Vistra Corp.
For the period ended Jun 30, 2025. Filed Aug 8, 2025.
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A company's report for each of its first three quarters. The financial statements are not audited. It shows how the business has moved since the last annual report, and what management says changed.
Jun 30, 2025 · Filed Aug 8, 2025
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Item 2. Results of Operations
Results of Operations
Net income decreased $140 million to $327 million for the three months ended June 30, 2025 compared to the three months ended June 30, 2024. Net income decreased $426 million to $59 million for the six months ended June 30, 2025 compared to the six months ended June 30, 2024. For additional information see the following discussion of our results of operations.
EBITDA and Adjusted EBITDA
In analyzing and planning for our business, we supplement our use of GAAP financial measures with non-GAAP financial measures, including EBITDA and Adjusted EBITDA as performance measures. These non-GAAP financial measures reflect an additional way of viewing aspects of our business that, when viewed (i) with our GAAP results and (ii) the accompanying reconciliations to corresponding GAAP financial measures may provide a more complete understanding of factors and trends affecting our business. Because EBITDA and Adjusted EBITDA are financial measures that management uses to allocate resources, determine our ability to fund capital expenditures, assess performance against our peers, and evaluate overall financial performance, we believe they provide useful information for investors.
These non-GAAP financial measures should not be relied upon to the exclusion of GAAP financial measures and are, by definition, an incomplete understanding of Vistra and must be considered in conjunction with GAAP measures. In addition, non-GAAP financial measures are not standardized; therefore, it may not be possible to compare these financial measures with other companies' non-GAAP financial measures having the same or similar names. We strongly encourage investors to review the condensed consolidated financial statements and publicly filed reports in their entirety and not rely on any single financial measure.
When EBITDA or Adjusted EBITDA is discussed in reference to performance on a consolidated basis, the most directly comparable GAAP financial measure to EBITDA and Adjusted EBITDA is Net income (loss).
Vistra Consolidated Financial Results — Three Months Ended June 30, 2025 Compared to the Three Months Ended June 30, 2024
| Three Months Ended June 30, 2025 | |||||||
|---|---|---|---|---|---|---|---|
| Retail | Texas | East | West | Asset Closure | Eliminations / Corporate and Other | Vistra Consolidated | |
| (in millions) | |||||||
| Operating revenues | $3,532 | $1,788 | $1,480 | $25 | $20 | $(2,595) | $4,250 |
| Fuel, purchased power costs and delivery fees | (3,321) | (468) | (746) | (35) | — | 2,596 | (1,974) |
| Operating costs | (37) | (277) | (355) | (18) | (45) | (1) | (733) |
| Depreciation and amortization | (24) | (167) | (316) | (16) | 1 | (19) | (541) |
| Selling, general and administrative expenses | (256) | (43) | (58) | (7) | (19) | (36) | (419) |
| Impairment of long-lived assets | — | (68) | — | — | — | — | (68) |
| Operating income (loss) | (106) | 765 | 5 | (51) | (43) | (55) | 515 |
| Other income, net | — | 80 | 108 | — | 1 | 2 | 191 |
| Interest expense and related charges | (17) | 18 | 8 | 1 | (1) | (312) | (303) |
| Income (loss) before income taxes | (123) | 863 | 121 | (50) | (43) | (365) | 403 |
| Income tax expense | — | — | (1) | — | — | (75) | (76) |
| Net income (loss) | $(123) | $863 | $120 | $(50) | $(43) | $(440) | $327 |
| Income tax expense | — | — | 1 | — | — | 75 | 76 |
| Interest expense and related charges (a) | 17 | (18) | (8) | (1) | 1 | 312 | 303 |
| Depreciation and amortization (b) | 24 | 197 | 412 | 16 | (1) | 20 | 668 |
| EBITDA before Adjustments | (82) | 1,042 | 525 | (35) | (43) | (33) | 1,374 |
| Unrealized net (gain) loss resulting from hedging transactions | 841 | (900) | (39) | 82 | — | — | (16) |
| Purchase accounting impacts | 8 | — | 9 | — | — | — | 17 |
| Non-cash compensation expenses | — | — | — | — | — | 25 | 25 |
| Transition and merger expenses | 5 | — | — | — | — | 17 | 22 |
| Impairment of long lived assets | — | 68 | — | — | — | — | 68 |
| Insurance income (c) | — | (80) | — | — | (21) | — | (101) |
| Decommissioning-related activities (d) | — | 4 | (81) | — | 43 | — | (34) |
| ERP system implementation expenses | 3 | 3 | 3 | — | 1 | — | 10 |
| Other, net (e) | (19) | 5 | 1 | 2 | 3 | (25) | (33) |
| Adjusted EBITDA | $756 | $142 | $418 | $49 | $(17) | $(16) | $1,332 |
(a)Includes $26 million of unrealized mark-to-market net losses on interest rate swaps.
(b)Includes nuclear fuel amortization of $30 million and $92 million, respectively, in the Texas and East segments.
(c)Includes involuntary conversion gain recognized from Martin Lake Incident property damage insurance in the Texas segment and revenues from Moss Landing Incident business interruption proceeds in the Asset Closure segment.
(d)Represents net of all NDT (income) loss of the PJM nuclear facilities and all ARO and environmental remediation expenses.
(e)Includes the final application of bill credits to large commercial and industrial customers that curtailed their usage during Winter Storm Uri in the Retail segment.
| Three Months Ended June 30, 2024 | |||||||
|---|---|---|---|---|---|---|---|
| Retail | Texas | East | West | Asset Closure | Eliminations / Corporate and Other | Vistra Consolidated | |
| (in millions) | |||||||
| Operating revenues | $3,168 | $221 | $1,532 | $193 | $9 | $(1,278) | $3,845 |
| Fuel, purchased power costs and delivery fees | (1,960) | (381) | (494) | (40) | (1) | 1,279 | (1,597) |
| Operating costs | (40) | (254) | (297) | (17) | (20) | — | (628) |
| Depreciation and amortization | (31) | (134) | (233) | (14) | (7) | (18) | (437) |
| Selling, general and administrative expenses | (224) | (41) | (33) | (2) | (15) | (60) | (375) |
| Operating income (loss) | 913 | (589) | 475 | 120 | (34) | (77) | 808 |
| Other income (deductions), net | — | 4 | 42 | (1) | 4 | 10 | 59 |
| Interest expense and related charges | (16) | 12 | 1 | — | (1) | (237) | (241) |
| Income (loss) before income taxes | 897 | (573) | 518 | 119 | (31) | (304) | 626 |
| Income tax expense | — | — | — | — | — | (159) | $(159) |
| Net income (loss) | $897 | $(573) | $518 | $119 | $(31) | $(463) | $467 |
| Income tax expense | — | — | — | — | — | 159 | 159 |
| Interest expense and related charges (a) | 16 | (12) | (1) | — | 1 | 237 | 241 |
| Depreciation and amortization (b) | 31 | 160 | 304 | 14 | 7 | 18 | 534 |
| EBITDA before Adjustments | 944 | (425) | 821 | 133 | (23) | (49) | 1,401 |
| Unrealized net (gain) loss resulting from hedging transactions | (162) | 656 | (460) | (77) | (2) | — | (45) |
| Purchase accounting impacts | — | — | (3) | — | — | — | (3) |
| Non-cash compensation expenses | — | — | — | — | — | 32 | 32 |
| Transition and merger expenses | 1 | — | — | — | — | 24 | 25 |
| Decommissioning-related activities (c) | — | 5 | (15) | — | — | — | (10) |
| ERP system implementation expenses | 4 | 3 | 3 | — | 1 | — | 11 |
| Other, net | 2 | 3 | (1) | 2 | — | (29) | (23) |
| Adjusted EBITDA | $789 | $242 | $345 | $58 | $(24) | $(22) | $1,388 |
(a)Includes $11 million of unrealized mark-to-market net gains on interest rate swaps.
(b)Includes nuclear fuel amortization of $26 million and $71 million, respectively, in the Texas and East segments.
(c)Represents net of all NDT (income) loss, ARO accretion expense for operating assets, and ARO remeasurement impacts for operating assets.
GAAP Net income decreased $140 million to $327 million for the three months ended June 30, 2025 compared to the three months ended June 30, 2024. The primary drivers for the decrease in GAAP Net income include:
Unfavorable impacts:
An increase of $105 million in operating costs due primarily to increased plant outage expenses and expenses related to the Moss Landing Incident.
An increase of $104 million in depreciation and amortization due primarily to an increase in capital additions in Texas and East.
An increase of $68 million in impairment of long-lived assets related to certain development projects in the three months ended June 30, 2025.
An increase of $62 million in interest expense due primarily to unrealized mark-to-market net losses on interest rate swaps in the three months ended June 30, 2025.
A decrease of $29 million in unrealized mark-to-market gains on commodity derivative positions. See further information on our derivative results in Energy-Related Commodity Contracts and Mark-to-Market Activities below.
Favorable impacts:
$80 million of involuntary conversion gains on property damage insurance from the Martin Lake Incident and $21 million of business interruption revenue from the Moss Landing Incident recognized in the three months ended June 30, 2025.
An increase of $67 million in NDT income due to realized and unrealized gains on equity securities.
A decrease in income tax expense due to lower pre-tax income.
| Three Months Ended June 30, | ||||||||
|---|---|---|---|---|---|---|---|---|
| Retail | Texas | East | West | |||||
| 2025 | 2024 | 2025 | 2024 | 2025 | 2024 | 2025 | 2024 | |
| Retail sales volumes (GWh): | ||||||||
| Retail electricity sales volumes: | ||||||||
| Sales volumes in ERCOT | 19,885 | 18,967 | ||||||
| Sales volumes in Northeast/Midwest | 13,382 | 15,980 | ||||||
| Total retail electricity sales volumes | 33,267 | 34,947 | ||||||
| Production volumes (GWh): | ||||||||
| Natural gas facilities | 11,200 | 11,201 | 12,198 | 12,370 | 545 | 697 | ||
| Lignite and coal facilities | 4,871 | 5,546 | 4,020 | 3,901 | ||||
| Nuclear facilities | 4,490 | 5,035 | 8,017 | 7,432 | ||||
| Solar facilities | 213 | 216 | 67 | |||||
| Capacity factors: | ||||||||
| CCGT facilities | 54.8% | 59.3% | 51.2% | 50.1% | 24.5% | 31.3% | ||
| Lignite and coal facilities | 49.6% | 56.4% | 46.9% | 45.5% | ||||
| Nuclear facilities | 85.7% | 96.0% | 90.7% | 84.1% | ||||
| Weather - percent of normal (a): | ||||||||
| Cooling degree days | 101% | 118% | 111% | 118% | 101% | 123% | 91% | 72% |
| Heating degree days | 84% | 44% | 99% | 25% | 90% | 77% | 131% | 148% |
(a)Reflects cooling degree or heating degree days based on Weather Services International (WSI) data. A degree day compares the average of the hourly outdoor temperatures during each day to a 65° Fahrenheit base temperature. Retail amounts represent weather data for the Dallas-Fort Worth area.
| Three Months Ended June 30, · Three Months Ended June 30, | |||||
|---|---|---|---|---|---|
| 2025 · 2024 · 2025 · 2024 | |||||
| Average Power Price ($MWh) (a): · Average Natural gas price ($MWh) (b): | |||||
| ERCOT North Hub | $32.02 | $28.64 | NYMEX Henry Hub | $3.16 | $2.04 |
| ERCOT West Hub | $31.44 | $27.60 | Houston Ship Channel | $2.74 | $1.67 |
| PJM AEP Dayton Hub | $40.58 | $28.64 | Permian Basin | $1.10 | $(0.59) |
| PJM Northern Illinois Hub | $31.03 | $22.36 | Dominion South | $2.32 | $1.45 |
| PJM Western Hub | $42.35 | $30.83 | Tetco ELA | $2.88 | $1.83 |
| MISO Indiana Hub | $39.35 | $30.47 | Chicago Citygate | $2.86 | $1.65 |
| ISONE Massachusetts Hub | $40.07 | $29.28 | Tetco M3 | $2.47 | $1.53 |
| New York Zone A | $35.73 | $26.60 | Algonquin Citygates | $2.86 | $1.68 |
| CAISO NP15 | $26.62 | $23.30 | PG&E Citygate | $2.81 | $2.21 |
(a) Reflects the average around-the-clock settled prices for the periods presented and does not necessarily reflect prices we realized.
(b)Reflects the average around-the-clock settled prices for the periods presented and does not reflect costs incurred by us.
Adjusted EBITDA for the three months ended June 30, 2025 compared to the three months ended June 30, 2024 decreased by $56 million. The primary drivers for the increase include:
| Three Months Ended June 30, 2025 Compared to 2024 | ||||
|---|---|---|---|---|
| Retail | Texas | East | West | |
| (in millions) | ||||
| Favorable change in realized revenue net of fuel in East driven by higher volumes and margins. Unfavorable change in Texas driven by the Martin Lake Incident | $— | $(72) | $138 | $(5) |
| Retail margins consistent with prior year | (3) | — | — | — |
| Unfavorable change in weather impacts | (8) | — | — | — |
| Increase in plant operating costs due primarily to increased outage expenses | — | (24) | (56) | (1) |
| Change in SG&A and other due primarily to higher retail revenues and customer acquisition costs | (22) | (4) | (9) | (3) |
| Change in Adjusted EBITDA | $(33) | $(100) | $73 | $(9) |
| Change in depreciation and amortization driven primarily by an increase in capital additions in Texas and East | 7 | (37) | (108) | (2) |
| Change in unrealized net gains (losses) on hedging activities (a) | (1,003) | 1,556 | (421) | (159) |
| Impairment of long-lived assets | — | (68) | — | — |
| Increase in other income due to involuntary conversion gain on Martin Lake Incident | — | 80 | — | — |
| Decommissioning related activities | — | 1 | 66 | — |
| Other (including interest expenses) | 9 | 3 | (8) | 1 |
| Change in Net income (loss) | $(1,020) | $1,435 | $(398) | $(169) |
(a) See Energy-Related Commodity Contracts and Mark-to-Market Activities below for analysis of hedging strategy.
Vistra Consolidated Financial Results — Six Months Ended June 30, 2025 Compared to the Six Months Ended June 30, 2024
The following table presents Net income (loss), EBITDA and Adjusted EBITDA for the six months ended June 30, 2025:
| Six Months Ended June 30, 2025 | |||||||
|---|---|---|---|---|---|---|---|
| Retail | Texas | East | West | Asset Closure | Eliminations / Corporate and Other | Vistra Consolidated | |
| (in millions) | |||||||
| Operating revenues | $6,700 | $1,998 | $2,860 | $182 | $24 | $(3,581) | $8,183 |
| Fuel, purchased power costs, and delivery fees | (5,033) | (965) | (1,918) | (87) | — | 3,582 | (4,421) |
| Operating costs | (77) | (535) | (682) | (30) | (101) | (1) | (1,426) |
| Depreciation and amortization | (47) | (317) | (632) | (31) | 2 | (38) | (1,063) |
| Selling, general, and administrative expenses | (499) | (84) | (116) | (9) | (36) | (66) | (810) |
| Impairment of long-lived assets | — | (68) | — | — | — | — | (68) |
| Operating income (loss) | 1,044 | 29 | (488) | 25 | (111) | (104) | 395 |
| Other income, net | — | 82 | 99 | — | 2 | 3 | 186 |
| Interest expense and related charges | (35) | 32 | 20 | 2 | (2) | (639) | (622) |
| Income (loss) before income taxes | 1,009 | 143 | (369) | 27 | (111) | (740) | (41) |
| Income tax (expense) benefit | — | — | (1) | — | — | 101 | 100 |
| Net income (loss) | $1,009 | $143 | $(370) | $27 | $(111) | $(639) | $59 |
| Income tax expense (benefit) | — | — | 1 | — | — | (101) | (100) |
| Interest expense and related charges (a) | 35 | (32) | (20) | (2) | 2 | 639 | 622 |
| Depreciation and amortization (b) | 47 | 378 | 808 | 31 | (2) | 39 | 1,301 |
| EBITDA before Adjustments | 1,091 | 489 | 419 | 56 | (111) | (62) | 1,882 |
| Unrealized net (gain) loss resulting from commodity hedging transactions | (156) | 130 | 528 | 50 | (1) | — | 551 |
| Purchase accounting impacts | 8 | — | 23 | — | — | — | 31 |
| Non-cash compensation expenses | — | — | — | — | — | 46 | 46 |
| Transition and merger expenses | 5 | — | 1 | — | — | 34 | 40 |
| Impairment of long-lived assets | — | 68 | — | — | — | — | 68 |
| Insurance income (c) | — | (80) | — | — | (21) | — | (101) |
| Decommissioning-related activities (d) | — | 9 | (46) | — | 89 | — | 52 |
| ERP system implementation expenses | 3 | 3 | 3 | — | 1 | — | 10 |
| Other, net (e) | (11) | 13 | 4 | 5 | 2 | (44) | (31) |
| Adjusted EBITDA | $940 | $632 | $932 | $111 | $(41) | $(26) | $2,548 |
(a)Includes $74 million of unrealized mark-to-market net losses on interest rate swaps.
(b)Includes nuclear fuel amortization of $61 million and $176 million, respectively, in the Texas and East segments.
(c)Includes involuntary conversion gain recognized from Martin Lake Incident property damage insurance in the Texas segment and revenues from Moss Landing Incident business interruption proceeds in the Asset Closure segment.
(d)Represents net of all NDT (income) loss of the PJM nuclear facilities and all ARO and environmental remediation expenses.
(e)Includes the final application of bill credits to large commercial and industrial customers that curtailed their usage during Winter Storm Uri in the Retail segment.
The following table presents Net income (loss), EBITDA and Adjusted EBITDA for the six months ended June 30, 2024:
| Six Months Ended June 30, 2024 | |||||||
|---|---|---|---|---|---|---|---|
| Retail | Texas | East | West | Asset Closure | Eliminations / Corporate and Other | Vistra Consolidated | |
| (in millions) | |||||||
| Operating revenues | $5,662 | $680 | $2,388 | $469 | $18 | $(2,318) | $6,899 |
| Fuel, purchased power costs, and delivery fees | (3,607) | (762) | (1,141) | (119) | (3) | 2,319 | (3,313) |
| Operating costs | (71) | (511) | (478) | (28) | (37) | (1) | (1,126) |
| Depreciation and amortization | (54) | (268) | (443) | (28) | (14) | (33) | (840) |
| Selling, general, and administrative expenses | (449) | (76) | (61) | (6) | (25) | (109) | (726) |
| Operating income (loss) | 1,481 | (937) | 265 | 288 | (61) | (142) | 894 |
| Other income (deductions), net | (1) | 6 | 80 | (1) | 7 | 55 | 146 |
| Interest expense and related charges | (22) | 22 | — | — | (2) | (409) | (411) |
| Impacts of Tax Receivable Agreement | — | — | — | — | — | (5) | (5) |
| Income (loss) before income taxes | 1,458 | (909) | 345 | 287 | (56) | (501) | 624 |
| Income tax expense | — | — | — | — | — | (139) | (139) |
| Net income (loss) | $1,458 | $(909) | $345 | $287 | $(56) | $(640) | $485 |
| Income tax expense | — | — | — | — | — | 139 | 139 |
| Interest expense and related charges (a) | 22 | (22) | — | — | 2 | 409 | 411 |
| Depreciation and amortization (b) | 54 | 320 | 537 | 28 | 14 | 33 | 986 |
| EBITDA before Adjustments | 1,534 | (611) | 882 | 315 | (40) | (59) | 2,021 |
| Unrealized net (gain) loss resulting from commodity hedging transactions | (786) | 1,260 | (131) | (207) | (6) | — | 130 |
| Purchase accounting impacts | (1) | — | (4) | — | — | (14) | (19) |
| Impacts of Tax Receivable Agreement (c) | — | — | — | — | — | (5) | (5) |
| Non-cash compensation expenses | — | — | — | — | — | 53 | 53 |
| Transition and merger expenses | 2 | — | 6 | — | — | 52 | 60 |
| Decommissioning-related activities (d) | — | 11 | (40) | 1 | — | — | (28) |
| ERP system implementation | 6 | 5 | 5 | 1 | 1 | — | 18 |
| Other, net | 6 | 6 | (5) | 3 | 1 | (63) | (52) |
| Adjusted EBITDA | $761 | $671 | $713 | $113 | $(44) | $(36) | $2,178 |
(a)Includes $58 million of unrealized mark-to-market net gains on interest rate swaps.
(b)Includes nuclear fuel amortization of $52 million and $94 million, respectively, in the Texas and East segments.
(c)Includes $10 million gain recognized on the repurchase of TRA Rights.
(d)Represents net of all NDT (income) loss, ARO accretion expense for operating assets, and ARO remeasurement impacts for operating assets.
GAAP Net income decreased $426 million to $59 million for the six months ended June 30, 2025 compared to the six months ended June 30, 2024. The primary drivers for the decrease in GAAP Net income include:
Unfavorable impacts:
An increase of $421 million in unrealized mark-to-market losses on derivative positions due to power and natural gas curves moving up more significantly in the six months ended June 30, 2025 as compared to the six months ended June 30, 2024. See further information on our derivative results in Energy-Related Commodity Contracts and Mark-to-Market Activities below.
An increase of $77 million in operating costs due to the Moss Landing Incident, net of expected insurance recoveries.
An increase of $68 million in impairment of long-lived assets related to certain development projects in the six months ended June 30, 2025.
Favorable impacts:
Inclusion of six months of Energy Harbor revenues net of expenses in the East and Retail segments for 2025 compared to four months in 2024.
$80 million of involuntary conversion gains on property damage insurance from the Martin Lake Incident and $21 million of business interruption revenue from the Moss Landing Incident recognized in the three months ended June 30, 2025.
The following table presents the operational performance of our retail and generation segments:
| Six Months Ended June 30, | ||||||||
|---|---|---|---|---|---|---|---|---|
| Retail | Texas | East | West | |||||
| 2025 | 2024 | 2025 | 2024 | 2025 | 2024 | 2025 | 2024 | |
| Retail electricity sales volumes (GWh): | ||||||||
| Sales volumes in ERCOT | 37,850 | 35,041 | ||||||
| Sales volumes in Northeast/Midwest | 28,740 | 26,241 | ||||||
| Total retail electricity sales volumes | 66,590 | 61,282 | ||||||
| Production volumes (GWh): | ||||||||
| Natural gas facilities | 20,345 | 19,352 | 26,840 | 27,132 | 1,047 | 1,925 | ||
| Lignite and coal facilities | 10,308 | 10,660 | 9,194 | 7,135 | ||||
| Nuclear facilities | 9,719 | 10,043 | 15,696 | 9,761 | ||||
| Solar facilities | 375 | 372 | 111 | |||||
| Capacity factors: | ||||||||
| CCGT facilities | 51.5% | 51.6% | 57.2% | 55.8% | 23.6% | 43.1% | ||
| Lignite and coal facilities | 52.7% | 54.2% | 53.9% | 41.6% | ||||
| Nuclear facilities | 93.2% | 95.8% | 89.3% | 82.4% | ||||
| Weather - percent of normal (a): | ||||||||
| Cooling degree days | 104% | 120% | 114% | 118% | 102% | 123% | 88% | 69% |
| Heating degree days | 104% | 86% | 112% | 89% | 99% | 85% | 125% | 121% |
(a)Reflects cooling degree or heating degree days based on Weather Services International (WSI) data. A degree day compares the average of the hourly outdoor temperatures during each day to a 65° Fahrenheit base temperature. Retail amounts represent weather data for the Dallas-Fort Worth area.
| Six Months Ended June 30, · Six Months Ended June 30, | |||||
|---|---|---|---|---|---|
| 2025 · 2024 · 2025 · 2024 | |||||
| Average Power Price ($MWh) (a): · Average Natural Gas Price ($MWh) (b): | |||||
| ERCOT North Hub | $31.46 | $25.11 | NYMEX Henry Hub | $3.71 | $2.24 |
| ERCOT West Hub | $30.79 | $26.65 | Houston Ship Channel | $3.10 | $1.79 |
| PJM AEP Dayton Hub | $44.23 | $29.10 | Permian Basin | $1.46 | $0.31 |
| PJM Northern Illinois Hub | $33.10 | $24.16 | Dominion South | $3.02 | $1.66 |
| PJM Western Hub | $48.10 | $31.72 | Tetco ELA | $3.47 | $2.05 |
| MISO Indiana Hub | $42.08 | $31.56 | Chicago Citygate | $3.43 | $2.25 |
| ISONE Massachusetts Hub | $71.24 | $36.60 | Tetco M3 | $4.43 | $2.21 |
| New York Zone A | $52.08 | $29.64 | Algonquin Citygates | $7.32 | $2.97 |
| CAISO NP15 | $33.71 | $36.87 | PG&E Citygate | $3.26 | $3.05 |
(a) Reflects the average around-the-clock settled prices for the periods presented and does not necessarily reflect prices we realized.
(b)Reflects the average around-the-clock settled prices for the periods presented and does not reflect costs incurred by us.
Adjusted EBITDA for the six months ended June 30, 2025 compared to the six months ended June 30, 2024 increased by $370 million. The primary drivers for the increase include:
| Six Months Ended June 30, 2025 Compared to 2024 | ||||
|---|---|---|---|---|
| Retail (a) | Texas | East (a) | West | |
| (in millions) | ||||
| Favorable change in realized revenue net of fuel driven primarily by inclusion of six months of Energy Harbor results and higher realized energy and capacity prices in East | $— | $(7) | $431 | $1 |
| Higher retail margins driven by favorable power supply costs, customer count growth, and inclusion of a full six months of Energy Harbor retail contracts | 210 | — | — | — |
| Favorable impact of higher average consumption primarily due to weather | 11 | — | — | — |
| Increase in plant operating costs due primarily to inclusion of six months of Energy Harbor results in East | — | (19) | (190) | (2) |
| Change in SG&A and other primarily due to increase in costs related to addition of Energy Harbor in Retail and East | (42) | (13) | (22) | (1) |
| Change in Adjusted EBITDA | $179 | $(39) | $219 | $(2) |
| Change in depreciation and amortization driven primarily by addition of Energy Harbor assets in East | 7 | (58) | (271) | (3) |
| Change in unrealized net gains (losses) on hedging activities (b) | (630) | 1,130 | (659) | (257) |
| Impairment of long-lived assets | — | (68) | — | — |
| Increase in other income due to involuntary conversion gain on Martin Lake Incident | — | 80 | — | — |
| Decommissioning related activities | — | 2 | 6 | 1 |
| Other (including interest expenses) | (5) | 4 | (10) | 1 |
| Change in Net income (loss) | $(449) | $1,051 | $(715) | $(260) |
(a) Includes amounts associated with operations acquired in the Energy Harbor Merger beginning March 1, 2024.
(b)See Energy-Related Commodity Contracts and Mark-to-Market Activities below for analysis of hedging strategy.
Asset Closure Segment— Three and Six Months Ended June 30, 2025 Compared to Three and Six Months Ended June 30, 2024
| Three Months Ended June 30, · Favorable (Unfavorable) Change · Six Months Ended June 30, · Favorable (Unfavorable) Change | ||||||
|---|---|---|---|---|---|---|
| 2025 · 2024 · 2025 · 2024 | ||||||
| (in millions) | ||||||
| Operating revenues | $20 | $9 | $11 | $24 | $18 | $6 |
| Fuel, purchased power costs, and delivery fees | — | (1) | 1 | — | (3) | 3 |
| Operating costs | (45) | (20) | (25) | (101) | (37) | (64) |
| Depreciation and amortization | 1 | (7) | 8 | 2 | (14) | 16 |
| Selling, general, and administrative expenses | (19) | (15) | (4) | (36) | (25) | (11) |
| Operating loss | (43) | (34) | (9) | (111) | (61) | (50) |
| Other income (deductions), net | 1 | 4 | (3) | 2 | 7 | (5) |
| Interest expense and related charges | (1) | (1) | — | (2) | (2) | — |
| Loss before income taxes | (43) | (31) | (12) | (111) | (56) | (55) |
| Net loss | $(43) | $(31) | $(12) | $(111) | $(56) | $(55) |
| Adjusted EBITDA | $(17) | $(24) | $7 | $(41) | $(44) | $3 |
GAAP results for the three and six months ended June 30, 2025 are unfavorable compared to the three and six months ended June 30, 2024 primarily due to operating costs associated with the Moss Landing 300 Incident net of insurance receivables and business interruption insurance proceeds realized in the three months ended June 30, 2025. See Note 1 to the Financial Statements for additional information.
Energy-Related Commodity Contracts and Mark-to-Market Activities
As we entered the 2024 and 2025 calendar years, we had substantially all of our expected generation volumes hedged. This strategic hedging allowed us to lock in margins that were higher than what we would have realized if we had not hedged. These margins also exceeded those from hedging activities for the six months ended June 30, 2024, contributing to the increase in realized revenue net of fuel in our generation segments, along with the addition of Energy Harbor.
The changes in unrealized gains and losses on hedging activities are driven by forward power sales. When power prices increase or decrease compared to what our generation segments have sold forward, the generation segments recognize unrealized losses or gains, respectively. Conversely, the retail segment, which procures power from the generation segments to meet future load obligations, experiences an inverse effect on unrealized mark-to-market valuations compared to the generation segments.
During the three months ended 2025, forward power price curves decreased relative to our hedged positions resulting in unrealized gains in the Texas segment compared to an increase in power price curves in the three months ended 2024. During the six months ended 2025 and 2024, forward power curves increased relative to our hedge positions resulting in unrealized losses in the Texas segment.
During the three months ended 2025 and 2024, forward power price curves decreased relative to our hedge positions resulting in unrealized gains in the East segment. During the six months ended 2025, forward power price curves increased relative to our hedged positions resulting in unrealized losses in the East segment compared to a decrease in power price curves in the six months ended 2024.
These unrealized gains and losses in the Texas and East generation segments across these comparative periods were partially offset by unrealized gains and losses in the Retail segment across the same periods.
The table below summarizes the changes in commodity contract assets and liabilities for the six months ended June 30, 2025 and 2024.
| Six Months Ended June 30, | ||
|---|---|---|
| 2025 | 2024 | |
| (in millions) | ||
| Commodity contract net liability as of January 1 | $(1,459) | $(2,740) |
| Mark-to-market adjustments: | ||
| Settlements/termination of positions (a) | 135 | 573 |
| Changes in fair value of positions in the portfolio (b) | (686) | (703) |
| Net loss associated with mark-to-market accounting | (551) | (130) |
| Acquired commodity contracts (c) | — | (50) |
| Other activity (d) | 43 | 75 |
| Commodity contract net liability as of June 30 | $(1,967) | $(2,845) |
(a)Represents reversals of previously recognized unrealized gains and losses upon settlement/termination (offsets realized gains/(losses) recognized in the settlement period). Excludes changes in fair value in the month the position settled as well as amounts related to positions entered into, and settled, in the same month.
(b)Represents unrealized net gains/(losses) recognized, reflecting the effect of changes in fair value. Excludes changes in fair value in the month the position settled as well as amounts related to positions entered into, and settled, in the same month.
(c)Includes fair value of commodity contracts acquired in the Energy Harbor Merger (see Note 2 to the Financial Statements for additional information).
(d)Primarily represents changes in fair value of positions due to receipt or payment of cash not reflected in unrealized gains or losses. Amounts are generally related to premiums related to options purchased or sold as well as certain margin deposits classified as settlement for certain transactions executed on the CME.
The following maturity table presents the net commodity contract liability arising from recognition of fair values as of June 30, 2025, scheduled by the source of fair value and contractual settlement dates of the underlying positions.
| Source of Fair Value · Less than1 year · 1-3 years · 4-5 years · Excess of5 years · Total | ||||||
|---|---|---|---|---|---|---|
| (in millions) | ||||||
| Prices actively quoted | $(414) | $(93) | $(15) | $ | $(522) | |
| Prices provided by other external sources | (429) | (131) | (1) | (561) | ||
| Prices based on models | (194) | (566) | (135) | 11 | (884) | |
| Total | $(1,037) | $(790) | $(151) | $11 | $(1,967) | |
We have engaged in natural gas hedging activities to mitigate the risk of higher or lower wholesale electricity prices that have corresponded to increases or declines in natural gas prices. When natural gas prices are elevated or depressed, we continue to seek opportunities to manage our wholesale power price exposure through hedging activities, including forward wholesale and retail electricity sales.
Estimated hedging levels for generation volumes in our Texas, East, and West segments as of June 30, 2025 were as follows:
| Balance of 2025 | 2026 | |
|---|---|---|
| Nuclear/Renewable/Coal Generation: | ||
| Texas | 100% | 100% |
| East | 100% | 88% |
| Natural Gas Generation: | ||
| Texas | 100% | 82% |
| East | 100% | 100% |
| West | 96% | 58% |
The text of this filing, as the company filed it with the SEC, without its images or exhibits. This is not investment advice.