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

- Company: [Xcel Energy Inc](/companies/xel.md) (CIK 72903)
- Form: 10-Q
- Filed: 2024-10-31
- Accepted by EDGAR: Oct 31, 2024, 15:08 ET
- Period: 2024-09-30
- Accession: 0000072903-24-000199
- Inline XBRL: yes
- Main document: https://www.sec.gov/Archives/edgar/data/72903/000007290324000199/xel-20240930.htm
- All documents and exhibits: https://www.sec.gov/Archives/edgar/data/72903/000007290324000199/

## Figures reported in this filing

Standardized XBRL line items for the period ended 2024-09-30.

| Line item | Period | Value | XBRL concept |
| --- | --- | ---: | --- |
| Operating income | 3 months, 2024-07-01 to 2024-09-30 | $911.0m | us-gaap:OperatingIncomeLoss |
| Operating income | 9 months, 2024-01-01 to 2024-09-30 | $2.04bn | us-gaap:OperatingIncomeLoss |
| Interest expense | 3 months, 2024-07-01 to 2024-09-30 | $326.0m | us-gaap:InterestExpense |
| Interest expense | 9 months, 2024-01-01 to 2024-09-30 | $936.0m | us-gaap:InterestExpense |
| Income tax | 3 months, 2024-07-01 to 2024-09-30 | $10.0m | us-gaap:IncomeTaxExpenseBenefit |
| Income tax | 9 months, 2024-01-01 to 2024-09-30 | −$105.0m | us-gaap:IncomeTaxExpenseBenefit |
| Net income | 3 months, 2024-07-01 to 2024-09-30 | $682.0m | us-gaap:NetIncomeLoss |
| Net income | 9 months, 2024-01-01 to 2024-09-30 | $1.47bn | us-gaap:NetIncomeLoss |
| Diluted EPS | 3 months, 2024-07-01 to 2024-09-30 | $1.21 | us-gaap:EarningsPerShareDiluted |
| Diluted EPS | 9 months, 2024-01-01 to 2024-09-30 | $2.63 | us-gaap:EarningsPerShareDiluted |
| Basic EPS | 3 months, 2024-07-01 to 2024-09-30 | $1.21 | us-gaap:EarningsPerShareBasic |
| Basic EPS | 9 months, 2024-01-01 to 2024-09-30 | $2.63 | us-gaap:EarningsPerShareBasic |
| Diluted shares (weighted) | 3 months, 2024-07-01 to 2024-09-30 | 565,000,000 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Diluted shares (weighted) | 9 months, 2024-01-01 to 2024-09-30 | 559,000,000 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Operating cash flow | 9 months, 2024-01-01 to 2024-09-30 | $3.98bn | us-gaap:NetCashProvidedByUsedInOperatingActivities |
| Capital expenditure | 9 months, 2024-01-01 to 2024-09-30 | $5.15bn | us-gaap:PaymentsToAcquireProductiveAssets |
| Dividends paid | 9 months, 2024-01-01 to 2024-09-30 | $871.0m | us-gaap:PaymentsOfDividends |
| Cash and equivalents | at 2024-09-30 | $1.54bn | us-gaap:CashAndCashEquivalentsAtCarryingValue |
| Current assets | at 2024-09-30 | $5.47bn | us-gaap:AssetsCurrent |
| Total assets | at 2024-09-30 | $69.29bn | us-gaap:Assets |
| Current liabilities | at 2024-09-30 | $5.86bn | us-gaap:LiabilitiesCurrent |
| Long-term debt | at 2024-09-30 | $28.57bn | us-gaap:LongTermDebt |
| Short-term borrowings | at 2024-09-30 | $95.0m | us-gaap:ShortTermBorrowings |
| Shareholders' equity | at 2024-09-30 | $19.35bn | us-gaap:StockholdersEquity |

## Management's discussion and analysis

As filed, 73,045 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 EPS, 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.

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

| (Millions of Dollars) | Three Months Ended Sept. 30 2024 | 2023 | Nine Months Ended Sept. 30 2024 | 2023 |
| --- | ---: | ---: | ---: | ---: |
| GAAP net income | $682 | $656 | $1,472 | $1,362 |
| Loss on Comanche Unit 3 litigation | — | 34 | — | 34 |
| Sherco Unit 3 2011 outage refunds | 35 | — | 46 | — |
| Tax effect | (10) | (8) | (13) | (8) |
| Ongoing earnings | $707 | $682 | $1,505 | $1,388 |

*Sherco Unit 3 2011 Outage Refunds —* NSP-Minnesota’s Sherco Unit 3 experienced an extended outage following a 2011 incident which damaged its turbine. In October 2024 following contested case procedures, the MPUC ordered a customer refund of $46 million for replacement power incurred during the outage.

*Comanche Unit 3 Litigation —* As a result of an Oct. 25, 2023 jury verdict in Denver County District Court awarding CORE lost power damages and other costs, PSCo recognized a $34 million loss for the matter in the third quarter of 2023. Given the non-recurring nature of this specific item, it has been excluded from ongoing earnings.

### 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 Sept. 30 2024 | 2023 | Nine Months Ended Sept. 30 2024 | 2023 |
| --- | ---: | ---: | ---: | ---: |
| NSP-Minnesota | $0.45 | $0.47 | $1.06 | $0.95 |
| PSCo | 0.45 | 0.41 | 1.06 | 0.97 |
| SPS | 0.31 | 0.30 | 0.58 | 0.55 |
| NSP-Wisconsin | 0.07 | 0.06 | 0.19 | 0.18 |
| Earnings from equity method investments — WYCO | 0.01 | 0.01 | 0.02 | 0.03 |
| Regulated utility | 1.29 | 1.25 | 2.91 | 2.68 |
| Xcel Energy Inc. and Other | (0.08) | (0.06) | (0.28) | (0.22) |
| **GAAP diluted EPS (a)** | $1.21 | $1.19 | $2.63 | $2.47 |
| Loss on Comanche Unit 3 litigation | — | 0.05 | — | 0.05 |
| Sherco Unit 3 2011 outage refunds | 0.04 | $— | 0.06 | — |
| **Ongoing diluted EPS (a)** | $1.25 | $1.23 | $2.69 | $2.52 |

(a) Amounts may not add due to rounding.

### Summary of Earnings

***Xcel Energy —*** Xcel Energy’s third quarter GAAP earnings were $1.21 per share, compared with $1.19 per share in the same period in 2023 and ongoing earnings were $1.25 per share in 2024, compared with $1.23 per share in 2023. The change in earnings per share was primarily driven by increased recovery of infrastructure investments, 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 earnings decreased $0.02 per share and ongoing earnings increased 0.02 per share for the third quarter. Year-to-date GAAP earnings increased $0.11 per share and ongoing earnings increased $0.17 per share. Year-to-date earnings primarily reflect increased recovery of infrastructure investments (electric and natural gas), partially offset by higher depreciation and interest charges. See Note 6 for reconciliation from GAAP to ongoing earnings.

***PSCo —*** GAAP earnings increased $0.04 per share and ongoing earnings increased $0.01 per share for the third quarter. Year-to-date GAAP earnings increased $0.09 per share and ongoing earnings increased $0.04 per share. Year-to-date ongoing earnings primarily reflect higher recovery of electric infrastructure investments, which was partially offset by increased interest charges, depreciation and O&M expenses.

***SPS —*** GAAP and ongoing earnings increased $0.01 per share for the third quarter of 2024 and $0.03 year-to-date. Year-to-date earnings reflect the impact of regulatory rate outcomes and sales growth, partially offset by increased depreciation and O&M expenses.

***NSP-Wisconsin —*** GAAP and ongoing earnings increased $0.01 per share for the third quarter of 2024 and year-to-date. Year-to-date earnings reflect the impact of electric infrastructure investment recoveries, partially offset by higher depreciation and interest expenses.

***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 Sept. 30 | Nine Months Ended Sept. 30 |
| --- | ---: | ---: |
| **GAAP diluted EPS — 2023** | **$1.19** | **$2.47** |
| Components of change - 2024 vs. 2023 |  |  |
| Electric regulatory rate outcomes and riders | 0.24 | 0.65 |
| Higher AFUDC | 0.04 | 0.12 |
| Natural gas regulatory rate outcomes and riders | 0.01 | 0.06 |
| Loss on Comanche Unit 3 litigation | 0.05 | 0.05 |
| Higher depreciation and amortization | (0.08) | (0.31) |
| Higher interest charges | (0.08) | (0.20) |
| Higher O&M expenses | (0.09) | (0.08) |
| Sherco Unit 3 2011 outage refunds | (0.04) | (0.06) |
| Other, net | (0.03) | (0.07) |
| **GAAP diluted EPS — 2024** | **1.21** | **2.63** |
| Sherco Unit 3 2011 outage refunds | 0.04 | 0.06 |
| **Ongoing diluted EPS — 2024** | **$1.25** | **$2.69** |

25

### 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 Sept. 30 2024 vs. Normal | 2023 vs. Normal | 2024 vs. 2023 | Nine Months Ended Sept. 30 2024 vs. Normal | 2023 vs. Normal | 2024 vs. 2023 |
| --- | ---: | ---: | ---: | ---: | ---: | ---: |
| HDD | (72.7)% | (66.7)% | (24.0)% | (14.7)% | (2.1)% | (13.4)% |
| CDD | 20.1 | 15.2 | 5.9 | 24.7 | 3.2 | 21.7 |
| THI | (1.8) | 2.6 | (4.4) | (10.8) | 12.7 | (20.1) |

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

|  | Three Months Ended Sept. 30 2024 vs. Normal | 2023 vs. Normal | 2024 vs. 2023 | Nine Months Ended Sept. 30 2024 vs. Normal | 2023 vs. Normal | 2024 vs. 2023 |
| --- | ---: | ---: | ---: | ---: | ---: | ---: |
| Retail electric | $0.038 | $0.032 | $0.006 | $0.015 | $0.035 | $(0.020) |
| Decoupling and sales true-up | (0.001) | 0.007 | (0.008) | 0.040 | (0.015) | 0.055 |
| Electric total | $0.037 | $0.039 | $(0.002) | $0.055 | $0.020 | $0.035 |
| Firm natural gas | (0.002) | (0.002) | — | (0.040) | 0.024 | (0.064) |
| Decoupling | (0.001) | 0.001 | (0.002) | 0.017 | 0.001 | 0.016 |
| Natural gas total | $(0.003) | $(0.001) | $(0.002) | $(0.023) | $0.025 | $(0.048) |
| Total | $0.034 | $0.038 | $(0.004) | $0.032 | $0.045 | $(0.013) |

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

| Actual | Three Months Ended Sept. 30 PSCo | NSP-Minnesota | SPS | NSP-Wisconsin | Xcel Energy |
| --- | ---: | ---: | ---: | ---: | ---: |
| Electric residential | 4.1% | (2.7)% | (2.3)% | (1.0)% | —% |
| Electric C&I | 1.2 | (2.2) | 9.4 | (0.6) | 2.3 |
| Total retail electric sales | 2.1 | (2.4) | 7.0 | (0.7) | 1.5 |
| Firm natural gas sales | (3.4) | (3.8) | N/A | 6.6 | (3.0) |

| Weather-Normalized | Three Months Ended Sept. 30 PSCo | NSP-Minnesota | SPS | NSP-Wisconsin | Xcel Energy |
| --- | ---: | ---: | ---: | ---: | ---: |
| Electric residential | —% | (0.8)% | (0.1)% | (1.3)% | (0.5)% |
| Electric C&I | (0.4) | (1.6) | 9.8 | (0.6) | 2.2 |
| Total retail electric sales | (0.3) | (1.4) | 8.0 | (0.8) | 1.3 |
| Firm natural gas sales | (2.7) | (3.5) | N/A | 6.7 | (2.4) |

| Actual | Nine Months Ended Sept. 30 PSCo | NSP-Minnesota | SPS | NSP-Wisconsin | Xcel Energy |
| --- | ---: | ---: | ---: | ---: | ---: |
| Electric residential | 4.1% | (6.2)% | 1.5% | (4.8)% | (1.2)% |
| Electric C&I | 0.3 | (3.7) | 8.0 | (1.9) | 1.0 |
| Total retail electric sales | 1.6 | (4.5) | 6.7 | (2.7) | 0.3 |
| Firm natural gas sales | (8.7) | (12.7) | N/A | (11.5) | (10.1) |

*Weather-Normalized*

|  | Nine Months Ended Sept. 30 PSCo | NSP-Minnesota | SPS | NSP-Wisconsin | Xcel Energy |
| --- | ---: | ---: | ---: | ---: | ---: |
| Electric residential | 0.2% | (0.3)% | (1.1)% | (1.9)% | (0.4)% |
| Electric C&I | (1.1) | (2.5) | 7.9 | (1.5) | 1.0 |
| Total retail electric sales | (0.7) | (1.8) | 6.3 | (1.6) | 0.6 |
| Firm natural gas sales | 1.7 | 0.4 | N/A | (2.3) | 1.0 |

26

*Weather-Normalized*

|  | Nine Months Ended Sept 30 (Leap Year Adjusted) PSCo | NSP-Minnesota | SPS | NSP-Wisconsin | Xcel Energy |
| --- | ---: | ---: | ---: | ---: | ---: |
| Electric residential | (0.2)% | (0.7)% | (1.5)% | (2.3)% | (0.7)% |
| Electric C&I | (1.5) | (2.8) | 7.5 | (1.9) | 0.7 |
| Total retail electric sales | (1.1) | (2.1) | 5.9 | (2.0) | 0.2 |
| Firm natural gas sales | 0.8 | (0.5) | N/A | (3.1) | 0.1 |

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

- PSCo — Residential sales declined due to a 1.5% decrease in use per customer, partially offset by customer growth of 1.4%. The C&I sales decline was related to decreased use per customer, primarily in the information sector.
- NSP-Minnesota — Residential sales declined due to a 2.2% 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, retail trade and education sectors.
- SPS — Residential sales declined as a result of a 2.2% decrease in use per customer, partially offset by 0.6% customer growth. C&I sales increased due to higher use per customer, primarily driven by the energy sector and cryptocurrency mining.
- NSP-Wisconsin — Residential sales declined due to a 3.2% decrease in use per customer, partially offset by 0.9% increase in customers. C&I sales decline was associated with decreased use per customer, experienced largely in the manufacturing and professional services 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 residential use per customer in PSCo offset by decreased use per customer in PSCo C&I and other jurisdictions.

### 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 Sept. 30, 2024 vs. 2023 | Nine Months Ended Sept. 30, 2024 vs. 2023 |
| --- | ---: | ---: |
| Recovery of lower cost of electric fuel and purchased power | $(83) | $(418) |
| Wholesale generation revenues | (45) | (76) |
| Sherco Unit 3 2011 outage refunds | (35) | (46) |
| PTCs flowed back to customers (offset by lower ETR) | (23) | (35) |
| Regulatory rate outcomes (MN, CO, TX, NM, & WI) | 130 | 363 |
| Non-fuel riders | 43 | 112 |
| Conservation and demand side management (offset in expense) | 39 | 82 |
| Revenue recognition for the Texas rate case surcharge (a) | 2 | 39 |
| Estimated impact of weather (net of sales true-up) | (2) | 25 |
| Other, net | (20) | (60) |
| Total increase | $6 | $(14) |

(a) 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 Sept. 30, 2024 vs. 2023 | Nine Months Ended Sept. 30, 2024 vs. 2023 |
| --- | ---: | ---: |
| Recovery of lower cost of natural gas | $(8) | $(418) |
| Estimated impact of weather (net of decoupling) | (2) | (35) |
| Regulatory rate outcomes (MN, WI & ND) | 6 | 41 |
| Retail sales growth (net of decoupling) | 1 | 10 |
| Infrastructure and integrity riders | 1 | 6 |
| Other, net | (4) | 5 |
| Total decrease | $(6) | $(391) |

***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 $121 million for the third quarter and $465 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 $7 million for the third quarter and $420 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 $69 million for the third quarter and increased $58 million year-to-date. The year-to-date increase was primarily due to operational activities (generation maintenance, damage prevention, storm response and wildfire mitigation) and recognition of previously deferred costs associated with the Texas Electric Rate Case, partially offset by gain on land sale in the first quarter and lower bad debt expense.

***Depreciation and Amortization —*** Depreciation and amortization increased $63 million for the third quarter and $235 million year-to-date. The year-to-date increase was largely the result of system expansion partially offset by recognition of previously deferred costs and depreciation rate changes associated with various rate cases.

***Interest Charges —*** Interest charges increased $57 million for the third quarter and $146 million year-to-date, largely due to increased debt levels and higher interest rates.

***Other Income —*** Other income increased $36 million for the third quarter and $56 million year-to-date. The year-to-date increase was primarily due to interest earned and rabbi trust performance, which is partially offset in O&M expenses.

***AFUDC, Equity and Debt —*** AFUDC increased $25 million for the third quarter and $71 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 was 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.

In October 2024, an ALJ recommended the MPUC approve the rate case settlement. A MPUC decision and order is expected in the first quarter of 2025.

*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 August 2024, NSP-Minnesota filed a settlement agreement with NDPSC Staff and AARP. Key terms of the settlement included an increase in natural gas rates of $7.3 million (8.1%), based on a ROE of 9.9% and an equity ratio of 52.5%.

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

*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 to the Minnesota Court of Appeals regarding MPUC decisions relating to executive compensation, insurance expense and treatment of prepaid pension assets. The appeal is pending a court decision expected in the first quarter of 2025.

*2024 Minnesota Electric Rate Case —* In early November 2024, NSP-Minnesota plans to file an electric rate case in Minnesota, seeking a total revenue increase of $491 million (13.2%) over two years, based on an ROE of 10.3%, a 52.5% equity ratio and rate base of $13.2 billion in 2025 and $14 billion in 2026. NSP-Minnesota will also request interim rates of $224 million to go into effect in January 2025. A decision is expected in 2026.

### 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 2025 revenue deficiencies of $28 million for electric and $3 million for natural gas, by amortizing IRA deferrals, stopping a deferral related to IRA benefits ordered in a previous rate case, and deferring revenue requirement impacts of two natural gas capital projects. NSP-Wisconsin expects to have a PSCW decision by year-end 2024.

### NSP System

*2022 Upper Midwest IRP Resource Acquisition —* NSP-Minnesota and NSP-Wisconsin are actively engaged in multiple processes and proceedings to acquire resources to meet their identified generation resource needs.

- In the second quarter of 2023, NSP-Minnesota initiated the process with the MPUC for acquisition of firm dispatchable resources. In October 2024, a settlement was reached with various parties, pending MPUC approval. See below for more details.
- 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 2024, 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, including reutilization of the interconnection rights associated with the retiring Sherco coal units, and 650 MW of solar and storage resources to specifically reutilize the interconnection rights associated with the retiring King coal unit. Bids are currently under evaluation; NSP-Minnesota and NSP-Wisconsin expect to announce short listed projects in December 2024 and 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. In October 2024, NSP-Minnesota filed a settlement with several parties reaching agreement on the targeted resource additions for the 5-year Action Plan and the process under which those resources will be secured, as well as the proposed projects to be approved in the pending 800 MW firm dispatchable resource acquisition.

NSP-Minnesota anticipates a MPUC decision in 2025 and will file a RFP for remaining resource needs upon approval. The settlement included the following key items:

- The selection of the company-owned 420 MW Lyon County combustion turbine.
- The selection of the company-owned 300 MW 4-hour Sherco battery energy storage system.
- Multiple PPAs to proceed to the negotiation stage.
- 3,200 MW of wind, 400 MW of solar and 600 MW of stand-alone storage to be added through 2030 based on an RFP process (a portion of which is expected to be fulfilled with the resources acquired as part of the June and July 2024 RFPs). Of these amounts, approximately 2,800 MW of wind are projected to utilize the Minnesota Energy Connection transmission line.
- Planned life extensions of the Prairie Island and Monticello nuclear plants through the early 2050s.

### 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 was based on a 10.25% ROE, an equity ratio of 55%, a 2023 test year and a $4.2 billion year-end rate base.

In October 2024, the CPUC issued an order including the following key decisions:

- Use of a historic 2023 test year, with a 13-month average rate base.
- Weighted-average cost of capital of 7.0%, based on an ROE range of 9.2%-9.5% and an equity ratio range of 52%-55%.
- Acceleration of $15 million per year of depreciation expense (incremental to PSCo’s original rate request), to be held in an external trust for future decommissioning costs.
- Modifications to recoverability of certain operating expenses.
- Denial of PSCo’s decoupling proposal.

Based on the CPUC order, PSCo estimates an annual revenue increase of approximately $130 million, inclusive of $15 million of accelerated depreciation, with rates expected to be effective Nov. 5, 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. In September 2024, PSCo filed a proposed framework for CPUC review of pricing adjustments for both company owned and PPA resources to enable delivery of the approved portfolio in light of supply chain and geopolitical developments. A decision is expected in the fourth quarter of 2024.

PSCo filed or expects to file generation and transmission CPCNs throughout 2024 and early 2025.

*2024 Colorado Electric Resource Plan —* In October 2024, PSCo filed its electric resource plan, known as the Just Transition Solicitation, with the CPUC. The filing reflects the expected growth on the system, the generation resources needed to meet the projected growth and the future evaluation of competitive bids for new generation resources.

- The plan reflects a base sales forecast with 7% compound annual sales growth through 2031.
- The plan also presents a low sales forecast with a 3% compound annual sales growth through 2031.
- The resource plan includes forecasted need of 5-14 GW of new generation capacity through 2031, including renewables and firm dispatchable resources to meet the two different scenarios. The acquisitions of generation resources will be determined through a competitive solicitation after the CPUC determines the portfolio. The table below summarizes two of the proposed portfolios based on the different sales scenarios:

| (Megawatts) | Base Plan | Low Load |
| --- | ---: | ---: |
| Wind | 7,250 | 2,800 |
| Solar | 3,077 | 1,200 |
| Natural gas combustion turbine | 1,575 | 1,400 |
| Storage (long duration) | 1,600 | — |
| Other storage | 450 | — |
| **Total** | 13,952 | 5,400 |

A CPUC decision on the resource plan is expected by the fall of 2025 (Phase I) with the competitive solicitation for resource additions expected in early 2026.

*Wildfire Mitigation Plan —* In June 2024, PSCo filed an updated WMP 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 the third quarter of 2025.

The WMP is a key component of keeping our customers and communities safe while providing reliable and affordable electric service. The WMP 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.

The CPUC requested that PSCo file supplemental testimony including the impacts of potential securitization of the proposed wildfire mitigation plan investments. 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 |

The procedural schedule is as follows:

- Answer testimony: Feb. 14, 2025
- Rebuttal testimony: March 21, 2025
- Settlement deadline: April 11, 2025
- Hearing: May 5-15, 2025
- Decision deadline: Aug. 28, 2025

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

The CPUC opened a docket related to the proactive de-energizing of power lines to evaluate potential improvements to the process. The CPUC plans to continue evaluation of PSCo’s policies for proactive line de-energizations through its ongoing review of the 2025-2027 wildfire mitigation plan and, in the interim, will require PSCo to file additional information to the CPUC, hold work sessions with emergency responders, test customer communication protocols, and provide monthly progress updates to the CPUC.

*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 gas cost adjustment rate. As a result, costs above the upper limit are deferred for future recovery, with interest, and costs below the lower limit 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. In September 2024, the CPUC issued a recommended decision in adopting rules to implement a natural gas PIM prior to Jan. 1, 2025. Per the recommended decision, natural gas costs incurred will be compared to the prior year to determine any incentive/penalty. In October 2024, PSCo filed targeted exceptions. A final decision is expected in fourth quarter of 2024.

In October 2024, the CPUC also issued a proposed PIM for electric utilities. Similar to the natural gas PIM, it would determine any incentive/penalty by comparing the year-over-year change in the price of natural gas procured for electric generation. PSCo filed comments in October 2024 and a hearing is expected to occur in November 2024. A CPUC decision is expected by the end of 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 through a rider for 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. PSCo expects to file an updated 2025 rider in November 2024.

*Cabin Creek Prudency Review —* In 2015, the CPUC granted a CPCN for an $88 million upgrade project to 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.

Procedural schedule:

- Answer testimony: Feb. 3, 2025
- Rebuttal testimony: March 14, 2025
- Settlement testimony: April 4, 2025
- Hearing: April 17-18, 2025
- Statements of position: May 9, 2025

A final CPUC decision is expected in the second quarter of 2025.

*Excess Liability Insurance Deferral —* In August 2024, PSCo filed a request with the CPUC to establish a tracker to defer differences in excess liability insurance premiums after the October 2024 policy renewal (reflecting significantly rising premiums, largely associated with wildfire risks throughout the United States) and amounts currently recovered. In October 2024, the CPUC approved an accelerated procedural schedule which is as follows:

- Rebuttal testimony: Nov. 1, 2024
- Settlement deadline: Nov. 12, 2024
- Hearing: Nov. 21, 2024
- Target decision date: Dec. 31, 2024

### 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. A PUCT decision is expected in the fourth quarter of 2024.

*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.

*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’ 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 3,200 MW of accredited generation capacity by 2030. The total capacity to be added to the system is expected to align with the 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 portfolio in 2026.

### 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 May 2024, the U.S. Department of Commerce announced the initiation of anti-dumping and countervailing duty investigations of CSPV cells from Cambodia, Malaysia, Thailand and Vietnam, whether or not assembled into modules.

In October 2024, the U.S. Department of Commerce announced its preliminary determination in the countervailing duty circumvention investigation, which is not expected to impact Xcel Energy projects. A preliminary decision related to the anti-dumping portion of the matter is anticipated in November 2024.

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.

### Excess Liability Insurance Coverage

Xcel Energy maintains excess liability coverage, which is intended to insure against liability to third parties. During 2024, Xcel Energy had approximately $600 million of excess liability coverage; including $520 million of wildfire coverage with an annual premium of approximately $40 million. Examples of claims paid under this policy include property damage or bodily injury to members of the public caused by Xcel Energy’s employees, equipment or facilities. The increased wildfire liability risk and claims are driving a significant increase of premiums and reductions in insurance coverage in the excess liability markets, especially in the western United States. In October 2024, Xcel Energy renewed its excess liability coverage and now has $450 million of total coverage; including $450 million of wildfire coverage for the NSP System and $300 million of wildfire coverage for PSCo and SPS. The annual premium for this excess liability insurance is approximately $130 million. Xcel Energy is seeking to recover these increased costs through various regulatory proceedings, including a deferral request at PSCo and planned deferral requests or rate filings in other states.

### 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 June 2024, the EPA finalized a rule that designated certain PFAS as hazardous substances under CERCLA. In July 2024, the EPA finalized another rule that set enforceable drinking water standards for certain PFAS.

Potential costs for these rules and any additional proposed regulations related to PFAS 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 Sept. 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) | $(2) | $(4) | $(1) | $— | $(7) |
| NSP- Minnesota (b) | (11) | (4) | (3) | 2 | (16) |
| PSCo (a) | 1 | 2 | 1 | — | 4 |
| PSCo (b) | (2) | 3 | — | — | 1 |
|  | $(14) | $(3) | $(3) | $2 | $(18) |

| (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) | $— | $— | $12 | $2 | $14 |
|  | $— | $— | $12 | $2 | $14 |

(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 nine months ended Sept. 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 | 1 |
| Commodity trading contract additions and changes during the period | (7) | 33 |
| Fair value of commodity trading net contracts outstanding at Sept. 30 | $(4) | $1 |

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 $2 million and $4 million at Sept. 30, 2024 and Sept. 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 Sept. 30 | Average | High | Low |
| --- | ---: | ---: | ---: | ---: |
| 2024 | $— | $— | $1 | $— |
| 2023 | 1 | 1 | 2 | 1 |

***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 $1 million and $2 million in Sept. 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 Sept. 30, 2024, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $31 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $30 million. At Sept. 30, 2023, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $32 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $28 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) | Nine Months Ended Sept 30 |
| --- | ---: |
| Cash provided by operating activities — 2023 | $4,353 |
| Components of change — 2024 vs. 2023 |  |
| Higher net income | 110 |
| Non-cash transactions | 183 |
| Changes in deferred income taxes | 579 |
| Changes in working capital | (799) |
| Changes in net regulatory and other assets and liabilities | (449) |
| Cash provided by operating activities — 2024 | $3,977 |

Net cash provided by operating activities decreased $376 million for the nine months ended Sept. 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) | Nine Months Ended Sept 30 |
| --- | ---: |
| Cash used in investing activities — 2023 | $(4,292) |
| Components of change — 2024 vs. 2023 |  |
| Increased capital expenditures | (907) |
| Other investing activities | 2 |
| Cash used in investing activities — 2024 | $(5,197) |

Net cash used in investing activities increased $905 million for the nine months ended Sept. 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) | Nine Months Ended Sept 30 |
| --- | ---: |
| Cash provided by financing activities — 2023 | $422 |
| Components of change — 2024 vs. 2023 |  |
| Lower net short-term repayments | 123 |
| Higher long-term debt issuances, net of repayments | 1,113 |
| Higher proceeds from issuance of common stock | 1,026 |
| Other financing activities | (48) |
| Cash provided by financing activities — 2024 | $2,636 |

Net cash provided by financing activities increased $2,214 million for the nine months ended Sept. 30, 2024 compared with the prior year. The increase was largely related to additional debt and common stock 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 Oct. 28, 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 | $45 | $1,455 | $31 | $1,486 |
| PSCo | 700 | 31 | 669 | 536 | 1,205 |
| NSP-Minnesota | 700 | 12 | 688 | 198 | 886 |
| SPS | 500 | — | 500 | 115 | 615 |
| NSP-Wisconsin | 150 | — | 150 | 104 | 254 |
| Total | $3,550 | $88 | $3,462 | $984 | $4,446 |

(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 Sept. 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.

***Capital Expenditures —*** Base capital expenditures and incremental capital forecasts for Xcel Energy for 2025 through 2029 are as follows:

| By Regulated Utility | Base Capital Forecast (Millions of Dollars) 2025 | 2026 | 2027 | 2028 | 2029 | Total |
| --- | ---: | ---: | ---: | ---: | ---: | ---: |
| PSCo | $5,820 | $5,190 | $3,940 | $3,780 | $3,550 | $22,280 |
| NSP-Minnesota | 3,240 | 2,500 | 2,830 | 2,080 | 2,570 | 13,220 |
| SPS | 1,400 | 1,540 | 1,280 | 1,040 | 1,040 | 6,300 |
| NSP-Wisconsin | 640 | 650 | 690 | 660 | 670 | 3,310 |
| Other (a) | (100) | (40) | 10 | 10 | 10 | (110) |
| Total base capital expenditures | $11,000 | $9,840 | $8,750 | $7,570 | $7,840 | $45,000 |

(a) Other category includes intercompany transfers for safe harbor wind turbines.

| By Function | Base Capital Forecast (Millions of Dollars) 2025 | 2026 | 2027 | 2028 | 2029 | Total |
| --- | ---: | ---: | ---: | ---: | ---: | ---: |
| Electric distribution | $2,570 | $3,000 | $3,400 | $3,320 | $3,540 | $15,830 |
| Electric transmission | 2,260 | 2,860 | 2,740 | 2,390 | 2,310 | 12,560 |
| Renewables | 3,360 | 1,400 | 260 | — | — | 5,020 |
| Electric generation | 1,210 | 1,150 | 910 | 580 | 620 | 4,470 |
| Natural gas | 800 | 680 | 690 | 630 | 620 | 3,420 |
| Other | 800 | 750 | 750 | 650 | 750 | 3,700 |
| Total base capital expenditures | $11,000 | $9,840 | $8,750 | $7,570 | $7,840 | $45,000 |

The base plan does not include any potential incremental generation or transmission assets that are pending commission approval through a RFP, a resource plan, or from additional data center load, which could result in additional capital expenditures of approximately $10 billion or greater. Xcel Energy generally expects to fund additional capital investment with approximately 40% equity and 60% debt.

Xcel Energy’s capital expenditure forecast is subject to continuing review and modification. Actual capital expenditures may vary from estimates due to changes in electric and natural gas projected load growth, safety and reliability needs, regulatory decisions, legislative initiatives, tax policy, reserve requirements, availability of purchased power, alternative plans for meeting long-term energy needs, environmental initiatives and regulation, and merger, acquisition and divestiture opportunities.

***Financing for Capital Expenditures through 2029 —*** Xcel Energy issues debt and equity securities to refinance retiring debt maturities, reduce short-term debt, fund capital programs, infuse equity in subsidiaries, fund asset acquisitions and for general corporate purposes. Current estimated financing plans of Xcel Energy for 2025-2029 (includes the impact of tax credit transferability):

| (Millions of Dollars) Funding Capital Expenditures |  |
| --- | ---: |
| Cash from operations (a) | $25,320 |
| New debt (b) | 15,180 |
| Equity through the DRIP and benefit program | 500 |
| Other equity | 4,000 |
| Base capital expenditures 2025-2029 | $45,000 |
| Maturing debt | $3,730 |

(a) Net of dividends and pension funding.

(b) Reflects a combination of short and long-term debt; net of refinancing.

***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 |

In the nine months ended Sept. 30, 2024, 18.27 million shares ($1.1 billion in net proceeds) were issued under an ATM program.

***Long-Term Borrowings, Equity Issuances and Other Financing Instruments —*** Xcel Energy may issue equity through its ATM 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, including requests for deferral of incremental insurance costs associated with wildfire risk.
- 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 decline by ~1%.
- Capital rider revenue is projected to increase $60 million to $70 million (net of PTCs).
- O&M expenses are projected to increase 3% to 4%.
- Depreciation expense is projected to increase approximately $290 million to $300 million.
- Property taxes are expected to decline $10 to $20 million.
- Interest expense (net of AFUDC - debt) is projected to increase $130 million to $140 million, net of interest income.
- AFUDC - equity is projected to increase $70 million to $80 million.

***Xcel Energy 2025 Earnings Guidance —*** Xcel Energy’s 2025 ongoing earnings guidance is a range of $3.75 to $3.85 per share.(a)

Key assumptions as compared with 2024 projected levels unless noted:

- Constructive outcomes in all pending rate case and regulatory proceedings, including requests for deferral of incremental insurance costs associated with wildfire risk and recovery of O&M costs associated with wildfire mitigation plans.
- Normal weather patterns for the year.
- Weather-normalized retail electric sales are projected to increase ~3%.
- Weather-normalized retail firm natural gas sales are projected to increase ~1%.
- Capital rider revenue is projected to increase $240 million to $250 million (net of PTCs).
- O&M expenses are projected to increase ~3%.
- Depreciation expense is projected to increase approximately $210 million to $220 million.
- Property taxes are projected to increase $40 million to $50 million.
- Interest expense (net of AFUDC - debt) is projected to increase $130 million to $140 million, net of interest income.
- AFUDC - equity is projected to increase $120 million to $130 million.

(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 6% to 8% based off of $3.55 per share (the mid-point of 2024 original ongoing earnings guidance of $3.50 to $3.60 per share).
- Deliver annual dividend increases of 4% to 6%.
- 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, 1,202 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 Sept. 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 Oct 31, 2024.
Source: SEC EDGAR, the filing index for accession 0000072903-24-000199. Last ingested by Listed: Nov 7, 2026, 12:19 ET. No prices; not investment advice.