XCEL ENERGY INC

Previous wording

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 months ended March 31, 2024 and 2023, there were no such adjustments to GAAP earnings and therefore GAAP earnings equal ongoing earnings for these periods.

Current wording

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.

Previous wording

Xcel Energy — Xcel Energy’s first quarter GAAP and ongoing diluted earnings were $0.88 per share, compared with $0.76 per share in the same period in 2023. The increase in earnings per share was primarily driven by increased recovery of infrastructure investments, higher AFUDC and lower O&M expenses, partially offset by increased interest charges and depreciation. 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).

Current wording

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).

Previous wording

NSP-Minnesota— GAAP and ongoing earnings increased $0.13 per share for the first quarter of 2024. The change was driven by increased recovery of electric and natural gas infrastructure investments and lower O&M expenses, partially offset by higher interest expenses and depreciation.

Current wording

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.

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SPS— GAAP and ongoing earnings were flat for the first quarter of 2024 primarily due to regulatory rate outcomes and lower O&M expenses, offset by increased depreciation and amortization expenses.

Current wording

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.

Previous wording

Xcel Energy Inc. and Other— Primarily includes financing costs and interest income at the holding company and earnings from Energy Impact Partners (EIP) funds equity method investments. The decline in earnings is largely due to increased interest rates.

Current wording

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.

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Percentage increase (decrease) in normal and actual HDD:

Current wording

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

Previous wording

•PSCo — Residential sales decreased due to a 1.5% 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 information and professional services sectors partially offset by increases in the manufacturing and health care sectors.

Current wording

•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.

Previous wording

•NSP-Minnesota — Residential sales decreased due to a 3.5% 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.

Current wording

•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.

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•SPS — Residential sales declined as a result of a 4.6% 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.

Current wording

•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.

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•NSP-Wisconsin — Residential sales declined due to a 4.9% 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.

Current wording

•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.

Previous wording

•Increase in natural gas sales was driven by continued strength in PSCo residential and C&I use per customer. Additionally, overall residential and C&I customer growth was 1.1% and 0.6%, respectively.

Current wording

•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.

Previous wording

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. In the first quarter, electric revenues decreased $78 million.

Current wording

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.

Previous wording

Natural gas revenues vary with changing sales, the cost of natural gas and regulatory outcomes. In the first quarter, natural gas revenues decreased $347 million.

Current wording

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

Previous wording

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. However, these incurred expenses are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are generally offset in operating revenues and have minimal earnings impact.

Current wording

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.

Previous wording

Electric fuel and purchased power expenses decreased $169 million for the first quarter of 2024. The decrease is primarily due to lower commodity prices and timing of fuel recovery.

Current wording

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.

Previous wording

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 generally offset in operating revenues and have minimal earnings impact.

Current wording

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.

Previous wording

Natural gas sold and transported decreased $361 million for the first quarter of 2024. The decrease is primarily due to l lower commodity prices, timing of fuel recovery and decreased volumes.

Current wording

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.

Previous wording

O&M Expenses — O&M expenses decreased $45 million for the first quarter. The decrease was primarily due to decreased labor and benefit costs, gain on land sale, and lower bad debt expenses.

Current wording

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.

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Depreciation and Amortization— Depreciation and amortization increased $34 million for the first quarter as a result of system expansion, offset by depreciation life extensions implemented in the Minnesota Electric Rate Case.

Current wording

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.

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Interest Charges— Interest charges increased $38 million for the first quarter, largely due to increased long-term debt levels and higher interest rates.

Current wording

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.

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AFUDC, Equity and Debt— AFUDC increased $22 million for the first quarter driven by increased investment in renewable projects in 2024.

Current wording

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.

Previous wording

2024 Minnesota Natural Gas Rate Case — In November 2023, NSP-Minnesota filed a request with the MPUC for an annual 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).

Current wording

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).

Previous wording

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%), a 2024 test year, ROE of 10.20%, an equity ratio of 52.5% and rate base of $168 million. In February 2024, the NDPSC approved interim rates of $8 million, effective March 1, 2024.

Current wording

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.

Previous wording

2022 Upper Midwest IRP Resource Acquisition —Following the MPUC’s approval of NSP-Minnesota and NSP-Wisconsin’s latest IRP in April 2022, NSP-Minnesota and NSP-Wisconsin have been engaged in multiple resource acquisition processes and proceedings to meet the need identified in the IRP.

Current wording

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.

Previous wording

•In July 2023, NSP-Wisconsin issued an RFP seeking approximately 650 MW of solar and/or solar plus storage development assets that will be developed in the 2027-2029 timeframe to replace the capacity from the retiring King Generating Station. The RFP closed in September 2023 and bids are being evaluated.

Current wording

•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.

Previous wording

•In October 2023, NSP-Minnesota issued an RFP seeking approximately 1,200 MW of wind development assets to replace capacity and reutilize interconnection rights associated with the retiring Sherco coal facilities. The RFP closed in December 2023 and NSP-Minnesota expects to file for approval of recommended projects by mid-2024.

Current wording

•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.

Previous wording

These proposed resources are in addition to projects already approved by the MPUC. NSP-Minnesota anticipates a MPUC decision in 2025.

Current wording

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.

Previous wording

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, or an approximately 9.5% increase in the average residential customer bill. The request is based on a 2023 test year, a 10.25% ROE, an equity ratio of 55% 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.

Current wording

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.

Previous wording

PSCo has proposed to defer collection of the increased rates until Feb. 15, 2025 (following the 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.

Current wording

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.

Previous wording

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. PSCo expects to invest approximately $4.8 billion in generation resources under the portfolio for the benefit of its customers and achieving the state’s clean energy goals.

Current wording

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.

Previous wording

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

Current wording

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.

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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. The CPUC approved PSCo’s proposal to offer rebates for residential chargers and wiring to be paired with residential managed charging programs and vehicle rebates for Income-Qualified customers, as well as its proposal to offer rebates for commercial public chargers and electric vehicle supply infrastructure. Additionally, the CPUC approved PSCo’s proposed budget to support innovation projects including electric school buses, Vehicle-to-Everything demonstrations, and stakeholder-driven projects with a focus on disproportionately impacted communities. The Commission also approved a WACC return on rebates with a 3-year amortization.

Current wording

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.

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CPUC Proactive Line De-Energization Investigation— In early April 2024, PSCo proactively de-energized certain lines in Colorado due to winds that were over 90 MPH to reduce potential wildfire risk. Later in April, the CPUC opened a Miscellaneous Proceeding to seek information on:

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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.

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Colorado Legislation — In May 2023, Colorado Senate Bill 23-291 passed and 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).

Current wording

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).

Previous wording

In November 2023, the CPUC approved PSCo’s natural gas price risk management plan, 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.

Current wording

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.

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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 the first quarter of 2024, the CPUC discussed proposed rules for the gas utility. The written notice of the proposed rule is expected in the second quarter of 2024, which will be followed by a comment period. The Commission's proposed rules for electric utilities are expected later in 2024.

Current wording

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.

Previous wording

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%). The request was based on a ROE of 10.65%, an equity ratio of 54.6%, a retail rate base of $3.6 billion and a change in the Tolk coal plant depreciation life from 2034 to 2028.

Current wording

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:

Previous wording

•A 9.55% ROE, a 54.51% equity ratio and a 7.11% WACC for purposes of calculating SPS’ allowance for funds used during construction and in other proceedings filed before the PUCT where a stated WACC is required.

Current wording

•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.

Previous wording

2022 All-Source RFP— In July 2023, SPS filed for approval of a Certificate of Convenience and Necessity for a recommended generation portfolio, which includes 418 MW of self-build solar projects and a 36 MW battery. A decision from PUCT and NMPRC is expected in mid-2024.

Current wording

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.

Previous wording

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. Regulatory decisions on these PPA agreements are expected in the third quarter of 2024.

Current wording

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.