| UNITED STATES SECURITIES AND EXCHANGE COMMISSION | |||||||||||
| Washington, D.C. 20549 | |||||||||||
| FORM | |||||||||||
| CURRENT REPORT | ||||||||
| Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 | ||||||||
| Date of Report (Date of earliest event reported) | ||||||||
| Commission File Number | Name of Registrant; State or Other Jurisdiction of Incorporation; Address of Principal Executive Offices; and Telephone Number | IRS Employer Identification Number | ||||||||||||
(a | ||||||||||||||
(a | ||||||||||||||
| Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions: | |||||
| Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425) | |||||
| Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12) | |||||
| Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b)) | |||||
| Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c)) | |||||
| Securities registered pursuant to Section 12(b) of the Act: | ||||||||||||||
| Title of each class | Trading Symbol(s) | Name of each exchange on which registered | ||||||||||||
| CONSTELLATION ENERGY CORPORATION: | ||||||||||||||
| Indicate by check mark whether any of the registrants are emerging growth companies as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2 of this chapter). | |||||
Emerging growth company | |||||
| If an emerging growth company, indicate by check mark if any of the registrants have elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐ | ||
Section 2 - Financial Information
Item 2.02. Results of Operations and Financial Condition.
Section 7 - Regulation FD
Item 7.01. Regulation FD Disclosure.
On February 16, 2023, Constellation Energy Corporation (Nasdaq: CEG) announced via press release its results for the fourth quarter ended December 31, 2022. A copy of the press release and related attachments are attached hereto as Exhibit 99.1. Also attached as Exhibit 99.2 to this Current Report on Form 8-K are the presentation slides to be used during the fourth quarter 2022 earnings conference call. This Form 8-K and the attached exhibits are provided under Items 2.02, 7.01 and 9.01 of Form 8-K and are furnished to, but not filed with, the Securities and Exchange Commission.
We have scheduled the conference call for 10:00 AM ET on February 16, 2023. To access the call by phone, please follow the registration link available on the Investor Relations page of our website: https://investors.constellationenergy.com. The call will also be webcast and archived on the Investor Relations page of our website. Media representatives are invited to participate on a listen-only basis.
Section 9 - Financial Statements and Exhibits
Item 9.01. Financial Statements and Exhibits
(d) Exhibits.
| Exhibit No. | Description | ||||
| 101 | Cover Page Interactive Data File - the cover page XBRL tags are embedded within the Inline XBRL document. | ||||
| 104 | The cover page from the Current Report on Form 8-K, formatted as Inline XBRL. | ||||
* * * * *
This combined Current Report on Form 8-K is being furnished separately by Constellation Energy Corporation and Constellation Energy Generation, LLC, (collectively, the "Registrants"). Information contained herein relating to one of the Registrants has been furnished by such Registrant on its own behalf. Neither Registrant makes any representation as to information relating to the other Registrant.
This report contains certain forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 that are subject to risks and uncertainties. Words such as “could,” “may,” “expects,” “anticipates,” “will,” “targets,” “goals,” “projects,” “intends,” “plans,” “believes,” “seeks,” “estimates,” “predicts,” and variations on such words, and similar expressions that reflect our current views with respect to future events and operational, economic, and financial performance, are intended to identify such forward-looking statements.
The factors that could cause actual results to differ materially from the forward-looking statements made by the Registrants include those factors discussed herein, as well as the items discussed in (1) the Registrants' 2022 Annual Report on Form 10-K (to be filed on February 16, 2023) in (a) Part I, ITEM 1A. Risk Factors, (b) Part II, ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and (c) Part II, ITEM 8. Financial Statements and Supplementary Data: Note 19, Commitments and Contingencies; and (2) other factors discussed in filings with the SEC by the Registrants.
Investors are cautioned not to place undue reliance on these forward-looking statements, whether written or oral, which apply only as of the date of this report. Neither Registrant undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this report.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, each Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
| CONSTELLATION ENERGY CORPORATION | |||||
| /s/ Daniel L. Eggers | |||||
| Daniel L. Eggers | |||||
| Executive Vice President and Chief Financial Officer | |||||
| Constellation Energy Corporation | |||||
| CONSTELLATION ENERGY GENERATION, LLC | |||||
| /s/ Daniel L. Eggers | |||||
| Daniel L. Eggers | |||||
| Executive Vice President and Chief Financial Officer | |||||
| Constellation Energy Generation, LLC | |||||
February 16, 2023
EXHIBIT INDEX
| Exhibit No. | Description | ||||
| 101 | Cover Page Interactive Data File - the cover page XBRL tags are embedded within the Inline XBRL document. | ||||
| 104 | The cover page from the Current Report on Form 8-K, formatted as Inline XBRL. | ||||
Exhibit 99.1
News Release
| Contact: | Paul Adams Corporate Communications 410-470-4167 Emily Duncan Investor Relations 833-447-2783 | |||||||
CONSTELLATION REPORTS FOURTH QUARTER AND FULL YEAR 2022 RESULTS AND INITIATES 2023 FINANCIAL OUTLOOK
Earnings Release Highlights
•GAAP Net Income of $34 million and Adjusted EBITDA (non-GAAP) of $605 million for the fourth quarter of 2022. GAAP Net Loss of ($160) million and Adjusted EBITDA (non-GAAP) of $2,667 million for the full year 2022.
•Introducing 2023 Adjusted EBITDA (non-GAAP) guidance range of $2,900 million to $3,300 million
•Announcing initial capital allocation strategy focused on supporting and growing our business and returning capital to shareholders. It includes $1.5 billion in organic growth capital that will exceed our double-digit return threshold, doubling the per share dividend from the 2022 level and targeting growth at 10% thereafter, and authorizing $1 billion in share repurchases
•During Winter Storm Elliott, from December 23 through December 25, our always-on nuclear fleet provided reliable power to homes and businesses as record-setting low temperatures blanketed the PJM region and a significant portion of fossil-fueled generators failed to perform
•Our best-in-class nuclear fleet operated at a capacity factor of 95.4% for the fourth quarter of 2022 and 94.8% for the full year 2022, marking more than a decade as the industry leader among major nuclear operators
•Celebrated our first anniversary by launching a $1 million workforce development program aimed at fostering change in underserved communities
Baltimore (Feb. 16, 2023) — Constellation Energy Corporation (Nasdaq: CEG) today reported its financial results for the fourth quarter and full year 2022.
“We had an incredible first year that exceeded expectations as we adapted to rapidly evolving market conditions, successfully advocated for clean energy policies and positioned the company for sustainable, long-term growth,” said Joe Dominguez, president and CEO of Constellation. “I want to emphasize that there is no commodity more valuable to our economy, national security and way of life than energy that is carbon-free, affordable and always there when you need it, and no U.S. company produces more of it than we do. The unique reliability and resiliency of our nuclear fleet was driven home yet again during Winter Storm Elliott, when our operated fleet performed at 100 percent, helping to prevent rolling blackouts on
Christmas Eve as fossil generation in our nation’s largest electric grid failed. Nuclear’s value to the grid was also proven in the 2014 polar vortex and again in 2021 during Winter Storm Uri, and it’s only going to increase in the years ahead as we invest to extend the lives of our nuclear plants, increase their output and utilize their carbon-free energy to power the dirtiest parts of our economy with clean hydrogen. We set out one year ago to be the nation’s answer to the climate crisis, and today we have the assets and financial foundation to deliver on that promise.”
“Our strong financial position allows us to return exceptional value to shareholders by doubling our dividend and authorizing a $1 billion share repurchase program, while still leaving us the flexibility to build a new, clean hydrogen business and reserve $2 billion in unallocated capital to invest in other organic and inorganic growth as opportunities arise, or return additional capital to shareholders,” said Dan Eggers, chief financial officer of Constellation. “Operationally, our nuclear fleet remains the most reliable and efficient in the industry and our commercial business delivered high value in a market buffeted by global events. For the year, we delivered $2.667 billion in adjusted EBITDA, which exceeded the top of our range, and we are introducing 2023 adjusted EBITDA guidance of $2.9 billion to $3.3 billion.”
Fourth Quarter 2022
Our GAAP Net Income for the fourth quarter of 2022 was $34 million, down from $42 million GAAP Net Income in the fourth quarter of 2021. Adjusted EBITDA (non-GAAP) for the fourth quarter of 2022 decreased to $605 million from $1,027 million in the fourth quarter of 2021. For the reconciliations of GAAP Net Income to Adjusted EBITDA (non-GAAP), refer to the tables beginning on page 4.
Adjusted EBITDA (non-GAAP) in the fourth quarter of 2022 primarily reflects:
•Increased labor, contracting, and materials, unfavorable market and portfolio conditions, and decreased capacity revenues, partially offset by favorable nuclear outages.
Full Year 2022
Our GAAP Net Loss for 2022 was ($160) million, compared to ($205) million GAAP Net Loss in 2021. Adjusted EBITDA (non-GAAP) for 2022 increased to $2,667 million from $2,185 million in 2021.
Adjusted EBITDA (non-GAAP) for the full year 2022 primarily reflects:
•The absence of impacts from the February 2021 extreme cold weather event, partially offset by decreased capacity revenues, increased labor, contracting, and materials, and lower CTV gains in 2022 compared to 2021.
Initiates Annual Guidance for 2023
We introduced a guidance range for 2023 Adjusted EBITDA (non-GAAP) of $2,900 million to $3,300 million. The outlook for Adjusted EBITDA (non-GAAP) excludes the following items:
•Income taxes
•Depreciation and amortization
•Interest expense, net
•Unrealized impacts of fair value adjustments
•Decommissioning-related activities
•Pension and Other Postretirement Employment Benefit (OPEB) non-service credits
•Separation costs
•Enterprise Resource Program (ERP) system implementation
•Other items not directly related to the ongoing operations of the business
•Noncontrolling interest related to exclusion items
Recent Developments and Fourth Quarter Highlights
•Initial Capital Allocation Strategy: We are announcing our capital allocation strategy for 2023 and 2024 supporting our core principles previously laid out at Analyst Day. Our balance sheet strength is the foundation of this strategy. Through our strong free cash flows, we will grow the business and return capital to shareholders. We are allocating capital towards our best-in-class generation fleet by committing $1.5 billion of growth capital over the next three years, including nuclear uprates, wind repowering and hydrogen. These organic growth opportunities are projected to exceed our double-digit return threshold. We will double the annual dividend in 2023 from $0.5640 per share to $1.1280 per share while targeting growth at 10% annually. In our commitment to return value to shareholders, we are also authorizing $1 billion in share buybacks.
•Dividend Declaration: In keeping with the newly announced capital allocation strategy, our Board of Directors has declared a quarterly dividend of $0.2820 per share on our common stock. The dividend is payable on Friday, March 10, 2023, to shareholders of record as of 5 p.m. Eastern time on Monday, February 27, 2023.
•December 2022 PJM Performance Bonuses: On Dec. 23, 2022, and continuing through the morning of Dec. 25, 2022, Winter Storm Elliott blanketed the entirety of PJM’s footprint with record low temperatures and extreme weather conditions. A significant portion of PJM's fossil generation fleet failed to perform as reserves were called, while our operated nuclear fleet performed at 100 percent and helped avoid a grid failure. PJM’s initial estimate of non-performance charges ranges from $1 billion to $2 billion and, in accordance with its tariff, funds collected from those charges are redistributed to generating resources that performed above expectations during the event, including nuclear. Leveraging preliminary data from PJM and applying significant judgments and assumptions, we recognized an estimated benefit of $109 million (pre-tax) for performance bonuses (net of non-performance charges), primarily driven by the over performance of our nuclear fleet that prevented rolling blackouts across PJM.
•Nuclear Operations: Our nuclear fleet, including our owned output from the Salem Generating Station, produced 44,436 gigawatt-hours (GWhs) in the fourth quarter of 2022, compared with 42,604 GWhs in the fourth quarter of 2021. Excluding Salem, our nuclear plants at ownership achieved a 95.4% capacity factor for the fourth quarter of 2022, compared with 92.4% for the fourth quarter of 2021. There were 65 planned refueling outage days in the fourth quarter of 2022 and 90 in the fourth quarter of 2021. There were three non-refueling outage days in the fourth quarter of 2022 and 24 in the fourth quarter of 2021.
•Natural Gas, Oil, and Renewables Operations: The dispatch match rate for our gas and hydro fleet was 96.6% in the fourth quarter of 2022, compared with 98.8% in the fourth quarter of 2021. Energy capture for the wind and solar fleet was 95.9% in the fourth quarter of 2022, compared with 94.3% in the fourth quarter of 2021.
•“Powering Change” Workforce Development Initiative: In celebration of our first anniversary as a stand-alone company on Feb. 2, we announced the launch of a $1 million workforce development program as part of our commitment to foster equitable change in underserved communities. The new program, called Powering Change, will provide grants to five nonprofit organizations focused on improving job awareness and training, providing advancement and upskilling opportunities and breaking down employment barriers for individuals from underrepresented communities.
GAAP/Adjusted EBITDA (non-GAAP) Reconciliation
Adjusted EBITDA (non-GAAP) for the fourth quarter of 2022 and 2021, respectively, does not include the following items that were included in our reported GAAP Net Income:
| (in millions) | Three Months Ended December 31, 2022 | Three Months Ended December 31, 2021 | ||||||
| GAAP Net Income Attributable to Common Shareholders | $ | 34 | $ | 42 | ||||
| Income Taxes | 133 | 117 | ||||||
| Depreciation and Amortization | 272 | 268 | ||||||
| Interest Expense, Net | 64 | 72 | ||||||
| Unrealized Loss on Fair Value Adjustments | 413 | 771 | ||||||
| Asset Impairments | — | 4 | ||||||
| Plant Retirements and Divestitures | (7) | 11 | ||||||
| Decommissioning-Related Activities | (306) | (275) | ||||||
| Pension & OPEB Non-Service Credits | (31) | (14) | ||||||
| Separation Costs | 41 | 24 | ||||||
| COVID-19 Direct Costs | — | 11 | ||||||
| ERP System Implementation Costs | 6 | 3 | ||||||
| Change in Environmental Liabilities | (2) | 5 | ||||||
| Noncontrolling Interests | (12) | (12) | ||||||
| Adjusted EBITDA (non-GAAP) | $ | 605 | $ | 1,027 | ||||
Webcast Information
We will discuss fourth quarter 2022 earnings in a conference call scheduled for today at 10 a.m. Eastern Time. The webcast and associated materials can be accessed at https://investors.constellationenergy.com.
About Constellation
Headquartered in Baltimore, Constellation Energy Corporation (Nasdaq: CEG) is the nation’s largest producer of clean, carbon-free energy and a leading supplier of energy products and services to businesses, homes, community aggregations and public sector customers across the continental United States, including three fourths of Fortune 100 companies. With annual output that is nearly 90 percent carbon-free, our hydro, wind and solar facilities paired with the nation’s largest nuclear fleet have the generating capacity to power the equivalent of 15 million homes, providing 11 percent of the nation’s clean energy. We are further accelerating the nation’s transition to a carbon-free future by helping our customers reach their sustainability goals, setting our own ambitious goal of achieving 100 percent carbon-free generation by 2040, and by investing in promising emerging technologies to eliminate carbon emissions across all sectors of the economy. Follow Constellation on LinkedIn and Twitter.
Non-GAAP Financial Measures
In analyzing and planning for our business, we supplement our use of net income as determined under generally accepted accounting principles in the United States (GAAP), with Adjusted EBITDA (non-GAAP) as a performance measure. Adjusted EBITDA (non-GAAP) reflects an additional way of viewing our business that, when viewed with our GAAP results and the accompanying reconciliation to GAAP net income included above, may provide a more complete understanding of factors and trends affecting our business. Adjusted EBITDA (non-GAAP) should not be relied upon to the exclusion of GAAP financial measures and is, by definition, an incomplete understanding of our business, and must be considered in conjunction with GAAP measures. In addition, Adjusted EBITDA (non-GAAP) is neither a standardized
financial measure, nor a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this press release and earnings release attachments. We have provided the non-GAAP financial measure as supplemental information and in addition to the financial measures that are calculated and presented in accordance with GAAP. Adjusted EBITDA (non-GAAP) should not be deemed more useful than, a substitute for, or an alternative to the most comparable GAAP Net Income measure provided in this earnings release and attachments. This press release and earnings release attachments provide reconciliations of Adjusted EBITDA (non-GAAP) to the most directly comparable financial measures calculated and presented in accordance with GAAP and are posted on our website: www.ConstellationEnergy.com, and have been furnished to the Securities and Exchange Commission on Form 8-K on February 16, 2023.
Cautionary Statements Regarding Forward-Looking Information
This press release contains certain forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 that are subject to risks and uncertainties. Words such as “could,” “may,” “expects,” “anticipates,” “will,” “targets,” “goals,” “projects,” “intends,” “plans,” “believes,” “seeks,” “estimates,” “predicts,” and variations on such words, and similar expressions that reflect our current views with respect to future events and operational, economic, and financial performance, are intended to identify such forward-looking statements.
The factors that could cause actual results to differ materially from the forward-looking statements made by Constellation Energy Corporation and Constellation Energy Generation, LLC, (Registrants) include those factors discussed herein, as well as the items discussed in (1) the Registrants' 2022 Annual Report on Form 10-K (to be filed on February 16, 2023) in (a) Part I, ITEM 1A. Risk Factors, (b) Part II, ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and (c) Part II, ITEM 8. Financial Statements and Supplementary Data: Note 19, Commitments and Contingencies, and (2) other factors discussed in filings with the SEC by the Registrants.
Investors are cautioned not to place undue reliance on these forward-looking statements, whether written or oral, which apply only as of the date of this press release. Neither of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this press release.
1
Earnings Release Attachments
Table of Contents
Constellation Energy Corporation and Subsidiary Companies
Consolidated Statements of Operations
(unaudited)
(in millions)
| Three Months Ended December 31, 2022 | Twelve Months Ended December 31, 2022 | |||||||||||||
| Operating revenues | $ | 7,333 | $ | 24,440 | ||||||||||
| Operating expenses | ||||||||||||||
| Purchased power and fuel | 5,708 | 17,462 | ||||||||||||
| Operating and maintenance | 1,375 | 4,841 | ||||||||||||
| Depreciation and amortization | 272 | 1,091 | ||||||||||||
| Taxes other than income taxes | 138 | 552 | ||||||||||||
| Total operating expenses | 7,493 | 23,946 | ||||||||||||
| (Loss) gain on sales of assets and businesses | (12) | 1 | ||||||||||||
| Operating (loss) income | (172) | 495 | ||||||||||||
| Other income and (deductions) | ||||||||||||||
| Interest expense, net | (64) | (251) | ||||||||||||
| Other, net | 383 | (786) | ||||||||||||
| Total other income and (deductions) | 319 | (1,037) | ||||||||||||
| Income (loss) before income taxes | 147 | (542) | ||||||||||||
| Income taxes | 116 | (388) | ||||||||||||
| Equity in losses of unconsolidated affiliates | (4) | (13) | ||||||||||||
| Net income (loss) | 27 | (167) | ||||||||||||
| Net loss attributable to noncontrolling interests | (7) | (7) | ||||||||||||
| Net income (loss) attributable to common shareholders | $ | 34 | $ | (160) | ||||||||||
| Three Months Ended December 31, 2021 | Twelve Months Ended December 31, 2021 | |||||||||||||
| Operating revenues | $ | 5,532 | $ | 19,649 | ||||||||||
| Operating expenses | ||||||||||||||
| Purchased power and fuel | 4,061 | 12,163 | ||||||||||||
| Operating and maintenance | 1,141 | 4,555 | ||||||||||||
| Depreciation and amortization | 268 | 3,003 | ||||||||||||
| Taxes other than income taxes | 121 | 475 | ||||||||||||
| Total operating expenses | 5,591 | 20,196 | ||||||||||||
| Gain on sales of assets and businesses | 57 | 201 | ||||||||||||
| Operating loss | (2) | (346) | ||||||||||||
| Other income and (deductions) | ||||||||||||||
| Interest expense, net | (72) | (297) | ||||||||||||
| Other, net | 234 | 795 | ||||||||||||
| Total other income and (deductions) | 162 | 498 | ||||||||||||
| Income before income taxes | 160 | 152 | ||||||||||||
| Income taxes | 117 | 225 | ||||||||||||
| Equity in losses of unconsolidated affiliates | (4) | (10) | ||||||||||||
| Net income (loss) | 39 | (83) | ||||||||||||
| Net (loss) income attributable to noncontrolling interests | (3) | 122 | ||||||||||||
| Net income (loss) attributable to common shareholders | $ | 42 | $ | (205) | ||||||||||
| Change in Net income (loss) from 2021 to 2022 | $ | (8) | $ | 45 | ||||||||||
1
Constellation Energy Corporation and Subsidiary Companies
Consolidated Balance Sheets
(unaudited)
(in millions)
| December 31, 2022 | December 31, 2021 | |||||||||||||
| Assets | ||||||||||||||
| Current assets | ||||||||||||||
| Cash and cash equivalents | $ | 422 | $ | 504 | ||||||||||
| Restricted cash and cash equivalents | 106 | 72 | ||||||||||||
| Accounts receivable | ||||||||||||||
| Customer accounts receivable (net of allowance for credit losses of $46 and $55 as of December 31, 2022 and December 31, 2021, respectively) | 2,585 | 1,669 | ||||||||||||
| Other accounts receivable (net of allowance for credit losses of $5 as of December 31, 2022 and December 31, 2021) | 731 | 592 | ||||||||||||
| Mark-to-market derivative assets | 2,368 | 2,169 | ||||||||||||
| Receivables from affiliates | — | 160 | ||||||||||||
| Inventories, net | ||||||||||||||
| Natural gas, oil, and emission allowances | 429 | 284 | ||||||||||||
| Materials and supplies | 1,076 | 1,004 | ||||||||||||
| Renewable energy credits | 617 | 520 | ||||||||||||
| Other | 1,026 | 1,007 | ||||||||||||
| Total current assets | 9,360 | 7,981 | ||||||||||||
| Property, plant, and equipment, net | 19,822 | 19,612 | ||||||||||||
| Deferred debits and other assets | ||||||||||||||
| Nuclear decommissioning trust funds | 14,114 | 15,938 | ||||||||||||
| Investments | 202 | 174 | ||||||||||||
| Mark-to-market derivative assets | 1,261 | 949 | ||||||||||||
| Prepaid pension asset | — | 1,683 | ||||||||||||
| Deferred income taxes | 44 | 32 | ||||||||||||
| Other | 2,106 | 1,717 | ||||||||||||
| Total deferred debits and other assets | 17,727 | 20,493 | ||||||||||||
| Total assets | $ | 46,909 | $ | 48,086 | ||||||||||
2
| December 31, 2022 | December 31, 2021 | |||||||||||||
| Liabilities and shareholders’ equity | ||||||||||||||
| Current liabilities | ||||||||||||||
| Short-term borrowings | $ | 1,159 | $ | 2,082 | ||||||||||
| Long-term debt due within one year | 143 | 1,220 | ||||||||||||
| Accounts payable | 2,828 | 1,757 | ||||||||||||
| Accrued expenses | 906 | 737 | ||||||||||||
| Payables to affiliates | — | 131 | ||||||||||||
| Mark-to-market derivative liabilities | 1,558 | 981 | ||||||||||||
| Renewable energy credit obligation | 901 | 777 | ||||||||||||
| Other | 344 | 311 | ||||||||||||
| Total current liabilities | 7,839 | 7,996 | ||||||||||||
| Long-term debt | 4,466 | 4,575 | ||||||||||||
| Long-term debt to affiliates | — | 319 | ||||||||||||
| Deferred credits and other liabilities | ||||||||||||||
| Deferred income taxes and unamortized investment tax credits | 3,031 | 3,703 | ||||||||||||
| Asset retirement obligations | 12,699 | 12,819 | ||||||||||||
| Pension obligations | 605 | — | ||||||||||||
| Non-pension postretirement benefit obligations | 609 | 847 | ||||||||||||
| Spent nuclear fuel obligation | 1,230 | 1,210 | ||||||||||||
| Payables to affiliates | — | 3,357 | ||||||||||||
| Payable related to Regulatory Agreement Units | 2,897 | — | ||||||||||||
| Mark-to-market derivative liabilities | 983 | 513 | ||||||||||||
| Other | 1,178 | 1,133 | ||||||||||||
| Total deferred credits and other liabilities | 23,232 | 23,582 | ||||||||||||
| Total liabilities | 35,537 | 36,472 | ||||||||||||
| Commitments and contingencies | ||||||||||||||
| Shareholders' Equity | ||||||||||||||
| Predecessor Member's Equity | — | 11,250 | ||||||||||||
| Common stock | 13,274 | — | ||||||||||||
| Retained deficit | (496) | — | ||||||||||||
| Accumulated other comprehensive loss, net | (1,760) | (31) | ||||||||||||
| Total shareholders’ equity | 11,018 | 11,219 | ||||||||||||
| Noncontrolling interests | 354 | 395 | ||||||||||||
| Total equity | 11,372 | 11,614 | ||||||||||||
| Total liabilities and shareholders’ equity | $ | 46,909 | $ | 48,086 | ||||||||||
3
Constellation Energy Corporation and Subsidiary Companies
Consolidated Statements of Cash Flows
(unaudited)
(in millions)
| Twelve Months Ended December 31, | ||||||||||||||
| 2022 | 2021 | |||||||||||||
| Cash flows from operating activities | ||||||||||||||
| Net loss | $ | (167) | $ | (83) | ||||||||||
| Adjustments to reconcile net loss to net cash flows used in operating activities | ||||||||||||||
| Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization | 2,427 | 4,540 | ||||||||||||
| Asset impairments | — | 545 | ||||||||||||
| Gain on sales of assets and businesses | (1) | (201) | ||||||||||||
| Deferred income taxes and amortization of ITC | (643) | (205) | ||||||||||||
| Net fair value changes related to derivatives | 986 | (568) | ||||||||||||
| Net realized and unrealized losses (gains) on NDT funds | 794 | (586) | ||||||||||||
| Net realized and unrealized losses on equity investments | 13 | 160 | ||||||||||||
| Other non-cash operating activities | 249 | (605) | ||||||||||||
| Changes in assets and liabilities: | ||||||||||||||
| Accounts receivable | (868) | (616) | ||||||||||||
| Receivables from and payables to affiliates, net | 20 | 14 | ||||||||||||
| Inventories | (228) | (68) | ||||||||||||
| Accounts payable and accrued expenses | 1,142 | 346 | ||||||||||||
| Option premiums paid, net | (177) | (338) | ||||||||||||
| Collateral posted, net | (351) | (130) | ||||||||||||
| Income taxes | 162 | 256 | ||||||||||||
| Pension and non-pension postretirement benefit contributions | (237) | (259) | ||||||||||||
| Other assets and liabilities | (5,474) | (3,540) | ||||||||||||
| Net cash flows used in operating activities | (2,353) | (1,338) | ||||||||||||
| Cash flows from investing activities | ||||||||||||||
| Capital expenditures | (1,689) | (1,329) | ||||||||||||
| Proceeds from NDT fund sales | 4,050 | 6,532 | ||||||||||||
| Investment in NDT funds | (4,271) | (6,673) | ||||||||||||
| Collection of DPP, net | 4,964 | 3,902 | ||||||||||||
| Proceeds from sales of assets and businesses | 52 | 878 | ||||||||||||
| Other investing activities | (2) | (28) | ||||||||||||
| Net cash flows provided by investing activities | 3,104 | 3,282 | ||||||||||||
| Cash flows from financing activities | ||||||||||||||
| Change in short-term borrowings | 257 | 362 | ||||||||||||
| Proceeds from short-term borrowings with maturities greater than 90 days | — | 880 | ||||||||||||
| Repayments of short-term borrowings with maturities greater than 90 days | (1,180) | — | ||||||||||||
| Issuance of long-term debt | 14 | 152 | ||||||||||||
| Retirement of long-term debt | (1,162) | (105) | ||||||||||||
| Retirement of long-term debt to affiliate | (258) | — | ||||||||||||
| Change in money pool with Exelon | — | (285) | ||||||||||||
| Acquisition of CENG noncontrolling interest | — | (885) | ||||||||||||
| Distributions to Exelon | — | (1,832) | ||||||||||||
| Contributions from Exelon | 1,750 | 64 | ||||||||||||
| Dividends paid on common stock | (185) | — | ||||||||||||
| Other financing activities | (35) | (46) | ||||||||||||
| Net cash flows used in financing activities | (799) | (1,695) | ||||||||||||
| (Decrease) increase in cash, restricted cash, and cash equivalents | (48) | 249 | ||||||||||||
| Cash, restricted cash, and cash equivalents at beginning of period | 576 | 327 | ||||||||||||
| Cash, restricted cash, and cash equivalents at end of period | $ | 528 | $ | 576 | ||||||||||
4
Constellation Energy Corporation
Reconciliation of GAAP Net Income to Adjusted EBITDA (non-GAAP) and Analysis of Earnings
Three Months Ended December 31, 2022 and 2021
(unaudited)
(in millions)
| 2021 GAAP Net Income Attributable to Common Shareholders | $ | 42 | ||||||
| Income Taxes | 117 | |||||||
| Depreciation and Amortization | 268 | |||||||
| Interest Expense, Net | 72 | |||||||
| Unrealized Loss on Fair Value Adjustments (1) | 771 | |||||||
| Asset Impairments | 4 | |||||||
| Plant Retirements and Divestitures | 11 | |||||||
| Decommissioning-Related Activities (2) | (275) | |||||||
| Pension & OPEB Non-Service Credits | (14) | |||||||
| Separation Costs (3) | 24 | |||||||
| COVID-19 Direct Costs (4) | 11 | |||||||
| ERP System Implementation Costs (5) | 3 | |||||||
| Change in Environmental Liabilities | 5 | |||||||
| Noncontrolling Interests (6) | (12) | |||||||
| 2021 Adjusted EBITDA (non-GAAP) | $ | 1,027 | ||||||
| Year Over Year Effects on Adjusted EBITDA (non-GAAP): | ||||||||
| February 2021 Extreme Weather Event | $ | (95) | ||||||
| Nuclear Fuel Cost (8) | (15) | |||||||
| Market and Portfolio Conditions (9) | (131) | |||||||
| PJM Performance Bonuses, Net (10) | 109 | |||||||
| Nuclear Outages (11) | 133 | |||||||
| Capacity Revenue (12) | (117) | |||||||
| Labor, Contracting and Materials (13) | (139) | |||||||
| Impact of Equity Investments (14) | (56) | |||||||
| NEIL Distributions (15) | (83) | |||||||
| Other (16) | (31) | |||||||
| Noncontrolling Interests (17) | 3 | |||||||
| Total Year Over Year Effects on Adjusted EBITDA (non-GAAP) | $ | (422) | ||||||
| 2022 GAAP Net Income Attributable to Common Shareholders | $ | 34 | ||||||
| Income Taxes (7) | 133 | |||||||
| Depreciation and Amortization | 272 | |||||||
| Interest Expense, Net | 64 | |||||||
| Unrealized Loss on Fair Value Adjustments (1) | 413 | |||||||
| Plant Retirements and Divestitures | (7) | |||||||
| Decommissioning-Related Activities (2) | (306) | |||||||
| Pension & OPEB Non-Service Credits | (31) | |||||||
| Separation Costs (3) | 41 | |||||||
| ERP System Implementation Costs (5) | 6 | |||||||
| Change in Environmental Liabilities | (2) | |||||||
| Noncontrolling Interests (6) | (12) | |||||||
| 2022 Adjusted EBITDA (non-GAAP) | $ | 605 | ||||||
5
(1)Includes mark-to-market on economic hedges and fair value adjustments related to gas imbalances and equity investments.
(2)Reflects all gains and losses associated with Nuclear Decommissioning Trusts (NDT), Asset Retirement Obligation (ARO) accretion, ARO remeasurement, and any earnings neutral impacts of contractual offset for regulatory agreement units.
(3)Represents certain incremental costs related to the separation (system-related costs, third-party costs paid to advisors, consultants, lawyers, and other experts assisting in the separation), including a portion of the amounts billed to us pursuant to the Transition Services Agreement (TSA).
(4)Represents direct costs related to COVID-19 consisting primarily of costs to acquire personal protective equipment, costs for cleaning supplies and services, and costs to hire healthcare professionals to monitor the health of employees.
(5)Reflects costs related to a multi-year Enterprise Resource Program (ERP) system implementation.
(6)Represents elimination of the noncontrolling interest related to certain adjustments related to Constellation Renewables Partners, LLC (CRP).
(7)Includes amounts contractually owed to Exelon under the Tax Matters Agreement (TMA) reflected in Other, net.
(8)Reflects an increase in volumes and prices, primarily in the Midwest.
(9)Primarily related to the absence of favorable commodity prices on fuel hedges in prior year and lower commodity optimization.
(10)Reflects estimated bonus payments from PJM for overperformance primarily at our nuclear fleet during a weather event in December 2022, partially offset by non-performance charges assessed on certain of our generating units during event.
(11)Reflects volume and operating and maintenance impact of nuclear outages, including Salem.
(12)Reflects decreased capacity revenues primarily in the Mid-Atlantic and Midwest.
(13)Primarily reflects increased employee-related costs, including labor, stock-based compensation, and other incentives, etc.
(14)Primarily reflects the absence of gains on Constellation Technology Ventures (CTV) investments realized in prior year.
(15)Lower Nuclear Electric Insurance Limited (NEIL) distributions in 2022 compared to 2021.
(16)Includes certain Taxes other than income taxes and fees on credit facilities.
(17)Reflects elimination of the noncontrolling interest from results of activity, primarily relating to CRP.
6
Constellation Energy Corporation
Reconciliation of GAAP Net Loss to Adjusted EBITDA (non-GAAP) and Analysis of Earnings
Twelve Months Ended December 31, 2022 and 2021
(unaudited)
(in millions)
| 2021 GAAP Net Loss Attributable to Common Shareholders | $ | (205) | ||||||
| Income Taxes | 225 | |||||||
| Depreciation and Amortization (1) | 3,003 | |||||||
| Interest Expense, Net | 297 | |||||||
| Unrealized Gain on Fair Value Adjustments (2) | (420) | |||||||
| Asset Impairments (3) | 541 | |||||||
| Plant Retirements and Divestitures (4) | (4) | |||||||
| Decommissioning-Related Activities (5) | (1,289) | |||||||
| Pension & OPEB Non-Service Credits | (50) | |||||||
| Separation Costs (6) | 49 | |||||||
| COVID-19 Direct Costs (7) | 35 | |||||||
| Acquisition Related Costs (8) | 21 | |||||||
| ERP System Implementation Costs (9) | 14 | |||||||
| Change in Environmental Liabilities | 12 | |||||||
| Cost Management Program | 9 | |||||||
| Noncontrolling Interests (10) | (53) | |||||||
| 2021 Adjusted EBITDA (non-GAAP) | $ | 2,185 | ||||||
| Year Over Year Effects on Adjusted EBITDA (non-GAAP): | ||||||||
| February 2021 Extreme Weather Event | $ | 1,132 | ||||||
| Nuclear Fuel Cost (13) | 74 | |||||||
| Market and Portfolio Conditions (14) | 70 | |||||||
| PJM Performance Bonuses, Net (15) | 109 | |||||||
| Nuclear Outages (16) | 25 | |||||||
| Capacity Revenue (17) | (377) | |||||||
| Labor, Contracting and Materials (18) | (295) | |||||||
| Impact of Equity Investments (19) | (131) | |||||||
| NEIL Distributions (20) | (83) | |||||||
| Other (21) | (175) | |||||||
| Noncontrolling Interests (22) | 133 | |||||||
| Total Year Over Year Effects on Adjusted EBITDA (non-GAAP) | $ | 482 | ||||||
| 2022 GAAP Net Loss Attributable to Common Shareholders | $ | (160) | ||||||
| Income Taxes (11) | (339) | |||||||
| Depreciation and Amortization | 1,091 | |||||||
| Interest Expense, Net | 251 | |||||||
| Unrealized Loss on Fair Value Adjustments (2) | 1,058 | |||||||
| Plant Retirements and Divestitures | (11) | |||||||
| Decommissioning-Related Activities (5) | 820 | |||||||
| Pension & OPEB Non-Service Credits | (116) | |||||||
| Separation Costs (6) | 140 | |||||||
| ERP System Implementation Costs (9) | 22 | |||||||
| Change in Environmental Liabilities | 10 | |||||||
| Prior Merger Commitment (12) | (50) | |||||||
| Noncontrolling Interests (10) | (49) | |||||||
| 2022 Adjusted EBITDA (non-GAAP) | $ | 2,667 | ||||||
7
(1)Includes the accelerated depreciation associated with early plant retirements.
(2)Includes mark-to-market on economic hedges and fair value adjustments related to gas imbalances and equity investments.
(3)Reflects an impairment in the New England asset group, an impairment as a result of the sale of the Albany Green Energy biomass facility, and an impairment of a wind project.
(4)In 2021, primarily reflects nuclear fuel amortization for Byron and Dresden, partially offset by a gain on sale of our solar business and a reversal of one-time charges resulting from the reversal of the previous decision to retire Byron and Dresden.
(5)Reflects all gains and losses associated with NDT, ARO accretion, ARO remeasurement, and any earnings neutral impacts of contractual offset for regulatory agreement units.
(6)Represents certain incremental costs related to the separation (system-related costs, third-party costs paid to advisors, consultants, lawyers, and other experts assisting in the separation), including a portion of the amounts billed to us pursuant to the TSA.
(7)Represents direct costs related to COVID-19 consisting primarily of costs to acquire personal protective equipment, costs for cleaning supplies and services, and costs to hire healthcare professionals to monitor the health of employees.
(8)Reflects costs related to the acquisition of Electricite de France SA's (EDF's) interest in Constellation Energy Nuclear Group, LLC (CENG), which was completed in the third quarter of 2021.
(9)Reflects costs related to a multi-year ERP system implementation.
(10)Represents elimination of the noncontrolling interest related to certain adjustments. In 2022, primarily relates to CRP and in 2021, primarily relates to CENG and the noncontrolling interest portion of a wind project impairment recognized within CRP.
(11)Includes amounts contractually owed to Exelon under the TMA reflected in Other, net.
(12)Reversal of a charge related to a prior 2012 merger commitment.
(13)Primarily reflects a decrease in fuel prices.
(14)Primarily related to favorable realized energy prices.
(15)Reflects estimated bonus payments from PJM for overperformance primarily at our nuclear fleet during a weather event in December 2022, partially offset by non-performance charges assessed on certain of our generating units during event.
(16)Reflects volume and operating and maintenance impact of nuclear outages, including Salem.
(17)Reflects decreased capacity revenues primarily in the Mid-Atlantic and Midwest.
(18)Primarily reflects increased employee-related costs, including labor, stock-based compensation, and other incentives, etc.
(19)Primarily relates to the absence of gains on CTV investments realized in prior year.
(20)Lower NEIL distributions in 2022 compared to 2021.
(21)Includes certain Taxes other than income taxes, reserves for future claims associated with asbestos-related personal injury actions and fees on credit facilities.
(22)Reflects elimination of the noncontrolling interest from results of activity, primarily relating to CRP in 2022 and CENG and CRP in 2021. We acquired the noncontrolling interest in CENG on August 6, 2021.
8
Constellation Energy Corporation
GAAP Consolidated Statements of Operations and
Adjusted EBITDA (non-GAAP) Reconciling Adjustments
(unaudited)
(in millions, except per share data)
| Three Months Ended December 31, 2022 | Three Months Ended December 31, 2021 | ||||||||||||||||||||||||||||||||||
GAAP (a) | Non-GAAP Adjustments | GAAP (a) | Non-GAAP Adjustments | ||||||||||||||||||||||||||||||||
| Operating revenues | $ | 7,333 | $ | (713) | (b),(c) | $ | 5,532 | $ | (326) | (b),(c) | |||||||||||||||||||||||||
| Operating expenses | |||||||||||||||||||||||||||||||||||
| Purchased power and fuel | 5,708 | (1,125) | (b) | 4,061 | (1,020) | (b) | |||||||||||||||||||||||||||||
| Operating and maintenance | 1,375 | (86) | (c),(d),(h),(i),(k) | 1,141 | (74) | (c),(d),(e),(f),(g),(h),(i),(j),(k) | |||||||||||||||||||||||||||||
| Depreciation and amortization | 272 | (272) | (l) | 268 | (268) | (l) | |||||||||||||||||||||||||||||
| Taxes other than income taxes | 138 | — | 121 | — | |||||||||||||||||||||||||||||||
| Total operating expenses | 7,493 | 5,591 | |||||||||||||||||||||||||||||||||
| (Loss) gain on sales of assets and businesses | (12) | — | 57 | — | |||||||||||||||||||||||||||||||
| Operating loss | (172) | (2) | |||||||||||||||||||||||||||||||||
| Other income and (deductions) | |||||||||||||||||||||||||||||||||||
| Interest expense, net | (64) | 64 | (m) | (72) | 72 | (m) | |||||||||||||||||||||||||||||
| Other, net | 383 | (367) | (b),(c),(d),(h),(i),(j),(n),(p) | 234 | (228) | (b),(c),(d),(e),(i),(c) | |||||||||||||||||||||||||||||
| Total other income and (deductions) | 319 | 162 | |||||||||||||||||||||||||||||||||
| Income before income taxes | 147 | 160 | |||||||||||||||||||||||||||||||||
| Income taxes | 116 | (116) | (n) | 117 | (117) | (n) | |||||||||||||||||||||||||||||
| Equity in losses of unconsolidated affiliates | (4) | — | (4) | — | |||||||||||||||||||||||||||||||
| Net income | 27 | 39 | |||||||||||||||||||||||||||||||||
| Net loss attributable to noncontrolling interests | (7) | 12 | (o) | (3) | 12 | (o) | |||||||||||||||||||||||||||||
| Net income attributable to common shareholders | $ | 34 | $ | 42 | |||||||||||||||||||||||||||||||
| Effective tax rate | 78.9 | % | 73.1 | % | |||||||||||||||||||||||||||||||
| Earnings per average common share | |||||||||||||||||||||||||||||||||||
| Basic | $ | 0.10 | $ | — | |||||||||||||||||||||||||||||||
| Diluted | $ | 0.10 | $ | — | |||||||||||||||||||||||||||||||
| Average common shares outstanding | |||||||||||||||||||||||||||||||||||
| Basic | 328 | — | |||||||||||||||||||||||||||||||||
| Diluted | 329 | — | |||||||||||||||||||||||||||||||||
__________
(a)Results reported in accordance with GAAP.
(b)Adjustment for mark-to-market on economic hedges and fair value adjustments related to gas imbalances and equity investments.
(c)Adjustment for all gains and losses associated with NDTs, ARO accretion, ARO remeasurement, and any earnings neutral impacts of contractual offset for Regulatory Agreement Units.
(d)Adjustments related to plant retirements and divestitures.
(e)In 2021, adjustment primarily for reorganization and severance costs related to cost management programs.
(f)In 2021, adjustment for direct costs related to COVID-19 consisting primarily of costs to acquire personal protective equipment, costs for cleaning supplies and services, and costs to hire healthcare professionals to monitor the health of employees.
(g)In 2021, adjustment for costs related to the acquisition of EDF's interest in CENG, which was completed in the third quarter of 2021.
(h)Adjustment for costs related to a multi-year ERP system implementation.
(i)Adjustment for certain incremental costs related to the separation (system-related costs, third-party costs paid to advisors, consultants, lawyers, and other experts assisting in the separation), including a portion of the amounts billed to us pursuant to the TSA.
(j)Adjustment for Pension and OPEB Non-Service credits. Historically, we were allocated our portion of pension and OPEB non-service costs from Exelon, which was included in Operating and maintenance expense. Effective February 1, 2022, the non-service credit (cost) components are included in Other, net.
(k)Adjustment for certain changes in environmental liabilities.
(l)Adjustment for depreciation and amortization expense.
(m)Adjustment for interest expense.
(n)Adjustment for income taxes.
(o)Adjustment for elimination of the noncontrolling interest related to certain adjustments.
(p)In 2022, includes amounts contractually owed to Exelon under the TMA.
(q)Reversal of a charge related to a prior 2012 merger commitment.
9
Constellation Energy Corporation
GAAP Consolidated Statements of Operations and
Adjusted (non-GAAP) EBITDA Reconciling Adjustments
(unaudited)
(in millions, except per share data)
| Twelve Months Ended December 31, 2022 | Twelve Months Ended December 31, 2021 | ||||||||||||||||||||||||||||||||||
GAAP (a) | Non-GAAP Adjustments | GAAP (a) | Non-GAAP Adjustments | ||||||||||||||||||||||||||||||||
| Operating revenues | $ | 24,440 | $ | 1,184 | (b),(c) | $ | 19,649 | $ | 629 | (b),(c) | |||||||||||||||||||||||||
| Operating expenses | |||||||||||||||||||||||||||||||||||
Purchased power and fuel | 17,462 | 138 | (b) | 12,163 | 1,064 | (b),(d) | |||||||||||||||||||||||||||||
Operating and maintenance | 4,841 | (28) | (c),(d),(h),(i),(j),(k) (r) | 4,555 | (184) | (c),(d),(e),(f),(g),(h),(i),(j),(k),(p) | |||||||||||||||||||||||||||||
Depreciation and amortization | 1,091 | (1,091) | (l) | 3,003 | (3,003) | (l) | |||||||||||||||||||||||||||||
Taxes other than income taxes | 552 | (2) | (i) | 475 | — | ||||||||||||||||||||||||||||||
Total operating expenses | 23,946 | 20,196 | |||||||||||||||||||||||||||||||||
| Gain on sales of assets and businesses | 1 | $ | 1 | (d) | 201 | (68) | (d) | ||||||||||||||||||||||||||||
| Operating income (loss) | 495 | (346) | |||||||||||||||||||||||||||||||||
| Other income and (deductions) | |||||||||||||||||||||||||||||||||||
Interest expense, net | (251) | 251 | (m) | (297) | 297 | (m) | |||||||||||||||||||||||||||||
Other, net | (786) | 845 | (b),(c),(d), (i),(j),(n)(q) | 795 | 763 | (b),(c),(d) | |||||||||||||||||||||||||||||
| Total other income and (deductions) | (1,037) | 498 | |||||||||||||||||||||||||||||||||
| (Loss) income before income taxes | (542) | 152 | |||||||||||||||||||||||||||||||||
| Income taxes | (388) | 388 | (n) | 225 | (225) | (n) | |||||||||||||||||||||||||||||
| Equity in losses of unconsolidated affiliates | (13) | — | (10) | — | |||||||||||||||||||||||||||||||
| Net loss | (167) | (83) | |||||||||||||||||||||||||||||||||
| Net (loss) income attributable to noncontrolling interests | (7) | 49 | (o) | 122 | 53 | (o) | |||||||||||||||||||||||||||||
| Net loss attributable to common shareholders | $ | (160) | $ | (205) | |||||||||||||||||||||||||||||||
| Effective tax rate | 71.6 | % | 148.0 | % | |||||||||||||||||||||||||||||||
| Earnings per average common share | |||||||||||||||||||||||||||||||||||
| Basic | $ | (0.49) | $ | — | |||||||||||||||||||||||||||||||
| Diluted | $ | (0.49) | $ | — | |||||||||||||||||||||||||||||||
| Average common shares outstanding | |||||||||||||||||||||||||||||||||||
| Basic | 328 | — | |||||||||||||||||||||||||||||||||
| Diluted | 329 | — | |||||||||||||||||||||||||||||||||
__________
(a)Results reported in accordance with GAAP.
(b)Adjustment for mark-to-market on economic hedges and fair value adjustments related to gas imbalances and equity investments.
(c)Adjustment for all gains and losses associated with NDTs, ARO accretion, ARO remeasurement, and any earnings neutral impacts of contractual offset for Regulatory Agreement Units.
(d)Adjustments related to plant retirements and divestitures.
(e)In 2021, adjustment primarily for reorganization and severance costs related to cost management programs.
(f)In 2021, adjustment for direct costs related to COVID-19 consisting primarily of costs to acquire personal protective equipment, costs for cleaning supplies and services, and costs to hire healthcare professionals to monitor the health of employees.
(g)In 2021, adjustment for costs related to the acquisition of EDF's interest in CENG, which was completed in the third quarter of 2021.
(h)Adjustment for costs related to a multi-year ERP system implementation.
(i)Adjustment for certain incremental costs related to the separation (system-related costs, third-party costs paid to advisors, consultants, lawyers, and other experts assisting in the separation), including a portion of the amounts billed to us pursuant to the TSA.
(j)Adjustment for Pension and OPEB Non-Service credits. Historically, we were allocated our portion of pension and OPEB non-service costs from Exelon, which was included in Operating and maintenance expense. Effective February 1, 2022, the non-service credit (cost) components are included in Other, net.
(k)Adjustment for certain changes in environmental liabilities.
(l)Adjustment for depreciation and amortization expense.
(m)Adjustment for interest expense.
(n)Adjustment for income taxes.
(o)Adjustment for elimination of the noncontrolling interest related to certain adjustments. In 2022, primarily relates to CRP and in 2021, primarily relates to CENG and the noncontrolling interest portion of a wind project impairment recognized within CRP.
(p)Reflects an impairment in the New England asset group, an impairment as a result of the sale of the Albany Green Energy biomass facility, and an impairment of a wind project
(q)In 2022, includes amounts contractually owed to Exelon under the tax matters agreement.
(r)Reversal of a charge related to a prior 2012 merger commitment.
10
Statistics
| Three Months Ended December 31, | Twelve Months Ended December 31, | |||||||||||||||||||||||||
| 2022 | 2021 | 2022 | 2021 | |||||||||||||||||||||||
| Supply Source (GWhs) | ||||||||||||||||||||||||||
Nuclear Generation(a) | ||||||||||||||||||||||||||
| Mid-Atlantic | 13,942 | 13,386 | 53,214 | 53,589 | ||||||||||||||||||||||
| Midwest | 24,011 | 22,745 | 95,090 | 93,107 | ||||||||||||||||||||||
New York(b) | 6,483 | 6,473 | 25,046 | 26,294 | ||||||||||||||||||||||
| Total Nuclear Generation | 44,436 | 42,604 | 173,350 | 172,990 | ||||||||||||||||||||||
| Natural Gas, Oil, and Renewables | ||||||||||||||||||||||||||
| Mid-Atlantic | 524 | 596 | 2,097 | 2,271 | ||||||||||||||||||||||
| Midwest | 372 | 320 | 1,202 | 1,083 | ||||||||||||||||||||||
| New York | — | — | — | 1 | ||||||||||||||||||||||
| ERCOT | 3,106 | 2,936 | 14,124 | 13,187 | ||||||||||||||||||||||
Other Power Regions(c) | 2,518 | 2,353 | 10,189 | 9,995 | ||||||||||||||||||||||
| Total Natural Gas, Oil, and Renewables | 6,520 | 6,205 | 27,612 | 26,537 | ||||||||||||||||||||||
| Purchased Power | ||||||||||||||||||||||||||
| Mid-Atlantic | 3,202 | 1,453 | 15,366 | 13,576 | ||||||||||||||||||||||
| Midwest | 185 | 174 | 610 | 561 | ||||||||||||||||||||||
| ERCOT | 720 | 629 | 3,575 | 3,256 | ||||||||||||||||||||||
Other Power Regions(c) | 11,167 | 11,434 | 51,131 | 50,212 | ||||||||||||||||||||||
| Total Purchased Power | 15,274 | 13,690 | 70,682 | 67,605 | ||||||||||||||||||||||
| Total Supply/Sales by Region | ||||||||||||||||||||||||||
| Mid-Atlantic | 17,668 | 15,435 | 70,677 | 69,436 | ||||||||||||||||||||||
| Midwest | 24,568 | 23,239 | 96,902 | 94,751 | ||||||||||||||||||||||
New York(b) | 6,483 | 6,473 | 25,046 | 26,295 | ||||||||||||||||||||||
| ERCOT | 3,826 | 3,565 | 17,699 | 16,443 | ||||||||||||||||||||||
Other Power Regions(c) | 13,685 | 13,787 | 61,320 | 60,207 | ||||||||||||||||||||||
| Total Supply/Sales by Region | 66,230 | 62,499 | 271,644 | 267,132 | ||||||||||||||||||||||
| Three Months Ended December 31, | Twelve Months Ended December 31, | |||||||||||||||||||||||||
| 2022 | 2021 | 2022 | 2021 | |||||||||||||||||||||||
Outage Days(d) | ||||||||||||||||||||||||||
| Refueling | 65 | 90 | 212 | 262 | ||||||||||||||||||||||
| Non-refueling | 3 | 24 | 54 | 34 | ||||||||||||||||||||||
| Total Outage Days | 68 | 114 | 266 | 296 | ||||||||||||||||||||||
__________
(a)Includes the proportionate share of output where we have an undivided ownership interest in jointly-owned generating plants. Includes the total output for fully owned plants and the total output for CENG prior to the acquisition of EDF’s interest on August 6, 2021 as CENG was fully consolidated.
(b)2021 values have been revised from those previously reported to correctly reflect our 82% undivided ownership interest in Nine Mile Point Unit 2.
(c)Other Power Regions includes New England, South, West, and Canada.
(d)Outage days exclude Salem.
11
| Three Months Ended December 31, | Twelve Months Ended December 31, | |||||||||||||||||||||||||
| ZEC Reference Prices | 2022 | 2021 | 2022 | 2021 | ||||||||||||||||||||||
| State (Region) | ||||||||||||||||||||||||||
| New Jersey (Mid-Atlantic) | $ | 10.00 | $ | 10.00 | $ | 10.00 | $ | 10.00 | ||||||||||||||||||
| Illinois (Midwest) | 12.01 | 16.50 | 13.88 | 16.50 | ||||||||||||||||||||||
| New York (New York) | 21.38 | 21.38 | 21.38 | 20.93 | ||||||||||||||||||||||
| Three Months Ended December 31, | Twelve Months Ended December 31, | |||||||||||||||||||||||||
| Capacity Reference Prices | 2022 | 2021 | 2022 | 2021 | ||||||||||||||||||||||
| Location (Region) | ||||||||||||||||||||||||||
| Eastern Mid-Atlantic Area Council (Mid-Atlantic) | $ | 97.86 | $ | 165.73 | $ | 126.14 | $ | 174.96 | ||||||||||||||||||
| ComEd (Midwest) | 68.96 | 195.55 | 121.71 | 192.45 | ||||||||||||||||||||||
| Rest of State (New York) | 72.44 | 164.40 | 85.36 | 98.35 | ||||||||||||||||||||||
| Southeast New England (Other) | 126.67 | 154.37 | 138.21 | 163.66 | ||||||||||||||||||||||
| Three Months Ended December 31, | Twelve Months Ended December 31, | |||||||||||||||||||||||||
| Electricity Reference Prices | 2022 | 2021 | 2022 | 2021 | ||||||||||||||||||||||
| Location (Region) | ||||||||||||||||||||||||||
| PJM West (Mid-Atlantic) | $ | 68.62 | $ | 54.60 | $ | 72.90 | $ | 38.91 | ||||||||||||||||||
| ComEd (Midwest) | 52.26 | 43.77 | 60.24 | 34.76 | ||||||||||||||||||||||
| Central (New York) | 47.40 | 39.82 | 57.52 | 29.90 | ||||||||||||||||||||||
| North (ERCOT) | 52.12 | 41.11 | 64.38 | 146.63 | ||||||||||||||||||||||
Southeast Massachusetts (Other)(a) | 77.07 | 60.86 | 86.02 | 46.38 | ||||||||||||||||||||||
__________
(a)Reflects New England, which comprises the majority of the activity in the Other region.
12
Earnings Conference Call Fourth Quarter 2022 February 16, 2023
This presentation contains certain forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 that are subject to risks and ans and variations on such words, and similar expressions that reflect our current views with respect to future events and operational, economic, and financial performance, are intended to identify such forward-looking statements. The factors that could cause actual results to differ materially from the forward-looking statements made by Constellation Energy Corporation and Constellation Energy 2022 Annual Report on Form 10-K (to be filed on al Condition and Results of Operations, (c) Part II, ITEM 8. Financial Statements and Supplementary Data: Note 19, Commitments and Contingencies, and (d) other factors discussed in filings with the SEC by the Registrants. Investors are cautioned not to place undue reliance on these forward-looking statements, whether written or oral, which apply only as of the date of this presentation. Neither of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this presentation. Cautionary Statements Regarding Forward-Looking Information 2
The Registrants report their financial results in accordance with accounting principles generally accepted in the United States (GAAP). Constellation supplements the reporting of financial information determined in accordance with GAAP with certain non-GAAP financial measures, including: • Adjusted EBITDA represents earnings before interest, income taxes, depreciation and amortization, and excludes certain costs, expenses, gains and losses and other specified items, including mark-to-market adjustments from economic hedging activities and fair value adjustments related to gas imbalances and equity investments, decommissioning related activity, asset impairments, certain amounts associated with plant retirements and divestitures, pension and other post-employment benefits (OPEB) non-service credits, separation related costs and other items as set forth in the Appendix. Includes nuclear fuel amortization expense. • Adjusted cash flows from operations primarily includes net cash flows from operating activities and Collection of Deferred Purchase Price (DPP) related to the revolving accounts receivable arrangement, which is presented in cash flows from investing activities under GAAP • Free cash flows before growth (FCFbg) is adjusted cash flows from operations less capital expenditures under GAAP for maintenance and nuclear fuel, non-recurring capital expenditures related to separation and Enterprise Resource Program (ERP) system implementation, changes in collateral, net merger and acquisitions, and equity investments and other items as set forth in the Appendix • Adjusted operating revenues excludes the mark-to-market impact of economic hedging activities due to the volatility and unpredictability of the future changes in commodity prices • Adjusted purchased power and fuel excludes the mark-to-market impact of economic hedging activities and fair value adjustments related to gas imbalances due to the volatility and unpredictability of the future changes in commodity prices • Total gross margin is defined as adjusted operating revenues less adjusted purchased power and fuel expense, excluding revenue related to decommissioning, gross receipts tax, JExel Nuclear JV, variable interest entities, and net of direct cost of sales for certain end-user businesses • Adjusted operating and maintenance (O&M) excludes direct cost of sales for certain end-user businesses, ARO accretion expense from unregulated units and decommissioning costs that do not affect profit and loss, the impact from operating and maintenance expense related to variable interest entities at Constellation, and other items as set forth in the reconciliation in the Appendix Due to the forward-looking nature of some forecasted non-GAAP measures, information to reconcile the forecasted adjusted (non-GAAP) measures to the most directly comparable GAAP measure may not be available, as management is unable to project all of these items for future periods. Non-GAAP Financial Measures 3
de operating performance by excluding items that are considered by management to be not directly related to the ongoing operations of the business. In addition, this information is among the primary indicators management uses as a basis for evaluating performance, allocating resources, setting incentive compensation targets and planning and forecasting of future periods. These non- tations. Constellation has provided these non-GAAP financial measures as supplemental information and in addition to the financial measures that are calculated and presented in accordance with GAAP. These non-GAAP measures should not be deemed more useful than, a substitute for, or an alternative to the most comparable GAAP measures provided in the materials presented. Non- - -GAAP measures to the most comparable GAAP measures are provided in the appendices and attachments to this presentation, except for the reconciliation for total gross margin*, which appears on slide 36 of this presentation. Non-GAAP Financial Measures Continued 4
Delivered on Our Commitments in 2022 Enduring Businesses Ready to Meet the Climate Crisis Delivering Value for Our Shareholders Premier ESG Company • Introduced industry-leading climate goals • Issued carbon emissions reports to customers • Published first sustainability report • Launched $1M workforce development program • Created first DEI Advisory Board • Donated more than $12.5M to charitable causes, including $4.6M from employee contributions • 80,000 hours of employee volunteerism Generated ~180 TWhs of clean energy, avoiding ~127 million metric tons of carbon dioxide; equivalent to over 27.5M passenger vehicles being removed for one year • Earned Adjusted EBITDA* of $2,667M, above our revised guidance range • Paid down $2.5B in long-term debt and term loans, and generated strong FCF to support investment grade balance sheet • S&P upgraded to BBB • Paid $185M in dividends • Nuclear capacity factor of 94.8% • 98.4% power dispatch match • 95.8% wind and solar energy capture • Partnered with Microsoft to develop an hourly carbon-free energy matching technology that will allow our customers to have a transparent and independent way to certify that they are meeting their clean energy goals • Secured nuclear fuel supply through 2028 • Pilot program to begin hydrogen production at Nine Mile Point • Hydrogen hubs being encouraged by DOE • Executed two largest CORe deals ever • Ranked overall #1 Retail Energy Supplier in 5
Doubling common dividend, targeting 10% annual future growth Authorized $1.0 billion in share repurchases $1.5 billion of organic growth meeting our double-digit return threshold • Commercial-scale hydrogen project • Nuclear uprates at Byron and Braidwood • Wind repower and refurbishment Credit Ratings • S&P BBB; positive outlook • Baa2; stable outlook Providing Value to Our Shareholders Through Our Capital Allocation Plan Approximately $2.0 billion of additional capital to be allocated in 2023-2024 6
Strong Operations Deliver Reliable and Affordable Carbon-Free Power 7 (1) -owned units. Includes 100% ownership of CENG following closure of EDF Put on August 6, 2021. (2) Excludes Salem. Constellation and Industry averages reflect Oyster Creek and TMI partial year operation in 2018 and 2019, respectively. (3) Major nuclear operator is defined as one entity responsible for the operation of at least two sites and comprising of at least four units; Major Operator rankings reflect 100% ownership for Constellation. (4) Refueling outage values are not adjusted for ownership (5) Composite Operational Excellence Metric consists of 14 indicators in Production, Cost, and Safety. Value represents the percentage of the maximum available score by ranking of Major Operators across the 14 indicators. (6) Power Dispatch Match is used to measure the responsiveness of a unit to the market, expressed as actual energy gross margin relative to total desired energy gross margin. Desired energy gross margin is measured by revenues less fuel costs and variable O&M when unit is dispatched. Wind Energy Capture represents actual energy produced by wind turbine generators of a wind farm, divided by the on-site measured total wind energy available. Solar Energy Capture represents actual energy produced by the sum of the Generating System Modules of a solar plant or group of solar plants, divided by total expected energy to be produced by the sum of the same Generating System Modules. Energy Capture for the combined wind and solar fleet is weighted by the relative site projected pre-tax variable revenue, with deductions made for certain excusable events that are non-controllable. 21 21 22 22 21 35 36 34 32 2018 2019 2020 2021 2022 94.6% 95.7% 95.4% 94.5% 94.8% 90.8% 91.7% 90.8% 90.9% 20222018 2019 2020 2021 Nuclear Capacity Factor (%) (1,2) Average Nuclear Refueling Outage Days (2,4) Nuclear Composite Operational Excellence (5) (Total of Rankings of 14 Indicators) Power Metrics (6) Ranking Among Major Operators (3) 2021 1 2020 1 2019 1 2018 1 Ranking Among Major Operators (2-Yr) (3) 2021 1 2020 1 2019 1 2018 1 Ranking Among Major Operators (3) 2021 1 2020 1 2019 1 2018 2 Industry Average 2019 55.9% 2018 55.8%55.8% 2021 55.9% 2020 73.0% 84.9% 91.3% 92.1% Industry Average 98.1% 97.9% 98.4% 72.4% 98.4%96.1% 96.3% 93.4% 95.7% 95.8% 20192018 2020 2021 2022 Power Dispatch Match Wind & Solar Energy Capture Industry Average
Leading Customer Platform Enables Customers to Meet Their Energy and Sustainability Needs 8 (1) Other includes New England, South and West (2) Leading Customer Operational Metrics (TTM) 2022 Electric Load Served by Region (TWhs) 37 46 14 16 30 13 25 25 Other (1)Midwest New York 16 71 Mid-Atlantic 50 ERCOT 2 55 Wholesale Retail 36% 18% 79% 90% Power New Customer Win Rate Gas New Customer Win Rate C&I Power Customer Renewal Rate C&I Gas Customer Renewal Rate CORe Continues to Grow, Setting Another Record Year Ranked #1 Overall Retail Energy Supplier (2) #1 In Pre-Sale Support #1 In After-Sale Support #1 In Pricing and Contracting • Executed our two largest CORe deals ever • Entered into six long-term power purchase agreements with new build renewable generators across three ISOs, with total nameplate capacity of 824 MWs • 1.65 TWhs will be delivered annually to 12 different customers across 12 states • Approximately 20 TWhs will be delivered over the term of the agreements
Accelerating the Transition to Carbon-Free Future 9 License Renewals Notified NRC of intent to apply for renewals at Clinton and Dresden Nuclear Uprates ~135 additional MWs planned at Byron and Braidwood Hydrogen Hubs DOE encouraged Midwest, Mid-Atlantic and Northeast hubs Hydrogen Production Pilot project at Nine Mile Point will be first nuclear produced hydrogen Direct Air Capture Received grant from DOE to explore carbon removal technology at Byron
10 Always-on Nuclear Keeps the Lights On, Fossil Fails During Grid Emergency • Between December 23-25, Winter Storm Elliott brought record-setting low temperatures to the PJM region, threatening the reliability of the grid and safety of Americans • Always-on nuclear power provided the resiliency and reliability needed by the grid to prevent catastrophic blackouts • 100% during the event (1) • Fossil failed to perform. 23% of PJM capacity failed, nearly 90% of the outages were fossil. • PJM was forced to issue emergency conservation alerts, which were followed by alerts from utilities, g offices, and media outlets (1) Source: https://www.nrc.gov/reading-rm/doc-collections/event-status/reactor-status/2022/index.html (2) Does not include minority ownership share of Salem, which Constellation does not operate (3) Source: https://www.nei.org/news/2023/nuclear-saves-the-holiday-season (4) Other includes nuclear, oil, wind, and solar (5) Source: https://pjm.com/-/media/committees-groups/committees/mic/2023/20230111/item-0x---winter-storm-elliott-overview.ashx 32 GW (71%) 6 GW (13%) Natural Gas 8 GW (16%) Coal Other (4) Total Forced Outages (5) 100% 96% 62% 83% 91% 77% 38% 17% 9% 23% Other (4)CEG Operated Nuclear (2) PJM Nuclear (3) 4%Forced Outage Natural Gas Total PJM (5) Coal Available Capacity Forced Outage vs. Available Capacity
$2,185 $2,667 2021 Results 2022 Results $3,300 2023 Guidance Initiating Full-Year 2023 Adjusted EBITDA* Guidance of $2,900M - $3,300M 11 • Higher realized energy prices • Continued strong performance of customer business • Incremental costs to invest in the business • 14 refueling outages in 2023 versus 11 in 2022 (1) $2,900 ($M) 2023 Year-Over-Year Guidance Drivers $3,100 Delivered 2022 Adj. EBITDA* Above Revised Guidance • Effective portfolio management and strong results in the customer business • PJM capacity performance bonuses, net of non-performance charges • Supporting long-term value: Accelerated investment in growth projects, including hydrogen post- IRA Invested in attracting and retaining top employee talent in competitive job market Margin shaping of retail contracts: 2022 headwinds for fixed price customer contracts that have compelling economics over the term of the contract 2022 Revised Guidance Range $2,450M - $2,650M (1) Includes Constellation-operated nuclear plants and Salem
20 25 30 35 40 45 50 55 60 20 25 30 35 40 45 50 55 60 Market Revenues ($/MWh) M a rk e t R e v e n u e s + P T C ($ / M W h ) 12 PTC Provides Support for Nuclear Units When Revenues Fall Below $43.75/MWh Illustrative Payoff Dynamics for Non-State-Supported Units in 2024 • The PTC provides support of up to $15.00/MWh for units when revenues are between $25.00/MWh and $43.75/MWh while preserving the ability of the unit to participate in upside from commodity markets • The green line assumes revenues of $47.00/MWh and since it is above the $43.75/MWh PTC phase out units would not receive PTC value • When revenues fall below the $43.75/MWh phase out, the PTC will provide support for the units • Assuming revenues of $35.00/MWh, the orange line, we would expect units to receive $7.00/MWh PTC, bringing the total value the unit would receive to $42.00/MWh $47/MWhMerchant Unit Payoff $35/MWh PTC provides support from $25/MWh - $43.75/MWh
Gross Margin Category ($M) (1) 2023 2024 2023 Open Gross Margin* (including South, West, New England, Canada hedged gross margin) $7,000 $6,400 ($1,500) Contracted Revenues (Capacity, ZEC and IL CMC Plant Revenues) (2) $2,800 $2,750 - Mark-to-Market of Hedges (3) ($2,300) ($1,050) $1,500 Power New Business / To Go $400 $300 $100 Non-Power Margins Executed $250 $200 - Non-Power New Business / To Go $200 $350 - Total Gross Margin* (4) $8,350 $8,950 $100 Nuclear PTC Value For Plants Not Supported By State Programs (4,5) N/A - N/A December 31, 2022 Change from September 30, 2022 Gross Margin* Update (1) Gross margin* categories rounded to nearest $50M (2) Includes gross margin* and CMC payments for CMC plants. NY ZEC revenues reflect the expected NY ZEC payment as of current market forwards. Should market forwards exceed the ZEC reference index in New York, ZEC payments may decline. (3) Mark-to-Market of Hedges assumes mid-point of hedge percentages (4) Based on December 31, 2022, market conditions (5) Plants included are Calvert Cliffs, LaSalle, Limerick and Peach Bottom Federal PTC Assumptions • There are still many uncertainties about how the nuclear PTC will be calculated, including the definition of gross receipts and interactions with the state programs, that will need to be determined by the IRS before the actual value of the PTC can be known • Although we are advocating that gross receipts be calculated in a manner that accounts for hedging, we have conservatively assumed gross receipts are defined using a spot price • We are working with state policymakers to reduce the amount of state support to account for the federal support provided by the nuclear PTC. However, we have not assumed any reduction in support in these disclosures. • Given these assumptions and 12/31 market prices, we do not currently anticipate receiving any incremental value from nuclear PTCs in 2024 13
Investing for Long-Term Value Through Capital Expenditures (1) 14 $750 $1,000 $775 $800 $850 $1,175 $1,175 $1,175 $400 $575 $525 $1,650 $50 2025E $2,575 2023E2022 $2,475$2,525 2024E Commited Growth BaselineNuclear Fuel ($M) Note: All amounts rounded to the nearest $25M. Items may not sum due to rounding. (1) Reflects cash CapEx for Power at 100% ownership
Investments in Carbon-Free Future that Comfortably Exceed our Double- Digit Return Threshold 15 • Hydrogen facility will initially use ~250 MWs and produce ~33,450 TPA hydrogen, with the ability to expand to 400 MWs – Expect long-term off-take agreements to consume more than 90% of the ~250 MWs • Investing total construction CapEx of ~$900M from 2023-2025 (1) • Hydrogen will be provided to customers co-located at our facility • We anticipate commercial production of hydrogen beginning in 2026 • Increasing nuclear output by ~135 MWs at Byron and Braidwood • Investing ~$800M from 2023-2029 for needed low pressure turbine replacements, upgrading the high pressure turbines and pulling forward planned generator maintenance at Byron, of which ~$200M is growth capital to uprate the plants (2) • Anticipate uprate MWs to be phased in starting in 2026 with full implementation by 2029 based on timing of the turbine installations during planned refuel outages • 315 MWs in initial scope of repowering program • Investing $350 million from 2023-2025 (3) • First 70 MWs partial repowering expected to be in commercial operation in 2023 Growth CapEx Commercial Hydrogen Production Nuclear Uprates Wind Repower & Refurbishment Hydrogen Nuclear Uprates Wind Repower & Refurbishment Note: All amounts rounded to the nearest $25M. Items may not sum due to rounding. (1) Does not assume DOE cost-share through the hydrogen hub (2) $600 million of investment included in baseline CapEx (3) Reflects cash CapEx at 100% ownership; excludes $20 million invested in 2022 ($M) $200 $325 $375 $100 $175 $25 $50 $25 $25 2023 $25 2024 $50 $50 2025 $400 $575 $525 Hydrogen OtherWind Repower & Refurbishment Nuclear Uprates
Securing Nuclear Fuel Supply Through 2028 16 Nuclear Fuel Capital Expenditures • We have built a diverse and resilient portfolio that can withstand a Russian supply disruption • We entered into contracts to increase our inventory to mitigate the risk of possible supply disruption that could occur between now and 2028 the year when multiple Western enrichment providers expect to have additional capacity online • We will continue to work with policymakers and suppliers to ensure reliable sources of supply remain available in the long-term • Fuel costs are expected to rise over coming years but remain under $6/MWh through 2028, even with higher prices Note: All amounts rounded to the nearest $25M (1) ($M) $850 $1,175 $1,175 $1,175 2022 (1) 2023E 2024E 2025E
Adjusted O&M* Flat 2023-2025 17 $4,600 $4,875 $4,850 $4,850 2022 2023E 2024E 2025E ($M) Note: All amounts rounded to the nearest $25M
Our Investment Grade Balance Sheet is a Competitive Advantage 18 35% 45% Pre-WC/ Debt* S&P FFO / Debt* 1.8x Net Debt / EBITDA* (1) 2.2x Book Excluding Non-Recourse (1) 2023 forecasted year-end net debt is $6.7 billion (2) Maturity profile excludes non-recourse debt, P-Cap facility, securitized debt, capital leases, fair value adjustments, unamortized debt issuance costs and unamortized discount/premium (3) Long-term debt balances reflect 2022 Annual Form 10-K GAAP financials, which include items listed in footnote 2 except for the P-Cap facility 2023E Credit Metrics Long-Term Debt Maturity Profile (2) Current Credit Ratings Baa2; stable outlook S&P BBB; positive outlook $ 9 0 0 $ 9 0 0 $ 3 5 0 $ 7 8 8 2 0 3 0 2 0 3 6 2 0 2 3 2 0 2 4 2 0 2 5 2 0 2 9 2 0 3 4 2 0 2 8 2 0 2 6 2 0 2 7 2 0 3 1 2 0 3 2 2 0 3 7 2 0 3 3 2 0 3 5 2 0 3 9 2 0 3 8 2 0 4 0 2 0 4 1 2 0 4 2 Long-Term Debt Balances (3) Recourse $3.0B Non-Recourse $1.6B Total Long-Term Debt $4.6B As of 12/31/2022 ($M)
Strong Free Cash Flows Create Value Through Growth and Capital Return 19 (1) Beginning Cash Available reflects excess cash balance above minimum targets as of December 31, 2022 (2) Available Cash is a midpoint of a range based on December 31, 2022, market prices (3) Debt Issuance & Other Financing includes collateral activity, and contributions from and distributions to JV partners (4) Separation O&M / CapEx includes costs and investments related to separation and multi-year implementation of Enterprise Resource Program (ERP) system $3.8 - $4.2 Separation O&M / CapEx (4) $0.2 Dividend ($0.2) 2023 - 2024 Available Cash (2) $0.6 - $1.0 Debt Issuance & Other Financing (3) ($1.0) Identified Growth ($0.8) ($1.0) Authorized Share Repurchases FCFbg* $1.8 - $2.2 Unidentified Growth / Return of Capital Beginning Cash Available (1) $3.9 - $4.3 ($B)
2023 Priorities 20 Continue as leader in operational excellence Accelerate transition to carbon-free future Work with Treasury and states to implement the IRA provisions Deliver on financial commitments Attract and retain the best talent as a premier workplace Effectively deploy capital to the benefit of our shareholders
Additional Disclosures 21
22
E S G Environmental: • Clean Energy Leadership: Continue to be the cleanest supplier of power in the U.S. and maintain leadership through our climate commitment to own 100% carbon-free generation by 2040. • Investing in a Clean Energy Economy: Leverage our platform to impact customers through enabling new clean energy products and services and providing our customers with an accounting of their carbon emissions and ways to reduce their carbon footprint. • Protecting the Environment: Minimize the impacts of our operations on local air quality, water resources and biodiversity through robust environmental programs. Social: • DEI: Foster a culture of innovation and deliver strong performance by prioritizing a respectful workplace, ensuring a sense of belonging, providing opportunities for growth, attracting and retaining passionate and talented people, and integrating diversity as a business imperative and core value. • Supplier Diversity: Increase diverse supplier spend by expanding Constellation Diverse Business Empowerment strategy internally and externally with supplier diversity councils and other stakeholders. • Community Engagement: Act as a catalyst for positive change in our community, with a focus on employee giving and volunteerism and equity through STEM, scholarships, and workforce development opportunities. Governance: • Board & Executive Governance: Provide effective leadership and guidance to drive our sustainability efforts and deliver on our purpose to accelerate the transition to a carbon-free future. • Act with Integrity: Maintain a comprehensive ethics and compliance program that can adapt to the changing risks we face and guide us as we deliver on our purpose. 23
24 Q4 2022 Adjusted EBITDA* $1,027 $605 $109 $133 ($56) Labor, Contracting and Materials Q4 2022Lower NEIL Distributions ($139) PJM Performance Bonuses, Net Nuclear Outages Q4 2021 ($117) Capacity Revenues ($95) Impact of the February 2021 Extreme Cold Weather Event ($83) ($131) Market and Portfolio Conditions Impact of CTV Investments ($43) Other ($M)
25 Full Year 2022 Adjusted EBITDA* $1,132 $109 ($295) 2021 ($131) Impact of CTV Investments Lower NEIL Distributions ($17) 2022Market and Portfolio Conditions Impact of the February 2021 Extreme Cold Weather Event $70 $74 OtherNuclear Fuel Costs PJM Performance Bonuses, Net ($377) $2,667 $2,185 ($83) Capacity Revenues Labor, Contracting and Materials ($M)
• Starting in 2025, the maximum PTC and gross receipts threshold are subject to an inflation adjustment based on the GDP price deflator for the preceding calendar year: • Maximum PTC is rounded to nearest $2.50/MWh and gross receipts threshold is rounded to nearest $1.00/MWh Inflation of Nuclear Production Tax Credit (PTC) (1) 26 (1) See H.R. 5376 for additional details; all numbers assume that prevailing wage requirements are satisfied (2) Annual inflation adjustment is consistent with past published guidance for renewable energy credits, published annually PTC Overview Example Assuming 2%, 3% and 4% Inflation (2) PTC Inflation Adjustment • The PTC is in effect beginning after 12/31/23 and through 12/31/32 • In the base year 2024, Constellation qualifies for the nuclear PTC up to $15.00/MWh; the PTC amount is reduced by 80% of gross receipts exceeding $25.00/MWh, phasing out completely after $43.75/MWh • The nuclear PTC can be credited against taxes or monetized by transferring to an eligible taxpayer Maximum PTC Gross Receipts Threshold Power Price At Which PTC=$0 Maximum PTC Gross Receipts Threshold Power Price At Which PTC=$0 Maximum PTC Gross Receipts Threshold Power Price At Which PTC=$0 2024 $15.00 $25.00 $43.75 $15.00 $25.00 $43.75 $15.00 $25.00 $43.75 2025 $15.00 $26.00 $44.75 $15.00 $26.00 $44.75 $15.00 $26.00 $44.75 2026 $15.00 $26.00 $44.75 $15.00 $27.00 $45.75 $15.00 $27.00 $45.75 2027 $15.00 $27.00 $45.75 $17.50 $27.00 $48.88 $17.50 $28.00 $49.88 2028 $15.00 $27.00 $45.75 $17.50 $28.00 $49.88 $17.50 $29.00 $50.88 2029 $17.50 $28.00 $49.88 $17.50 $29.00 $50.88 $17.50 $30.00 $51.88 2030 $17.50 $28.00 $49.88 $17.50 $30.00 $51.88 $20.00 $32.00 $57.00 2031 $17.50 $29.00 $50.88 $17.50 $31.00 $52.88 $20.00 $33.00 $58.00 2032 $17.50 $29.00 $50.88 $20.00 $32.00 $57.00 $20.00 $34.00 $59.00 2% Inflation 3% Inflation 4% Inflation
Extending the Life of our Nuclear Fleet to 80 years 27 0 2,000 4,000 6,000 8,000 10,000 12,000 14,000 16,000 18,000 20,000 22,000 20502022 20352030 C a p a c it y ( M W ) 2025 2040 2045 2055 2060 2065 2070 Potential Subsequent License Renewal for Remaining Fleet Clinton License Renewal (60 Years) Dresden Subsequent License Renewal (80 Years) Clinton Subsequent License Renewal (80 Years) Peach Bottom Subsequent License Renewal (80 Years) (1) Current License Life of Fleet (1) icenses out to 2053 and 2054. On February 24, the NRC issued orders in the Peach Bottom and Turkey Point adjudicatory proceedings (which had not been terminated even though the NRC had already issued the renewed licenses) finding that s in place but directed the staff to amend the Peach Bottom licenses to change the expiration dates to the initial renewed license period (2033 and 2034) until the NRC updates its generic environmental analysis and regulations, which is expected to be completed in 2024. Please refer to 2022 Annual Form 10-K for additional information.
28 100% 100% 100% Of our owned generation will be carbon-free by 2040 Reduction of our operations- driven emissions by 2040 (1) Of C&I customers provided with specific information about how to meet GHG reduction goals ✓Clean Energy Supply: ▪ Clean Electricity Supply: We commit that our owned generation supply will be 100% carbon-free by 2040; with an interim goal of 95% carbon- free by 2030 subject to policy support and technology advancements. ▪ Operational Emissions Reduction Goal: We aspire to reduce operations driven emissions by 100% by 2040 subject to technology and policy advancement ▪ Interim target to reduce carbon emissions by 65% from 2020 levels by 2030 ▪ thane pledge ▪ Supply Chain Engagement: Partner with our key energy suppliers on their GHG emissions and climate adaptation strategies ✓Clean Customer Transformation: ▪ Provided 100% of C&I customers with customer- specific information on their GHG impact for facilities contracting for power and gas supply from Constellation including mitigation opportunities that include 24/7 clean electric use ▪ ✓Technology Enablement and Commercialization: ▪ Commit to enable the future technologies and business models needed to drive the clean energy economy to improve the health and welfare of communities through venture investing and R&D. We will target 25% of these investments to minority and women led businesses and will require investment recipients to disclose how they engage in equitable employment and contracting practices, using performance as a factor when considering investments (1) Any emissions that cannot be technologically reduced by that time will be offset; includes all GHGs except methane which is addressed in a separate methane reduction goal
New York ZEC Price Determination 29 Tranche Date U.S. SCC ($/Short Ton) Baseline RGGI Estimate ($/Short Ton) Net CO2 Externality ($/Short Ton) Short Ton to MWh (Conversion Factor) Adjusted SCC ($/MWh) Reference Price ($/MWh) Energy and Capacity Forecast Adjustment ($/MWh) Upstate ZEC Price ($/MWh) Tranche 1 4/1/2017- 3/31/2019 $42.87 $10.41 $32.47 0.53846 $17.48 N/A N/A $17.48 Tranche 2 4/1/2019- 3/31/2021 $46.79 $10.41 $36.38 0.53846 $19.59 $39.00 N/A $19.59 Tranche 3 4/1/2021- 3/31/2023 $50.11 $10.41 $39.71 0.53846 $21.38 $39.00 N/A $21.38 Tranche 4 4/1/2023- 3/31/2025 $54.66 $10.41 $44.26 0.53846 $23.83 $37.78 $5.56 $18.27 Tranche 5 4/1/2025- 3/31/2027 $59.54 $10.41 $49.13 TBD TBD $37.78 TBD TBD Tranche 6 4/1/2027- 3/31/2029 $64.54 $10.41 $54.13 TBD TBD $37.78 TBD TBD
Commercial Disclosures December 31, 2022 30
Open Gross Margin* Generation Gross Margin* at current market prices, including ancillary revenues, nuclear fuel amortization and fuel expense Power Purchase Agreement (PPA) Costs and Revenues Provided at a consolidated level for all regions (includes hedged gross margin* for South, West, New England and Canada (1)) Contracted Revenues Expected contracted revenues from CMC payments to eligible IL plants Expected capacity revenues for generation of electricity Expected revenues from Zero Emissions Credits (ZEC) MtM of Hedges (2) Mark-to-Market (MtM) of power, capacity and ancillary hedges, including cross commodity, retail and wholesale load transactions Provided directly at a consolidated level for four major regions. Provided indirectly for each of the four major regions via Effective Realized Energy Price (EREP), reference price, hedge %, and expected generation. Business Retail, Wholesale planned electric sales Portfolio Management new business Mid marketing new business Executed Retail, Wholesale executed gas sales Energy Efficiency (3) Constellation Home (3) New Business Retail, Wholesale planned gas sales Energy Efficiency (3) Constellation Home (3) Portfolio Management / origination fuels new business Proprietary trading (4) Components of Gross Margin* Categories 31 Margins move from new business to MtM of hedges over the course of the year as sales are executed (5) course of the year Gross margin* linked to power production and sales Gross margin* from other business activities (1) Hedged gross margins* for South, West, New England & Canada region will be included with Open Gross Margin*; no expected generation, hedge %, EREP or reference prices provided for these regions (2) MtM of hedges provided directly for the four larger regions; MtM of hedges is not provided directly at the regional level but can be easily estimated using EREP, reference price and hedged MWh (3) (4) on (5) Margins for South, West, New England & Canada regions and optimization of fuel and PPA activities captured in Open Gross Margin*
Gross Margin Category ($M) (1) 2023 2024 2023 Open Gross Margin (including South, West, New England & Canada hedged GM)* $7,000 $6,400 ($1,500) Contracted Revenues (Capacity, ZEC and IL CMC Plant Revenues) (2) $2,800 $2,750 - Mark-to-Market of Hedges (3) ($2,300) ($1,050) $1,500 Power New Business / To Go $400 $300 $100 Non-Power Margins Executed $250 $200 - Non-Power New Business / To Go $200 $350 - Total Gross Margin* (4) $8,350 $8,950 $100 Nuclear PTC Value for Plants Not Supported By State Programs (4,5) N/A - - Reference Prices (4) 2023 2024 2023 Henry Hub Natural Gas ($/MMBtu) $4.26 $4.27 ($1.17) Midwest: NiHub ATC prices ($/MWh) $49.82 $47.52 ($14.64) Mid-Atlantic: PJM-W ATC prices ($/MWh) $61.18 $58.34 ($13.90) ERCOT-N ATC Spark Spread ($/MWh) HSC Gas, 7.2HR, $2.50 VOM $20.30 $16.71 $1.24 New York: NY Zone A ($/MWh) $41.27 $38.52 ($6.49) December 31, 2022 Change from September 30, 2022 Gross Margin* 32 (1) Gross margin* categories rounded to nearest $50M (2) NY ZEC revenues reflect the expected NY ZEC payment as of current market forwards. Should market forwards exceed the ZEC reference index in New York, ZEC payments may decline. (3) Mark-to-Market of Hedges assumes mid-point of hedge percentages (4) Based on December 31, 2022, market conditions (5) Plants included are Calvert Cliffs, LaSalle, Limerick and Peach Bottom
Generation and Hedges 2023 2024 2023 Expected Generation (GWh) (1) 196,500 198,200 (1,400) Midwest (Total) (2) 95,500 96,400 (100) Midwest (Excluding CMCs) 41,300 42,300 (100) Mid-Atlantic 54,800 56,400 (700) ERCOT 20,400 20,100 (600) New York 25,800 25,300 - % of Expected Generation Hedged (3) 94%-97% 75%-78% 1% - 4% Midwest (Total) 95%-98% 83%-86% 0% - 3% Midwest (Excluding CMCs) 91%-94% 63%-66% 2% - 5% Mid-Atlantic 100%-103% 73%-76% 0% - 3% ERCOT 90%-93% 61%-64% 14% - 17% New York 79%-82% 60%-63% (7%) - (4%) Effective Realized Energy Price ($/MWh) (4) Midwest (Excluding CMCs) $29.50 $35.50 $0.50 Mid-Atlantic $46.50 $45.00 $1.00 ERCOT (5) $6.00 $9.00 $5.00 New York $21.50 $33.00 ($3.00) December 31, 2022 Change from September 30, 2022 Generation and Hedges 33 (1) Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contracted for capacity based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products, and options. Expected generation assumes 14 refueling outages in 2023 and 13 in 2024 at Constellation-operated nuclear plants and Salem. Expected generation assumes capacity factors of 94.1% and 94.2% in 2023 and 2024, respectively at Constellation-operated nuclear plants, at ownership. These estimates of expected generation in 2022 and 2023 do not represent guidance or a forecast of future results as we have not completed its planning or optimization processes for those years. (2) Midwest (Total) expected generation includes generation from CMC plants of 54,200 GWh in 2023 and 54,100 GWh in 2024 (3) Percent of expected generation hedged is the amount of equivalent sales divided by expected generation. It includes all hedging products, such as wholesale and retail sales of power, options and swaps. The Midwest values in the table reflect IL plants receiving CMC payments as 100% hedged. To align with the Midwest EREP, however, one should exclude plant and hedge volumes associated with CMC payments. New York values include the effect of the New York ZEC. (4) Effective realized energy price is representative of an all-in hedged price, on a per MWh basis, at which expected generation has been hedged. It is developed by considering the energy revenues and costs associated with our hedges and by considering the natural gas that has been purchased to lock in margin. It excludes uranium costs, RPM capacity, ZEC and CMC revenues, but includes the mark-to-market value of capacity contracted at prices other than RPM clearing prices including our load obligations. It can be compared with the reference prices used to calculate open gross margin* in order to determine the mark-to- (5) Spark spreads shown for ERCOT
Sensitivities (with existing hedges) (1,2) 2023 2024 2023 2023 2024 NiHub ATC Energy Price + $5.00/MWh - $65 ($15) - - - $5.00/MWh - ($65) $15 - $30 PJM-W ATC Energy Price + $5.00/MWh - $60 ($20) - - - $5.00/MWh - ($60) $10 - - NYPP Zone A ATC Energy Price + $5.00/MWh $20 $55 $5 - - - $5.00/MWh ($20) ($55) ($5) - - Nuclear Capacity Factor +/- 1% +/- $65 +/- $65 $(15) Nuclear PTC Value For Plants Not Supported By State Programs (3) December 31, 2022December 31, 2022 Change from September 30, 2022 Gross Margin Sensitivities 34 (1) Sensitivities rounded to the nearest $5M (2) Based on December 31, 2022, market conditions and hedged position; power price sensitivities are derived by adjusting the power price assumption while keeping all other price inputs constant; due to correlation of the various assumptions, the hedged gross margin* impact calculated by aggregating individual sensitivities may not be equal to the hedged gross margin* impact calculated when correlations between the various assumptions are also considered; sensitivities based on commodity exposure which includes open generation and all committed transactions. (3) Plants included are Calvert Cliffs, LaSalle, Limerick and Peach Bottom
Row Item Midwest (Excl. CMCs) (2) Mid-Atlantic ERCOT (3) New York (A) Start with fleet-wide open gross margin* (B) Contracted Revenues (C) Expected Generation (TWh) 42.3 56.4 20.1 25.3 (D) Hedge % (assuming mid-point of range) 64.5% 74.5% 62.5% 61.5% (E=C*D) Hedged Volume (TWh) 27.3 42.0 12.6 15.6 (F) Effective Realized Energy Price ($/MWh) $35.50 $45.00 $9.00 $33.00 (G) Reference Price ($/MWh) $47.52 $58.34 $16.71 $38.52 (H=F-G) Difference ($/MWh) ($12.02) ($13.34) ($7.71) ($5.52) (I=E*H) Mark-to-Market value of hedges ($ million) (1) ($330) ($560) ($95) ($85) (J=A+B+I) Hedged Gross Margin* ($ million) (K) Power New Business / To Go ($ million) (L) Non-Power Margins Executed ($ million) (M) Non-Power New Business / To Go ($ million) (N=J+K+L+M) Total Gross Margin* $200 $350 $8,950 million $6.4 billion $8,100 $300 $2.75 billion Illustrative Example of Modeling 2024 Total Gross Margin* 35 (1) Mark-to-market rounded to the nearest $5M (2) Uses the Midwest hedge ratio that excludes the CMC plant volume and hedges (3) Spark spreads shown for ERCOT
Additional Constellation Modeling Data 36 Total Gross Margin* Reconciliation ($M) (1) 2023 2024 Adjusted Operating Revenues* (2) $30,350 $31,750 Adjusted Purchased Power and Fuel* (2) ($21,500) ($22,325) Wind Production Tax Credits (PTC) ($25) ($25) Other Revenues (3) ($225) ($225) Direct cost of sales incurred to generate revenues for certain Commercial and Power businesses ($250) ($225) Total Gross Margin* (Non-GAAP) $8,350 $8,950 Note: 329 million average outstanding diluted shares as of December 31, 2022, per Annual Form 10-K (1) Items may not sum due to rounding. All amounts rounded to the nearest $25M (2) Excludes the mark-to-market impact of economic hedging activities due to the volatility and unpredictability of the future changes to power prices (3) Other Revenues primarily reflects revenues from variable interest entities, funds collected through revenues for decommissioning the former PECO nuclear plants through regulated rates and gross receipts tax revenues (4) Other primarily reflects noncontrolling interest and Other Revenues (excluding gross receipts tax revenue) (5) Cash tax rate includes receivable from Exelon for tax credits. If receivable were to be excluded in calculation, cash tax rate would be 13% in 2023 and 26% in 2024. Inputs ($M) 2023 2024 Adjusted O&M* ($4,875) ($4,850) Wind PTCs $25 $25 Other (4) $25 ($25) Taxes Other Than Income (TOTI) ($425) ($450) Effective Tax Rate 28% 27% Cash Tax Rate (5) 0% 19%
Appendix Reconciliation of Non-GAAP Measures 37
S&P FFO/Debt (2) = FFO (a) CFO Pre-WC/Debt (3) = CFO (Pre-WC) (c) Adjusted Debt (b) Adjusted Debt (d) S&P FFO Calculation (2) -WC Calculation (3) GAAP Operating Income Cash Flow From Operations + Depreciation & Amortization +/- Working Capital Adjustment = EBITDA - Nuclear Fuel Capital Expenditures - Interest +/- +/- Cash Taxes = CFO Pre-Working Capital (c) + Nuclear Fuel Amortization +/- Mark-to-Market Adjustments (Economic Hedges) +/- Other S&P Adjustments = FFO (a) S&P Adjusted Debt Calculation (2) (3) Long-Term Debt Long-Term Debt + Short-Term Debt + Short-Term Debt + Purchase Power Agreement and Operating Lease Imputed Debt + Underfunded Pension (pre-tax) + Pension/OPEB Imputed Debt (after-tax) +Operating Lease Imputed Debt + AR Securitization Imputed Debt +/- - Off-Credit Treatment of Non-Recourse Debt = Adjusted Debt (d) - Cash on Balance Sheet +/- Other S&P Adjustments = Adjusted Debt (b) GAAP to Non-GAAP Reconciliations (1) 38 (1) Due to the forward-looking nature of some forecasted non-GAAP measures, information to reconcile the forecasted adjusted (non-GAAP) measures to the most directly comparable GAAP measure may not be available; therefore, management is unable to reconcile these measures (2) Calculated using S&P Methodology (3)
Net Debt/EBITDA = Net Debt (a) Net Debt/EBITDA Excluding Non-Recourse = Net Debt (c) Adjusted EBITDA* (b) Adjusted EBITDA* (d) Net Debt Calculation Net Debt Calculation Excluding Non-Recourse Long-Term Debt (including current maturities) Long-Term Debt (including current maturities) + Short-Term Debt + Short-Term Debt - Cash on Balance Sheet - Cash on Balance Sheet = Net Debt (a) - Non-Recourse Debt = Net Debt Excluding Non-Recourse (c) Adjusted EBITDA* Calculation Adjusted EBITDA* Calculation Excluding Non-Recourse GAAP Net Income GAAP Net Income + Income Tax Expense + Income Tax Expense + Interest Expense, Net + Interest Expense, Net + Depreciation & Amortization + Depreciation & Amortization +/- Adjustments +/- Adjustments = Adjusted EBITDA* (b) - EBITDA from Projects Financed by Non-Recourse Debt = Adjusted EBITDA* Excluding Non-Recourse Debt (d) GAAP to Non-GAAP Reconciliations (1) 39 (1) Due to the forward-looking nature of some forecasted non-GAAP measures, information to reconcile the forecasted adjusted (non-GAAP) measures to the most directly comparable GAAP measure may not be currently available; therefore, management is unable to reconcile these measures
Three Months Ended December 31, Twelve Months Ended December 31, Adjusted EBITDA* Reconciliation ($M) 2021 2022 2021 2022 GAAP Net Income (Loss) $42 $34 ($205) ($160) Income Taxes (1) $117 $133 $225 ($339) Depreciation and Amortization (2) $268 $272 $3,003 $1,091 Interest Expense, Net $72 $64 $297 $251 Unrealized (Gain)/Loss on Fair Value Adjustments (3) $771 $413 ($420) $1,058 Asset Impairments (4) $4 - $541 - Plant Retirements & Divestitures (5) $11 ($7) ($4) ($11) Decommissioning-Related Activities (6) ($275) ($306) ($1,289) $820 Pension & OPEB Non-Service Credits ($14) ($31) ($50) ($116) Separation Costs (7) $24 $41 $49 $140 COVID-19 Direct Costs (8) $11 - $35 - Acquisition Related Costs (9) - - $21 - ERP System Implementation Costs (10) $3 $6 $14 $22 Change in Environmental Liabilities $5 ($2) $12 $10 Cost Management Program - - $9 - Prior Merger Commitment (11) - - - ($50) Noncontrolling Interests (12) ($12) ($12) ($53) ($49) Adjusted EBITDA* $1,027 $605 $2,185 $2,667 GAAP to Non-GAAP Reconciliation 40 Note: Items may not sum due to rounding (1) Includes amounts contractually owed to Exelon under the Tax Matters Agreement (TMA) reflected in Other, net (2) Includes the accelerated depreciation associated with early plant retirements (3) Includes mark-to-market on economic hedges and fair value adjustments related to gas imbalances and equity investments (4) Reflects an impairment in the New England asset group, an impairment as a result of the sale of the Albany Green Energy biomass facility, and an impairment of a wind project (5) In 2021, primarily reflects nuclear fuel amortization for Byron and Dresden, partially offset by a gain on sale of our solar business and a reversal of one-time charges resulting from the reversal of the previous decision to retire Byron and Dresden. (6) Reflects all gains and losses associated with NDT, ARO accretion, ARO remeasurement, and any earnings neutral impacts of contractual offset for Regulatory Agreement Units (7) Represents certain incremental costs related to the separation (system-related costs, third-party costs paid to advisors, consultants, lawyers, and other experts assisting in the separation), including a portion of the amounts billed to us pursuant to the TSA (8) Represents direct costs related to COVID-19 consisting primarily of costs to acquire personal protective equipment, costs for cleaning supplies and services, and costs to hire healthcare professionals to monitor the health of employees (9) Reflects costs related to the acquisition of Electricite de France SA's (EDF's) interest in Constellation Energy Nuclear Group, LLC (CENG), which was completed in the third quarter of 2021 (10) Reflects costs related to a multi-year ERP system implementation (11) Reversal of a charge related to a prior 2012 merger commitment (12) Represents elimination of the noncontrolling interest related to certain adjustments. In 2022, primarily relates to CRP and in 2021, primarily relates to CENG and the noncontrolling interest portion of a wind project impairment recognized within CRP.
Adjusted EBITDA* Reconciliation ($M) 2023 GAAP Net Income $550 - $850 Income Taxes $425 Interest Expense $425 Depreciation and Amortization $1,125 Unrealized (Gain)/Loss on Fair Value Adjustments (1) $400 Pension and OPEB Non-Service Credits ($50) Decommissioning Related Activity (2) $50 Separation Costs (3) $75 ERP System Implementation (4) $25 Noncontrolling Interest (5) ($50) Other ($25) Adjusted EBITDA* (Non-GAAP) $2,900 - $3,300 GAAP to Non-GAAP Reconciliation 41 Note: Items may not sum due to rounding. All amounts rounded to the nearest $25M (1) Includes mark-to-market on economic hedges and fair value adjustments related to gas imbalances and equity investments. (2) Reflects all gains and losses associated with NDT, ARO accretion, ARO remeasurement, and any earnings neutral impacts of contractual offset for Regulatory Agreement Units (3) Represents certain incremental costs related to the separation (system-related costs, third-party costs paid to advisors, consultants, lawyers, and other experts assisting in the separation), including a portion of the amounts billed to us pursuant to the TSA (4) Reflects costs related to a multi-year ERP system implementation (5) Represents elimination of the noncontrolling interest related to certain adjustments
GAAP to Non-GAAP Reconciliation 42 Adjusted O&M* Reconciliation ($M) 2022 2023 2024 2025 GAAP O&M $4,850 $5,425 $5,275 $5,250 Decommissioning (1) $75 ($200) ($200) ($175) Prior Merger Commitment (2) $50 - - - Direct cost of sales incurred to generate revenues for certain Commercial and Power businesses (3) ($225) ($250) ($225) ($225) Separation Costs (4) ($125) ($75) - - ERP System Implementation (5) ($25) ($25) - - Adjusted O&M* (Non-GAAP) $4,600 $4,875 $4,850 $4,850 Note: Items may not sum due to rounding. All amounts rounded to the nearest $25M. (1) Reflects all gains and losses associated with NDT, ARO accretion, ARO remeasurement, and any earnings neutral impacts of contractual offset for Regulatory Agreement Units. (2) 2022 reflects reversal of a charge related to a prior 2012 merger commitment (3) Reflects the direct cost of sales of certain businesses, which are included in Total Gross Margin* (4) Represents certain incremental costs related to the separation (system-related costs, third-party costs paid to advisors, consultants, lawyers, and other experts assisting in the separation), including a portion of the amounts billed to us pursuant to the TSA (5) Reflects costs related to a multi-year ERP system implementation
GAAP to Non-GAAP Reconciliation 43 Free Cash Flow before Growth* ($M) 2023 - 2024 Adjusted Cash Flows from Operations* (Non-GAAP) (1) $8,050 - $8,450 Baseline and Nuclear Fuel Capital Expenditures ($4,000) Reinvestment in Nuclear Decommissioning Trust Funds (2) ($450) Collateral activity $150 O&M related to Separation and ERP System Implementation $100 Other Net Investing Activities ($50) Free Cash Flow before Growth* $3,750 - $4,150 Note: All amounts rounded to the nearest $50M. Items may not sum due to rounding (1) Includes Collection of Deferred Purchase Price (DPP) related to the revolving accounts receivable arrangement, which is presented in cash flows from investing activities for GAAP. Cash flows from collection of DPP are not forecasted. (2) Reflects reinvestment of proceeds from nuclear decommissioning trust funds that are presented in Adjusted Cash Flows from Operations*. Impact is cash flow neutral.
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