Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) was prepared in accordance with the SEC’s Regulation S-K for interim financial information and with the instructions to Form 10-Q. Accordingly, this MD&A does not contain the full detail or analysis, or the full discussion of trends and uncertainties, that are required to accompany financial statements for a full fiscal year and are contained in the Company's 2025 Form 10-K. Therefore, this MD&A should be read in conjunction with the Company's 2025 Form 10-K for full detail and analysis of the Company's financial condition, and results of operations, and a full discussion of trends and uncertainties that the Company faces.
Business Segments
Our business segments have not changed during the six months ended June 30, 2026. See the 2025 Form 10-K as well as “Note 16 of the Notes to Condensed Consolidated Financial Statements” for further information regarding our business segments.
The following table presents net income (loss) for each of our business segments and the other businesses for the three and six months ended June 30 (dollars in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30, |
|
|
Six months ended June 30, |
|
|
|
2026 |
|
|
2025 |
|
|
2026 |
|
|
2025 |
|
Avista Utilities |
|
$ |
22 |
|
|
$ |
23 |
|
|
$ |
109 |
|
|
$ |
101 |
|
AEL&P |
|
|
1 |
|
|
|
1 |
|
|
|
5 |
|
|
|
4 |
|
Other non-reportable segment income (loss) |
|
|
12 |
|
|
|
(10 |
) |
|
|
13 |
|
|
|
(12 |
) |
Net income |
|
$ |
35 |
|
|
$ |
14 |
|
|
$ |
127 |
|
|
$ |
93 |
|
Executive Overview
Overall Results
Net income for the three and six months ended June 30, 2026 increased compared to the three and six months ended June 30, 2025, primarily due to net investment gains at our other businesses, compared to net investment losses in the respective periods of 2025. See “Note 5 of the Notes to Condensed Consolidated Financial Statements” for additional information regarding the gain recorded in the second quarter of 2026, as well as expected gains and losses during the remainder of 2026.
The effects of our general rate cases also increased net income in 2026.
When comparing results from the first half of 2026 to the first half of 2025, the transfer of our ownership of Colstrip (effective January 1, 2026) has resulted in fluctuations in multiple line items on the income statement, which ultimately net to an immaterial impact on net income. The removal of Colstrip from our generation portfolio resulted in an increase in authorized power supply cost and increases in both electric utility revenues and electric resource costs (resulting in no impact on net income). In addition, other operating costs and depreciation expense have decreased, with a corresponding decrease in electric utility revenues associated with recovery of these costs.
More detailed explanations of the fluctuations in revenues and expenses are provided in the results of operations and business segment discussions (Avista Utilities, AEL&P, and the other businesses) that follow this summary.
See the summary of key developments and issues that are the focus of management under the heading “Executive Overview” in the MD&A of our 2025 10-K. The following developments have occurred since that report:
2026 Wildfire Conditions
A number of wildfires have occurred within our service territory in 2026, impacting our operations. While the causes of some fires remain under investigation, virtually all have been attributed to human activity or lightning. Two fires ignited near our facilities but have since been fully contained. One fire damaged a small storage facility. No structures were impacted by the other fire. We do not believe either of these ignitions resulted from the improper operation or maintenance of our facilities. In response to an increased
wildfire risk driven primarily by high winds and drier-than-normal conditions, we have proactively implemented enhanced system protections and public safety power shutoffs. We continue to monitor conditions closely and respond as needed to mitigate this elevated risk.
Hydroelectric Conditions and Outlook
Our hydroelectric generation year-to-date has been above normal. The amount of hydroelectric generation is affected not only by snowpack levels but also by prevailing temperatures (which affect the timing and speed of run-off) and the volume, timing and form of precipitation. On balance, we expect hydroelectric generation for the entire year will be above normal. While our current hydroelectric forecast shows above normal levels of generation for the full year, whether actual results are above or below normal, there would be no material change to our net income, based upon our forecast surcharge position in the 90 percent customer, 10 percent company sharing band of the ERM.
Potential Large Load Growth
In May 2026, we entered into a non-binding memorandum of understanding (MOU) with a data center developer seeking interconnection and energy supply in our Washington service territory. The developer is seeking an initial load demand of 125 MW starting in 2029, with a pathway to expand to 500 MW by 2032.
In June 2026, we announced that we will take additional time to evaluate the processing of energy requests from data center developers, and have paused negotiations associated with the MOU. This decision followed community interest and concern surrounding the MOU. We are seeking to partner with governmental agencies on creating a clear and coordinated planning process as we consider additional stakeholder feedback associated with large load requests.
Enterprise Resource Planning (ERP) Project
We are planning to implement an ERP system, replacing certain existing technology tools currently in use. The system will be designed to accurately maintain our financial records, enhance operational functionality, and provide timely information to our management team related to business operations. We expect the ERP system to be implemented in 2028, with capital expenditures of approximately $130 million.
Regulatory Matters
General Rate Cases
We regularly review the need for electric and natural gas rate changes in each state in which we provide service. We expect to continue to file for rate adjustments to:
•seek recovery of operating costs and capital investments, and
•seek the opportunity to earn reasonable returns as allowed by regulators.
With regard to the timing and plans for future filings, the assessment of our need for rate relief and the development of rate case plans takes into consideration short-term and long-term needs, as well as specific factors including, but not limited to, in-service dates of major capital investments and the timing of changes in major revenue and expense items.
Avista Utilities
Washington General Rate Cases
2024 General Rate Cases
In December 2024, the WUTC issued orders related to our multi-year electric and natural gas general rate cases filed with the WUTC in January 2024.
The approved rates within the orders are designed to increase annual electric base revenues by $12 million (or 2.0 percent), effective January 1, 2025 (Rate Year 1), and $69 million (or 11.4 percent), effective January 1, 2026 (Rate Year 2). The Rate Year 2 increase includes $54 million related to higher authorized power supply costs resulting from the removal of Colstrip from our generation portfolio. This base increase is offset by decreases in capital and operating costs removed from customer rates of $43 million, effective January 1, 2026, as we are no longer recovering Colstrip related costs.
The approved rates are also designed to increase annual natural gas base revenues by $14 million (or 11.2 percent), effective January 1, 2025, and $4 million (or 2.8 percent), effective January 1, 2026.
The WUTC approved an ROE of 9.8 percent, based on a common equity ratio of 48.5 percent, and an ROR of 7.32 percent.
The WUTC did not approve our request to modify the ERM under which differences between actual net power supply costs and the amount reflected in base retail customer rates are tracked. Based on our forecast energy commodity costs in 2026, we expect actual net power supply costs to exceed the level included in base rates. We plan to continue to address how net power supply costs are set in base rates in future regulatory proceedings.
The WUTC continued its support for important recovery mechanisms such as wildfire and insurance balancing accounts, and decoupling.
2026 General Rate Cases
In January 2026, we filed an MYRP with the WUTC. The MYRP requests base rate relief over four years designed to produce the additional base revenues shown below (dollars in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Rate Year |
Rates Effective |
|
Electric |
|
|
Natural Gas |
|
1 |
2027 |
|
$ |
111 |
|
|
|
13.9 |
% |
|
$ |
12 |
|
|
|
4.7 |
% |
2 |
2028 |
|
|
43 |
|
|
|
4.7 |
% |
|
|
7 |
|
|
|
2.4 |
% |
3 |
2029 |
|
|
34 |
|
|
|
3.5 |
% |
|
|
6 |
|
|
|
2.1 |
% |
4 |
2030 |
|
|
28 |
|
|
|
2.8 |
% |
|
|
3 |
|
|
|
1.1 |
% |
We requested an overall rate of return beginning in 2027 of 7.5 percent, with a 48.5 common equity ratio and a 10.2 percent return on equity. We requested an increase to the overall rate of return in 2029 to 7.67 percent, with a 48.5 common equity ratio and 10.5 percent return on equity.
Key drivers of the revenue requirement in Rate Year 1 (2027) are outlined below (dollars in millions):
|
|
|
|
|
|
|
|
|
|
|
Electric |
|
|
Natural Gas |
|
Electric resource costs |
|
$ |
46 |
|
|
$ |
— |
|
Capital additions |
|
|
29 |
|
|
|
5 |
|
Employee benefits |
|
|
7 |
|
|
|
1 |
|
Insurance |
|
|
7 |
|
|
|
— |
|
Regulatory amortizations |
|
|
5 |
|
|
|
4 |
|
Wildfire |
|
|
4 |
|
|
|
— |
|
Other |
|
|
13 |
|
|
|
2 |
|
Total |
|
$ |
111 |
|
|
$ |
12 |
|
In the MYRP, we propose certain changes to the calculation of authorized baseline power supply costs. These changes are designed to address the changing market dynamics which have led to significant volatility in actual power supply costs. The MYRP provides updates to our baseline power supply cost for rate years one and two; as required by Washington law, baseline power supply costs for Rate Years 3 and 4 will be established in later filings and as such are not included in the additional revenue requirements for those years shown above. In addition, we are proposing changes to the timing for recovery of costs deferred under the ERM.
In addition to requesting re-approval of existing insurance, wildfire, and decoupling deferral accounts, we are proposing an additional deferral mechanism for costs associated with employee benefits.
Washington law requires utilities to file MYRPs of a minimum of two and up to four years. The law allows utilities filing a rate plan of three or four years the option to file a new rate plan for the third year and fourth year. Under this provision, we have the opportunity
to address the numerous unpredictable factors that could materially affect our financial position over a longer-term rate plan. These risks include, but are not limited to, inflation, interest rate volatility, labor and benefits challenges, escalating capital costs, and other unforeseen cost drivers.
The WUTC has up to eleven months to review the general rate case filings and issue a decision. The evidentiary hearing is scheduled for September 2026.
Idaho General Rate Cases
2025 General Rate Cases
In August 2025, the IPUC approved the all-party settlement agreement designed to increase annual base electric revenues by $20 million, or 6.3 percent, effective September 2025, and $15 million, or 4.5 percent, effective September 2026. For natural gas, the agreement was designed to increase annual base natural gas revenues by $5 million, or 9.2 percent, effective September 2025, and decrease annual base natural gas revenues by $0.2 million, or 0.4 percent, effective September 2026.
The settlement was based on an ROE of 9.6 percent with a common equity ratio of 50 percent and an ROR of 7.28 percent.
2027 General Rate Cases
We expect to file electric and natural gas general rate cases with the IPUC in the first quarter of 2027.
Oregon General Rate Case
2024 General Rate Case
In May 2025, the OPUC approved the all-party settlement agreement designed to increase annual base revenues by $4 million, or 5.0 percent, effective in September 2025. The settlement was based on an ROE of 9.5 percent with a common equity ratio of 50 percent and an ROR of 7.22 percent.
To mitigate the overall impact of the revenue increases on customers, $5 million of tax customer credits will be accelerated and returned to customers over a three-year period.
Future Oregon General Rate Cases
In July 2025, the Governor of Oregon signed House Bill 3179 into law which modifies certain provisions of law that relate to general rate case filings and cost recovery. The law, among other things, extends the length of time for the OPUC to suspend rates from a proposed effective date from nine to ten months, does not allow residential rate increases of any kind between November 1 and March 31, does not allow new rates to take effect from a proceeding where the return on equity is at issue within eighteen months of the prior rate effective date, authorizes (but does not require) securitization of “capital investments” that will cause rates to “rise by more than five percent” under specific circumstances, and calls for the OPUC to establish rules requiring utilities to establish a multi-year rate plan for rate revisions where a company’s return on equity is reviewed. Such rate plans must be no less than three years and no more than seven years in length. Rulemakings to institute these provisions started in September 2025 and will continue through 2026. We are analyzing the possible effects of this legislation, including how it will impact the timing of future rate case filings.
Purchased Gas Adjustments, Power Cost Deferrals and Decoupling Mechanisms
See our 2025 Form 10-K for discussion of the various regulatory recovery mechanisms in each of our jurisdictions.
In 2025, we received approval from the WUTC to recover $32 million of the ERM deferred surcharge balance in Washington over a two-year period starting July 1, 2025. In 2026, we received approval from the WUTC to recover an additional $65 million of the ERM deferred surcharge balance in Washington over a two-year period starting July 1, 2026.
Alaska Electric Light and Power Company
Alaska General Rate Case
In May 2026, AEL&P filed an electric general rate case with the Regulatory Commission of Alaska (RCA). AEL&P's request for an interim base rate increase of 12.5 percent (designed to increase electric revenues by $5 million), was approved and took effect in June 2026. AEL&P is seeking a permanent base rate increase of an additional 12.6 percent (designed to increase electric revenues by $5 million), which, if approved, could take effect in August 2027. This represents a combined total rate increase of 25.1 percent (designed to increase electric revenues by $10.0 million). The proposed revenue increase request is based on a 13.2 percent ROE with a common equity ratio of 58.33 percent and a ROR of 9.75 percent.
The RCA must rule on permanent rate increases within 450 days (approximately 15 months) from the date of filing.
Results of Operations - Overall
The following provides an overview of changes in our Condensed Consolidated Statements of Income and Comprehensive Income. More detailed explanations are provided, particularly for operating revenues and operating expenses, in the business segment discussions (Avista Utilities, AEL&P, and the other businesses) that follow this section.
The balances included below for utility operations reconcile to the Condensed Consolidated Statements of Income and Comprehensive Income.
Three months ended June 30, 2026 compared to the three months ended June 30, 2025
The following graph shows the total change in net income for the second quarter of 2026 compared to the second quarter of 2025, as well as the factors that caused such change (dollars in millions):
Electric Utility revenues increased due to increases in retail rates associated with our general rate case, which were partially offset by removing the recovery of Colstrip related costs. This increase to revenues was largely offset by decreased wholesale revenues and decreases in volumes sold. The decrease in volumes sold is due to the departure of a large industrial customer in April 2026. Natural gas revenues increased due to rate increases, largely offset by decreases in wholesale revenues and decoupling revenues.
Electric utility resource costs decreased primarily due to decreased fuel for generation costs partially due to the removal of Colstrip from our generation portfolio. This was partially offset by increased purchased power volumes and wholesale prices, as well as increased costs under the ERM. Natural gas utility resource costs decreased due to decreases in volumes of natural gas purchased.
Other utility operating expenses increased due primarily to increased employee salaries and benefit costs, partially offset with decreases from removing Colstrip related expenses.
Utility depreciation and amortization decreased primarily due to our exit from Colstrip in 2026.
Income tax expense increased primarily due to increased pre-tax income from continuing operations (including equity method earnings) compared to the prior year.
Increased equity method earnings were primarily the result of underlying investment appreciation recognized in the second quarter of 2026, compared to losses recognized in the second quarter of 2025. See “Note 5 of the Notes to Condensed Consolidated Financial Statements” for additional information regarding the gain recorded in the second quarter of 2026.
Six months ended June 30, 2026 compared to the six months ended June 30, 2025
The following graph shows the total change in net income for the six months ended June 30, 2026 compared to the six months ended June 30, 2025, as well as the factors that caused such change (dollars in millions):
Electric utility revenues decreased primarily as a result of decreased wholesale revenues associated with lower market prices, a reduction of revenues associated with the recovery of Colstrip costs, and the departure of a large industrial customer in April 2026, which were partially offset by other increases in retail rates associated with our general rate cases. Natural gas revenues decreased due to decreased rates associated with the PGAs and the CCA (which do not impact net income), as well as decreased wholesale revenues, transportation revenues and an increased provision for rate refunds associated with overearnings in Washington.
Electric utility resource costs decreased primarily due to decreased fuel for generation costs partially due to the removal of Colstrip from our generation portfolio. These decreases were partially offset by a decrease in deferrals under the ERM. Natural gas utility resource costs decreased due to decreases in the amortization of costs associated with the CCA and net deferrals and amortizations of costs under PGAs, as well as a decrease in volumes of natural gas purchased.
Other utility operating expenses increased due primarily to increased employee salaries and benefit costs, partially offset with decreases from removing Colstrip related expenses.
Utility depreciation and amortization decreased primarily due to our transfer of Colstrip.
Income tax expense increased primarily due to increased pre-tax income from continuing operations (including equity method earnings) compared to the prior year.
Increased equity method earnings were primarily the result of underlying investment appreciation recognized in the first half of 2026, compared to losses recognized in the first half of 2025. See “Note 5 of the Notes to Condensed Consolidated Financial Statements” for additional information regarding the gain recorded in the second quarter of 2026.
Results of Operations - Avista Utilities
Resource Optimization
We engage in resource optimization, which involves the selection from available energy resources to serve our load obligations and the use of these resources to capture economic value through wholesale market transactions; this is ultimately intended to lower net power and natural gas supply costs. Our resource optimization transactions can include physical sales and purchases of electric capacity and energy, fuel for electric generation, natural gas to optimize use of pipeline and storage capacity, as well as financial derivative contracts related to capacity, energy, fuel and fuel transportation. See our 2025 Form 10-K for further discussion of our optimization activities.
We typically enter into multiple transactions simultaneously to capture value. Even though these transactions are considered together when determining the net impact, they are recorded in separate items within components of utility operating revenue and resource costs and can cause fluctuations in each item. Gains and losses on financial derivative contracts are included in certain line items below (such as wholesale sales and purchases of power and natural gas, sales of fuel and other fuel costs). The ERM, PCA and PGAs are based on net supply costs and consider all transactions related to resource procurement and optimization (both physical and financial).
Intercompany Revenues and Resource Costs
Intracompany revenues and resource costs represent purchases and sales of natural gas between our natural gas distribution operations and our electric generation operations (as fuel for our generation plants). These transactions are eliminated in the presentation of total results for Avista Utilities and in the condensed consolidated financial statements but are included in the separate results for electric and natural gas presented below.
Three months ended June 30, 2026 compared to the three months ended June 30, 2025
Utility Operating Revenues
The following graphs present Avista Utilities' electric operating revenues and megawatt-hour (MWh) sales for the three months ended June 30, 2026 and 2025 (dollars in millions and MWhs in thousands):
(1)This balance includes public street and highway lighting, which is considered part of retail electric revenues.
Total electric operating revenues in the graph above include intracompany sales of $1 million for both the three months ended June 30, 2026 and 2025.
The following table presents the current year decoupling deferrals and the amortization of prior year decoupling deferrals reflected in utility electric operating revenues for the three months ended June 30 (dollars in millions):
|
|
|
|
|
|
|
|
|
|
|
Electric Decoupling Revenues |
|
|
|
2026 |
|
|
2025 |
|
Current year decoupling deferrals (a) |
|
$ |
9 |
|
|
$ |
3 |
|
Amortization of prior year decoupling deferrals (b) |
|
|
(2 |
) |
|
|
— |
|
Total electric decoupling revenue |
|
$ |
7 |
|
|
$ |
3 |
|
(a)Positive amounts are increases in decoupling revenue in the current year and will be surcharged to customers in future years. Negative amounts are decreases in decoupling revenue in the current year and will be rebated to customers in future years.
(b)Positive amounts are increases in decoupling revenue in the current year and are related to the amortization of rebate balances that resulted in prior years and are being refunded to customers (causing a corresponding decrease in retail revenue from customers) in the current year. Negative amounts are decreases in decoupling revenue in the current year and are related to the amortization of surcharge balances that resulted in prior years and are being surcharged to customers (causing a corresponding increase in retail revenue from customers) in the current year.
Total electric revenues did not change materially for the second quarter of 2026 as compared to the second quarter of 2025. The primary fluctuations that occurred during the period were as follows:
•A $5 million increase in retail electric revenue due to an increase in retail rates (increased revenues by $25 million) offset by a decrease in MWhs sold (decreased revenues by $20 million).
oRetail rates increased mainly due to the effects of our general rate cases, including base rate increases associated with higher authorized power supply expenses resulting from removing Colstrip from our generation portfolio. These increases to base rates were partially offset by the removal of revenues related to recovery of Colstrip related costs other than power supply costs.
oRetail sales volumes decreased due to a 21 percent decrease in industrial electric sales volumes, partially due to the departure of a large industrial customer in April 2026. Additionally, milder weather reduced customer usage. Residential and commercial use per customer decreased 5 percent and 3 percent, respectively.
•An $8 million decrease in wholesale electric revenues due to a decrease in sales volumes (decreased revenues $4 million) and a decrease in sales prices (decreased revenues $4 million).
•A $4 million increase in electric decoupling revenue primarily due to increased current year surcharge deferrals associated with decreased customer usage compared to the second quarter of 2025.
The following graphs present Avista Utilities' natural gas operating revenues and therms delivered for the three months ended June 30, 2026 and 2025 (dollars in millions and therms in thousands):
(1)This balance includes interruptible and industrial revenues, which are considered part of retail natural gas revenues.
Total natural gas operating revenues in the graph above include intracompany sales of $0 million and $1 million for the three months ended June 30, 2026 and 2025.
The following table presents the current year decoupling deferrals and the amortization of prior year decoupling deferrals reflected in utility natural gas operating revenues for the three months ended June 30 (dollars in millions):
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Decoupling Revenues |
|
|
|
2026 |
|
|
2025 |
|
Current year decoupling deferrals (a) |
|
$ |
10 |
|
|
$ |
9 |
|
Amortization of prior year decoupling deferrals (b) |
|
|
(2 |
) |
|
|
— |
|
Total natural gas decoupling revenue |
|
$ |
8 |
|
|
$ |
9 |
|
(a)Positive amounts are increases in decoupling revenue in the current year and will be surcharged to customers in future years. Negative amounts are decreases in decoupling revenue in the current year and will be rebated to customers in future years.
(b)Positive amounts are increases in decoupling revenue in the current year and are related to the amortization of rebate balances that resulted in prior years and are being refunded to customers (causing a corresponding decrease in retail revenue from customers) in the current year. Negative amounts are decreases in decoupling revenue in the current year and are related to the amortization of surcharge balances that resulted in prior years and are being surcharged to customers (causing a corresponding increase in retail revenue from customers) in the current year.
Total natural gas revenues did not change materially for the second quarter of 2026 as compared to the second quarter of 2025. The primary fluctuations that occurred during the period were as follows:
•A $3 million decrease in wholesale natural gas revenues due to a decrease in prices (decreased revenues $2 million) and a decrease in volumes (decreased revenues $1 million).
•A $4 million increase in other gas revenues primarily due to the amortization of previously deferred revenues associated with the sale of CCA emissions credits. We amortize the deferred revenues as they are passed on to customers through decreases in retail rates. The increase in other revenues was offset by decreased retail revenues, resulting in no impact on net income.
Customers
The following table presents Avista Utilities' average number of electric and natural gas retail customers for the three months ended June 30, 2026 and 2025:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric Customers |
|
|
Natural Gas Customers |
|
|
|
2026 |
|
|
2025 |
|
|
2026 |
|
|
2025 |
|
Residential |
|
|
380,516 |
|
|
|
375,572 |
|
|
|
347,951 |
|
|
|
345,685 |
|
Commercial |
|
|
46,410 |
|
|
|
46,119 |
|
|
|
37,696 |
|
|
|
37,527 |
|
Interruptible |
|
|
— |
|
|
|
— |
|
|
|
52 |
|
|
|
51 |
|
Industrial |
|
|
1,144 |
|
|
|
1,171 |
|
|
|
181 |
|
|
|
184 |
|
Public street and highway lighting |
|
|
849 |
|
|
|
802 |
|
|
|
— |
|
|
|
— |
|
Total retail customers |
|
|
428,919 |
|
|
|
423,664 |
|
|
|
385,880 |
|
|
|
383,447 |
|
Utility Resource Costs
The following graph presents Avista Utilities' electric resource costs for the three months ended June 30, 2026 and 2025 (dollars in millions):
Total electric resource costs in the graph above include intracompany resource costs of $0 million and $1 million for the three months ended June 30, 2026 and 2025.
Total electric resource costs decreased $3 million for the second quarter of 2026 as compared to the second quarter of 2025. The primary changes that occurred during the period were as follows:
•A $5 million increase in power purchased due to an increase in the volume of power purchases (increased costs $3 million) and an increase in wholesale prices (increased costs $2 million).
•A $15 million decrease in fuel for generation due to decreased thermal generation due to increased hydroelectric generation. Thermal generation decreased due to the removal of Colstrip from our generation portfolio, as well as major maintenance at the Coyote Springs 2 facility in 2026.
•A $9 million increase in other electric resource costs primarily related to a decrease in deferred costs under the ERM. The decrease in deferred costs was due to an increase in authorized power supply costs primarily due to the removal of Colstrip from our generation portfolio. There were also increased costs related to our customer assistance payment programs (low-income rate assistance and demand side management).
In the second quarter of 2026, we had a pre-tax expense of $6 million under the ERM in Washington compared to a pre-tax expense of $1 million in the second quarter of 2025.
The following graph presents Avista Utilities' natural gas resource costs for the three months ended June 30, 2026 and 2025 (dollars in millions):
Total natural gas resource costs in the graph above include intracompany resource costs of $1 million for both the three months ended June 30, 2026 and 2025.
Total natural gas resource costs decreased $2 million for the second quarter of 2026 as compared to the second quarter of 2025 due to a $2 million decrease in natural gas purchased from a decrease in volumes, consistent with a decrease in retail and wholesale sales volumes.
Six months ended June 30, 2026 compared to the six months ended June 30, 2025
Utility Operating Revenues
The following graphs present Avista Utilities' electric operating revenues and megawatt-hour (MWh) sales for the six months ended June 30, 2026 and 2025 (dollars in millions and MWhs in thousands):
(1)This balance includes public street and highway lighting, which is considered part of retail electric revenues.
Total electric operating revenues in the graph above include intracompany sales of $1 million for both the six months ended June 30, 2026 and 2025.
The following table presents the current year decoupling deferrals and the amortization of prior year decoupling deferrals reflected in utility electric operating revenues for the six months ended June 30 (dollars in millions):
|
|
|
|
|
|
|
|
|
|
|
Electric Decoupling Revenues |
|
|
|
2026 |
|
|
2025 |
|
Current year decoupling deferrals (a) |
|
$ |
17 |
|
|
$ |
(4 |
) |
Amortization of prior year decoupling deferrals (b) |
|
|
(3 |
) |
|
|
— |
|
Total electric decoupling revenue |
|
$ |
14 |
|
|
$ |
(4 |
) |
(a)Positive amounts are increases in decoupling revenue in the current year due to lower customer usage and will be surcharged to customers in future years. Negative amounts are decreases in decoupling revenue in the current year due to higher customer usage and will be rebated to customers in future years.
(b)Positive amounts are increases in decoupling revenue in the current year and are related to the amortization of rebate balances that resulted in prior years due to higher customer usage and are being refunded to customers (causing a corresponding decrease in retail revenue from customers) in the current year. Negative amounts are decreases in decoupling revenue in the current year and are related to the amortization of surcharge balances that resulted in prior years due to lower customer usage and are being surcharged to customers (causing a corresponding increase in retail revenue from customers) in the current year.
Total electric revenues decreased $17 million for the first half of 2026 as compared to the first half of 2025. The primary changes that occurred during the period were as follows:
•A $1 million decrease in retail electric revenue due to a decrease in MWhs sold (decreased revenues by $42 million), offset by an increase in retail rates (increased revenues by $41 million).
oRetail rates increased mainly due to the effects of our general rate cases, including base rate increases associated with higher authorized power supply expenses resulting from removing Colstrip from our generation portfolio. These increases to base rates were partially offset by the removal of revenues related to recovery of Colstrip related costs other than power supply costs.
oRetail sales volumes decreased due to a 12 percent decrease in industrial electric sales volumes, partially due to the departure of a large industrial customer in April 2026. Additionally, milder weather led to reduced customer usage. Residential and commercial use per customer decreased 8 percent and 4 percent, respectively. Heating degree days in Spokane were 87 percent of the historical average during the first half of 2026, while they were 94 percent of the historical average during the first half of 2025.
•A $34 million decrease in wholesale electric revenues due to a decrease in sales prices (decreased revenues $29 million) and a decrease in sales volumes (decreased revenues $5 million).
•An $18 million increase in electric decoupling revenue primarily due to current year surcharge deferrals associated with decreased customer usage compared to rebate deferrals in the first half of 2025.
The following graphs present Avista Utilities' natural gas operating revenues and therms delivered for the six months ended June 30, 2026 and 2025 (dollars in millions and therms in thousands):
(1)This balance includes interruptible and industrial revenues, which are considered part of retail natural gas revenues.
Total natural gas operating revenues in the graph above include intracompany sales of $1 million and $4 million for the six months ended June 30, 2026 and 2025, respectively.
The following table presents the current year decoupling deferrals and the amortization of prior year decoupling deferrals reflected in utility natural gas operating revenues for the six months ended June 30 (dollars in millions):
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Decoupling Revenues |
|
|
|
2026 |
|
|
2025 |
|
Current year decoupling deferrals (a) |
|
$ |
31 |
|
|
$ |
10 |
|
Amortization of prior year decoupling deferrals (b) |
|
|
(7 |
) |
|
|
(2 |
) |
Total natural gas decoupling revenue |
|
$ |
24 |
|
|
$ |
8 |
|
(a)Positive amounts are increases in decoupling revenue in the current year due to lower customer usage and will be surcharged to customers in future years. Negative amounts are decreases in decoupling revenue in the current year due to higher customer usage and will be rebated to customers in future years.
(b)Positive amounts are increases in decoupling revenue in the current year and are related to the amortization of rebate balances that resulted in prior years due to higher customer usage and are being refunded to customers (causing a corresponding decrease in retail revenue from customers) in the current year. Negative amounts are decreases in decoupling revenue in the current year and are related to the amortization of surcharge balances that resulted in prior years due to lower customer usage and are being surcharged to customers (causing a corresponding increase in retail revenue from customers) in the current year.
Total natural gas revenues decreased $34 million for the first half of 2026 as compared to the first half of 2025. The primary changes that occurred during the period were as follows:
•A $50 million decrease in natural gas retail revenues (including industrial, which is included in other) due to a decrease in retail rates (decreased revenues $26 million) and decreased sales volumes (decreased revenues $24 million).
oRetail rates decreased mainly due to PGA rate decreases and rebates to Washington customers for revenues related to the sale of CCA emissions credits, neither of which impact net income. These decreases were partially offset by increases to base rates resulting from our general rate cases.
oRetail sales volumes decreased due to milder weather, which reduced customer usage. Residential and commercial use per customer each decreased 12 percent. Heating degree days in Spokane were 87 percent of the historical average during the first half of 2026, while they were 94 percent of the historical average in the first half of 2025.
•An $11 million decrease in wholesale natural gas revenues due to a decrease in prices (decreased revenues $8 million) and a decrease in volumes (decreased revenues $3 million).
•A $16 million increase in natural gas decoupling revenues primarily due to increased surcharge deferrals in the current year associated with lower customer usage.
•An $11 million increase in other gas revenues primarily due to the amortization of previously deferred revenues associated with the sale of CCA emissions credits. We amortize the deferred revenues as they are passed on to customers through decreases in retail rates. The increase in other revenues was offset by decreased retail rates as discussed above, resulting in no impact on net income. This increase was partially offset by a decrease in transportation revenue, as well as a provision for rate refunds associated with overearnings in Washington recorded in the first half of 2026.
Customers
The following table presents Avista Utilities' average number of electric and natural gas retail customers for the six months ended June 30, 2026 and 2025:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric Customers |
|
|
Natural Gas Customers |
|
|
|
2026 |
|
|
2025 |
|
|
2026 |
|
|
2025 |
|
Residential |
|
|
379,953 |
|
|
|
375,210 |
|
|
|
347,857 |
|
|
|
345,698 |
|
Commercial |
|
|
46,169 |
|
|
|
45,848 |
|
|
|
37,599 |
|
|
|
37,462 |
|
Interruptible |
|
|
— |
|
|
|
— |
|
|
|
51 |
|
|
|
52 |
|
Industrial |
|
|
1,133 |
|
|
|
1,162 |
|
|
|
181 |
|
|
|
184 |
|
Public street and highway lighting |
|
|
769 |
|
|
|
760 |
|
|
|
— |
|
|
|
— |
|
Total retail customers |
|
|
428,024 |
|
|
|
422,980 |
|
|
|
385,688 |
|
|
|
383,396 |
|
Utility Resource Costs
The following graph presents Avista Utilities' electric resource costs for the six months ended June 30, 2026 and 2025 (dollars in millions):
Total electric resource costs in the graph above include intracompany resource costs of $1 million and $4 million for the six months ended June 30, 2026 and 2025, respectively.
Total electric resource costs decreased $17 million for the first half of 2026 as compared to the first half of 2025. The primary changes that occurred during the period were as follows:
•A $2 million decrease in power purchased due to a decrease in wholesale prices (decreased costs $6 million), partially offset by an increase in the volume of power purchases (increased costs $4 million).
•A $37 million decrease in fuel for generation due to decreased thermal generation due to increased hydroelectric generation. Thermal generation decreased due to the removal of Colstrip from our generation portfolio, as well as major maintenance at the Coyote Springs 2 facility in 2026.
•A $22 million increase in other electric resource costs primarily related to a decrease in deferred costs under the ERM. The decrease in deferred costs was due to an increase in authorized power supply costs primarily due to the removal of
Colstrip from our generation portfolio. There were also increased costs related to our customer assistance payment programs (low-income rate assistance and demand side management).
In the first half of 2026, we had a pre-tax expense of $7 million under the ERM in Washington compared to a pre-tax expense of $9 million in the first half of 2025.
The following graph presents Avista Utilities' natural gas resource costs for the six months ended June 30, 2026 and 2025 (dollars in millions):
Total natural gas resource costs in the graph above include intracompany resource costs of $1 million for both the six months ended June 30, 2026 and 2025.
Total natural gas resource costs decreased $40 million for the first half of 2026 as compared to the first half of 2025 due to the following:
•A $12 million decrease in natural gas purchased due to a decrease in the volumes purchased.
•A $28 million decrease in other costs primarily related to a decrease in the amortization of costs associated with the CCA that were recovered from customers, resulting in no impact on net income, as well as a decrease in net deferrals and amortizations of previously deferred costs under our PGAs.
Results of Operations - Alaska Electric Light and Power Company
Net income for AEL&P was $1 million for both the second quarter of 2026 and 2025. For the first half of 2026 and 2025, net income for AEL&P was $5 million and $4 million, respectively.
Results of Operations - Other Businesses
Our other businesses had net income of $12 million for the three months ended June 30, 2026 compared to a net loss of $10 million for the three months ended June 30, 2025. For the first half of 2026, net income at our other businesses was $13 million compared to a net loss of $12 million for the first half of 2025.
The fluctuation in results is primarily related to recognizing our portion of earnings at our equity method investments, compared to losses in the first quarter of 2025. See “Note 5 of the Notes to Condensed Consolidated Financial Statements” for additional information regarding our equity method investments.
Critical Accounting Policies and Estimates
The preparation of our condensed consolidated financial statements in conformity with GAAP requires us to make estimates and assumptions that affect amounts reported in the condensed consolidated financial statements. Changes in these estimates and assumptions are considered reasonably possible and may have a material effect on our condensed consolidated financial statements and thus, actual results could differ from the amounts reported and disclosed herein. Our critical accounting policies that require the use of estimates and assumptions were discussed in detail in the 2025 Form 10-K and have not changed materially.
Liquidity and Capital Resources
Overall Liquidity
Our sources of overall liquidity and the requirements for liquidity have not materially changed in the six months ended June 30, 2026, with the exception of the following:
We have experienced increased regulatory deferrals (such as decoupling surcharges and ERM costs), as well as delayed recovery of deferrals. As such, we are evaluating the need for up to $100 million of additional short-term liquidity by the end of the fourth quarter of 2026.
See the 2025 Form 10-K for further discussion of our liquidity requirements.
As of June 30, 2026, we had $199 million of available liquidity under the Avista Corp. committed line of credit, $59 million of available liquidity under our letter of credit facility, and $25 million under the AEL&P committed line of credit. With our existing credit facilities and the expected issuances of common stock, long-term debt and contemplated short-term loan within the next year, we believe we have adequate liquidity to meet our needs for the next 12 months.
Review of Condensed Consolidated Cash Flow Statement
Operating Activities
Net cash provided by operating activities was $301 million for the six months ended June 30, 2026, compared to $224 million for the six months ended June 30, 2025. Net income increased $33 million; however, the majority of the increase was related to non-cash realized and unrealized gains on investments, compared to losses in the first half of 2025. The change in other current assets increased operating cash flows by $43 million compared to the prior year, and is primarily associated with increases to prepaid insurance proceeds receivable and prepayments in the first half of 2025. The change in accounts receivable also increased operating cash flows by $34 million, and the change in income taxes receivable increased operating cash flows by $26 million, primarily resulting from a refund received in the first half of 2026. These increases were partially offset by a larger portion of our revenues being from decoupling surcharges in the first half of 2026, which will be recovered from customers in future periods.
Investing Activities
Net cash used in investing activities was $334 million for the six months ended June 30, 2026, compared to $248 million for the six months ended June 30, 2025. We paid $326 million for utility capital expenditures in 2026, compared to $246 million in 2025.
Financing Activities
Net cash provided by financing activities was $39 million for the six months ended June 30, 2026, compared to $3 million for the six months ended June 30, 2025. We issued $160 million of long-term debt in the first half of 2026, with no long-term debt issuances in the first half of 2025. In the first half of 2026, we repaid $92 million in short term borrowings, compared to increasing our borrowings $51 million in the first half of 2025. We issued $58 million of common stock and paid $82 million in dividends in the six months
ended June 30, 2026, compared to issuing $35 million of common stock and paying $79 million in dividends in the six months ended June 30, 2025.
Capital Resources
Capital Structure
Our consolidated capital structure, including the current portion of long-term debt and short-term borrowings consisted of the following as of June 30, 2026 and December 31, 2025 (dollars in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2026 |
|
|
December 31, 2025 |
|
|
|
Amount |
|
|
Percent
of total |
|
|
Amount |
|
|
Percent
of total |
|
Current portion of long-term debt and leases |
|
$ |
9 |
|
|
|
0.2 |
% |
|
$ |
9 |
|
|
|
0.1 |
% |
Short-term borrowings |
|
|
226 |
|
|
|
3.7 |
|
|
|
388 |
|
|
|
6.5 |
|
Long-term debt to affiliated trusts |
|
|
52 |
|
|
|
0.8 |
|
|
|
52 |
|
|
|
0.9 |
|
Long-term debt and leases |
|
|
3,073 |
|
|
|
49.7 |
|
|
|
2,846 |
|
|
|
47.4 |
|
Total debt |
|
|
3,360 |
|
|
|
54.4 |
|
|
|
3,295 |
|
|
|
54.9 |
|
Total shareholders’ equity |
|
|
2,821 |
|
|
|
45.6 |
|
|
|
2,709 |
|
|
|
45.1 |
|
Total |
|
$ |
6,181 |
|
|
|
100.0 |
% |
|
$ |
6,004 |
|
|
|
100.0 |
% |
Our shareholders’ equity increased $112 million during the first half of 2026 primarily due to net income and the issuance of common stock, which was partially offset by dividends paid.
See “Note 10 of the Notes to Condensed Consolidated Financial Statements” for additional information regarding long-term debt and “Note 13 of the Notes to Condensed Consolidated Financial Statements” for additional information regarding common stock.
Short Term Borrowings
Avista Corp.
Avista Corp. has a committed line of credit with various financial institutions in the total amount of $500 million with an expiration date of June 2029. We may request that the lenders extend their commitments for an additional one-year period (subject to customary conditions).
We also have a continuing letter of credit agreement in the aggregate amount of $65 million, which was increased from $50 million in June 2026. Either party may terminate the agreement at any time.
The following table summarizes the balances outstanding and available liquidity as of June 30, 2026 (dollars in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount of Facility |
|
|
Borrowings Outstanding (1) |
|
|
Letters of Credit Outstanding (2) |
|
|
Available Liquidity |
|
Line of Credit expiring June 2029 |
|
$ |
500 |
|
|
$ |
296 |
|
|
$ |
5 |
|
|
$ |
199 |
|
Letter of Credit Facility |
|
|
65 |
|
|
N/A |
|
|
|
6 |
|
|
|
59 |
|
Total |
|
$ |
565 |
|
|
$ |
296 |
|
|
$ |
11 |
|
|
$ |
258 |
|
(1)As of June 30, 2026, there was $296 million outstanding under the committed line of credit; however, $226 million was classified as short-term borrowings and $70 million was classified as long-term on the Condensed Consolidated Balance Sheet due to the Company's intention to refinance such amount on a long-term basis. The amount classified as long-term debt will be refinanced through the issuance and sale of first mortgage bonds in August 2026, pursuant to a bond purchase agreement entered into in May 2026.
(2)Letters of credit are not reflected on the Condensed Consolidated Balance Sheets. If a letter of credit were drawn upon by the holder, we would have an immediate obligation to reimburse the bank that issued that letter.
The Avista Corp. credit facilities contain customary covenant and default provisions, including a change in control (as defined in the agreements). The events of default under each of the credit facilities also include a cross default from other indebtedness (as defined) and, in the case of the letter of credit agreement, other obligations. The committed line of credit agreement also includes a covenant
which does not permit our ratio of “consolidated total debt” to “consolidated total capitalization” to be greater than 65 percent at any time. As of June 30, 2026, we complied with this covenant with a ratio of 54.4 percent.
Balances outstanding and interest rates of borrowings (excluding letters of credit) under Avista Corp.'s lines of credit were as follows as of and for the six months ended June 30 (dollars in millions):
|
|
|
|
|
|
|
|
|
|
|
2026 |
|
|
2025 |
|
$500 million line of credit, expiring June 2029 |
|
|
|
|
|
|
Maximum balance outstanding during the period |
|
$ |
415 |
|
|
$ |
400 |
|
Average balance outstanding during the period |
|
$ |
352 |
|
|
$ |
312 |
|
Average interest rate during the period |
|
|
4.79 |
% |
|
|
5.44 |
% |
Average interest rate at end of the period |
|
|
4.74 |
% |
|
|
5.42 |
% |
AEL&P
AEL&P has a $25 million committed line of credit that expires in June 2028. As of June 30, 2026, there was no balance outstanding under this committed line of credit, and $25 million of available liquidity.
The AEL&P credit facility contains customary covenants and default provisions including a covenant which does not permit the ratio of “consolidated total debt at AEL&P” to “consolidated total capitalization at AEL&P” (including the impact of the Snettisham obligation) to be greater than 67.5 percent at any time. As of June 30, 2026, AEL&P complied with this covenant with a ratio of 48.3 percent.
As of June 30, 2026, Avista Corp. and its subsidiaries complied with all of the covenants of their financing agreements, and none of Avista Corp.'s subsidiaries constituted a “significant subsidiary” as defined in Avista Corp.'s committed line of credit.
See “Note 9 of the Notes to Condensed Consolidated Financial Statements” for additional information regarding our short-term borrowing arrangements.
Liquidity Expectations
In 2026, we expect to issue $230 million of long-term debt, including the $160 million issued through June 30, 2026. We expect to issue $90 million of common stock in 2026 (including $58 million issued through June 30, 2026).
In addition, we are evaluating the need for up to $100 million of additional short-term liquidity by the end of the fourth quarter of 2026. See further discussion of liquidity requirements in “Overall Liquidity” above.
Capital Expenditures and Other Investments
We are making capital investments to enhance service and system reliability for our customers and replace aging infrastructure, and expect base Avista Utilities' capital expenditures of the following (dollars in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2026 |
|
|
2027 |
|
|
2028 |
|
|
2029 |
|
|
2030 |
|
|
Expected base annual capital expenditures |
|
$ |
615 |
|
|
$ |
635 |
|
|
$ |
800 |
|
|
$ |
680 |
|
|
$ |
710 |
|
|
These planned capital expenditures are subject to continuing review and adjustment. These estimates include expenditures for new projects identified through our 2025 request for proposal process. However, these estimates do not include potential expenditures that could result from integrating a new large load customer, incremental transmission projects like regional grid expansion, or additional generation. See the 2025 Form 10-K for further information on our expected capital expenditures.
Pension Plan
In the six months ended June 30, 2026, we contributed $7 million to the pension plan and we expect contributions to total $10 million in 2026. We expect to contribute a total of $40 million to the pension plan in the period 2027 through 2030, with an annual contribution of $10 million.
The final determination of pension plan contributions for future periods is subject to multiple variables, most of which are beyond our control, including changes to the fair value of pension plan assets, changes in actuarial assumptions (in particular, the discount rate used in determining the benefit obligation), or changes in federal legislation. We may change our pension plan contributions in the future depending on changes to any variables, including those listed above.
See "Note 7 of the Notes to Condensed Consolidated Financial Statements" for additional information regarding the pension plan.
Environmental Issues and Contingencies
Our environmental issues and contingencies disclosures have not materially changed during the six months ended June 30, 2026 except as follows:
Presidential Executive Action
On March 16, 2026, the President of the U.S. issued an Executive Order entitled “Removing Regulatory Barriers to Affordable Home Construction,” with the stated objective of increasing housing supply and affordability by reducing federal, state and local regulatory requirements that the Administration views as increasing construction costs and slowing development. Among other things, the Executive Order directs various federal agencies to incentivize state and local governments to eliminate mandatory green or energy-efficient building codes, review and potentially eliminate “unduly burdensome or costly” federal energy efficiency requirements, revise permitting rules relating to stormwater, wetlands and water pollution controls, and shorten environmental review timelines for housing projects.
On April 20, 2026, the President of the U.S. issued several Executive Orders invoking authority under the Defense Production Act of 1950 (DPA) to (a) designate oil production and storage, coal and natural gas related power generation activities, electric facilities and supply chains, and large scale energy and energy-related infrastructure as critical resources under the DPA and (b) authorize the Department of Energy to use its authority under the DPA to expand and accelerate domestic capacity in each of these areas.
We are evaluating the extent to which potential changes from these Executive Orders may affect our financial results and operations.
Oregon Legislation and Regulatory Actions
Climate Protection Plan
In March 2020, Oregon Governor Kate Brown issued Executive Order No. 20-04, “Directing State Agencies to Take Actions to Reduce and Regulate Greenhouse Gas Emissions.” The Executive Order launched rulemaking proceedings for Oregon agencies with jurisdiction over GHG-related matters, with the aim of reducing Oregon’s overall GHG emissions to 80 percent below 1990 levels by 2050. This Executive Order led to the Oregon Department of Environmental Quality (ODEQ) developing cap and reduce rules known as the CPP. The CPP originally became effective in January 2022, but was subsequently challenged and declared invalid on procedural grounds. Thereafter, the ODEQ reissued the CPP in November 2024 with updated compliance periods.
On April 16, 2026, approximately 30 parties, consisting of businesses, utilities, trade associations and unions, filed a Petition challenging the repromulgated version of the CPP. Avista Corp. is a party to the litigation, which remains pending.
See the 2025 Form 10-K for further discussion of our environmental issues and contingencies.
Enterprise Risk Management
The material risks to our businesses, and our mitigation process and procedures to address these risks, were discussed in our 2025 Form 10-K and have not materially changed during the six months ended June 30, 2026. See the 2025 Form 10-K.
Financial Risk
Our financial risks have not materially changed during the six months ended June 30, 2026. Refer to the 2025 Form 10-K. The financial risks included below are required interim disclosures, even if they have not materially changed from December 31, 2025.
Credit Risk
As of June 30, 2026, we had cash deposited as collateral of $13 million and letters of credit of $6 million outstanding related to our energy contracts. Price movements and/or a downgrade in our credit ratings or other established credit criteria could impact further the amount of collateral required. See “Credit Ratings” in the 2025 Form 10-K for further information. For example, in addition to limiting our ability to conduct transactions, if our credit ratings were lowered to below “investment grade” based on our positions outstanding at June 30, 2026 (including both contracts considered derivatives and those considered non-derivatives), we would potentially be required to post the following additional collateral (dollars in millions):
|
|
|
|
|
|
|
June 30, 2026 |
|
Additional collateral taking into account contractual thresholds |
|
$ |
25 |
|
Additional collateral without contractual thresholds |
|
|
36 |
|
Energy Commodity Risk
Our energy commodity risks have not materially changed during the six months ended June 30, 2026. See the 2025 Form 10-K. The following table presents energy commodity derivative fair values as a net asset or (liability) as of June 30, 2026 expected to be settled in each respective year (dollars in millions). As of June 30, 2026, there are no energy commodity derivative contracts outstanding with expected settlements after 2028:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchases |
|
|
Sales |
|
|
|
Electric Derivatives |
|
|
Gas Derivatives |
|
|
Electric Derivatives |
|
|
Gas Derivatives |
|
Year |
|
Physical (1) |
|
|
Financial (1) |
|
|
Physical (1) |
|
|
Financial (1) |
|
|
Physical (1) |
|
|
Financial (1) |
|
|
Physical (1) |
|
|
Financial (1) |
|
Remainder 2026 |
|
$ |
— |
|
|
$ |
— |
|
|
$ |
(13 |
) |
|
$ |
(8 |
) |
|
$ |
5 |
|
|
$ |
2 |
|
|
$ |
(1 |
) |
|
$ |
— |
|
2027 |
|
|
— |
|
|
|
— |
|
|
|
(11 |
) |
|
|
(6 |
) |
|
|
— |
|
|
|
— |
|
|
|
(4 |
) |
|
|
— |
|
2028 |
|
|
— |
|
|
|
— |
|
|
|
(3 |
) |
|
|
(2 |
) |
|
|
— |
|
|
|
— |
|
|
|
(3 |
) |
|
|
— |
|
The following table presents energy commodity derivative fair values as a net asset or (liability) as of December 31, 2025 expected to be settled in each respective year (dollars in millions). As of December 31, 2025, there are no energy commodity derivative contracts outstanding with expected settlements after 2028.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchases |
|
|
Sales |
|
|
|
Electric Derivatives |
|
|
Gas Derivatives |
|
|
Electric Derivatives |
|
|
Gas Derivatives |
|
Year |
|
Physical (1) |
|
|
Financial (1) |
|
|
Physical (1) |
|
|
Financial (1) |
|
|
Physical (1) |
|
|
Financial (1) |
|
|
Physical (1) |
|
|
Financial (1) |
|
2026 |
|
$ |
— |
|
|
$ |
— |
|
|
$ |
(17 |
) |
|
$ |
(10 |
) |
|
$ |
8 |
|
|
$ |
4 |
|
|
$ |
(3 |
) |
|
$ |
— |
|
2027 |
|
|
— |
|
|
|
— |
|
|
|
(3 |
) |
|
|
(1 |
) |
|
|
— |
|
|
|
— |
|
|
|
(4 |
) |
|
|
— |
|
2028 |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(3 |
) |
|
|
— |
|
(1)Physical transactions represent commodity transactions in which we take or make delivery of either electricity or natural gas; financial transactions represent financial derivative instruments that are settled in cash with no physical delivery of the underlying commodity, such as futures, swap derivatives, or options contracts.
The above electric and natural gas derivative contracts will be included in either power supply costs or natural gas supply costs during the period they are settled and will be included in deferral and recovery mechanisms (ERM, PCA, and PGAs), or in the general rate case process, and are expected to eventually be collected through retail rates from customers.
Item 3. Quantitative and Qualitative Disclosures about Market Risk
The information required by this item is set forth in the Enterprise Risk Management section of "Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations" and is incorporated herein by reference.
Item 4. Controls and Procedures
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
The Company has disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended) (Act) that are designed to ensure that information required to be disclosed in the reports it files or submits under
the Act is recorded, processed, summarized and reported on a timely basis. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Company in the reports that it files or submits under the Act is accumulated and communicated to the Company’s management, including its principal executive and principal financial officers, as appropriate, to allow timely decisions regarding required disclosure. With the participation of the Company’s principal executive officer and principal financial officer, the Company's management evaluated its disclosure controls and procedures as of the end of the period covered by this report. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon this evaluation, the Company’s principal executive officer and principal financial officer have concluded that the Company’s disclosure controls and procedures are effective at a reasonable assurance level as of June 30, 2026.
There have been no changes in the Company's internal control over financial reporting that occurred during the second quarter of 2026 that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.