effective back to July 13, 2023.
- A 9.55% ROE, a 54.51% equity ratio and a 7.11% WACC for purposes of calculating SPS’ AFUDC and in other proceedings filed before the PUCT where a stated WACC is required.
- The reflection in rates of the retirement of Tolk Generation Station from 2034 to 2028.
- Establishment of a rate rider of approximately $18 million to be recovered over a three-year period for various deferred expenses.

In July 2024, SPS filed to surcharge the final under-recovered amount, estimated to be $37 million. This will be largely offset by previously deferred costs including depreciation, O&M, and taxes other than income tax.

*2022 All-Source RFP —* In July 2023, SPS filed for approval of a CPCN for a recommended generation portfolio, which includes 418 MW of self-build solar projects and a 36 MW battery. The NMPRC approved the projects in May 2024. In July 2024, the PUCT approved the solar projects and denied the battery project. The PUCT’s approval included minimum production and PTC guarantees.

The second portion of the portfolio includes a November 2023 filing for the approval of PPAs including 48 MW of battery energy storage and 230 MW of existing gas generation. The NMPRC approved the PPA agreements in June and a PUCT decision is expected in the fourth quarter of 2024.

*New Mexico Resource Plan (IRP) —* In October 2023, SPS filed its IRP with the NMPRC, which supports projected load growth and increasing reliability requirements, and secures replacement energy and capacity for retiring resources. SPS’ initial IRP modeling projected resource needs ranging from approximately 5,300 MW to 10,200 MW by 2030. In February 2024, the NMPRC accepted the IRP.

In July 2024, SPS issued a RFP, seeking approximately 3,000 MW of accredited generation capacity by 2030. The total capacity to be added to the system is expected to align with the approximate range identified in the SPS IRP, depending on the types of resources proposed in the RFP and their accredited capacity factors.

The RFP will be evaluated in the first quarter of 2025. SPS is expected to file for a certificate of need for the recommended portfolio in the summer of 2025. The Texas and New Mexico Commissions are expected to rule on the recommended portfolio in 2026.

*Texas DCRF —* In May 2024, SPS filed for a DCRF to recover $13 million through a rider for distribution capital investment placed in service for the year ended December 31, 2023. SPS’ requested DCRF rates went into effect in late July 2024.

### Other

### Supply Chain

Xcel Energy’s ability to meet customer energy requirements, execute our capital expenditure program and respond to storm-related disruptions are dependent on maintaining an efficient supply chain. Manufacturing processes have experienced disruptions related to scarcity of certain raw materials and interruptions in production and shipping. These disruptions have been further exacerbated by inflationary pressures, labor shortages and the impact of international conflicts/issues. Xcel Energy continues to monitor the situation as it remains fluid and seeks to mitigate the impacts by securing alternative suppliers, modifying design standards, and adjusting the timing of work.

Large global demand for energy-related infrastructure (renewables and gas generation, data centers, etc.) has stretched equipment supply chains, extended delivery dates and increased prices for items like combustion turbines, transformers and other large electrical equipment. The labor market for skilled engineering and construction resources to build renewables and gas generation has also been strained, impacting cost and availability.

#### Tariffs and Trade Complaints

In August 2023, the U.S. Department of Commerce completed its anti-circumvention investigation and concluded that CSPV solar panels and cells imported from Malaysia, Vietnam, Thailand, and Cambodia would be subject to incremental tariffs ranging from 50% to 250%. These countries account for more than 80% of CSPV panel imports.

An interim stay on tariffs remained in effect until June 2024 and many significant solar projects have resumed with modified costs and projected in-service dates, including the Sherco Solar facility in Minnesota and certain PPAs in PSCo.

In April 2024, the American Alliance for Solar Manufacturing Trade Committee filed a petition related to new anti-dumping and countervailing duty cases targeting solar products from Cambodia, Malaysia, Thailand and Vietnam with the United States Department of Commerce and the United States International Trade Commission.

In May 2024, the U.S. Department of Commerce announced the initiation of anti-dumping and countervailing duty investigations of CSPV cells, whether or not assembled into modules. A preliminary decision related to this matter is anticipated in November 2024.

In June 2024, a previous tariff exclusion for bi-facial panels ended. Tariff rate is now 14.25% until February 2025 and 14% until February 2026 for imported panels.

In May 2024, the White House imposed a new 25% tariff on Lithium-Ion storage along with other trade measures. The tariff went into immediate effect for EV batteries but has a grace period until January 2026 for stationary energy storage applications.

Xcel Energy continues to assess the impacts of these tariffs and trade complaints on its business, including company-owned projects and PPAs. Xcel Energy may seek regulatory relief for tariffs, if required, in its jurisdictions.

Further policy actions or other restrictions on solar and storage imports, disruptions in imports from key suppliers, or any new trade complaint could impact project timelines and costs of various generation projects and PPAs.

### Critical Accounting Policies and Estimates

Preparation of the consolidated financial statements requires the application of accounting rules and guidance, as well as the use of estimates. Application of these policies involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges and anticipated recovery of costs. These judgments could materially impact the consolidated financial statements, based on varying assumptions. The financial and operating environment also may have a significant effect on the operation of the business and results reported. Items considered critical, in addition to the matter noted below, are included within the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 2023.

#### Loss Contingencies – Wildfires

The outcomes of legal proceedings and claims brought against Xcel Energy related to the Marshall Fire, Smokehouse Creek Fire Complex or any future wildfire are subject to uncertainty. An estimated loss from a loss contingency such as a legal proceeding or claim is accrued if it is probable of being incurred and the amount of the loss can be reasonably estimated. Each reporting period we evaluate, among other factors, the degree of probability of unfavorable outcomes and the ability to make reasonable estimates of potential losses. The process for evaluating any wildfire-related liabilities requires a series of complex judgments about past and future events. Factors such as the cause of a wildfire, the extent and magnitude of potential damages and the status of investigations and legal proceedings are considered. See Note 10 accompanying the consolidated financial statements for additional information.

### Environmental Regulation

### Clean Air Act

*Power Plant Greenhouse Gas Regulations —* In April 2024, the EPA published final rules addressing control of CO2 emissions from the power sector. The rules regulate new natural gas generating units and emission guidelines for existing coal and certain natural gas generation. The rules create subcategories of coal units based on planned retirement date and subcategories of natural gas combustion turbines and combined cycle units based on utilization. The CO2 control requirements vary by subcategory. Based on current estimates and assumptions, Xcel Energy has determined that due to scheduled plant retirements, there is minimal financial or operational impact associated with these requirements and believes that the cost of these initiatives or replacement generation would be recoverable through rates based on prior state commission practices.

*Waste-to-Energy Air Regulations —* In January 2024, the EPA proposed air regulations addressing new and existing large municipal waste combustors. The proposed rules lower current emission standards for certain pollutants and would require installation of new pollution controls and/or more intense use of existing pollution controls at French Island Generating Station, Red Wing Generating Plant and Wilmarth Generating Plant. Until final rules are issued, it is not certain what the impact will be on Xcel Energy. Xcel Energy believes that the cost of these initiatives or replacement generation would be recoverable through rates based on prior state commission practices.

### Emerging Contaminants of Concern

PFAS are man-made chemicals that are widely used in consumer products and can persist and bio-accumulate in the environment. Xcel Energy does not manufacture PFAS, but because PFAS are so ubiquitous in products and the environment, it may impact our operations.

In September 2022, the EPA proposed to designate two types of PFAS as “hazardous substances” under the CERCLA. In July 2024, the EPA’s final rule went into effect.

In March 2023, the EPA published a proposed rule that would establish enforceable drinking water standards for certain PFAS chemicals. In June 2024, the EPA’s final rule went into effect.

In February 2024, the EPA proposed to change the Resource Conservation and Recovery Act by adding nine PFAS to its list of hazardous constituents.

Potential costs are uncertain and will be determined on a site specific basis where applicable. If costs are incurred, Xcel Energy believes the costs will be recoverable through rates based on prior state commission practices.

### Effluent Limitation Guidelines

In April 2024, the EPA published final rules under the Clean Water Act, setting Effluent Limitations Guidelines and Standards for steam generating coal plants. This rule establishes more stringent wastewater discharge standards for bottom ash transport water, flue-gas desulfurization wastewater, and combustion residuals leachate from steam electric power plants, particularly coal-fired power plants. Based on current estimates and assumptions, Xcel Energy has determined that there is minimal financial or operational impact associated with these requirements and that any costs would be recoverable through rates based on prior state commission practices.

### Derivatives, Risk Management and Market Risk

We are exposed to a variety of market risks in the normal course of business. Market risk is the potential loss that may occur as a result of adverse changes in the market or fair value for a particular instrument or commodity. All financial and commodity-related instruments, including derivatives, are subject to market risk.

Xcel Energy is exposed to the impact of adverse changes in price for energy and energy-related products, which is partially mitigated by the use of commodity derivatives. In addition to ongoing monitoring and maintaining credit policies intended to minimize overall credit risk, management takes steps to mitigate changes in credit and concentration risks associated with its derivatives and other contracts, including parental guarantees and requests of collateral. While we expect that the counterparties will perform on the contracts underlying our derivatives, the contracts expose us to credit and non-performance risk.

Distress in the financial markets may impact counterparty risk and the fair value of the securities in the nuclear decommissioning fund and pension fund.

***Commodity Price Risk —*** We are exposed to commodity price risk in our electric and natural gas operations. Commodity price risk is managed by entering into long and short-term physical purchase and sales contracts for electric capacity, energy and energy-related products and fuels used in generation and distribution activities.

Commodity price risk is also managed through the use of financial derivative instruments. Our risk management policy allows us to manage commodity price risk within each rate-regulated operation per commission approved hedge plans.

***Wholesale and Commodity Trading Risk —*** Xcel Energy conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy, energy-related instruments and natural gas-related instruments, including derivatives. Our risk management policy allows management to conduct these activities within guidelines and limitations as approved by our risk management committee.

Fair value of net commodity trading contracts as of June 30, 2024:

| (Millions of Dollars) | Futures / Forwards Maturity Less Than 1 Year | 1 to 3 Years | 4 to 5 Years | Greater Than 5 Years | Total Fair Value |
| --- | ---: | ---: | ---: | ---: | ---: |
| NSP-Minnesota (a) | $(1) | $(4) | $(2) | $— | $(7) |
| NSP- Minnesota (b) | (15) | (7) | (7) | 2 | (27) |
| PSCo (a) | — | 2 | 1 | — | 3 |
| PSCo (b) | (3) | 4 | 2 | — | 3 |
|  | $(19) | $(5) | $(6) | $2 | $(28) |

| (Millions of Dollars) | Options Maturity Less Than 1 Year | 1 to 3 Years | 4 to 5 Years | Greater Than 5 Years | Total Fair Value |
| --- | ---: | ---: | ---: | ---: | ---: |
| NSP-Minnesota (b) | $— | $— | $13 | $5 | $18 |
|  | $— | $— | $13 | $5 | $18 |

(a) Prices actively quoted or based on actively quoted prices.

(b) Prices based on models and other valuation methods.

Changes in the fair value of commodity trading contracts before the impacts of margin-sharing for the six months ended June 30:

| (Millions of Dollars) | 2024 | 2023 |
| --- | ---: | ---: |
| Fair value of commodity trading net contracts outstanding at Jan. 1 | $1 | $(33) |
| Contracts realized or settled during the period | (2) | — |
| Commodity trading contract additions and changes during the period | (9) | 33 |
| Fair value of commodity trading net contracts outstanding at June 30 | $(10) | $— |

A 10% increase and 10% decrease in forward market prices for Xcel Energy’s commodity trading contracts would have likewise increased and decreased pretax income from continuing operations, by approximately $3 million and $5 million at June 30, 2024 and June 30, 2023, respectively.

The utility subsidiaries’ commodity trading operations measure the outstanding risk exposure to price changes on contracts and obligations using an industry standard methodology known as VaR. VaR expresses the potential change in fair value of the outstanding contracts and obligations over a particular period of time under normal market conditions.

The VaRs for the NSP-Minnesota and PSCo commodity trading operations, excluding both non-derivative transactions and derivative transactions designated as normal purchases and normal sales, calculated on a consolidated basis using a Monte Carlo simulation with a 95% confidence level and a one-day holding period, were as follows:

| (Millions of Dollars) | Three Months Ended June 30 | Average | High | Low |
| --- | ---: | ---: | ---: | ---: |
| 2024 | $— | $1 | $1 | $— |
| 2023 | 1 | 1 | 1 | — |

32

***Nuclear Fuel Supply —*** In May 2024, the *Prohibiting Russian Uranium Imports Act* was signed into law. As such, NSP-Minnesota will no longer be permitted to accept deliveries of enriched nuclear material from Russia beginning in August 2024, unless specific waivers are requested and received. NSP-Minnesota has secured its enriched nuclear material requirements through 2029 with non-Russian material, which are in various stages of processing in Canada, Europe and the United States. NSP-Minnesota continues to assess the impacts of this legislation on its existing contracts related to Russian-sourced nuclear material.

***Interest Rate Risk —*** Xcel Energy is subject to interest rate risk. Our risk management policy allows interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate derivatives.

A 100-basis point change in the benchmark rate on Xcel Energy’s variable rate debt would impact pretax interest expense annually by approximately $8 million and $5 million in June 30, 2024 and 2023, respectively.

NSP-Minnesota maintains a nuclear decommissioning fund, as required by the NRC. The nuclear decommissioning fund is subject to interest rate and equity price risk. The fund is invested in a diversified portfolio of debt securities, equity securities and other investments. These investments may be used only for the purpose of decommissioning NSP-Minnesota’s nuclear generating plants.

Fluctuations in equity prices or interest rates affecting the nuclear decommissioning fund do not have a direct impact on earnings due to the application of regulatory accounting. Realized and unrealized gains on the decommissioning fund investments are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs.

The value of pension and postretirement plan assets and benefit costs are impacted by changes in discount rates and expected return on plan assets. Xcel Energy’s ongoing pension and postretirement investment strategy is based on plan-specific investment recommendations that seek to optimize potential investment risk and minimize interest rate risk associated with changes in the obligations as a plan’s funded status increases over time. The impacts of fluctuations in interest rates on pension and postretirement costs are mitigated by pension cost calculation methodologies and regulatory mechanisms that minimize the earnings impacts of such changes.

***Credit Risk —*** Xcel Energy is also exposed to credit risk. Credit risk relates to the risk of loss resulting from counterparties’ nonperformance on their contractual obligations. Xcel Energy maintains credit policies intended to minimize overall credit risk and actively monitors these policies to reflect changes and scope of operations.

At June 30, 2024, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $42 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $40 million. At June 30, 2023, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $47 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $46 million.

Xcel Energy conducts credit reviews for all wholesale, trading and non-trading commodity counterparties and employs credit risk controls, such as letters of credit, parental guarantees, master netting agreements and termination provisions.

Credit exposure is monitored, and when necessary, the activity with a specific counterparty is limited until credit enhancement is provided. Distress in the financial markets could increase our credit risk.

### Fair Value Measurements

Derivative contracts, with the exception of those designated as normal purchases and normal sales, are reported at fair value. Xcel Energy’s investments held in the nuclear decommissioning fund, rabbi trusts, pension and other postretirement funds are also subject to fair value accounting. See Note 8 to the consolidated financial statements for further information.

### Liquidity and Capital Resources

### Cash Flows

### Operating Cash Flows

| (Millions of Dollars) | Six Months Ended June 30 |
| --- | ---: |
| Cash provided by operating activities — 2023 | $2,455 |
| Components of change — 2024 vs. 2023 |  |
| Higher net income | 84 |
| Non-cash transactions | 131 |
| Changes in deferred income taxes | 477 |
| Changes in working capital | (547) |
| Changes in net regulatory and other assets and liabilities | (360) |
| Cash provided by operating activities — 2024 | $2,240 |

Net cash provided by operating activities decreased $215 million for the six months ended June 30, 2024 compared with the prior year. The decrease was largely due to interim rate refunds in Minnesota and timing of recovery of deferred fuel costs, partially offset by the change in deferred income taxes, which includes the impact of proceeds for tax credit transfers.

### Investing Cash Flows

| (Millions of Dollars) | Six Months Ended June 30 |
| --- | ---: |
| Cash used in investing activities — 2023 | $(2,639) |
| Components of change — 2024 vs. 2023 |  |
| Increased capital expenditures | (769) |
| Other investing activities | 5 |
| Cash used in investing activities — 2024 | $(3,403) |

Net cash used in investing activities increased $764 million for the six months ended June 30, 2024 compared with the prior year. The increase in capital expenditures was largely due to continued system expansion and increased investment in renewable and transmission projects.

### Financing Cash Flows

| (Millions of Dollars) | Six Months Ended June 30 |
| --- | ---: |
| Cash provided by financing activities — 2023 | $348 |
| Components of change — 2024 vs. 2023 |  |
| Lower net short-term repayments | 286 |
| Higher long-term debt issuances, net of repayments | 2,003 |
| Higher proceeds from issuance of common stock | 24 |
| Other financing activities | (29) |
| Cash provided by financing activities — 2024 | $2,632 |

Net cash provided by financing activities increased $2,284 million for the six months ended June 30, 2024 compared with the prior year. The increase was largely related to additional debt issuances to fund capital investment and the repayment of maturing debt issuances.

### Capital Requirements

Xcel Energy expects to meet future financing requirements by periodically issuing short-term debt, long-term debt, common stock, hybrid and other securities to maintain desired capitalization ratios.

**Pension Fund —** Xcel Energy’s pension assets are invested in a diversified portfolio of domestic and international equity securities, short-term to long-duration fixed income securities, and alternative investments, including private equity, real estate and hedge funds.

- In January 2024, contributions of $100 million were made across four of Xcel Energy’s pension plans.
- In 2023, contributions of $50 million were made across four of Xcel Energy’s pension plans.
- For future years, contributions will be made as deemed appropriate based on evaluation of various factors including the funded status of the plans, minimum funding requirements, interest rates and expected investment returns.

### Capital Sources

***Short-Term Funding Sources —*** Xcel Energy uses a number of sources to fulfill short-term funding needs, including operating cash flow, notes payable, commercial paper and bank lines of credit. The amount and timing of short-term funding needs depend on financing needs for construction expenditures, working capital and dividend payments.

***Short-Term Investments —*** Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS maintain cash operating and short-term investment accounts.

***Revolving Credit Facilities —*** Xcel Energy Inc., NSP-Minnesota, PSCo and SPS each have the right to request an extension of their revolving credit facility termination date for two additional one-year periods beyond the September 2027 termination date. NSP-Wisconsin has the right to request an extension of the revolving credit facility termination date for an additional one-year period. All extension requests are subject to majority bank group approval.

As of July 30, 2024, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available to meet liquidity needs:

| (Millions of Dollars) | Credit Facility (a) | Drawn (b) | Available | Cash | Liquidity |
| --- | ---: | ---: | ---: | ---: | ---: |
| Xcel Energy Inc. | $1,500 | $792 | $708 | $2 | $710 |
| PSCo | 700 | 31 | 669 | 602 | 1,271 |
| NSP-Minnesota | 700 | 12 | 688 | 129 | 817 |
| SPS | 500 | — | 500 | 252 | 752 |
| NSP-Wisconsin | 150 | — | 150 | 178 | 328 |
| Total | $3,550 | $835 | $2,715 | $1,163 | $3,878 |

(a) Credit facilities expire in September 2027.

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

***Short-Term Debt —*** Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each have individual commercial paper programs. As of June 30, 2024, the authorized levels for these commercial paper programs are:

- $1.5 billion for Xcel Energy Inc.
- $700 million for PSCo.
- $700 million for NSP-Minnesota.
- $500 million for SPS.
- $150 million for NSP-Wisconsin.

***Money Pool —*** Xcel Energy received FERC approval to establish a utility money pool arrangement with the utility subsidiaries, subject to receipt of required state regulatory approvals. The utility money pool allows for short-term investments in and borrowings between the utility subsidiaries.

Xcel Energy may make investments in the utility subsidiaries at market-based interest rates; however, the money pool arrangement does not allow the utility subsidiaries to make investments in Xcel Energy. The money pool balances are eliminated in consolidation. NSP-Minnesota, NSP-Wisconsin, PSCo and SPS participate in the money pool pursuant to approval from their respective state regulatory commissions.

***2024 Financing Activity —*** Xcel Energy and its utility subsidiaries issued the following long-term debt:

| Issuer | Security | Amount |  | Tenor | Coupon |
| --- | --- | ---: | --- | --- | ---: |
| Xcel Energy Inc. | Senior Unsecured Notes | $800 | million | 10 Year | 5.50% |
| NSP-Minnesota | First Mortgage Bonds | 700 | million | 30 Year | 5.40 |
| PSCo | First Mortgage Bonds | 1,200 | million | 10 Year & 30 Year | 5.35 & 5.75 |
| SPS | First Mortgage Bonds | 600 | million | 30 Year | 6.00 |
| NSP-Wisconsin | First Mortgage Bonds | 400 | million | 30 Year | 5.65 |

***Long-Term Borrowings, Equity Issuances and Other Financing Instruments —*** Xcel Energy may issue equity through its at-the-market program or other offerings. Financing plans are subject to change, depending on capital expenditures, regulatory outcomes, internal cash generation, market conditions, changes in tax policies and other factors.

See Note 4 to the consolidated financial statements for further information.

### Off-Balance-Sheet Arrangements

Xcel Energy does not have any off-balance-sheet arrangements, other than those currently disclosed, that have or are reasonably likely to have a current or future effect on financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.

### Earnings Guidance and Long-Term EPS and Dividend Growth Rate Objectives

***Xcel Energy 2024 Earnings Guidance —*** Xcel Energy’s 2024 ongoing earnings guidance is a range of $3.50 to $3.60 per share.(a)

Key assumptions as compared with 2023 actual levels unless noted:

- Constructive outcomes in all pending rate case and regulatory proceedings.
- Normal weather patterns for the remainder of the year.
- Weather-normalized retail electric sales are projected to increase 1%.
- Weather-normalized retail firm natural gas sales are projected to be flat.
- Capital rider revenue is projected to increase $60 million to $70 million (net of PTCs).
- O&M expenses are projected to increase 1% to 2%.
- Depreciation expense is projected to increase approximately $305 million to $315 million.
- Property taxes are projected to be flat. This change is largely earnings neutral and is offset in revenue due to property tax trackers.
- Interest expense (net of AFUDC - debt) is projected to increase $140 million to $150 million, net of interest income.
- AFUDC - equity is projected to increase $65 million to $75 million.
- ETR is projected to be ~(6%) to (8%). The assumption change is largely due to an increase in the PTC rate, which is offset in revenue and largely earnings neutral. The negative ETR is largely offset by PTCs flowing back to customers in capital riders and fuel mechanisms and is largely earnings neutral. The projected ETR does not reflect the potential impact of nuclear PTCs, which are also expected to flow back to customers.

(a) 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. Ongoing earnings could differ from those prepared in accordance with GAAP for unplanned and/or unknown adjustments. As Xcel Energy is unable to quantify the financial impacts of any additional adjustments that may occur for the year, we are unable to provide a quantitative reconciliation of the guidance for ongoing EPS to corresponding GAAP EPS.

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

- Deliver long-term annual EPS growth of 5% to 7% based off of a 2023 actual ongoing earnings base of $3.35 per share.
- Deliver annual dividend increases of 5% to 7%.
- Target a dividend payout ratio of 50% to 60%.
- Maintain senior secured debt credit ratings in the A range.

## Market risk

As filed, 195 characters.

There have been no material changes to the market risk disclosure included in our Annual Report on Form 10-K for the year ended Dec. 31, 2023 under “Derivatives, Risk Management and Market Risk.”

## Controls and procedures

As filed, 1,201 characters.

### Disclosure Controls and Procedures

Xcel Energy maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms. In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the CEO and CFO, allowing timely decisions regarding required disclosure.

As of June 30, 2024, based on an evaluation carried out under the supervision and with the participation of Xcel Energy’s management, including the CEO and CFO, of the effectiveness of its disclosure controls and procedures, the CEO and CFO have concluded that Xcel Energy’s disclosure controls and procedures were effective.

### Internal Control Over Financial Reporting

No changes in Xcel Energy’s internal control over financial reporting occurred during the most recent fiscal quarter that materially affected, or are reasonably likely to materially affect, Xcel Energy’s internal control over financial reporting.

## Risk factors

As filed, 270 characters.

Xcel Energy’s risk factors are documented in Item 1A of Part I of its Annual Report on Form 10-K for the year ended Dec. 31, 2023, which is incorporated herein by reference. There have been no material changes from the risk factors previously disclosed in the Form 10-K.

Filed Aug 1, 2024.
Source: SEC EDGAR, the filing index for accession 0000072903-24-000172. Last ingested by Listed: Nov 7, 2026, 12:19 ET. No prices; not investment advice.