Weather-normalized electric sales growth (decline) — year-to-date
•PSCo — Residential sales declined due to decreased use per customer, partially offset by a 1.1% increase in customers. C&I sales decline was attributable to decreased use per customer, primarily in the manufacturing sector (largely due to an alternative generation arrangement with a significant customer), partially offset by strong small C&I sales in the food services and health care sectors.
•NSP-Minnesota — Residential sales decline reflects a decreased use per customer, partially offset by a 1.1% increase in customers. Growth in C&I sales was primarily due to higher use per customer, particularly in the manufacturing, real estate and leasing, and food service sectors.
•SPS — Residential sales growth was primarily attributable to a 0.9% increase in customers, partially offset by lower use per customer. C&I sales increased due to higher use per customer, primarily driven by the energy sector.
•NSP-Wisconsin — C&I sales growth was associated with higher use per customer, experienced primarily in the transportation and manufacturing sectors.
Weather-normalized natural gas sales growth (decline) — year-to-date
•Natural gas sales reflect growth in NSP-Minnesota and NSP-Wisconsin attributable primarily to increased residential use per customer and customer growth as well as increases in C&I sales due to higher use per customer. These increases were offset by a reduction in PSCo natural gas sales, primarily driven by declines in residential use per customer.
Electric Margin
Electric margin is presented as electric revenues less electric fuel and purchased power expenses. Expenses incurred for electric fuel and purchased power are generally recovered through various regulatory recovery mechanisms.
As a result, changes in these expenses are generally offset in operating revenues.
Electric revenues and fuel and purchased power expenses are impacted by fluctuations in the price of natural gas, coal and uranium. These price fluctuations generally have minimal impact on earnings impact due to fuel recovery mechanisms. In addition, electric customers receive a credit for PTCs generated, which reduce electric revenue and income taxes.
Electric Revenues, Fuel and Purchased Power and Electric Margin
| | | | | | | | | | | | | | |
| (Millions of Dollars) | | 2022 | | 2021 |
| Electric revenues | | $ | 12,123 | | | $ | 11,205 | |
| Electric fuel and purchased power | | (5,005) | | | (4,733) | |
| Electric margin | | $ | 7,118 | | | $ | 6,472 | |
Change in Electric Margin
| | | | | | | | |
| (Millions of Dollars) | | 2022 vs. 2021 |
| Regulatory rate outcomes (Minnesota, Colorado, Texas, New Mexico and Wisconsin) | | $ | 506 | |
Revenue recognition for the Texas rate case surcharge (a) | | 85 | |
Sales and demand (b) | | 80 | |
| Non-fuel riders | | 64 | |
| Wholesale transmission (net) | | 50 | |
| Estimated impact of weather (net of decoupling/sales true-up) | | 33 | |
| | |
| PTCs flowed back to customers (offset by lower ETR) | | (150) | |
| | |
| Other (net) | | (22) | |
| Total increase | | $ | 646 | |
(a)Recognition of revenue from the Texas rate case outcome is largely offset by recognition of previously deferred costs.
(b)Sales excludes weather impact, net of decoupling in Colorado and proposed sales true-up mechanism in Minnesota.
Natural Gas Margin
Natural gas margin is presented as natural gas revenues less the cost of natural gas sold and transported. Expenses incurred for the cost of natural gas sold are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are generally offset in operating revenues.
Natural gas expense varies with changing sales and the cost of natural gas. However, fluctuations in the cost of natural gas generally have minimal earnings impact due to cost recovery mechanisms.
Natural Gas Revenues, Cost of Natural Gas Sold and Transported and Natural Gas Margin
| | | | | | | | | | | | | | |
| (Millions of Dollars) | | 2022 | | 2021 |
| Natural gas revenues | | $ | 3,080 | | | $ | 2,132 | |
| Cost of natural gas sold and transported | | (1,910) | | | (1,081) | |
| Natural gas margin | | $ | 1,170 | | | $ | 1,051 | |
Change in Natural Gas Margin
| | | | | | | | |
| (Millions of Dollars) | | 2022 vs. 2021 |
| Regulatory rate outcomes (Minnesota, Colorado, Wisconsin, North Dakota) | | $ | 61 | |
| Estimated impact of weather | | 46 | |
| Conservation revenue (offset in expenses) | | 13 | |
| Infrastructure and integrity riders | | 9 | |
| Winter Storm Uri disallowances | | (20) | |
| Other (net) | | 10 | |
| | |
| Total increase | | $ | 119 | |
Non-Fuel Operating Expenses and Other Items
O&M Expenses — O&M expenses increased $170 million year-to-date, due to the following approximately equal drivers: inflation and impacts of supply chain constraints; operational activities (vegetation management, repairs/maintenance and storms); costs for technology and customer programs; insurance-related costs; recognition of previously deferred amounts related to the 2021 Texas rate case; and other.
Depreciation and Amortization — Depreciation and amortization increased $292 million year-to-date. The increase was primarily driven by capital investment, recognition of previously deferred costs related to the Texas Electric Rate Case and several wind farms going into service.
Other Income (Expense) — Other income (expense) decreased $18 million year-to-date, largely related to rabbi trust performance, which is primarily offset in O&M expenses (employee benefit costs).
Earnings from Equity Method Investments — Earnings from equity method investments decreased $26 million year-to-date. The year-to-date change was largely attributable to the performance of the EIP funds, which invest in energy technology companies.
Interest Charges — Interest charges increased $111 million year-to-date. The increase was largely due to higher long-term debt levels to fund capital investments and higher interest rates.
Income Taxes — Income tax benefit increased $65 million year-to-date. The year-to-date increase was primarily driven by an increase in wind PTCs due to greater production at existing wind farms, several new wind farms going into service and an increase in the PTC rate partially offset by higher pretax earnings.
Xcel Energy Inc. and Other Results
Net income and diluted EPS contributions of Xcel Energy Inc. and its nonregulated businesses:
| | | | | | | | | | | | | | |
| | Contribution (Millions of Dollars) |
| | 2022 | | 2021 |
| Xcel Energy Inc. financing costs | | $ | (153) | | | $ | (129) | |
| | | | |
| | | | |
Venture Holdings (a) | | 5 | | | 21 | |
| Xcel Energy Inc. taxes and other results | | (12) | | | (12) | |
| Total Xcel Energy Inc. and other costs | | $ | (160) | | | $ | (120) | |
| | | | | | | | | | | | | | |
| | Contribution (Diluted Earnings (Loss) Per Share) |
| | 2022 | | 2021 |
| Xcel Energy Inc. financing costs | | $ | (0.28) | | | $ | (0.24) | |
| | | | |
| | | | |
Venture Holdings (a) | | 0.01 | | | 0.04 | |
| Xcel Energy Inc. taxes and other results | | (0.02) | | | (0.02) | |
| Total Xcel Energy Inc. and other costs | | $ | (0.29) | | | $ | (0.22) | |
(a)Amounts include gains or losses associated with EIP investments.
Xcel Energy Inc.’s results include interest charges, which are incurred at Xcel Energy Inc. and are not directly assigned to individual subsidiaries.
2021 Comparison with 2020
A discussion of changes in Xcel Energy’s results of operations, cash flows and liquidity and capital resources from the year ended Dec. 31, 2020 to Dec. 31, 2021 can be found in Part II, “Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our Annual Report on Form 10-K for the fiscal year 2021, which was filed with the SEC on Feb. 23, 2022. However, such discussion is not incorporated by reference into, and does not constitute a part of, this Annual Report on Form 10-K. | | |
| Public Utility Regulation |
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 DSM 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 and credit quality.
See Rate Matters within Note 12 to the consolidated financial statements for further information.
NSP-Minnesota
Summary of Regulatory Agencies / RTO and Areas of Jurisdiction
| | | | | | | | |
| Regulatory Body / RTO | | Additional Information |
| MPUC | | Retail rates, services, security issuances, property transfers, mergers, disposition of assets, affiliate transactions, and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Certifies the need and siting for generating plants greater than 50 MW and transmission lines greater than 100 KV in Minnesota. Reviews and approves natural gas supply plans. |
| NDPSC | | Retail rates, services and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in North Dakota. Pipeline safety compliance. |
| SDPUC | | Retail rates, services and other aspects of electric operations. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in South Dakota. Pipeline safety compliance. |
| FERC | | Wholesale electric operations, hydroelectric licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transfers and mergers, and natural gas transactions in interstate commerce. |
| MISO | | NSP-Minnesota is a transmission owning member of the MISO RTO and operates within the MISO RTO and wholesale markets. NSP-Minnesota makes wholesale sales in other RTO markets at market-based rates. NSP-Minnesota and NSP-Wisconsin also make wholesale electric sales at market-based prices to customers outside of their balancing authority as jointly authorized by the FERC. |
| DOT | | Pipeline safety compliance. |
| Minnesota Office of Pipeline Safety | | Pipeline safety compliance. |
Recovery Mechanisms
| | | | | | | | |
| Mechanism | | Additional Information |
CIP Rider (a) | | Recovers costs of conservation and DSM programs in Minnesota. |
| Environmental Improvement Rider | | Recovers costs of environmental improvement projects in Minnesota. |
| Renewable Development Fund | | Allocates money collected from customers to support research and development of emerging renewable energy projects and technologies in Minnesota. |
| RES | | Recovers cost of renewable generation in Minnesota. |
| Renewable Energy Rider | | Recovers cost of renewable generation in North Dakota. |
| Transmission Cost Recovery | | Recovers costs for investments in Minnesota, North Dakota, and South Dakota for electric transmission and distribution grid modernization. |
| Infrastructure Rider | | Recovers costs for investments in generation in South Dakota. |
| FCA | | Recovers prudently incurred costs of fuel related items and purchased energy (Minnesota, North Dakota and South Dakota). |
| Purchased Gas Adjustment | | Provides for prospective monthly rate adjustments in Minnesota and North Dakota for costs of purchased natural gas, transportation and storage service. Includes a true-up process for difference between projected and actual costs. |
| GUIC Rider | | Recovers costs for transmission and distribution pipeline integrity management programs, including funding for pipeline assessments, deferred costs for sewer separation and pipeline integrity management programs in Minnesota. The statute authorizing the GUIC Rider is set to expire June 30, 2023. |
| Sales True-up | | NSP-Minnesota has historically had a sales true-up mechanism for all electric customer classes which ended in 2021. We are requesting implementation of a new sales true-up mechanism for 2022 - 2024. These mechanisms mitigate the impact of changes to sales levels as compared to a baseline. |
(a)Minnesota state law requires NSP-Minnesota to spend 2% of its state electric revenues and 0.5% of its state natural gas revenues on CIP. These costs are recovered through an annual cost-recovery mechanism.
Pending and Recently Concluded Regulatory Proceedings
2022 Minnesota Electric Rate Case — In October 2021, NSP-Minnesota filed a three-year electric rate case with the MPUC. The request is based on a ROE of 10.2%, a 52.5% equity ratio and forward test years.
In December 2021, the MPUC approved interim rates, subject to refund, of $247 million, effective Jan. 1, 2022. In November 2022, NSP-Minnesota revised its rate request to $498 million over three years.
The revised request is detailed as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| (Amounts in Millions) | | 2022 | | 2023 | | 2024 | | Total |
| Rate request (annual increase) | | $ | 234 | | | $ | 94 | | | $ | 170 | | | $ | 498 | |
| Rate base | | 10,923 | | | 11,425 | | | 11,902 | | | N/A |
In 2022, several parties filed testimony with various recommendations. The DOC provided the following recommendations in surrebuttal testimony.
| | | | | | | | | | | | | | | | | | | | |
| | 2022 | | 2023 | | 2024 |
| NSP-Minnesota’s filed base revenue request | | $ | 396 | | | $ | 546 | | | $ | 677 | |
| | | | | | |
| Recommended adjustments: | | | | | | |
| Rate base and rate of return | | (72) | | | (65) | | | (65) | |
| MISO capacity credits | | (66) | | | (112) | | | (111) | |
| Sales forecast update | | (51) | | | — | | | — | |
| Monticello and wind farm life extension | | (21) | | | (54) | | | (51) | |
| PTC forecast | | (28) | | | (1) | | | (1) | |
| Property tax | | (14) | | | (23) | | | (34) | |
| Prepaid pension asset and liability | | (13) | | | (21) | | | (32) | |
| O&M expenses | | (37) | | | (39) | | | (44) | |
| Sherco 3 and King remaining life | | — | | | 29 | | | 28 | |
| Other, net | | (23) | | | (33) | | | (43) | |
| | | | | | |
| Total adjustments | | (325) | | | (319) | | | (353) | |
| Total proposed revenue change | | $ | 71 | | | $ | 227 | | | $ | 324 | |
Next steps in the procedural schedule are expected to be as follows:
•ALJ Report: March 31, 2023.
•MPUC Order: June 30, 2023.
2022 Minnesota Natural Gas Rate Case — In November 2021, NSP-Minnesota filed a request with the MPUC for a natural gas rate increase of $36 million, or 6.6%. The filing is based on a 2022 forecast test year and includes a requested ROE of 10.5%, an equity ratio of 52.5% and a rate base of $934 million. In December 2021, the MPUC approved an interim rate increase of $25 million, subject to refund, effective Jan. 1, 2022.
In October 2022, NSP-Minnesota and various parties filed an uncontested settlement, which includes the following key terms:
•Base rate revenue increase of $21 million, with a true up to weather normalized actual sales for 2022.
•Revenue decoupling mechanism.
•Symmetrical property tax true-up.
•ROE of 9.57%.
•Equity ratio of 52.5%.
In December 2022, the ALJ recommended MPUC approval of the settlement. A MPUC decision is expected in the first half of 2023.
2021 North Dakota Natural Gas Rate Case — In September 2021, NSP-Minnesota filed a request with the NDPSC for a natural gas rate increase of $7 million, or 10.5%. The filing is based on a ROE of 10.5%, an equity ratio of 52.54%, a 2022 forecast test year and rate base of $124 million. Interim rates of $7 million, subject to refund, were implemented on Nov. 1, 2021.
In May 2022, NSP-Minnesota and NDPSC Staff reached a settlement, which reflects a rate increase of $5 million, based on a 9.8% ROE and 52.54% equity ratio. In October 2022, the NDPSC approved the settlement and final rates were implemented on Nov. 1, 2022.
South Dakota Electric Rate Case — In June 2022, NSP-Minnesota filed a South Dakota electric rate case seeking a revenue increase of approximately $44 million. The filing is based on a 2021 historic test year adjusted for certain known and measurable changes for 2022 and 2023, a ROE of 10.75%, rate base of approximately $947 million and an equity ratio of 53%. Interim rates were implemented on Jan. 1, 2023. Final rates are expected to be approved by the SDPUC in mid-2023.
Wind Repowering — In January 2021, the MPUC approved NSP-Minnesota’s request for the repowering of 651 MW of owned wind projects. Two of the four repowering projects, where construction has not yet begun (in-service dates in 2025), now expect costs in excess of the original approval. While the capital costs have increased, the passage of the IRA and other changes result in a levelized cost of energy that is approximately 30% lower than the original approval.
In October 2022, NSP-Minnesota filed a request with the MPUC seeking approval of the higher capital costs for these repowering projects. In February 2023, the DOC filed comments recommending approval of recovery of the increased costs of these projects through the RES Rider. A final decision is pending.
2022 Upper Midwest RFP — In August 2022, NSP-Minnesota launched a RFP for 900 MW of solar or solar-plus-storage hybrid resources to come online by the end of 2025, including up to 300 MW of capacity to reuse the Sherco Unit 2 interconnection rights when the coal facility retires at the end of 2023.
NSP-Minnesota completed its bid evaluation process in December 2022 and will file for approval of the selected projects in early 2023.
2022 Minnesota Electric Vehicle Proposal — In August 2022, NSP-Minnesota filed a request with the MPUC for approval of approximately $320 million of capital investments (2022 through 2026) to support a public charging network, electric school bus pilot, and other expansions and modifications to its residential and commercial electric vehicle programs.
In October 2022, the MPUC referred the matter to the Office of Administrative Hearings to conduct a contested case on the proposals. In February 2023, other parties to the contested proceeding filed their direct testimony ranging in levels of support / opposition to the proposals. The evidentiary hearing is scheduled in Q2 2023 with a report from the ALJ expected in Q3 2023. A MPUC decision is expected in late 2023.
Nuclear Power Operations
Nuclear power plant operations produce gaseous, liquid and solid radioactive wastes, which are covered by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment contaminated through use.
NRC Regulation — The NRC regulates nuclear operations. Costs of complying with NRC requirements can affect both operating expenses and capital investments of the plants. NSP-Minnesota has obtained recovery of these compliance costs and expects to recover future compliance costs.
Low-Level Waste Disposal — Low level waste from Monticello and PI is disposed of at the Clive facility located in Utah and the Waste Control Specialists facility in Texas. NSP-Minnesota has storage capacity available on-site at PI and Monticello which would allow both plants to continue to operate until the end of their current licensed lives if off-site low-level waste disposal facilities become unavailable.
High-Level Radioactive Waste Disposal — The federal government has responsibility to permanently dispose of domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high-level waste management.
This includes the siting, licensing, construction and operation of a repository for spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent federal storage or disposal facility. Currently, there are no definitive plans for a permanent federal storage facility site.
Nuclear Spent Fuel Storage — NSP-Minnesota has interim on-site storage for spent nuclear fuel at its Monticello and PI nuclear generating plants. Authorized storage capacity is sufficient to allow NSP-Minnesota to operate until the end of the operating licenses in 2030 for Monticello, 2033 for PI Unit 1, and 2034 for PI Unit 2.
In September 2021, NSP-Minnesota filed an application for a CON for additional spent fuel storage (existing Independent spent fuel storage installation) at the Monticello Nuclear Power Generating Plant to allow continued operation of the Monticello Plant until 2040.
A decision is expected in late 2023. Authorizations for additional spent fuel storage capacity may be required at each site to support either continued operation or decommissioning if the federal government does not commence storage operations.
In February 2023, NSP-Minnesota also filed an application with the NDPSC for an Advance Determination of Prudence for continued operation of the Monticello Plant until at least 2040. A decision is expected in 2023.
Wholesale and Commodity Marketing Operations
NSP-Minnesota conducts wholesale marketing operations, including the purchase and sale of electric capacity, energy, ancillary services and energy-related products. NSP-Minnesota uses physical and financial instruments to minimize commodity price risk and to hedge sales and purchases.
NSP-Minnesota also engages in trading activity unrelated to these hedging activities. Sharing of any margins is determined through state regulatory proceedings as well as the operation of the FERC approved joint operating agreement. NSP-Minnesota does not serve any wholesale requirements customers at cost-based regulated rates.
NSP-Wisconsin
Summary of Regulatory Agencies / RTO and Areas of Jurisdiction
| | | | | | | | |
| Regulatory Body / RTO | | Additional Information |
| PSCW | | Retail rates, services and other aspects of electric and natural gas operations. Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built. The PSCW has a biennial base rate filing requirement. By June of each odd numbered year, NSP-Wisconsin must submit a rate filing for the test year beginning the following January. Pipeline safety compliance. |
| Michigan Public Service Commission | | Retail rates, services and other aspects of electric and natural gas operations. Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built. Pipeline safety compliance. |
| FERC | | Wholesale electric operations, hydroelectric generation licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce. |
| MISO | | NSP-Wisconsin is a transmission owning member of the MISO RTO that operates within the MISO RTO and wholesale energy market. NSP-Wisconsin and NSP-Minnesota are jointly authorized by the FERC to make wholesale electric sales at market-based prices. |
| DOT | | Pipeline safety compliance. |
Pending and Recently Concluded Regulatory Proceedings
Colorado Natural Gas Rate Case — In January 2022, PSCo filed a request with the CPUC seeking a net increase to retail natural gas rates of $107 million. The total change to base rates is $215 million, which reflects the transfer of $108 million previously recovered from customers through the pipeline system integrity adjustment rider. The request was based on a 10.25% ROE, an equity ratio of 55.66% and a 2022 current test year with a projected rate base of $3.6 billion.
PSCo’s request also included step revenue increases of $40 million (effective Nov. 1, 2023) and $41 million (effective Nov. 1, 2024) related to continued capital investment.
In October 2022, the CPUC approved a rate increase net of rider roll-ins of $64 million. The decision reflects a stated WACC of 6.7%, a historic test year with a year-end rate base and $16 million of incremental depreciation expense. PSCo has the option to determine its ROE within a range of 9.2% to 9.5% and its equity ratio within a range of 52% to 55%, as long as it results in a WACC of 6.7%. The CPUC denied the 2023-2024 step increases. Base rates were placed in effect November 1, 2022.
Colorado Electric Rate Case — In November 2022, PSCo filed an electric rate case seeking a net increase of $262 million, or 8.2%. The total request reflects a $312 million increase, which includes $50 million of authorized costs currently recovered through various rider mechanisms. The request is based on a 10.25% ROE, an equity ratio of 55.7% and a 2023 forecast test year with a 2023 year-end rate base of $11.3 billion. PSCo requested rates effective in September 2023. A procedural schedule is expected to be established by the CPUC in the first quarter of 2023.
Colorado Resource Plan — In August 2022, the CPUC approved an updated settlement, which will result in the further acceleration of the retirement of the Comanche Unit 3 coal plant, an expected carbon reduction of at least 85% and an 80% renewable mix by 2030. The CPUC deferred a decision on the method of cost recovery for the retiring coal units to a separate docket, which will consider accelerated depreciation, creation of regulatory assets and securitization. PSCo filed the recovery method docket in the fourth quarter of 2022.
Key settlement terms include:
•Early retirement of Hayden: Unit 2 in 2027 (was 2036); and Unit 1 in 2028 (was 2030).
•Conversion of the Pawnee coal plant to natural gas by no later than Jan. 1, 2026.
•Early retirement of Comanche Unit 3 by Jan. 1, 2031 (was 2070) with reduced operations beginning in 2025.
•Addition of ~2,400 MW of wind.
•Addition of ~1,600 MW of universal-scale solar.
•Addition of 400 MW of storage.
•Addition of 1,300 MW of flexible, dispatchable generation.
•Addition of ~1,200 MW of distributed solar resources through our renewable energy programs.
In December 2022, the Company commenced the RFP process for generation resources with a bid receipt date of March 1, 2023. After reviewing the bids received, PSCo will file a report with the CPUC with recommended resource acquisitions and a CPUC decision on the resources to be acquired is expected in October 2023.
Decoupling Filing — PSCo has a decoupling program, effective April 1, 2020 through Dec. 31, 2023. The program applies to Residential and metered small C&I customers who do not pay a demand charge. The program includes a refund and surcharge cap not to exceed 3% of forecasted base rate revenue for a specified period.
In October 2021, a settlement was reached on Winter Storm Uri costs and also addressed certain components of the 2020 decoupling refunds.
In April 2022, PSCo made its annual filing on this matter. In December 2022, the ALJ approved a settlement between PSCo, CPUC Staff and the UCA. The settlement requires PSCo to file a petition for declaratory judgment to address the treatment of any expired balance under the 3% soft cap provisions.
As of Dec. 31, 2022, PSCo has recognized a refund for Residential customers and a surcharge for small C&I customers based on 2020, 2021 and 2022 results.
Transmission Cost Adjustment — In December 2022, the CPUC suspended PSCo’s request for 2023 TCA rate changes. The CPUC Staff protested the TCA on the grounds that only projects resulting in new transmission should be included and no repair or replacement of existing infrastructure should be included. The CPUC consolidated the matter with the pending electric rate case for assessment.
ECA Fuel Recovery — In December 2022, PSCo filed its first quarter 2023 ECA Advice Letter, which sought to recover $123 million of under-recovered 2022 fuel costs over two quarters (instead of the typical one). In December 2022, the CPUC found that the $123 million should be removed from the proposed ECA rates and required PSCo to file a separate application to recover these fuel costs. Proposed ECA rates were updated to remove the 2022 under-recovered balance and were implemented on Jan. 1, 2023. In February 2023, PSCo submitted an interim ECA filing which included $70 million of the 2022 under-recovered costs. A filing for the remaining amount is anticipated in the first quarter of 2023.
GCA NOPR — In June 2021, the CPUC issued a NOPR addressing the recovery of costs through the GCA. The CPUC has reopened the GCA NOPR and proposed a 2-step process aimed at 1) considering near term process changes to the GCA and 2) a longer term process to evaluate potential performance incentive structures. In step 1, consensus proposed rule amendments to update the process and filing requirements for GCA and related filings have been submitted to the CPUC for consideration. PSCo worked with other utilities and stakeholders regarding consensus proposed rule amendments for step 2, including a provision that each LDC bring forward its own performance incentive mechanism in a future filing. In December 2022, the CPUC approved the consensus proposal.
In February 2023, the Governor of Colorado issued an open letter to the CPUC, utilities, and other stakeholders directing agencies to take additional steps to address energy costs. It is likely this request will result in the opening of additional dockets to further explore the GCA and other related mechanisms. Additionally, the Colorado Legislature announced the formation of a Joint Select Committee to investigate the source of rising utility rates and explore potential actions to prevent future price instability.
Natural Gas Planning NOPR — In October 2021, the CPUC issued a NOPR to implement recent state legislation requiring natural gas utilities to develop clean heat plans to meet state greenhouse gas emission reduction targets, as well as updated demand-side management criteria. Additionally, the proposed rules included new comprehensive natural gas infrastructure planning requirements and related Certificate of Public Convenience and Necessity application procedures, changes in natural gas line extension policy, and details on emission accounting related to clean heat plans. PSCo recommended changes to the proposed rules, which may be incorporated into the final rules issued in the first quarter of 2023.
Purchased Power and Transmission Service Providers
PSCo expects to meet its system capacity requirements through electric generating stations, power purchases, new generation facilities, DSM options and expansion of generation plants.
Purchased Power — PSCo purchases power from other utilities and IPPs. Long-term purchased power contracts for dispatchable resources typically require capacity and energy charges. It also contracts to purchase power for both wind and solar resources. PSCo makes short-term purchases to meet system load and energy requirements, replace owned generation, meet operating reserve obligations, or obtain energy at a lower cost.
Energy Markets — PSCo plans to join the SPP Western Energy Imbalance Service Market in April 2023. This market is an incremental step in the participation in the organized wholesale market. Energy imbalance markets allow participants to buy and sell power close to the time electricity is consumed and gives system operators real-time visibility across neighboring grids. The result improves balancing supply and demand at a lower cost.
Purchased Transmission Services — In addition to using its own transmission system, PSCo has contracts with regional transmission service providers to deliver energy to its customers.
Wholesale and Commodity Marketing Operations
PSCo conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy, ancillary services and energy related products. PSCo uses physical and financial instruments to minimize commodity price risk and hedge sales and purchases. PSCo also engages in trading activity unrelated to these hedging activities.
Sharing of any margin is determined through state regulatory proceedings as well as the operation of the FERC approved joint operating agreement.
SPS
Summary of Regulatory Agencies / RTO and Areas of Jurisdiction
| | | | | | | | |
| Regulatory Body / RTO | | Additional Information |
| PUCT | | Retail electric operations, rates, services, construction of transmission or generation and other aspects of SPS’ electric operations. The municipalities in which SPS operates in Texas have original jurisdiction over rates in those communities. The municipalities’ rate setting decisions are subject to PUCT review. Reviews and approves Integrated Resource Plans for meeting future energy needs |
| NMPRC | | Retail electric operations, retail rates and services and the construction of transmission or generation. |
| FERC | | Wholesale electric operations, accounting practices, wholesale sales for resale, the transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transactions and mergers, and natural gas transactions in interstate commerce. |
| SPP RTO and SPP Integrated and Wholesale Markets | | SPS is a transmission owning member of the SPP RTO and operates within the SPP RTO and SPP integrated and wholesale markets. SPS is authorized to make wholesale electric sales at market-based prices. |
| DOT | | Pipeline safety compliance. |
Recovery Mechanisms
| | | | | | | | |
| Mechanism | | Additional Information |
| Distribution Cost Recovery Factor | | Recovers distribution costs not included in rates in Texas. |
| Energy Efficiency Cost Recovery Factor | | Recovers costs for energy efficiency programs in Texas. |
| Energy Efficiency Rider | | Recovers costs for energy efficiency programs in New Mexico. |
| Fuel and Purchased Power Cost Adjustment Clause | | Adjusts monthly to recover actual fuel and purchased power costs in New Mexico. |
| Power Cost Recovery Factor | | Allows recovery of purchased power costs not included in Texas rates. |
| Renewable Portfolio Standards | | Recovers deferred costs for renewable energy programs in New Mexico. |
| Transmission Cost Recovery Factor | | Recovers certain transmission infrastructure improvement costs and changes in wholesale transmission charges not included in Texas base rates. |
| Fixed Fuel and Purchased Recovery Factor | | Provides for the over- or under-recovery of energy expenses in Texas. Regulations require refunding or surcharging over- or under- recovery amounts, including interest, when they exceed 4% of the utility’s annual fuel and purchased energy costs on a rolling 12-month basis if this condition is expected to continue. |
| Wholesale Fuel and Purchased Energy Cost Adjustment | | SPS recovers fuel and purchased energy costs from its wholesale customers through a monthly wholesale fuel and purchased energy cost adjustment clause accepted by the FERC. Wholesale customers also pay the jurisdictional allocation of production costs. |
| Electric Vehicle Rider | | Recovers costs of the Transportation Electrification Plan in New Mexico. |
| Advanced Metering System Surcharge | | Recovers costs incurred in deployment of the Advanced Metering System in Texas. |
| Consulting Fee Rider | | Recovers consulting fees and carrying charges incurred by SPS on behalf of the PUCT. |
Pending and Recently Concluded Regulatory Proceedings
2021 Texas Electric Rate Case — In May 2022, the PUCT approved a settlement between SPS and intervening parties.
In July 2022, SPS filed to surcharge the final under-recovered amount, estimated to be approximately $85 million, substantially offset by the recognition of previously deferred costs.
| | | | | | | | |
| (Millions of Dollars) | | Year Ended Dec. 31, 2022 |
| Revenue surcharge accrual | | $ | 85 | |
| Depreciation and amortization | | (43) | |
| O&M expenses | | (16) | |
| Interest expense | | (12) | |
| Taxes other than income taxes | | (10) | |
| Fuel and purchased power | | (2) | |
2022 New Mexico Electric Rate Case — In November 2022, SPS filed an electric rate case with NMPRC seeking a revenue increase of $78 million, or 10%. The request is based on a future test year ending June 30, 2024, a ROE of 10.75%, an equity ratio of 54.7% and rate base of $2.4 billion. Additionally, the request reflects further acceleration of the Tolk coal plant depreciation life from 2032 to 2028.
Next steps in the procedural schedule are expected to be as follows:
•Staff and intervenor testimony: March 31, 2023.
•Rebuttal testimony: April 25, 2023.
•Stipulation: May 8, 2023.
•Hearing: June 5, 2023.
•End of rate suspension: Sept. 19, 2023.
2023 Texas Electric Rate Case — On Feb. 8, 2023, SPS filed an electric rate case with the PUCT seeking an increase in base rate revenue of $149 million. The impact to overall customer bills is expected to be approximately 13%. The request is based on a historical test year period ended Sept. 30, 2022, with an Update Period ended Dec. 31, 2022, a ROE of 10.65%, an equity ratio of 54.6% and retail rate base of $3.6 billion. Additionally, the request reflects further acceleration of the Tolk coal plant depreciation life from 2034 to 2028.
SPS is requesting a surcharge from July 13, 2023 through the effective date of new base rates. A PUCT decision is expected in the first quarter of 2024.
SPS and LP&L Contract Termination — SPS and LP&L have a 25-year, 170 MW partial requirements contract. In May 2021, SPS and LP&L finalized a settlement which would terminate the contract upon LP&L’s move from the SPP to the Electric Reliability Council of Texas (expected in 2023). The settlement agreement requires LP&L to pay SPS $78 million (to the benefit of SPS’ remaining customers). LP&L would remain obligated to pay for SPP transmission charges associated with LP&L’s load in SPP. The agreement is pending PUCT and FERC approval.
2022 All-Source RFP — In 2022, SPS issued an RFP, which seeks up to 947 MW of new or existing capacity resources to provide replacement capacity for retiring units and meet SPS’ growing capacity needs through 2027. SPS will receive bids in the first quarter of 2023 and file for the approval of successful proposals in the second quarter of 2023.
Purchased Power Arrangements and Transmission Service Providers
SPS expects to use electric generating stations, power purchases, DSM and new generation options to meet its system capacity requirements.
Purchased Power — SPS purchases power from other utilities and IPPs. Long-term purchased power contracts typically require periodic capacity and energy charges. SPS also makes short-term purchases to meet system load and energy requirements to replace owned generation, meet operating reserve obligations or obtain energy at a lower cost.
Purchased Transmission Services — SPS has contractual arrangements with SPP and regional transmission service providers to deliver power and energy to its native load customers.
Natural Gas
SPS does not provide retail natural gas service, but purchases and transports natural gas for its generation facilities and operates limited natural gas pipeline facilities connecting the generation facilities to interstate natural gas pipelines. SPS is subject to the jurisdiction of the FERC with respect to natural gas transactions in interstate commerce and the PHMSA, DOT and PUCT for pipeline safety compliance.
Wholesale and Commodity Marketing Operations
SPS conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy, ancillary services and energy related products. SPS uses physical and financial instruments to minimize commodity price risk and to hedge sales and purchases. Sharing of any margin is determined through state regulatory proceedings as well as the operation of the FERC approved joint operating agreement.
Supply Chain
Xcel Energy’s ability to meet customer energy requirements, respond to storm-related disruptions and execute our capital expenditure program 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.
Electric Distribution and Transmission Transformers
The availability of certain transformers is an industry-wide issue that has been significantly impacted and in some cases may result in delays in projects and new customer connections. Xcel Energy continues to seek alternative suppliers and prioritize work plans to mitigate impacts of supply constraints.
Solar Resources
In April 2022, the U.S. Department of Commerce initiated an anti-circumvention investigation that would subject CSPV solar panels and cells imported from Malaysia, Vietnam, Thailand, and Cambodia with potential incremental tariffs ranging from 50% to 250%. These countries account for more than 80% of CSPV panel imports.
An interim stay on tariffs has been issued and many significant solar projects have resumed with modified costs and projected in-service dates, including the Sherco Solar facility in Minnesota and certain PPAs in PSCo. Further policy action or other restrictions on solar imports (i.e., as a result of implementation of the Uyghur Forced Labor Protection Act) could impact project timelines and costs.
Marshall Wildfire
In December 2021, a wildfire ignited in Boulder County, Colorado (the “Marshall Fire”), which burned over 6,000 acres and destroyed or damaged over 1,000 structures. Boulder County authorities are currently investigating the fire and have not yet determined a cause. There were no downed power lines in the ignition area, and nothing the Company has seen to this point indicates that our equipment or operations caused the fire.
In Colorado, the standard of review governing liability differs from the “inverse condemnation” or strict liability standard utilized in California. In Colorado, courts look to whether electric power companies have operated their system with a heightened duty of care consistent with the practical conduct of its business, and liability does not extend to occurrences that cannot be reasonably anticipated. In addition, PSCo has been operating under a commission approved wildfire mitigation plan and carries wildfire liability insurance.
In March 2022, a class action suit was filed in Boulder County pertaining to the Marshall Fire. In the remote event PSCo was found liable related to this litigation and were required to pay damages, such amounts could exceed our insurance coverage and have a material adverse effect on our financial condition, results of operations or cash flows. In December 2022, the District Court judge denied PSCo’s Motion to Dismiss.
MISO Capacity Credits
The NSP System offered 1,500 MW of excess capacity into the MISO planning resource auction for June 2022 through May 2023. Due to a projected overall capacity shortfall in the MISO region, the 1,500 MWs offered cleared the auction at maximum pricing, generating revenues of approximately $90 million in 2022, with approximately $60 million expected in 2023. These amounts will primarily be used to mitigate customer rate increases or returned through earnings sharing or other mechanisms.
Inflation Reduction Act
In August 2022, the IRA was signed into law.
Key provisions impacting Xcel Energy include:
•Extends current PTC and ITC for renewable technologies (e.g., wind and solar).
•Restores full value of the PTC and ITC for qualifying facilities placed in-service after 2021.
•Creates a PTC for solar, clean hydrogen and nuclear.
•Establishes an ITC for energy storage, microgrids, interconnection facilities, etc.
•Allows companies to monetize or sell credits to unrelated parties.
Xcel Energy anticipates the IRA will materially reduce the cost of renewable energy, resulting in significant customer savings.
The IRA is expected to allow Xcel Energy to monetize tax credits more efficiently with the incremental benefits passed through to customers. Transferability provisions apply to eligible tax credits generated starting in 2023 for both new and existing facilities. Xcel Energy anticipates tax credit transferability from existing renewable projects will improve cash from operations by $1.8 billion (2023 - 2027), assuming constructive regulatory outcomes and the development of a market.
The IRA creates a nuclear PTC beginning in 2024 that may also provide additional customer savings. The annual customer benefit from these PTCs could range from $0 to $300 million, depending on locational marginal pricing, as well as constructive U.S. Treasury guidance regarding computation of the credits.
In addition, the IRA created a new corporate AMT. Xcel Energy does not anticipate AMT having a material cash impact based on current estimates and our interpretation of its application.
Winter Storm Uri
In February 2021, the United States experienced Winter Storm Uri. Extreme cold temperatures impacted certain operational assets as well as the availability of renewable generation. The cold weather also affected the country’s supply and demand for natural gas.
These factors contributed to extremely high market prices for natural gas and electricity. As a result of the extremely high market prices, Xcel Energy incurred net natural gas, fuel and purchased energy costs of approximately $1 billion (largely deferred as regulatory assets).
Xcel Energy has received recovery approval from all of our impacted states except for Texas, which is pending. A summary of pending and recently approved regulatory requests for Winter Storm Uri cost recovery is listed below.
| | | | | | | | |
| Utility Subsidiary | Jurisdiction | Regulatory Status |
| NSP-Minnesota | Minnesota | In 2021, the MPUC allowed recovery of $179 million of costs (with no financing charge) starting in September 2021, pending a prudency review. The C&I class ($82 million) will be recovered over 27 months and the residential class ($97 million) will be recovered over a 63-month recovery period.
In August 2022, the MPUC approved recovery of Uri storm costs with a $19 million disallowance. |
| PSCo | Colorado | In May 2021, PSCo filed a request with the CPUC to recover $263 million in weather-related electric costs, $287 million in incremental natural gas costs and $4 million in incremental steam costs over 24 months with no financing charge.
In July 2022, the CPUC approved a partial settlement providing full recovery of fuel costs, with the exception of an $8 million disallowance, over 24 months for electric and 30 months for natural gas customers. |
| SPS | Texas | In 2021, SPS filed to recover $88 million of Winter Storm Uri costs over 24 months, as part of the Texas fuel surcharge filing, with total under-recovered costs of $121 million. In April 2022, interim rates designed to recover $121 million over 30 months were approved, subject to PUCT approval through the triennial Fuel Reconciliation proceeding.
In July 2022, the intervenors filed recommendations. The Texas Industrial Energy Consumers and PUCT staff recommended disallowances of approximately $10 million (off-system sales margins). The Office of Public Utility Counsel recommended disallowances of approximately $15 million (off-system sales margins and adjustment to energy loss factors). The Alliance of Xcel Municipalities recommended disallowances of approximately $100 million (natural gas storage, contracted capability and off-system sales margins).
In November 2022, the ALJs found that costs were prudently incurred and recommended no disallowances. A final PUCT decision is anticipated in the first quarter of 2023. |
| | |
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. In addition, the financial and operating environment also may have a significant effect on the operation of the business and results reported.
Accounting policies and estimates that are most significant to Xcel Energy’s results of operations, financial condition or cash flows, and require management’s most difficult, subjective or complex judgments are outlined below. Each of these has a higher likelihood of resulting in materially different reported amounts under different conditions or using different assumptions. Each critical accounting policy has been reviewed and discussed with the Audit Committee of Xcel Energy Inc.’s Board of Directors on a quarterly basis.
Regulatory Accounting
Xcel Energy is subject to the accounting for Regulated Operations, which provides that rate-regulated entities report assets and liabilities consistent with the recovery of those incurred costs in rates, if it is probable that such rates will be charged and collected. Our rates are derived through the ratemaking process, which results in the recording of regulatory assets and liabilities based on the probability of future cash flows.
Regulatory assets generally represent incurred or accrued costs that have been deferred because future recovery from customers is probable. Regulatory liabilities generally represent amounts that are expected to be refunded to customers in future rates or amounts collected in current rates for future costs. In other businesses or industries, regulatory assets and regulatory liabilities would generally be charged to net income or other comprehensive income.
Each reporting period we assess the probability of future recoveries and obligations associated with regulatory assets and liabilities. Factors such as the current regulatory environment, recently issued rate orders and historical precedents are considered. Decisions made by regulatory agencies can directly impact the amount and timing of cost recovery as well as the rate of return on invested capital, and may materially impact our results of operations, financial condition or cash flows.
As of Dec. 31, 2022 and 2021, Xcel Energy had regulatory assets of $3.9 billion and $3.8 billion, respectively and regulatory liabilities of $6.0 billion and $5.7 billion, respectively. Each subsidiary is subject to regulation that varies from jurisdiction to jurisdiction. If future recovery of costs in any such jurisdiction is no longer probable, Xcel Energy would be required to charge these assets to current net income or other comprehensive income.
At Dec. 31, 2022, in assessing the probability of recovery of recognized regulatory assets, unless otherwise disclosed, Xcel Energy noted no current or anticipated proposals or changes in the regulatory environment that it expects will materially impact the recovery of the assets.
See Notes 4 and 12 to the consolidated financial statements for further information.
Income Tax Accruals
Judgment, uncertainty and estimates are a significant aspect of the income tax accrual process that accounts for the effects of current and deferred income taxes. Uncertainty associated with the application of tax statutes and regulations and outcomes of tax audits and appeals require that judgment and estimates be made in the accrual process and in the calculation of the ETR.
Changes in tax laws and rates may affect recorded deferred tax assets and liabilities and our future ETR. ETR calculations are revised every quarter based on best available year-end tax assumptions, adjusted in the following year after returns are filed. Tax accrual estimates are trued-up to the actual amounts claimed on the tax returns and further adjusted after examinations by taxing authorities, as needed.
In accordance with the interim period reporting guidance, income tax expense for the first three quarters in a year is based on the forecasted annual ETR. The forecasted ETR reflects a number of estimates, including forecasted annual income, permanent tax adjustments and tax credits.
Valuation allowances are applied to deferred tax assets if it is more likely than not that at least a portion may not be realized based on an evaluation of expected future taxable income. Accounting for income taxes also requires that only tax benefits that meet the more likely than not recognition threshold can be recognized or continue to be recognized.
We may adjust our unrecognized tax benefits and interest accruals as disputes with the IRS and state tax authorities are resolved, and as new developments occur. These adjustments may increase or decrease earnings.
See Note 7 to the consolidated financial statements for further information.
Employee Benefits
We sponsor several noncontributory, defined benefit pension plans and other postretirement benefit plans that cover almost all employees and certain retirees. Projected benefit costs are based on historical information and actuarial calculations that include key assumptions (annual return level on pension and postretirement health care investment assets, discount rates, mortality rates and health care cost trend rates, etc.). In addition, the pension cost calculation uses a methodology to reduce the volatility of investment performance over time. Pension assumptions are continually reviewed.
At Dec. 31, 2022, Xcel Energy set the rate of return on assets used to measure pension costs at 6.93%, which is 44 basis points higher than the rate set in 2021. The rate of return used to measure postretirement health care costs is 5.00% at Dec. 31, 2022, which is 90 basis points higher than the rate set in 2021. Xcel Energy’s pension investment strategy is based on plan-specific investments that seek to minimize investment and interest rate risk as a plan’s funded status increases over time. This strategy results in a greater percentage of interest rate sensitive securities being allocated to plans with higher funded status ratios and a greater percentage of growth assets being allocated to plans having lower funded status ratios.
Xcel Energy set the discount rates used to value the pension obligations and postretirement health care obligations at 5.80% at Dec. 31, 2022. This represents a 272 basis point and 271 basis point increase, respectively, from 2021. Xcel Energy uses a bond matching study as its primary basis for determining the discount rate used to value pension and postretirement health care obligations. The bond matching study utilizes a portfolio of high grade (Aa or higher) bonds that matches the expected cash flows of Xcel Energy’s benefit plans in amount and duration.
The effective yield on this cash flow matched bond portfolio determines the discount rate for the individual plans. The bond matching study is validated for reasonableness against the Bank of America US Corporate 15+ Bond Index. In addition, Xcel Energy reviews general actuarial survey data to assess the reasonableness of the discount rate selected.
If Xcel Energy were to use alternative assumptions, a 1% change would result in the following impact on 2022 pension costs:
| | | | | | | | | | | | | | |
| | Pension Costs |
| (Millions of Dollars) | | +1% | | -1% |
Rate of return (a) | | $ | (11) | | | $ | 26 | |
Discount rate (a) | | $ | 1 | | | $ | 8 | |
(a)These costs include the effects of regulation.
Mortality rates are developed from actual and projected plan experience for pension plan and postretirement benefits. Xcel Energy’s actuary conducts an experience study periodically to determine an estimate of mortality. Xcel Energy considers standard mortality tables, improvement factors and the plans actual experience when selecting a best estimate.
As of Dec. 31, 2022, the initial medical trend cost claim assumptions for Pre-65 was 6.5% and Post-65 was 5.5%. The ultimate trend assumption remained at 4.5% for both Pre-65 and Post-65 claims costs. Xcel Energy bases its medical trend assumption on the long-term cost inflation expected in the health care market, considering the levels projected and recommended by industry experts, as well as recent actual medical cost experienced by Xcel Energy’s retiree medical plan.
Funding contributions in 2022 were $50 million and will remain relatively consistent in future years. Investment returns were less than the assumed levels in 2022, but exceeded the assumed levels in 2021 and 2020.
The pension cost calculation uses a market-related valuation of pension assets. Xcel Energy uses a calculated value method to determine the market-related value of the plan assets. The market-related value is determined by adjusting the fair market value of assets at the beginning of the year to reflect the investment gains and losses (the difference between the actual investment return and the expected investment return on the market-related value) during each of the previous five years at the rate of 20% per year.
As differences between actual and expected investment returns are incorporated into the market-related value, amounts are recognized in pension cost over the expected average remaining years of service for active employees (approximately 13 years in 2022).
Xcel Energy currently projects the pension costs recognized for financial reporting purposes will be $66 million in 2023 and $58 million in 2024, while the actual pension costs were $114 million in 2022 and $121 million in 2021. The expected decrease in 2023 is primarily due to the reductions in loss amortizations.
Pension funding contributions across all four of Xcel Energy’s pension plans, both voluntary and required, for 2020 - 2023:
•$50 million in January 2023.
•$50 million in 2022.
•$131 million in 2021.
•$150 million in 2020.
Future amounts may change based on actual market performance, changes in interest rates and any changes in governmental regulations. Therefore, additional contributions could be required in the future. Xcel Energy contributed $13 million, $15 million and $11 million during 2022, 2021 and 2020, respectively, to the postretirement health care plans. Xcel Energy expects to contribute approximately $12 million during 2023. Xcel Energy recovers employee benefits costs in its utility operations consistent with accounting guidance with the exception of the areas noted below.
•NSP-Minnesota recognizes pension expense in all regulatory jurisdictions using the aggregate normal cost actuarial method. Differences between aggregate normal cost and expense as calculated by pension accounting standards are deferred as a regulatory liability.
•In 2021, the PSCW approved NSP-Wisconsin’s request for deferred accounting treatment of the 2021 pension settlement accounting expense. Escrow accounting treatment was also approved for ongoing pension and other post-employment benefit expenses, including settlement charges.
•Regulatory Commissions in Colorado, Texas, New Mexico and FERC jurisdictions allow the recovery of other postretirement benefit costs only to the extent that recognized expense is matched by cash contributions to an irrevocable trust. Xcel Energy has consistently funded at a level to allow full recovery of costs in these jurisdictions.
•PSCo is required to create a regulatory liability that adjusts the annual post-retirement benefits amount to zero in order to match the amount collected in rates.
•PSCo and SPS recognize pension expense in all regulatory jurisdictions based on GAAP. The Texas and Colorado electric retail jurisdictions and the Colorado gas retail jurisdiction, each record the difference between annual recognized pension expense and the annual amount of pension expense approved in their last respective general rate case as a deferral to a regulatory asset.
See Note 11 to the consolidated financial statements for further information.
Nuclear Decommissioning
Xcel Energy recognizes liabilities for the expected cost of retiring tangible long-lived assets for which a legal obligation exists. These AROs are recognized at fair value as incurred and are capitalized as part of the cost of the related long-lived assets. In the absence of quoted market prices, Xcel Energy estimates the fair value of its AROs using present value techniques, in which it makes assumptions including estimates of the amounts and timing of future cash flows associated with retirement activities, credit-adjusted risk free rates and cost escalation rates. When Xcel Energy revises any assumptions, it adjusts the carrying amount of both the ARO liability and related long-lived asset. ARO liabilities are accreted to reflect the passage of time using the interest method.
A significant portion of Xcel Energy’s AROs relates to the future decommissioning of NSP-Minnesota’s nuclear facilities. The nuclear decommissioning obligation is funded by the external decommissioning trust fund. Difference between regulatory funding (including depreciation expense less returns from the external trust fund) and expense recognized is deferred as a regulatory asset. The amounts recorded for AROs related to future nuclear decommissioning were $2.2 billion in 2022 and $2.1 billion in 2021.
NSP-Minnesota obtains periodic independent cost studies to estimate the cost and timing of planned nuclear decommissioning activities. Estimates of future cash flows are highly uncertain and may vary significantly from actual results. NSP-Minnesota is required to file a nuclear decommissioning filing every three years. The filing covers all expenses for the decommissioning of the nuclear plants, including decontamination and removal of radioactive material.
The 2022 - 2024 Nuclear Decommissioning Study and Assumptions were approved by the MPUC in August 2022. The MPUC ordered the next triennial decommissioning study be filed by December 1, 2024, allowing for four years between filings.
The following assumptions have a significant effect on the estimated nuclear obligation:
Timing — Decommissioning cost estimates are impacted by each facility’s retirement date and timing of the actual decommissioning activities. Estimated retirement dates coincide with the approved retirement dates which can be different than the expiration dates of each unit’s operating license with the NRC (i.e., 2030 for Monticello and 2033 and 2034 for PI’s Unit 1 and 2, respectively).
In April 2022, the Company received approval from the MPUC, in the Integrated Resource Plan, to pursue extending the operating life of the Monticello Nuclear Generating Plant by ten years from 2030 to 2040. This life extension is subject to NRC approval of Monticello’s nuclear license extension request.
The retirement dates of the Prairie Island Unit 1 and Unit 2 remain unchanged, 2033 and 2034 respectively. The estimated timing of the decommissioning activities is based upon the DECON method, which assumes prompt removal and dismantlement. Decommissioning activities are expected to begin at the commission approved retirement date and be completed for both facilities by 2101.
Technology and Regulation — There is limited experience with actual decommissioning of large nuclear facilities. Changes in technology, experience and regulations could cause cost estimates to change significantly.
Escalation Rates — Escalation rates represent projected cost increases due to general inflation and increases in the cost of decommissioning activities. NSP-Minnesota used an escalation rate of 3.2% in calculating the ARO for nuclear decommissioning of its nuclear facilities, based on weighted averages of labor and non-labor escalation factors calculated by Goldman Sachs Asset Management.
Discount Rates — Changes in timing or estimated cash flows that result in upward revisions to the ARO are calculated using the then-current credit-adjusted risk-free interest rate. The credit-adjusted risk-free rate in effect when the change occurs is used to discount the revised estimate of the incremental expected cash flows of the retirement activity.
If the change in timing or estimated expected cash flows results in a downward revision of the ARO, the undiscounted revised estimate of expected cash flows is discounted using the credit-adjusted risk-free rate in effect at the date of initial measurement and recognition of the original ARO. Discount rates ranging from approximately 3% to 7% have been used to calculate the net present value of the expected future cash flows over time.
Significant uncertainties exist in estimating future costs including the method to be utilized, ultimate costs to decommission and planned method of disposing spent fuel. If different cost estimates, life assumptions or cost escalation rates were utilized, the AROs could change materially.
However, changes in estimates have minimal impact on results of operations as NSP-Minnesota expects to continue to recover all costs in future rates.
NSP-Minnesota continually makes judgments and estimates related to these critical accounting policy areas, based on an evaluation of the assumptions and uncertainties for each area. The information and assumptions of these judgments and estimates will be affected by events beyond the control of Xcel Energy, or otherwise change over time.
This may require adjustments to recorded results to better reflect updated information that becomes available. The accompanying financial statements reflect management’s best estimates and judgments of the impact of these factors as of Dec. 31, 2022.
See Note 12 to the consolidated financial statements for further information.
| | |
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 Dec. 31, 2022: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Futures / Forwards Maturity |
| (Millions of Dollars) | | Less Than
1 Year | | 1 to 3 Years | | 4 to 5 Years | | Greater Than
5 Years | | Total
Fair Value |
NSP-Minnesota (a) | | $ | (8) | | | $ | (6) | | | $ | (7) | | | $ | (2) | | | $ | (23) | |
NSP-Minnesota (b) | | 5 | | | (4) | | | — | | | (3) | | | (2) | |
PSCo (a) | | 10 | | | 3 | | | 3 | | | — | | | 16 | |
PSCo (b) | | (56) | | | (15) | | | 8 | | | — | | | (63) | |
| | $ | (49) | | | $ | (22) | | | $ | 4 | | | $ | (5) | | | $ | (72) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Options Maturity |
| (Millions of Dollars) | | Less Than
1 Year | | 1 to 3 Years | | 4 to 5 Years | | Greater Than
5 Years | | Total Fair Value |
NSP-Minnesota (b) | | $ | — | | | $ | — | | | $ | — | | | $ | 15 | | | $ | 15 | |
PSCo (b) | | 40 | | | 7 | | | — | | | — | | | 47 | |
| | $ | 40 | | | $ | 7 | | | $ | — | | | $ | 15 | | | $ | 62 | |
(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 years ended Dec. 31:
| | | | | | | | | | | | | | |
| (Millions of Dollars) | | 2022 | | 2021 |
| Fair value of commodity trading net contracts outstanding at Jan. 1 | | $ | (33) | | | $ | (54) | |
| Contracts realized or settled during the period | | (15) | | | (54) | |
| Commodity trading contract additions and changes during the period | | 38 | | | 75 | |
| Fair value of commodity trading net contracts outstanding at Dec. 31 | | $ | (10) | | | $ | (33) | |
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 $8 million at Dec. 31, 2022 and $13 million at Dec. 31, 2021. Market price movements can exceed 10% under abnormal circumstances.
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) | | Year Ended Dec. 31 | | | | Average | | High | | Low |
| 2022 | | $ | 2 | | | | | $ | 1 | | | $ | 5 | | | $ | — | |
| 2021 | | $ | 1 | | | | | $ | 2 | | | $ | 52 | | | $ | 1 | |
A short-term increase in VaR occurred during the week of Feb. 12, 2021 through Feb. 18, 2021. On Feb. 17, 2021, the portfolio VaR reached a high of $52 million. This increase in VaR was driven by the unprecedented market conditions during Winter Storm Uri. Prior to this weather event, VaR was $1 million and returned to $1 million by Feb. 19, 2021.
Nuclear Fuel Supply — NSP-Minnesota has contracted for its 2023 and 2024 enriched nuclear material requirements, which are in various stages of processing in Canada, Europe, and the United States. NSP-Minnesota is scheduled to take delivery of approximately 26% of its average enriched nuclear material requirements from Russia through 2030. We are closely monitoring the evolving situation in Ukraine and its global impacts. NSP-Minnesota is in the process of entering into new contracts to reduce the risk of supply interruptions of nuclear material from Russia. NSP-Minnesota will take additional further action to reduce this risk as necessary.
Interest Rate Risk — Xcel Energy is subject to interest rate risk. Our risk management policy allows interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate derivatives.
A 100 basis point change in the benchmark rate on Xcel Energy’s variable rate debt would impact pretax interest expense annually by approximately $8 million and $11 million in 2022 and 2021, 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 Dec. 31, 2022, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $56 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $47 million. At Dec. 31, 2021, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $36 million, while a decrease in prices of 10% would have resulted in an decrease in credit exposure of $26 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.
Current estimated financing plans of Xcel Energy for 2023 through 2027: | | | | | | | | |
| (Millions of Dollars) | | |
| Funding Capital Expenditures | | |
Cash from operations (a) | | $ | 20,540 | |
New debt (b) | | 8,210 | |
| Equity through the DRIP and benefit program | | 425 | |
| Other equity | | 325 | |
| Base capital expenditures 2023 - 2027 | | $ | 29,500 | |
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| Maturing Debt | | $ | 3,800 | |
(a)Net of dividends and pension funding.
(b)Reflects a combination of short and long-term debt; net of refinancing.
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.
Common Stock Dividends — Future dividend levels will be dependent on Xcel Energy’s results of operations, financial condition, cash flows, reinvestment opportunities and other factors, and will be evaluated by the Xcel Energy Inc. Board of Directors. In February 2023, Xcel Energy announced an increase in the annual dividend of 13 cents per share, which represents an increase of 6.7%.
Xcel Energy’s dividend policy balances the following:
•Projected cash generation.
•Projected capital investment.
•A reasonable rate of return on shareholder investment.
•The impact on Xcel Energy’s capital structure and credit ratings.
In addition, there are certain statutory limitations that could affect dividend levels. Federal law places limits on the ability of public utilities within a holding company to declare dividends. Under the Federal Power Act, a public utility may not pay dividends from any funds properly included in a capital account. The utility subsidiaries’ dividends may be limited directly or indirectly by state regulatory commissions or bond indenture covenants.
See Note 5 to the consolidated financial statements for further information.
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.
Funded status and pension assumptions:
| | | | | | | | | | | | | | |
| (Millions of Dollars) | | Dec. 31, 2022 | | Dec. 31, 2021 |
| Fair value of pension assets | | $ | 2,685 | | | $ | 3,670 | |
Projected pension obligation (a) | | 2,871 | | | 3,718 | |
| Funded status | | $ | (186) | | | $ | (48) | |
(a)Excludes non-qualified plan of $11 million and $43 million at Dec. 31, 2022 and 2021, respectively.
| | | | | | | | | | | | | | |
| Pension Assumptions | | 2022 | | 2021 |
| Discount rate | | 5.80 | % | | 3.08 | % |
| Expected long-term rate of return | | 6.93 | | | 6.49 | |
Capital Sources
Short-Term Funding Sources — Xcel Energy generally funds short-term needs, through operating cash flows, notes payable, commercial paper and bank lines of credit. The amount and timing of short-term funding needs depend on construction expenditures, working capital and dividend payments.
Short-Term Investments — Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS maintain cash and short-term investment accounts.
Short-Term Debt — Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each have individual commercial paper programs. Authorized levels for these commercial paper programs are:
•$1.50 billion for Xcel Energy Inc.
•$700 million for PSCo.
•$700 million for NSP-Minnesota.
•$500 million for SPS.
•$150 million for NSP-Wisconsin.
See Note 5 to the consolidated financial statements for further information.
Credit Facility Agreements — Xcel Energy Inc., NSP-Minnesota, PSCo and SPS each have the right to request an extension of the revolving credit facility for two additional one-year periods. NSP-Wisconsin has the right to request an extension of the revolving credit facility for an additional year. All extension requests are subject to majority bank group approval.
As of Feb. 22, 2023, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available to meet liquidity needs:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (Millions of Dollars) | | Facility (a) | | Drawn (b) | | Available | | Cash | | Liquidity |
| Xcel Energy Inc. | | $ | 1,500 | | | $ | 328 | | | $ | 1,172 | | | $ | 6 | | | $ | 1,178 | |
| PSCo | | 700 | | | 123 | | | 577 | | | 5 | | | 582 | |
| NSP-Minnesota | | 700 | | | 186 | | | 514 | | | 6 | | | 520 | |
| SPS | | 500 | | | 91 | | | 409 | | | 2 | | | 411 | |
| NSP-Wisconsin | | 150 | | | 29 | | | 121 | | | 2 | | | 123 | |
| Total | | $ | 3,550 | | | $ | 757 | | | $ | 2,793 | | | $ | 21 | | | $ | 2,814 | |
(a)Credit facilities expire in September 2027.
(b)Includes outstanding commercial paper and letters of credit.
Registration Statements — Xcel Energy Inc.’s Articles of Incorporation authorize the issuance of one billion shares of $2.50 par value common stock. As of Dec. 31, 2022 and 2021, Xcel Energy had approximately 550 million shares and 544 million shares of common stock outstanding, respectively.
Xcel Energy Inc. and its utility subsidiaries have registration statements on file with the SEC pursuant to which they may sell securities from time to time. These registration statements, which are uncapped, permit Xcel Energy Inc. and its utility subsidiaries to issue debt and other securities in the future at amounts, prices and with terms to be determined at the time of future offerings, and in the case of our utility subsidiaries, subject to commission approval.
Planned Financing Activity — Xcel Energy’s 2023 financing plans reflect the following:
| | | | | | | | | | | | | | | | | | | | |
| (Millions of Dollars) | | Security | | Amount | | Anticipated Timing |
| Xcel Energy Inc. | | Senior Unsecured Bonds | | $ | 500 | | | Third Quarter |
| PSCo | | First Mortgage Bonds | | 700 | | Second Quarter |
| SPS | | First Mortgage Bonds | | 100 | | Third Quarter |
| NSP-Minnesota | | First Mortgage Bonds | | 750 | | Second Quarter |
| NSP-Wisconsin | | First Mortgage Bonds | | 125 | | Second Quarter |
Long-Term Borrowings, Equity Issuances and Other Financing Instruments — Xcel Energy also plans to issue approximately $85 million of equity annually through the DRIP and benefit programs during the five-year forecast time period.
See Note 5 to the consolidated financial statements for further information.
Earnings Guidance and Long-Term EPS and Dividend Growth Rate Objectives
Xcel Energy 2023 Earnings Guidance — Xcel Energy’s 2023 GAAP and ongoing earnings guidance is a range of $3.30 to $3.40 per share.(a)
Key assumptions as compared with 2022 levels unless noted:
•Constructive outcomes in all rate case and regulatory proceedings.
•Normal weather patterns for the year.
•Weather-normalized retail electric sales are projected to increase ~1%.
•Weather-normalized retail firm natural gas sales are projected to increase ~1%.
•Capital rider revenue is projected to increase $90 million to $100 million (net of PTCs).
•O&M expenses are projected to decline ~2%.
•Depreciation expense is projected to increase approximately $130 million to $140 million.
•Property taxes are projected to increase approximately $35 million to $45 million.
•Interest expense (net of AFUDC - debt) is projected to increase $100 million to $110 million.
•AFUDC - equity is projected to increase $0 million to $10 million.
•ETR is projected to be ~(5%) to (7%).
(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. Xcel Energy is unable to forecast if any of these items will occur or provide a quantitative reconciliation of the guidance for ongoing EPS to corresponding GAAP EPS.
Long-Term EPS and Dividend Growth Rate Objectives — Xcel Energy expects to deliver an attractive total return to our shareholders through a combination of earnings growth and dividend yield, based on the following long-term objectives:
• Deliver long-term annual EPS growth of 5% to 7% based off of a 2022 base of $3.15 per share, which represents the mid-point of the original 2022 guidance range of $3.10 to $3.20 per share.
• Deliver annual dividend increases of 5% to 7%.
• Target a dividend payout ratio of 60% to 70%.
• Maintain senior secured debt credit ratings in the A range.
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ITEM 7A — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
See the “Derivatives, Risk Management and Market Risk” section in Item 7, incorporated by reference.
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ITEM 8 — FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
See Item 15-1 for an index of financial statements included herein.
See Note 15 to the consolidated financial statements for further information.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the stockholders and the Board of Directors of Xcel Energy Inc.
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheets of Xcel Energy Inc. and subsidiaries (the "Company") as of December 31, 2022 and 2021, the related consolidated statements of income, comprehensive income, stockholders' equity, and cash flows, for each of the three years in the period ended December 31, 2022, and the related notes and the schedules listed in the Index at Item 15 (collectively referred to as the "financial statements"). We also have audited the Company’s internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control — Integrated Framework (2013) issued by COSO.
Basis for Opinions
The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management Report on Internal Controls over Financial Reporting. Our responsibility is to express an opinion on these financial statements and an opinion on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the financial statements included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures to respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Regulatory Assets and Liabilities - Impact of Rate Regulation on the Financial Statements — Refer to Notes 4 and 12 to the consolidated financial statements.
Critical Audit Matter Description
The Company 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. The Company is also subject to the jurisdiction of the Federal Energy Regulatory Commission for its wholesale electric operations, hydroelectric generation licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with North American Electric Reliability Corporation standards, asset transactions and mergers and natural gas transactions in interstate commerce, (collectively with state utility regulatory agencies, the “Commissions”). Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation affects multiple financial statement line items and disclosures, including property, plant and equipment, regulatory assets and liabilities, operating revenues and expenses, and income taxes.
The Company is subject to regulatory rate setting processes. Rates are determined and approved in regulatory proceedings based on an analysis of the Company’s costs to provide utility service and a return on, and recovery of, the Company’s investment in assets required to deliver services to customers. Accounting for the Company’s regulated operations provides that rate-regulated entities report assets and liabilities consistent with the recovery of those incurred costs in rates, if it is probable that such rates will be charged and collected. The Commissions’ regulation of rates is premised on the full recovery of incurred costs and a reasonable rate of return on invested capital. Decisions by the Commissions in the future will impact the accounting for regulated operations, including decisions about the amount of allowable costs and return on invested capital included in rates and any refunds that may be required. In the rate setting process, the Company’s rates result in the recording of regulatory assets and liabilities based on the probability of future cash flows. Regulatory assets generally represent incurred or accrued costs that have been deferred because future recovery from customers is probable. Regulatory liabilities generally represent amounts that are expected to be refunded to customers in future rates or amounts collected in current rates for future costs.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs, (2) a disallowance of part of the cost of recently completed plant, and 3) a refund due to customers. Given that management’s accounting judgments are based on assumptions about the outcome of future decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the Commissions included the following, among others:
•We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management’s controls over the recognition of regulatory assets or liabilities and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.
•We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
•We read relevant regulatory orders issued by the Commissions for the Company, regulatory statutes, interpretations, procedural schedules and memorandums, filings made by intervenors, experts’ testimony and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions’ treatment of similar costs under similar circumstances. We also evaluated regulatory filings for any evidence that intervenors are challenging full recovery of the cost of any capital projects. If the full recovery of project costs is being challenged by intervenors, we evaluated management’s assessment of the probability of a disallowance. We evaluated the external information and compared to the Company’s recorded regulatory assets and liabilities for completeness.
•We obtained management’s analysis and correspondence from counsel, as appropriate, regarding regulatory assets or liabilities not yet addressed in a regulatory order to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.
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/s/ DELOITTE & TOUCHE LLP |
| Minneapolis, Minnesota |
| February 23, 2023 |
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| We have served as the Company’s auditor since 2002. |