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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

x			QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2026

OR

o			TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ______ to ______

Commission File Number 001-40503

NET Power Inc.

(Exact name of registrant as specified in its charter)

Delaware			98-1580612
(State or other jurisdiction of incorporation or organization)			(I.R.S. Employer Identification No.)
11700 Katy Freeway Suite 700 Houston, Texas			77079
(Address of Principal Executive Offices)			(Zip Code)

(888) 323-6797

Registrant’s telephone number, including area code

Securities registered pursuant to Section 12(b) of the Act:

Title of each class			Trading Symbol(s)			Name of each exchange on which registered
Class A Common Stock			NPWR			The New York Stock Exchange
Warrants, each exercisable for one share of Class A Common Stock at a price of $11.50			NPWR-WT			The New York Stock Exchange

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes x No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer			o			Accelerated filer			o
Non-accelerated filer			x			Smaller reporting company			x
						Emerging growth company			x

If an emerging growth company, indicate by check mark if the registrant has 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. o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x

The registrant had outstanding 91,700,715 shares of Class A Common Stock and 133,401,325 shares of Class B Common Stock as of November 10, 2026.

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TABLE OF CONTENTS

						Page
			Certain Defined Terms			1
			Cautionary Note Regarding Forward-Looking Statements			2
PART I.			FINANCIAL INFORMATION
Item 1.			Financial Statements (Unaudited)			4
			Condensed Consolidated Balance Sheets			4
			Condensed Consolidated Statements of Operations and Comprehensive Loss			6
			Condensed Consolidated Statements of Shareholders’ Equity and Mezzanine Shareholders’ Equity			7
			Condensed Consolidated Statements of Cash Flows			9
			Notes to Condensed Consolidated Financial Statements			11
Item 2.			Management’s Discussion and Analysis of Financial Condition and Results of Operations			28
Item 3.			Quantitative and Qualitative Disclosures About Market Risk			41
Item 4.			Controls and Procedures			41
PART II.			OTHER INFORMATION
Item 1.			Legal Proceedings			43
Item 1A.			Risk Factors			43
Item 2.			Unregistered Sales of Equity Securities and Use of Proceeds			50
Item 3.			Defaults Upon Senior Securities			51
Item 4.			Mine Safety Disclosures			51
Item 5.			Other Information			51
Item 6.			Exhibits			51
Signatures						54

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Table of Contents

Certain Defined Terms

For the definitions of certain defined terms used throughout this Quarterly Report on Form 10-Q (this “Report”), please refer to the section entitled “Certain Defined Terms” in our Annual Report on Form 10-K for the fiscal year ended December 31, 2025 (the “Annual Report”). Capitalized terms used but not otherwise defined in this Report have the meanings assigned to them in the Annual Report.

1

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Table of Contents

Cautionary Note Regarding Forward-Looking Statements

This Report contains “forward-looking statements” within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act. Statements that do not relate strictly to historical or current facts are forward-looking and are usually identified by the use of words such as “anticipate,” “believe,” “could,” “estimate,” “expect,” “forecast,” “future,” “intend,” “may,” “opportunity,” “plan,” “potential,” “project,” “seek,” “should,” “strategy,” “target,” “will,” “will likely result,” “would,” and other similar words and expressions, but the absence of these words does not mean that a statement is not forward-looking. Forward-looking statements may relate to the anticipated demand for the Company’s products and services, the Company’s ability to license third-party technology, the development and financing of the Company’s power generation projects and the Company’s entry into related agreements, the timing and configuration of project phases, permitting, grid interconnection, the Company’s business strategies, capital requirements, potential growth opportunities and expectations for future performance (financial or otherwise). Forward-looking statements are based on current expectations, estimates, projections, targets, opinions and/or beliefs of the Company, and such statements involve known and unknown risks, uncertainties and other factors.

The risks and uncertainties that could cause actual results to differ materially from those expressed or implied by these forward-looking statements include: risks relating to (i) the uncertainty of the projected financial information with respect to the Company and risks related to the Company’s ability to meet its projections; (ii) the Company’s ability to utilize its net operating loss and tax credit carryforwards effectively; (iii) the capital-intensive nature of the Company’s business model, which will likely require the Company to raise additional capital in the future; (iv) barriers the Company may face in its attempts to deploy its power plants and its ability to successfully develop its power plants; (v) the Company’s ability to agree on and execute a change order relocating the work under the engineering, procurement and construction agreement for its initial project, to resume that work and to fund the related payments, and the costs the Company would incur if that agreement were terminated; (vi) the possibility that the Company’s projects are developed without carbon capture, and the Company’s ability to obtain post-combustion carbon capture (“PCC”) technology from Entropy Inc. (“Entropy”) or another provider on acceptable terms if it elects to deploy carbon capture in later phases or projects; (vii) the Company’s ability to negotiate and enter into binding energy services or power offtake agreements on acceptable terms and on a timeline that supports a final investment decision (“FID”) for its initial project, and the conditions, approvals, exclusions and aggregate cap that limit the Company’s recovery of costs under its cost reimbursement agreement with a prospective customer; (viii) risks related to permitting and grid interconnection, including the timing and outcome of the large-load interconnection processes of the Electric Reliability Council of Texas (“ERCOT”), the pause in the issuance of permits for data center projects directed by the Governor of Texas in September 2026, the policies of the Texas administration taking office in January 2027, and any verification, audit, or other regulatory or legislative process applicable to data centers, the generation that serves them and other large loads in Texas; (ix) the availability, cost, and delivery timing of gas turbines, reciprocating engines and related equipment, including additional generating units that the Company does not currently hold; (x) the impact of tariffs, trade barriers, export controls, and sanctions on equipment costs and supply timelines; (xi) the development of competing energy technologies, including battery storage, nuclear, and other generation resources, that could reduce demand for the Company’s products; (xii) changes in, or the elimination of, governmental incentives and tax credits supporting carbon capture, including the credit available under Section 45Q of the Internal Revenue Code (as amended), and restrictions on the value, transferability, and monetization of such credits, and the availability of arrangements for the sale, transportation, sequestration, or other disposition of captured CO₂; (xiii) the proper functioning of the complex machinery the Company relies on for its operations and development; (xiv) the Company’s ability to adequately control or accurately predict the costs associated with its projects; (xv) potential changes and/or delays in site selection and construction that result from regulatory, logistical, and financing challenges; (xvi) the ability of the Company to integrate other energy technologies in its projects; (xvii) the Company’s ability to establish and maintain supply relationships and the impact of any supply chain disruptions; (xviii) risks related to strategic investors, partners and customers, including the risk that demand for power from customers may decline due to changes in general or industry-specific economic conditions; (xix) the Company’s ability to successfully commercialize its operations; (xx) the availability and cost of technological components and raw materials for

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the Company’s projects; (xxi) the impact of potential delays in discovering manufacturing and construction issues; (xxii) the ability of the Company’s commercial plants to efficiently provide net power output; (xxiii) the impact of public perception of fossil fuel-derived energy on the Company’s business; (xxiv) any political or other disruptions in gas-producing nations, including the ongoing conflicts in the Middle East; (xxv) risks relating to data privacy and cybersecurity, including the potential for future cyberattacks or security incidents that could disrupt the Company’s or its service providers’ operations; (xxvi) current and potential litigation that has been and may be instituted against the Company, including the litigation referenced in Part II, Item 1 of this Report; (xxvii) the Company’s ability to raise capital on acceptable terms, the dilutive effect of any equity or equity-linked issuance on existing stockholders, and limitations on the amount the Company may sell in primary offerings under an effective shelf registration statement for so long as the aggregate market value of its common equity held by non-affiliates remains below $75 million; (xxviii) the Company’s ability to satisfy the continued listing standards of the New York Stock Exchange, including the minimum average closing price requirement, and the risk that the Company’s securities could be suspended from trading and delisted; (xxix) the fact that the Company has committed, and may continue to commit, substantial capital to power generation equipment before binding power offtake, site-control or financing arrangements are in place, and may not recover some or all of that capital; (xxx) the Company’s ability to obtain the land and development rights required for its initial project and for the broader build-out at Project Permian, and its dependence on third-party data center developers and site owners; (xxxi) the Company’s ability to attract, retain, and motivate qualified personnel, and risks associated with workforce reductions; (xxxii) the Company’s ability to realize any value from the Oxy-Combustion Cycle intellectual property, the La Porte Demonstration Facility, and related assets, which have been fully impaired, the outcome of the Company’s evaluation of alternatives for the La Porte Demonstration Facility, and the timing and cost of decommissioning; and (xxxiii) other risks and uncertainties indicated in Part I, Item 1A of the Annual Report, Part II, Item 1A of this Report, and other documents subsequently filed with the SEC by the Company.

Should one or more of these risks or uncertainties materialize, or should any of the assumptions made by our management prove incorrect, actual results may vary in material respects from those projected in the forward-looking statements contained in this Report. Accordingly, you should not place undue reliance on these forward-looking statements in deciding whether to invest in our securities.

Forward-looking statements speak only as of the date they are made. Except to the extent required by applicable law or regulation, we undertake no obligation to update the forward-looking statements contained herein to reflect events or circumstances after the date of this Report or to reflect the occurrence of unanticipated events. The Company gives no assurance that it will achieve its expectations.

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Part I - Financial Information

Item 1. Financial Statements

NET Power Inc.

Condensed Consolidated Balance Sheets (Unaudited)

In thousands, except par value

						September 30,						December 31,
						2026						2025
ASSETS
Current assets
Cash and cash equivalents						$	143,031					$	199,430
Investments in securities, available-for-sale						39,858						138,462
Interest receivable						378						1,376
Prepaid expenses and other current assets						2,444						4,496
Total current assets						185,711						343,764
Long-term assets
Restricted cash						1,210						2,427
Investments in securities, available-for-sale						—						38,242
Intangible assets, net						439						181,572
Property, plant, and equipment, net						140,966						32,758
Operating lease right-of-use assets						245						551
Other long-term assets						76						387
Total assets						$	328,647					$	599,701
LIABILITIES, MEZZANINE SHAREHOLDERS’ EQUITY, AND SHAREHOLDERS’ EQUITY
Current liabilities
Accounts payable						$	341					$	1,437
Accrued liabilities						7,966						7,565
Due to related parties						10,619						37,262
Operating lease liabilities, current						1,100						1,074
Finance lease liabilities, current						—						127
Asset retirement obligation, current						4,597						—
Total current liabilities						24,623						47,465
Warrant liability						4,208						10,850
Non-current operating lease liabilities						1,968						2,584
Asset retirement obligation						—						3,597
Total liabilities						30,799						64,496
Commitments and contingencies (Note 14)

The accompanying notes are an integral part of these condensed consolidated financial statements.

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NET Power Inc.

Condensed Consolidated Balance Sheets (Unaudited) (Continued)

In thousands, except par value

						September 30,						December 31,
						2026						2025
Mezzanine shareholders’ equity
Redeemable non-controlling interests in subsidiary						204,718						331,301
Shareholders’ equity
Preferred Stock, $.0001 par value; 1,000 shares authorized; no shares issued or outstanding as of September 30, 2026 and December 31, 2025						—						—
Class A Common Stock, $.0001 par value; 520,000 shares authorized; 88,724 shares issued and outstanding as of September 30, 2026 and 83,980 shares issued and outstanding as of December 31, 2025						9						8
Class B Common Stock, $.0001 par value; 310,000 shares authorized; 136,378 shares issued and outstanding as of September 30, 2026 and 138,730 shares issued and outstanding as of December 31, 2025						14						14
Additional paid-in capital						884,440						898,425
Accumulated other comprehensive (loss) income						(49)						129
Accumulated deficit						(791,284)						(694,672)
Total shareholders’ equity						93,130						203,904
Total liabilities, mezzanine shareholders’ equity, and shareholders’ equity						$	328,647					$	599,701

The accompanying notes are an integral part of these condensed consolidated financial statements.

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NET Power Inc.

Condensed Consolidated Statements of Operations and Comprehensive Loss (Unaudited)

In thousands, except per share data

						Three Months Ended September 30,												Nine Months Ended September 30,
						2026						2025						2026						2025
Operating expenses
General and administrative						$	7,096					$	9,108					$	22,401					$	31,378
Sales and marketing						708						1,395						2,912						4,074
Research and development						9,187						24,543						33,108						73,761
Project development						2,622						10,032						4,752						41,719
Impairment and other charges						813						1,095,839						194,520						1,511,735
Depreciation, amortization, and accretion						151						15,580						7,017						58,936
Total operating expenses						20,577						1,156,497						264,710						1,721,603
Operating loss						(20,577)						(1,156,497)						(264,710)						(1,721,603)
Other income (expense)
Interest income, net						2,445						4,835						8,752						16,179
Change in Earnout Shares liability and Warrant liability						1,562						(9,323)						6,642						66,257
Change in Tax Receivable Agreement liability						—						—						—						21,317
Other income (expense)						(41)						2						(35)						8
Net other income (expense)						3,966						(4,486)						15,359						103,761
Net loss before income tax						(16,611)						(1,160,983)						(249,351)						(1,617,842)
Income tax (expense) benefit						—						1,177						(2)						2,403
Net loss after income tax						(16,611)						(1,159,806)						(249,353)						(1,615,439)
Net loss attributable to non-controlling interests						(10,147)						(748,308)						(152,741)						(1,056,449)
Net loss attributable to NET Power Inc.						$	(6,464)					$	(411,498)					$	(96,612)					$	(558,990)
Other comprehensive income
Unrealized gain (loss) on investments						(5)						163						(178)						245
Total other comprehensive income (loss)						(5)						163						(178)						245
Comprehensive loss						(16,616)						(1,159,643)						(249,531)						(1,615,194)
Comprehensive loss attributable to non-controlling interests						(10,147)						(748,203)						(152,741)						(1,056,291)
Comprehensive loss attributable to NET Power Inc.						$	(6,469)					$	(411,440)					$	(96,790)					$	(558,903)
Loss per share of Class A Common Stock, basic and diluted						$	(0.07)					$	(5.28)					$	(1.10)					$	(7.21)
Weighted average shares of Class A Common Stock, basic and diluted						88,572						77,883						87,459						77,530

The accompanying notes are an integral part of these condensed consolidated financial statements.

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NET Power Inc.

Condensed Consolidated Statements of Shareholders’ Equity and Mezzanine Shareholders’ Equity (Unaudited)

In thousands

						Class A Common Stock												Class B Common Stock												Additional Paid-in Capital						Accumulated Other Comprehensive Income (Loss)						Accumulated Deficit						Total Shareholders’ Equity						Non-controlling Interests - Mezzanine Equity
						Shares						Amount						Shares						Amount
Balance at December 31, 2025						83,980						$	8					138,730						$	14					$	898,425					$	129					$	(694,672)					$	203,904					$	331,301
Redemption of Class B Common Stock						3,872						1						(3,872)						—						—						—						—						1						—
Issuance of Class A Common Stock						65						—						—						—						160						—						—						160						—
Remeasurement adjustment to redeemable non-controlling interest resulting from ownership changes						—						—						—						—						8,600						—						—						8,600						(8,600)
Unrealized loss on investments						—						—						—						—						—						(128)						—						(128)						(207)
Share-based compensation						127						—						1,520						—						2,645						—						—						2,645						6,011
Net loss						—						—						—						—						—						—						(9,857)						(9,857)						(15,953)
Balance at March 31, 2026						88,044						$	9					136,378						$	14					$	909,830					$	1					$	(704,529)					$	205,325					$	312,552
Redemption of Class B Common Stock						—						—						—						—						—						—						—						—						—
Issuance of Class A Common Stock						116						—						—						—						184						—						—						184						—
Remeasurement adjustment to redeemable non-controlling interest resulting from ownership changes						—						—						—						—						(1,920)						—						—						(1,920)						1,920
Unrealized loss on investments						—						—						—						—						—						(45)						—						(45)						(70)
Share-based compensation						288						—						—						—						1,782						—						—						1,782						—
Adjustment of redeemable non-controlling interest to redemption value						—						—						—						—						(41,508)						—						—						(41,508)						41,508
Net loss						—						—						—						—						—						—						(80,291)						(80,291)						(126,640)
Balance at June 30, 2026						88,448						$	9					136,378						$	14					$	868,368					$	(44)					$	(784,820)					$	83,527					$	229,270
Redemption of Class B Common Stock						—						—						—						—						—						—						—						—						—
Issuance of Class A Common Stock						73						—						—						—						127						—						—						127						—
Remeasurement adjustment to redeemable non-controlling interest resulting from ownership changes						—						—						—						—						(68)						—						—						(68)						68
Unrealized loss on investments						—						—						—						—						—						(5)						—						(5)						(8)
Share-based compensation						203						—						—						—						839						—						—						839						709
Adjustment of redeemable non-controlling interest to redemption value						—						—						—						—						15,174						—						—						15,174						(15,174)
Net loss						—						—						—						—						—						—						(6,464)						(6,464)						(10,147)
Balance at September 30, 2026						88,724						$	9					136,378						$	14					$	884,440					$	(49)					$	(791,284)					$	93,130					$	204,718

The accompanying notes are an integral part of these condensed consolidated financial statements.

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NET Power Inc.

Condensed Consolidated Statements of Shareholders’ Equity and Mezzanine Shareholders’ Equity (Unaudited) (Continued)

In thousands

						Class A Common Stock												Class B Common Stock												Additional Paid-in Capital						Accumulated Other Comprehensive Income						Accumulated Deficit						Total Shareholders’ Equity						Non-controlling Interests - Mezzanine Equity
						Shares						Amount						Shares						Amount
Balance at December 31, 2024						76,760						$	8					139,691						$	14					$	771,594					$	32					$	(116,044)					$	655,604					$	1,506,584
Redemption of Class B Common Stock						300						—						(300)						—						—						—						—						—						—
Remeasurement adjustment to redeemable non-controlling interest resulting from ownership changes						—						—						—						—						1,503						—						—						1,503						(1,503)
Increase in Tax Receivable Agreement liability from qualifying exchanges						—						—						—						—						(343)						—						—						(343)						—
Unrealized gain on investments						—						—						—						—						—						6						—						6						10
Share-based compensation						3						—						1,175						—						1,199						—						—						1,199						9,053
Adjustment of redeemable non-controlling interest to book value						—						—						—						—						98,592						—						—						98,592						(98,592)
Net loss						—						—						—						—						—						—						(119,350)						(119,350)						(254,236)
Balance at March 31, 2025						77,063						$	8					140,566						$	14					$	872,545					$	38					$	(235,394)					$	637,211					$	1,161,316
Redemption of Class B Common Stock						473						—						(473)						—						—						—						—						—						—
Issuance of Class A Common Stock						65						—						—						—						141						—						—						141						—
Remeasurement adjustment to redeemable non-controlling interest resulting from ownership changes						—						—						—						—						3,707						—						—						3,707						(3,707)
Unrealized gain on investments						—						—						—						—						—						23						—						23						43
Share-based compensation						278						—						1,247						—						3,260						—						—						3,260						10,532
Net loss						—						—						—						—						—						—						(28,142)						(28,142)						(53,905)
Balance at June 30, 2025						77,879						$	8					141,340						$	14					$	879,653					$	61					$	(263,536)					$	616,200					$	1,114,279
Remeasurement adjustment to redeemable non-controlling interest resulting from ownership changes						—						—						—						—						(870)						—						—						(870)						870
Unrealized gain on investments						—						—						—						—						—						58						—						58						105
Share-based compensation						4						—						1,562						—						2,506						—						—						2,506						9,146
Adjustment of redeemable non-controlling interest to redemption value						—						—						—						—						(62,634)						—						—						(62,634)						62,634
Net loss						—						—						—						—						—						—						(411,498)						(411,498)						(748,308)
Balance at September 30, 2025						77,883						$	8					142,902						$	14					$	818,655					$	119					$	(675,034)					$	143,762					$	438,726

The accompanying notes are an integral part of these condensed consolidated financial statements.

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NET Power Inc.

Condensed Consolidated Statements of Cash Flows (Unaudited)

In thousands

						Nine Months Ended September 30,
						2026						2025
Cash flows from operating activities:
Net loss after income tax						$	(249,353)					$	(1,615,439)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation, amortization, and accretion						7,017						58,936
Impairment and other charges						194,520						1,511,735
Non-cash income						(3,010)						(1,683)
Deferred taxes						—						(2,404)
Loss on available-for-sale securities						45						—
Change in fair value of Earnout Shares liability and Warrant liability						(6,642)						(66,257)
Change in Tax Receivable Agreement liability						—						(21,317)
Share-based compensation expense						12,479						35,759
Changes in operating assets and liabilities:
Interest receivable						1,234						3,336
Prepaid expenses and other current assets						2,052						(953)
Other long-term assets						311						(42)
Accounts payable						(1,096)						(1,778)
Accrued liabilities						718						5,442
Due to related parties						(26,643)						1,685
Net cash used in operating activities						(68,368)						(92,980)
Cash flows from investing activities:
Purchases of available-for-sale securities						(149,964)						(156,416)
Maturities of available-for-sale securities						258,825						65,845
Proceeds from sale of available-for-sale securities						29,765						—
Maturities of short-term investments						—						100,000
Consideration paid for asset acquisition						(117,581)						—
Purchase of property, plant and equipment						(9,856)						(15,129)
Capitalized software						(285)						(1,035)
Net cash provided by (used in) investing activities						10,904						(6,735)
Cash flows from financing activities:
Issuance of Class A Common Stock under share-based compensation plans						471						157
Payment of tax withholdings on vested share-based payment awards						(491)						(172)
Payments on finance lease obligations						(132)						(149)
Net cash used in financing activities						(152)						(164)
Net decrease in cash, cash equivalents, and restricted cash						(57,616)						(99,879)
Cash, cash equivalents, and restricted cash, beginning of period						201,857						331,676
Cash, cash equivalents, and restricted cash, end of period						$	144,241					$	231,797

The accompanying notes are an integral part of these condensed consolidated financial statements.

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NET Power Inc.

Condensed Consolidated Statements of Cash Flows (Unaudited) (Continued)

In thousands

						Nine Months Ended September 30,
						2026						2025
Supplemental cash flow information:
Cash paid for interest						$	5					$	24
Cash paid for income taxes						2						—
Supplemental non-cash investing and financing activities:
Change in accruals for capital expenditures						$	(324)					$	(1,609)
Revision of estimated asset retirement obligation						714						—
Operating lease right-of-use asset acquired						—						1,591
Reconciliation of cash, cash equivalents, and restricted cash to the condensed consolidated balance sheet:
Cash and cash equivalents						$	143,031					$	229,315
Restricted cash						1,210						2,482
Total cash, cash equivalents, and restricted cash						$	144,241					$	231,797

The accompanying notes are an integral part of these condensed consolidated financial statements.

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NET Power Inc.

Notes to Condensed Consolidated Financial Statements (Unaudited)

NOTE 1 — Nature of Business and Basis of Presentation

Nature of Business

NET Power Inc. (“Net Power” or the “Company”) is an energy technology and project development company focused on the development of natural gas power generation projects to meet growing demand for reliable power. The Company’s near-term development activities are focused on delivering natural gas power generation behind the meter to data centers and other large-load customers.

The Company is developing its initial natural gas power generation project to supply power behind the meter, without a connection to the grid of the Electric Reliability Council of Texas (“ERCOT”), to a co-located data center at a site in Texas that the Company has not yet secured and that is separate from the Project Permian site described below (the “Initial Project”). For the Initial Project, the Company intends to use the ten reciprocating engine generating units being supplied under an engineering, procurement and construction agreement (the “EPC Agreement”) under which the Company assumed the owner’s rights and obligations in August 2026, as described in Note 6 — Property, Plant, and Equipment, together with additional generating capacity that the Company has not secured. The Company has not made a final investment decision (“FID”) for the Initial Project and has not obtained the site rights, permits, binding energy services or power offtake agreement, or the financing that FID would require. The Company also continues to develop its Project Permian site in West Texas (“Project Permian”) on a longer timeline. Project Permian is located within a ranch owned by affiliates of Occidental Petroleum, and the Company’s existing lease covers a portion of the site; development beyond the capacity that leasehold supports would require additional land rights that the Company has not obtained. The Company previously developed a reference design for a modular, standardized natural gas power plant product intended to accommodate PCC technology (the “Gas Power Product”, previously referred to as the “Clean Gas Product”). The Company does not currently expect the Initial Project to include carbon capture and is not designing it to accommodate the later addition of carbon capture. The configuration, generation capacity, carbon capture scope and timeline of each of the Company’s projects will depend on customer requirements, commercial arrangements, site rights, permits, equipment availability and financing.

Net Power’s technology portfolio also includes the Oxy-Combustion Cycle (also known as the Allam-Fetvedt cycle), a patented oxy-combustion and supercritical CO2 power generation system that was designed to produce reliable and affordable electricity from natural gas while capturing virtually all atmospheric emissions. As discussed in Note 12 — Related Party Transactions, development of the Oxy-Combustion Cycle has been indefinitely suspended and the Company has no current plans to resume development. The Company retains the related intellectual property, subject to licenses held by affiliates of Baker Hughes, and its interests in the La Porte Demonstration Facility, which were fully impaired during the second quarter of 2026 and are carried at no value. Any future recovery of value would depend on a royalty under those licenses or on a sale, license or other disposition of all or part of those assets, as to which there can be no assurance. See Note 5 — Goodwill and Intangible Assets.

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements included in this Quarterly Report on Form 10-Q have been prepared in conformity with accounting principles generally accepted in the United States of America (“US GAAP”) for interim financial information; however, certain information or footnote disclosures normally included in complete financial statements prepared in accordance with US GAAP may have been condensed or omitted pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”). In management’s opinion, these unaudited condensed consolidated financial statements have been prepared on the same basis as the annual financial statements for the year ended December 31, 2025 and include all adjustments, which consist of only normal and recurring adjustments, necessary for a fair presentation. Certain prior period financial information has been reclassified to conform to current period presentation.

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The results reported in these unaudited condensed consolidated financial statements are not necessarily indicative of the results to be expected for the entire year. These unaudited condensed consolidated financial statements should be read in conjunction with the annual financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2025, filed with the SEC on March 9, 2026 (the “2025 Annual Report”).

NOTE 2 — Significant Accounting Policies

The Company’s significant accounting policies used to prepare these condensed consolidated financial statements, unless otherwise noted below, are consistent with those used for the fiscal year ended December 31, 2025. Accordingly, refer to Note 2 to the consolidated financial statements in the 2025 Annual Report for the Company’s significant accounting policies.

Use of Estimates

The preparation of financial statements in conformity with US GAAP requires management to make certain estimates, judgments, and assumptions. The estimates, judgments and assumptions made by the Company when accounting for items and matters such as, but not limited to, depreciation, amortization, asset valuations, long-lived asset impairment, warrants, and share-based compensation, were reasonable based on information available at the time they were made. These estimates, judgments, and assumptions can affect the reported amounts of assets and liabilities as of the date of the condensed consolidated financial statements, as well as amounts reported on the condensed consolidated statements of operations and comprehensive loss during the periods presented. To the extent there are differences between these estimates and actual results, the Company’s condensed consolidated financial statements may be materially affected.

Segment Reporting

In accordance with ASC Topic 280, Segment Reporting (“ASC 280”), the Company has determined that it has one operating segment and one reportable segment, which includes all of the Company’s consolidated accounts. The Company’s chief operating decision maker (“CODM”) is its Chief Executive Officer. The CODM focuses on consolidated operating income (loss), with a focus on research and development, general and administrative expenses, and project development expenses, along with interest income to assess the Company’s performance and allocate resources. Segment expenses and other segment items are provided to the CODM on the same basis as disclosed in the condensed consolidated financial statements. The measure of segment assets is reported on the Company’s condensed consolidated balance sheet as total assets.

Accounting Standards Not Yet Adopted

In December 2023, the Financial Accounting Standards Board (“FASB”) issued ASU 2023-09, Income Taxes (Topic 740)—Improvements to Income Tax Disclosures (“ASU 2023-09”). ASU 2023-09 requires companies to provide annually a tabular reconciliation of the reported income tax expense (or benefit) from continuing operations to the product of the income (or loss) from continuing operations before income taxes and the applicable statutory federal income tax rate using specified categories and to disclose separately reconciling items within certain categories with absolute values equal to or greater than five percent of the product of the income (or loss) from continuing operations before tax and the applicable statutory tax rate. Additionally, ASU 2023-09 requires a public business entity to disclose the annual income taxes paid, net of refunds received, to federal, state, and foreign jurisdictions. If a payment to a single federal, state or foreign jurisdiction equals or exceeds five percent of total income taxes paid, ASU 2023-09 requires separate disclosure of that payment. Finally, ASU 2023-09 requires a public business entity to disclose income (or loss) from continuing operations before income tax expense (or benefit), disaggregated between domestic and foreign jurisdictions, and to disclose income tax expense (or benefit) from continuing operations, disaggregated between federal, state, and foreign jurisdictions. ASU 2023-09 removes the requirement to disclose the nature and estimate of the range of reasonably possible increases or decreases in the unrecognized tax benefits balance in the next 12 months, or to make a statement that an estimate of the range cannot be made. ASU 2023-09 is effective for the Company for calendar years beginning after December 15, 2025. Early adoption is permitted. The Company is required to

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apply ASU 2023-09 to its income tax disclosures in its consolidated financial statements for the year ending December 31, 2026. The Company has evaluated the impact of adoption of ASU 2023-09 and does not expect any material impacts on its consolidated financial statements.

In November 2024, the FASB issued ASU 2024-03, Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses (“ASU 2024-03”), which requires new tabular disclosures in the notes to consolidated financial statements, disaggregating certain cost and expense categories within relevant captions on the consolidated statements of operations. The prescribed cost and expense categories requiring disaggregated disclosures include purchases of inventory, employee compensation, depreciation, and intangible asset amortization, along with certain other expense disclosures already required by US GAAP that would need to be integrated within the new tabular disaggregated expense disclosures. Additionally, the amendments also require the disclosure of total selling expenses and an entity’s definition of those expenses. The amendments in ASU 2024-03 are effective for annual periods beginning after December 15, 2026 and for interim periods beginning after December 15, 2027. Early adoption is permitted, and the amendments should be applied on a prospective basis, although retrospective application is permitted. The Company is evaluating the impact of adopting ASU 2024-03 on its expense disclosures.

NOTE 3 — Investments

The Company is currently invested in available-for-sale securities. The following tables present the Company’s available-for-sale investments included in the condensed consolidated balance sheets:

$ in thousands						September 30, 2026
Current assets						Amortized Cost												Unrealized Gain						Unrealized Loss						Fair Value
U.S. treasuries						$	39,887											$	2					$	(31)					$	39,858
Total						$	39,887											$	2					$	(31)					$	39,858

$ in thousands						December 31, 2025
Current assets						Amortized Cost						Unrealized Gain						Unrealized Loss						Fair Value
Corporate bonds						$	32,195					$	57					$	—					$	32,252
Commercial paper						23,423						—						—						23,423
U.S. treasuries						82,618						169						—						82,787
Total						$	138,236					$	226					$	—					$	138,462
Long-term assets						Amortized Cost						Unrealized Gain						Unrealized Loss						Fair Value
Corporate bonds						$	25,724					137						—						$	25,861
U.S. treasuries						12,311						$	70					—						12,381
Total						$	38,035					$	207					$	—					$	38,242

The cost of securities sold, if any, is based on the specific-identification method. During the three and nine months ended September 30, 2026, the Company sold $29.8 million of available-for-sale securities and recognized a nominal amount of realized losses related to the sale. The realized losses are included in other income (expense) on the condensed consolidated statements of operations and comprehensive loss. During the three and nine months ended September 30, 2025, there were no securities sold.

There were no credit losses recognized during the three and nine months ended September 30, 2026 and 2025. The Company had no allowances for credit losses as of September 30, 2026 and December 31, 2025.

NOTE 4 — Fair Value Measurements

The following table presents the assets and liabilities that the Company measures at fair value on a recurring basis included in the condensed consolidated balance sheets and indicates the level of the valuation inputs the

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Company utilized to determine the fair value:

												September 30,						December 31,
$ in thousands						Level						2026						2025
Assets
Available-for-sale investments						1						$	39,858					$	176,704
Total assets												$	39,858					$	176,704
Liabilities
Public Warrants						1						$	1,810					$	4,310
Private Placement Warrants						3						2,398						6,540
Total liabilities												$	4,208					$	10,850

The following table contains a reconciliation of the beginning and ending balances of recurring Level 3 fair value measurements included in the condensed consolidated statements of operations and comprehensive loss:

						Three Months Ended September 30,												Nine Months Ended September 30,
$ in thousands						2026						2025						2026						2025
Balance of recurring Level 3 liabilities at the beginning of the period						$	3,270					$	4,817					$	6,540					$	52,207
Change in Earnout Shares liability						—						34						—						(1,903)
Change in Private Placement Warrant liability						(872)						5,668						(4,142)						(39,785)
Balance of recurring Level 3 liabilities at the end of the period						$	2,398					$	10,519					$	2,398					$	10,519

Available-for-sale Securities

The fair value of the available-for-sale investments is classified as a Level 1 fair value measurement, because the investments are valued using the most recent quoted prices for identical assets in active markets.

Warrants

The Public Warrants are exercisable for 8,620,535 shares of Class A Common Stock at a price of $11.50 per share. The Company may redeem the Public Warrants for $0.01 if the last reported trading price of the Company’s Class A Common Stock equals or exceeds $18.00 per share for any 20 trading days within a 30-trading-day period. Additionally, the Public Warrants may be redeemed if the last reported trading price of the Company’s Class A Common Stock equals or exceeds $10.00 and is below $18.00 by paying a make-whole premium. The Public Warrants expire June 8, 2028. The Public Warrants are valued using their quoted and publicly available market prices. Since their fair value is predicated on quoted prices in an active market for identical instruments, the fair value of the Public Warrants is considered a Level 1 fair value measurement.

The Private Placement Warrants are exercisable for 10,900,000 shares of Class A Common Stock at a price of $11.50 per share. The Private Placement Warrants expire on June 8, 2028. The Private Placement Warrants are exercisable on a cashless basis and are non-redeemable as long as they are held by the initial purchasers or their permitted transferees. The Private Placement Warrants and Class A Common Stock issuable upon exercise of the Private Placement Warrants are entitled to registration rights.

The Company uses a Black-Scholes-Merton Model to value the Private Placement Warrants. Key inputs into the Black-Scholes-Merton Model include the last Class A Common Stock closing price of $1.49 as of September 30, 2026 and the strike price of $11.50 per share. The volatility assumption is based on the

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Company’s own historical volatility and the implied volatility of the Public Warrants. For the valuation as of December 31, 2025, the volatility assumption was based on a blended average of equity volatility of publicly traded companies within the Company’s peer group, the Company’s own historical volatility, and the implied volatility of the Public Warrants. The fair value of the Private Placement Warrants is considered a Level 3 fair value measurement.

The following table contains the key inputs used in the valuations of the Private Placement Warrants:

						September 30, 2026						December 31, 2025
Term (in years)						1.69						2.44
Volatility						115.0		%				104.0		%
Risk-free rate						4.7		%				3.5		%

NOTE 5 — Goodwill and Intangible Assets

Goodwill

Goodwill represented the future economic benefits derived from the Company’s unique market position, the growth attributable to the Oxy-Combustion Cycle technology, and the Company’s assembled workforce, none of which are individually and separately recognized as intangible assets. Goodwill was allocated to the Company’s sole reportable segment and reporting unit.

As of September 30, 2026 and December 31, 2025, the Company had no goodwill. In March 2025, the Company assessed its goodwill for impairment. Due to a change in the Company’s business plans in the first quarter of 2025 and the related sustained decrease in the Company’s market capitalization, the Company concluded that it was more likely than not that the fair value of its goodwill was less than its carrying amount as of March 31, 2025. As a result, the Company fully impaired its goodwill and recognized an impairment of $359.8 million during the nine months ended September 30, 2025, included in impairment and other charges on the condensed consolidated statements of operations and comprehensive loss.

Definite-Lived Intangible Assets

The following table summarizes the Company’s definite-lived intangible assets included in the condensed consolidated balance sheets:

						September 30,																		December 31,
						2026																		2025
$ in thousands						Gross Amount						Accumulated Amortization						Net Amount						Gross Amount						Accumulated Amortization						Net Amount
Software						$	550					$	(111)					$	439					$	613					$	(37)					576
Developed technology						—						—						—						184,465						(3,469)						180,996
Total definite-lived intangible assets						$	550					$	(111)					$	439					$	185,078					$	(3,506)					$	181,572

The following table presents the Company’s amortization expense for the following periods:

						Three Months Ended September 30,												Nine Months Ended September 30,
$ in thousands						2026						2025						2026						2025
Amortization expense						$	37					$	12,122					$	5,272					$	45,943

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The Company does not own or control any intangible assets with indefinite useful lives. The following table presents estimated amortization expense for the next five years and thereafter (in thousands):

Remaining 2026						$	43
2027						172
2028						172
2029						51
2030						1
Total						$	439

The Company regularly evaluates whether events or changes in circumstances warrant a revision to the remaining estimated useful lives of its long-lived assets.

During the second quarter of 2026, the Company identified indicators of impairment for its definite-lived intangible assets, the La Porte Demonstration Facility, and certain other assets (the “Developed Technology Asset Group”).

During the first half of 2026, the Company and Baker Hughes agreed to temporarily suspend development activities under the BHES JDA (as discussed in Note 12 — Related Party Transactions) while Baker Hughes evaluated the development and commercialization of the industrial-scale Oxy-Combustion Cycle technology. During the suspension period, the Company and Baker Hughes engaged in negotiations related to the future development and commercialization of the industrial-scale Oxy-Combustion Cycle technology. As of June 30, 2026, the terms of the indefinite suspension of the BHES JDA were substantially negotiated, giving rise to the impairment and other effects described in Note 6 — Property, Plant, and Equipment, Note 12 — Related Party Transactions, and Note 14 — Commitments and Contingencies.

The Company determined that triggering events had occurred requiring an impairment assessment of its Developed Technology Asset Group as a result of (i) the Company’s determination during the second quarter of 2026 that development of the Oxy-Combustion Cycle under the BHES JDA would not resume, and (ii) the fact that the Company had no current plans as of June 30, 2026, and has no current plans, to continue development of the Oxy-Combustion Cycle technology. Accordingly, any recovery of the carrying value would be contingent upon a sale, license or other disposition of all or part of the Oxy-Combustion Cycle intellectual property and the Company’s improvements, equipment and lease interests at the La Porte Demonstration Facility. There can be no assurance that any transaction will be agreed or consummated, or as to its terms or timing.

Management determined that no value should be ascribed to the Developed Technology Asset Group based on the following factors: (i) the indefinite suspension of further development of the Oxy-Combustion Cycle technology under the BHES JDA, (ii) there are no current plans to resume development of the Company’s Oxy-Combustion Cycle technology, and (iii) uncertainty as to whether any disposal transaction to sell all or part of the Developed Technology Asset Group will be consummated. Accordingly, the Company recognized a full impairment of the Developed Technology Asset Group of $193.7 million during the second quarter of 2026. During the three months ended September 30, 2026, the Company recognized additional impairment losses of $0.8 million related to construction-in-progress expenditures related to the La Porte Demonstration Facility. The factors leading to the full impairment during the second quarter of 2026 remained throughout the third quarter of 2026. The impairment loss is included in impairment and other charges on the condensed consolidated statements of operations and comprehensive loss.

As discussed in Note 12 — Related Party Transactions, on September 8, 2026, the Company and affiliates of Baker Hughes entered into definitive agreements to, among other things, indefinitely suspend development and commercialization of the utility-scale Oxy-Combustion Cycle technology and amend the related license agreement.

During the three and nine months ended September 30, 2025, the Company recognized an impairment loss of $1,095.8 million related to the Developed Technology Asset Group, which is included in impairment and other

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charges on the condensed consolidated statements of operations and comprehensive loss. In late August 2025, the Company completed a techno-economic analysis that identified slower than anticipated acceptance and deployment of the Oxy-Combustion Cycle technology. Based on that analysis, feedback from potential customers, and the estimated cost reductions achieved through a value engineering process for the first utility-scale plant incorporating the Oxy-Combustion Cycle technology (“SN1”), the Company revised its long-range forecasts of future unit deployments and related cash flows and determined that a triggering event had occurred requiring an impairment assessment of the Developed Technology Asset Group. The Company determined that the carrying value of the asset group was not recoverable and estimated its fair value at $200.0 million using the income and market approaches, both of which used Level 3 inputs. The income approach used a probability-weighted discounted cash flow method based on management’s projections of future revenues and operating expenses from future deployments of the Oxy-Combustion Cycle technology. The market approach used an implied value approach, applying a control premium to the Company’s market capitalization, less working capital, investments in securities, and other assets not part of the Developed Technology Asset Group. See Note 5 to the consolidated financial statements included in the Company’s 2025 Annual Report for additional information.

The following table details the total amount of long-lived asset impairment losses recognized for the Developed Technology Asset Group:

						Three Months Ended September 30,												Nine Months Ended September 30,
$ in thousands						2026						2025						2026						2025
Intangible assets, net						$	—					$	1,012,344					$	176,110					$	1,012,344
Property, plant, and equipment, net						813						80,201						18,203						80,201
Operating lease right-of-use assets						—						3,294						207						3,294
Total						$	813					$	1,095,839					$	194,520					$	1,095,839

NOTE 6 — Property, Plant, and Equipment

Power Generation Equipment Contractual Rights Acquisition

On August 31, 2026, the Company acquired, under an Assignment and Assumption Agreement (the “Assignment Agreement”) with EMPower USA, LLC (“EMPower”), EMPower’s position as owner under the EPC Agreement with Saulsbury Industries, Inc. (“Saulsbury”) for an approximately 123-megawatt reciprocating engine natural gas power generation facility, together with specified related rights and benefits under Saulsbury’s equipment supply agreement with Wärtsilä North America, Inc. (“Wärtsilä”) for ten engine-generator sets (the “EEQ Agreement”). The aggregate acquisition cost of approximately $117.6 million consisted of (i) approximately $59.0 million paid to EMPower, comprising a $40.0 million premium, $20.0 million of which was paid as deposits under a deposit and exclusivity agreement entered into on August 13, 2026, and approximately $18.9 million in reimbursement of amounts EMPower previously paid under the EPC Agreement, and (ii) a milestone payment of approximately $58.6 million to Saulsbury for equipment supplied under the EEQ Agreement, which was due and paid at closing under the EPC Agreement. The assignment transferred contractual rights and did not transfer title to the engine-generator sets. Title passes under the applicable contractual delivery and payment provisions. Amounts funded before title passes are supported by a contractual security interest in the equipment and identifiable proceeds, subject to the applicable lender arrangements.

Saulsbury consented to the assignment and to the relocation of the project from its original site to a replacement site at Project Permian, and the Company and Saulsbury agreed to negotiate a change order documenting the relocation, the resumption and sequencing of the work and a revised project schedule (the “Post-closing Change Order”). The Company now intends to relocate the project instead to the site of the Initial Project described in Note 1 — Nature of Business and Basis of Presentation, which the Post-closing Change Order would document. Wärtsilä acknowledged the owner substitution and consented to a subsequent assignment of the EEQ Agreement to the Company; Saulsbury remained the buyer under that agreement. Wärtsilä reserved its position

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on the relocation. Work under the EPC Agreement has been suspended since July 1, 2026. Resumption of the full scope of work requires a full notice to proceed from the Company, payment of the approximately $10.2 million mobilization payment and any other amounts then due, and satisfaction of other conditions, including Saulsbury’s and Wärtsilä’s review of the project financing. The Company is not obligated to issue the full notice to proceed. The Post-closing Change Order was not executed within 30 days after closing and, as of the date of this Report, has not been executed, and the Company is negotiating with Saulsbury a limited notice to proceed that would authorize specified engineering and procurement activities before the full notice to proceed. Because the Post-closing Change Order was not executed within 30 days after closing, the Company had the right, exercisable by notice during the following ten days, to elect either to continue the work pending execution of the change order or to terminate the EPC Agreement. The Company did not elect to terminate the EPC Agreement, which remains in effect pending execution of the Post-closing Change Order. In October 2026, the date by which the Company may issue the full notice to proceed under the EPC Agreement was extended to March 31, 2027. If the Company does not issue the full notice to proceed by that date, either party may terminate the EPC Agreement, whereupon Saulsbury would be entitled to a termination payment of $3.5 million, which may become payable earlier if the applicable execution and payment conditions are not satisfied, as described in Note 14 — Commitments and Contingencies. Upon termination, the Company may take assignment of the EEQ Agreement, subject to specified conditions, by assuming the remaining payment obligations under it, which totaled approximately $23.3 million as of September 30, 2026. Until the Company delivers a full or limited notice to proceed, it bears specified suspension, standby, preservation, and storage charges, subject to negotiated caps.

The transaction does not qualify as a business combination under ASC Topic 805, Business Combinations (“ASC 805”) and has therefore been accounted for as an asset acquisition. The Company concluded that the acquired contractual rights and equipment-related expenditures constitute a single construction asset as the contractual rights relate specifically to, and are expected to be realized through, the acquisition of identified power generation equipment. Accordingly, the Company recognized the acquisition cost in construction-in-progress.

The following table summarizes the key classifications of property, plant, and equipment included in the condensed consolidated balance sheets:

						September 30,						December 31,
$ in thousands						2026						2025
Furniture and equipment						$	94					$	132
La Porte Demonstration Facility						—						13,484
Assets acquired under finance lease						—						45
Construction-in-progress						140,903						20,062
Total property, plant, and equipment, gross						140,997						33,723
Accumulated depreciation and amortization						(31)						(965)
Total property, plant, and equipment, net						$	140,966					$	32,758

As of September 30, 2026, construction-in-progress consisted of $117.6 million related to the contractual rights and equipment-related payments acquired under the Assignment Agreement discussed above and $23.3 million related to deposits on natural gas turbine equipment packages for use in a future natural gas power generation project.

Of the impairment recognized in 2026 and 2025, $18.2 million and $80.2 million, respectively, were allocated to property, plant, and equipment of the Developed Technology Asset Group. Refer to Note 5 — Goodwill and Intangible Assets for discussion of the impairment of the Developed Technology Asset Group recognized during 2026.

During the first quarter of 2025, as a result of management’s assessment of the probability of the construction of the first utility-scale plant incorporating the Oxy-Combustion Cycle technology, or SN1, $56.1 million of costs

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previously included in construction-in-progress were expensed. This amount is included in impairment and other charges in the condensed consolidated statements of operations and comprehensive loss for the nine months ended September 30, 2025.

The following table presents the Company’s depreciation and amortization expense for the following periods:

						Three Months Ended September 30,												Nine Months Ended September 30,
$ in thousands						2026						2025						2026						2025
Depreciation and amortization expense						$	6					$	3,374					$	1,459					$	12,747

The Company regularly evaluates whether events or changes in circumstances warrant a revision to the remaining estimated useful lives of its long-lived assets.

NOTE 7 — Accrued Liabilities

Accrued liabilities in the condensed consolidated balance sheets consist of the following:

						September 30,						December 31,
$ in thousands						2026						2025
Professional fees						$	2,496					$	1,617
Incentive compensation						1,950						3,347
Capital expenditures						86						410
Franchise tax						54						546
Accrued project expenses						1,250						460
Other accrued liabilities						2,130						1,185
Total accrued liabilities						$	7,966					$	7,565

NOTE 8 — Redeemable Non-Controlling Interests in Subsidiary

The following table presents the Company’s and non-controlling interest holders’ (“NCI”) ownership percentages in OpCo as of the following dates:

									September 30,						December 31,
									2026						2025
Non-controlling interest holders									60.6		%				62.2		%
NET Power Inc.									39.4		%				37.8		%

The Company measures redeemable NCI each quarter at the higher of its book value or its redemption value. As of September 30, 2026, the Company measured redeemable NCI at redemption value. As of December 31, 2025, the Company measured redeemable NCI at book value. The adjustment to record redeemable NCI at book or redemption value is recorded through additional paid-in capital on the condensed consolidated statements of shareholders’ equity and mezzanine shareholders’ equity.

OpCo’s net loss before income tax was attributed to redeemable NCI holders at 60.6% and 61.0% for the three and nine months ended September 30, 2026. OpCo’s net loss before income tax was attributed to redeemable NCI holders at 64.5% and 64.5% for the three and nine months ended September 30, 2025.

NOTE 9 — Share-Based Compensation

The 2023 Omnibus Incentive Plan reserved 20,468,545 shares of Class A Common Stock for issuance as equity awards. The quantity of shares of Class A Common Stock reserved for grants under the 2023 Omnibus Incentive Plan will be subject to an annual increase on the first day of each calendar year beginning January 1, 2024, and ending and including January 1, 2033, equal to the lesser of (i) 5% of the aggregate number of shares

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outstanding on December 31 of the immediately preceding calendar year and (ii) any such smaller number of shares as is determined by the Board.

The following table presents the aggregate share-based compensation expense, net of forfeitures, for the following periods:

						Three Months Ended September 30,												Nine Months Ended September 30,
$ in thousands						2026						2025						2026						2025
Share-based compensation expense						$	1,662					$	11,656					$	12,479					$	35,759

During 2026, in connection with employee terminations, the Company modified certain unvested restricted stock units and unvested stock options to accelerate vesting of awards that would otherwise have been forfeited upon separation (refer to Note 13 — One-time Employee Termination Costs). The Company determined the acceleration of the unvested awards constituted a Type III modification, as defined in ASC Topic 718, Compensation-Stock Compensation (“ASC 718”), as the expectation of the awards’ vesting changed from improbable to probable, resulting in a new measurement of compensation expense. During the nine months ended September 30, 2026, the Company recognized additional share-based compensation expense of $1.4 million related to the accelerated vesting of awards as a result of employee terminations.

Restricted Stock Units

As of September 30, 2026, there was $4.7 million of unrecognized share-based compensation expense related to unvested restricted stock units (“RSUs”), which the Company expects to recognize over a weighted-average period of 2.1 years.

The following table presents a summary of RSU activity during the nine months ended September 30, 2026:

In thousands, except per share data						Quantity						Weighted-Average Grant Date Fair Value Per Share
Unvested, beginning of period						3,476						$	7.35
Granted						2,784						1.61
Vested						(910)						6.39
Forfeited						(379)						2.47
Unvested, end of period						4,971						$	4.67

Performance Stock Units

As of September 30, 2026, there was $1.1 million of unrecognized share-based compensation expense related to unvested performance stock units (“PSUs”), which the Company expects to be recognized over a weighted-average period of 2.4 years.

The following table presents a summary of PSU activity as of September 30, 2026 and the changes during the nine months ended September 30, 2026:

In thousands, except per share data						Quantity						Weighted-Average Grant Date Fair Value Per Share
Unvested, beginning of period						322						$	6.00
Granted						426						2.44
Forfeited						(96)						4.58
Unvested, end of period						652						$	3.88

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A portion of payments for services under the BHES JDA is settled in equity; refer to Note 12 — Related Party Transactions for additional information.

NOTE 10 — Loss per Share

Basic loss per share attributable to shareholders is calculated by dividing net loss attributable to shareholders by the weighted-average number of shares outstanding during the period. Diluted loss per share attributable to shareholders includes the effect of potentially dilutive common shares outstanding.

The following table sets forth the computation of the Company’s basic and diluted loss per share for the following periods:

						Three Months Ended September 30,												Nine Months Ended September 30,
In thousands, except per share data						2026						2025						2026						2025
Numerator
Net loss after income tax						$	(16,611)					$	(1,159,806)					$	(249,353)					$	(1,615,439)
Net loss attributable to NET Power Inc.						$	(6,464)					$	(411,498)					$	(96,612)					$	(558,990)
Denominator
Weighted-average number of shares outstanding, basic and diluted						88,572						77,883						87,459						77,530
Loss per share attributable to shareholders, basic and diluted						$	(0.07)					$	(5.28)					$	(1.10)					$	(7.21)

Only shares of Class A Common Stock participate in the Company’s undistributed earnings. As such, the Company’s undistributed earnings are allocated entirely to the Class A Common Stock based on the weighted-average number of shares of Class A Common Stock outstanding for the three and nine months ended September 30, 2026 and 2025.

Based on the amounts outstanding at September 30, 2026 and 2025, the Company excluded the following financial instruments from the computation of diluted loss per share because their inclusion would be anti-dilutive:

In thousands																		September 30,
Anti-Dilutive Instruments																		2026						2025
Public Warrants																		8,621						8,621
Private Placement Warrants																		10,900						10,900
Vested Class A OpCo Units																		136,485						143,930
Unvested RSUs																		3,714						2,219
Unvested PSUs																		652						322
Make-Whole Awards																		1,257						1,257
Stock Options																		6,490						6,482
BHES Bonus Shares																		—						2,068
Earnout Shares																		—						329
Total																		168,119						176,128

    

NOTE 11 — Income Taxes

The Company recognized no income tax expense or benefit for the three months ended September 30, 2026 and income tax expense of less than $0.1 million for the nine months ended September 30, 2026, resulting in an effective tax rate (“ETR”) of 0%, compared to deferred income tax benefits of $1.2 million and $2.4 million based on an estimated annual ETR of 1.9% for the three and nine months ended September 30, 2025.

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The 0% ETR for the current quarter reflects the fact that the portion of the Company’s loss attributable to non-controlling interest is taxable to those partners and not the Company, as well as the valuation allowance established by the Company on the remainder of the loss. A full valuation allowance has been established against deferred tax assets, as the Company has determined it is more likely than not that such assets will not be realized. Accordingly, no tax benefit has been recognized on current-period losses.

The decrease in the ETR compared to the prior year period reflects the reversal during 2025 of the Company’s net deferred tax liability at December 31, 2024. Impairments recognized during 2025 reduced the book basis of the Company’s investment in OpCo below its tax basis and moved the Company into a net deferred tax asset position, against which it has recorded a full valuation allowance.

Tax Receivable Agreement

In March 2025, due to the Company’s decision to pause new purchase commitments for SN1’s long-lead equipment and commencement of a value engineering exercise to determine project cost reductions and better understand SN1’s expected economic feasibility, the Company determined it was not more likely than not that its deferred tax assets subject to the Tax Receivable Agreement (“TRA”) would be realized and therefore reduced the TRA liability to zero as payments under the TRA were not considered probable. Accordingly, in March 2025, the Company recognized a $21.3 million reduction in the Tax Receivable Agreement liability, which is recorded in Change in Tax Receivable Agreement liability in the condensed consolidated statements of operations for the nine months ended September 30, 2025.

On May 12, 2025, pursuant to its rights under the TRA, the Company delivered to the agent of the TRA holders notice of the Company’s intent to terminate the TRA (the “Early Termination Notice”). No early termination payment was payable to any TRA holder. The Early Termination Notice became final and binding on June 12, 2025.

NOTE 12 — Related Party Transactions

The following table summarizes the related party transactions included in the condensed consolidated statements of operations and comprehensive loss:

						Three Months Ended September 30,												Nine Months Ended September 30,
$ in thousands						2026						2025						2026						2025
Master services agreement administrative costs						$	39					$	21					$	100					$	90
General and administrative						$	39					$	21					$	100					$	90
Master services agreement costs for the La Porte Demonstration Facility						$	321					$	457					$	880					$	1,711
BHES JDA						4,257						17,307						17,174						55,312
Research and development						$	4,578					$	17,764					$	18,054					$	57,023
BHES Limited Notice to Proceed						—						—						$	—					$	19,533
Project development						$	—					$	—					$	—					$	19,533

The Company had $10.6 million and $37.3 million in current liabilities payable to related parties as of September 30, 2026 and December 31, 2025, respectively, on the condensed consolidated balance sheets related

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to the following services. These related party payables are unsecured and are due on demand.

Master Services Agreements

A significant shareholder provides the Company with patent administration services related to the development of the Oxy-Combustion Cycle technology. Costs incurred under this agreement are included in general and administrative on the condensed consolidated statements of operations and comprehensive loss.

Another shareholder supports the Company with regard to general business oversight and with the operation of the La Porte Demonstration Facility. On June 30, 2026, this shareholder notified the Company that it is terminating all outstanding work orders under the related master services agreement, effective December 26, 2026. Costs incurred under this agreement are reflected in research and development on the condensed consolidated statements of operations and comprehensive loss.

BHES JDA

On February 3, 2022, the Company and BHES entered into the Original JDA, which was subsequently amended and restated on June 30, 2022, and December 13, 2022 with BHES to invest in, develop, and deploy the Oxy-Combustion Cycle technology in collaboration with the Company (as amended and restated, the “BHES JDA”). The BHES JDA is settled in cash and issuances of equity in exchange for services related to the development and commercialization of the Oxy-Combustion Cycle technology. The Company recorded the expense for services provided by BHES within research and development on the condensed consolidated statements of operations and comprehensive loss.

By a letter agreement dated January 22, 2026, the Company agreed to temporarily suspend development activities under the BHES JDA, which covered joint development of turboexpander equipment for utility-scale application of the Oxy-Combustion Cycle, from the December 31, 2025 effective date through March 31, 2026 (the “BHES JDA Suspension Letter”), which was subsequently extended through June 30, 2026 pursuant to the BHES JDA Variation Agreement No. 1, dated March 31, 2026, and BHES JDA Variation Agreement No. 2, dated June 4, 2026. The Company is obligated to reimburse BHES for costs incurred to terminate certain third-party supplier and subcontractor purchase orders and, subject to a $3.0 million cap, for certain other costs resulting or arising from the suspension.

During the first quarter of 2026, the Company incurred $9.6 million related to reimbursement of costs incurred by BHES to terminate certain third-party supplier and subcontractor purchase orders entered into by BHES in furtherance of the BHES JDA scope. During the three months ended September 30, 2026, the Company incurred an additional $3.4 million, bringing the total incurred to $13.0 million for the nine months ended September 30, 2026. The additional amount consists of $2.2 million of the other suspension costs, which are subject to the $3.0 million cap, and a $1.2 million increase in BHES’s estimate of the purchase order termination costs, which are not subject to the cap. These amounts are based on preliminary estimates provided by BHES and may change when BHES issues its invoices. As of September 30, 2026, the amounts due to BHES related to these reimbursements remained outstanding and are expected to be settled in the fourth quarter of 2026. Of this amount, $7.6 million will be settled in cash and is included in current liabilities payable to related parties, and $5.4 million will be settled with issuance of equity as discussed below.

On September 8, 2026, the Company entered into agreements with affiliates of Baker Hughes that suspend indefinitely, but do not terminate, the BHES JDA retroactive to January 1, 2026, and the related commercial agreement, and that amend the related license agreement. The suspension of the BHES JDA will end only if the parties agree in writing to reinstate or terminate it. Under these agreements, Baker Hughes’ rights of access to, and exclusivity over, the La Porte Demonstration Facility ended, and each party released the other parties and their affiliates from claims arising before September 8, 2026, other than specified excluded matters, including the Company’s payment and wind-down obligations under the BHES JDA Suspension Letter and the limited notice to proceed for long-lead equipment dated December 28, 2023 (the “BHES LNTP”), and amounts accrued or invoiced but unpaid. These agreements formalized the indefinite suspension of the BHES JDA that was substantially negotiated as of June 30, 2026, which gave rise to the impairment and other effects described in

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Note 5 — Goodwill and Intangible Assets, Note 6 — Property, Plant, and Equipment, and Note 14 — Commitments and Contingencies.

Under the amended license agreement, Baker Hughes holds a perpetual, irrevocable, royalty-free license, exclusive subject to rights retained by the Company, to manufacture and sell industrial-scale products incorporating the Oxy-Combustion Cycle technology, and a license to install and operate industrial plants incorporating those products, for which a royalty is payable to the Company. The royalty must be commercially reasonable and agreed in writing, under a commercial model that supports the customer’s value proposition, allows a competitive cost of electricity and provides commercially reasonable compensation to the Company. If the parties do not agree within 180 days after either party proposes terms for a plant, either party may refer the determination to an independent expert, whose determination, applying those standards, is binding absent manifest error. Baker Hughes may continue to exercise the license pending the determination, and the royalty applies from the first commercial operation of the plant. No royalty amount has been agreed, no royalty is assured, and Baker Hughes is not obligated to deploy any plant. Baker Hughes’ exclusive license to manufacture and sell utility-scale equipment packages remains in effect, and the provision under which that exclusivity could be lost is suspended. The Company retains ownership of the licensed intellectual property.

The portion of BHES JDA costs that the Company paid with Class A OpCo Units and shares of Class B Common Stock was recorded within additional paid-in capital on the condensed consolidated balance sheets and the condensed consolidated statements of shareholders’ equity and mezzanine shareholders’ equity. The following table displays the expense recognized in the condensed consolidated statements of operations and comprehensive loss for shares distributed as payment for services rendered under the terms of the BHES JDA during the periods described below:

						Quantity												Expense Recognized
						Three Months Ended September 30,												Three Months Ended September 30,
in thousands						2026						2025						2026						2025
Class A OpCo Units						108						1,357						$	710					$	8,971
Class B Common Stock						108						1,357						—						—
Total																		$	710					$	8,971

																		Quantity												Expense Recognized
																		Nine Months Ended September 30,												Nine Months Ended September 30,
in thousands																														2026						2025						2026						2025
Class A OpCo Units																														1,017						4,166						$	6,721					$	27,541
Class B Common Stock																														1,017						4,166						—						—
Total																																										$	6,721					$	27,541

Shares issued as payment under the terms of the BHES JDA were issued at a discount that resulted in inception-to-date losses to the Company of $16.3 million. Following the suspension arrangements, the Company does not expect to make additional equity issuances under the BHES JDA other than in respect of final billings and other surviving obligations under those arrangements. For the three and nine months ended September 30, 2026, the Company incurred losses of $0.1 million and $1.3 million, respectively.

If the volume-weighted average price of the Company’s stock for ten consecutive trading days (“10-Day VWAP”) immediately preceding the payment date for services under the BHES JDA is less than $4.00 per share (the “Floor Price”), an incremental cash payment is required for the difference between the 10-Day VWAP and the Floor Price (the “BHES JDA Make-Whole Payment”). As of September 30, 2026 and December 31, 2025, the Company had $2.9 million and $2.8 million in current liabilities payable to related parties on the condensed consolidated balance sheets related to the BHES JDA Make-Whole Payment. During the three and nine months ended September 30, 2026, the Company incurred expenses of $0.8 million and $2.9 million, respectively, related to the BHES JDA Make-Whole Payment. During the three and nine months

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ended September 30, 2025, the Company incurred expenses of $1.0 million and $4.9 million, respectively, related to the BHES JDA Make-Whole Payment.

NOTE 13 — One-time Employee Termination Costs

During the three and nine months ended September 30, 2026, the Company recognized $0.4 million and $5.2 million of employee termination costs related to workforce reductions, the nine-month amount consisting of $3.8 million of severance costs and $1.4 million of accelerated share-based compensation expense. For the three months ended September 30, 2026, these costs are included in general and administrative in the condensed consolidated statements of operations and comprehensive loss. For the nine months ended September 30, 2026, these costs are included in general and administrative, research and development, and sales and marketing expenses in the condensed consolidated statements of operations and comprehensive loss, totaling $3.5 million, $1.2 million, and $0.5 million, respectively.

In April 2025, the Company terminated certain members of its management team. As a result of these terminations, the Company recognized $3.1 million in severance costs and approximately $1.1 million of costs related to the accelerated vesting of stock-based compensation during the nine months ended September 30, 2025.

NOTE 14 — Commitments and Contingencies

Litigation

From time to time, the Company is party to certain legal actions and claims. Other than any ordinary routine litigation incidental to the business and except as described below, the Company is not currently a party to, nor is its property currently subject to, any material legal proceedings, and the Company is not aware of any such proceedings contemplated by governmental authorities.

On April 18, 2025, an alleged stockholder filed a putative class action complaint in the United States District Court for the Middle District of North Carolina against the Company, its Chief Executive Officer, its former Chief Financial Officer and its former President and Chief Operating Officer, on behalf of a putative class of persons and entities other than the defendants that acquired the Company’s securities between June 9, 2023 and March 7, 2025, asserting violations of Sections 10(b) and 20(a) of the Exchange Act and Rule 10b-5. On April 23, 2026, the Court appointed a lead plaintiff, who filed an amended complaint on June 22, 2026 (the “Amended Complaint”). The Amended Complaint alleges, among other things, that the defendants made materially false and misleading statements about the Company’s business, operations, and prospects, including the timing and costs of developing SN1, which the Company then referred to as Project Permian. The lead plaintiff seeks, among other things, class certification, unspecified compensatory damages, interest, and costs and expenses, including attorneys’ and expert fees. On August 6, 2026, the Company moved to dismiss the Amended Complaint, and briefing on the motion was completed on October 21, 2026. As of the date of this Report, the Court has not decided the motion. The Company intends to defend vigorously against the claims.

On May 29, 2025, an alleged stockholder filed a derivative suit on behalf of the Company in the same court against certain of the Company’s current and former officers and directors, with the Company named as a nominal defendant, asserting claims for breach of fiduciary duty, unjust enrichment, abuse of control, gross mismanagement, waste of corporate assets and violations of the federal securities laws (the “First Derivative Action”). On August 28, 2026, another alleged stockholder filed a second derivative suit in the same court against the same defendants, asserting similar claims. The claims in both derivative actions are predicated on the same allegedly false and misleading statements that are the subject of the Amended Complaint. The First Derivative Action has been stayed pending resolution of the Amended Complaint. On October 14, 2026, the parties to both derivative actions filed a motion to consolidate the cases and stay all proceedings in the consolidated action pending resolution of the Amended Complaint. As of the date of this Report, the Court has not decided the motion.

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These matters are at an early stage; the motion to dismiss is pending, discovery has not commenced, no class has been certified, the plaintiffs have not specified an amount of alleged damages, and the First Derivative Action is stayed. For these reasons, and given the inherent uncertainty of litigation, the Company is unable to estimate a reasonably possible loss or range of loss, if any, that it may incur to resolve or settle these matters.

EPC Agreement

In connection with the Assignment Agreement discussed in Note 6 — Property, Plant, and Equipment, the Company assumed the owner’s payment obligations under the EPC Agreement. As of September 30, 2026, remaining payments under the EPC Agreement totaled approximately $119.1 million, of which approximately $88.2 million would become payable during the 12 months following September 30, 2026 if the Company issues the full notice to proceed on its current schedule. The timing of the remaining payments depends on the achievement of specified milestones, and the amounts may change as a result of the Post-closing Change Order, including relocation costs, suspension and storage charges and price escalation.

On October 16, 2026, the Company and Saulsbury agreed, effective as of October 15, 2026 (the “Extension Agreement”), to extend to March 31, 2027 the date by which the Company may issue the full notice to proceed under the EPC Agreement and make the mobilization payment. On November 11, 2026, the Company and Saulsbury entered into an amendment to the Extension Agreement, which extended from November 15, 2026 to November 20, 2026 the date by which the Post-closing Change Order and a limited notice to proceed must be executed, and the payments required under the limited notice to proceed made, for the termination payment to remain deferred. In the amendment, Saulsbury confirmed that it had not demanded the $3.5 million contract termination payment, that the termination payment was not payable, and that it remained deferred under the Extension Agreement as amended. If the Post-closing Change Order and a limited notice to proceed are not both executed, or the payments required under the limited notice to proceed are not made, on or before November 20, 2026, for any reason, the Company must pay Saulsbury, within ten days after receiving its written demand and invoice, the termination payment. Otherwise, the termination payment is deferred until March 31, 2027 and becomes payable if the Company does not issue the full notice to proceed and make the mobilization payment by that date. As of the date of this Report, neither the Post-closing Change Order nor a limited notice to proceed has been executed, and their execution is subject to conditions that include the approval of the related expense items by the Company’s prospective customer under the Cost Reimbursement Agreement described below. If they are not executed, or the payments required under the limited notice to proceed are not made, on or before November 20, 2026, the termination payment would become payable. The Company currently expects to issue the full notice to proceed in connection with obtaining financing for the Initial Project.

Cost Reimbursement Agreement

In August 2026, the Company entered into a cost reimbursement agreement (the “Cost Reimbursement Agreement”) with a prospective customer, a leading developer of frontier artificial intelligence models, while the parties negotiate an energy services agreement for the Initial Project. If none has been executed by February 14, 2027, or if certain other events occur, the customer must reimburse the Company’s nonrefundable costs of approved expense items, up to approximately $180.0 million and subject to conditions, unless the Company elects to keep the related equipment. The Company has not recognized any receivable or any gain under the Cost Reimbursement Agreement.

Equipment Purchase Commitments

As of September 30, 2026, the Company has committed to purchase natural gas turbine equipment packages for use in a future natural gas power generation project. The gross commitments totaled $77.7 million, and as of September 30, 2026, there were $54.4 million remaining related to these commitments. These payments are due in installments aligned to contractual milestones through 2028. Of the remaining amounts due under the contract, approximately $38.9 million is due during the 12 months following September 30, 2026, and approximately $15.5 million is due thereafter through 2028. The Company expects to fund these amounts from existing liquidity and, if obtained, from equipment or project-level financing, none of which has been committed.

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Asset Retirement Obligation

Under the terms of the lease for the La Porte Demonstration Facility, the Company is required to remove the La Porte Demonstration Facility and restore the land to post-clearing grade level. During the second quarter of 2026, the Company revised its expected decommissioning timing for the La Porte Demonstration Facility from June 2030 to June 2027, based on management’s expectations regarding the Company’s continued ownership and use of the Oxy-Combustion Cycle technology and the La Porte Demonstration Facility, as described in Note 5 — Goodwill and Intangible Assets. As a result, the Company recognized an upward revision to the asset retirement obligation of $0.7 million.

The following table reconciles the beginning and ending balances of the asset retirement obligation as of the dates presented:

						September 30,						December 31,
$ in thousands						2026						2025
Asset retirement obligation, beginning of period						$	3,597					$	3,265
Revision of estimate						714						—
Accretion expense						286						332
Asset retirement obligation, end of period						$	4,597					$	3,597

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following management’s discussion and analysis (“MD&A”) provides information that management believes is relevant to an assessment and understanding of our condensed consolidated results of operations and financial condition and includes forward-looking statements that involve risks, uncertainties and assumptions, including those described in “Cautionary Note Regarding Forward-Looking Statements” included in the forepart of this Quarterly Report on Form 10-Q (our “Quarterly Report”), in Part II, Item 1A Risk Factors in this Quarterly Report, and in Part I, Item 1A Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2025 (our “Annual Report”), as filed with the SEC on March 9, 2026.

The following MD&A should be read in conjunction with our condensed consolidated financial statements and related notes included in Part I, Item 1 in this Quarterly Report and our audited consolidated financial statements and related notes included in our Annual Report.

Overview

We are an energy technology and project development company focused on the rapid deployment of natural gas power generation behind the meter to serve co-located data centers and other large-load customers. To meet growing demand for reliable power on accelerated timelines, we have repositioned our business from its historical focus on developing an oxy-combustion power generation system with integrated carbon capture. Under our current strategy, our projects are expected to generate revenue principally from the sale of electricity and related services under long-term energy services or power offtake agreements.

Our current projects do not include carbon capture, and our current business plan does not depend on carbon capture or related tax credits. Our Initial Project is not being designed to accommodate the later addition of carbon capture, a change from our earlier descriptions of equipment designed to accommodate it in later phases. We continue to evaluate carbon capture for later phases or projects where customer requirements, commercial arrangements and financing support it, but we have not committed capital or adopted a timetable for its deployment. See Part II, Item 1A “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements.”

If carbon capture is deployed at any later phase or project, captured CO₂ and associated environmental attributes could also generate revenue, but we have not entered into any agreement for the sale, transportation, or sequestration of CO₂, and there can be no assurance that we will do so on acceptable terms or at all.

We do not have any plans to resume development of the Oxy-Combustion Cycle. In September 2026, we entered into agreements with affiliates of Baker Hughes that indefinitely suspend the BHES JDA and the related commercial agreement and amend the related license agreement (see Note 12 to our condensed consolidated financial statements); we have adjusted our workforce in areas affected by these changes, and we have recognized a full impairment of the related developed technology assets (see Note 5 to our condensed consolidated financial statements).

Key Factors Affecting Our Prospects and Future Results

We believe that our performance and future success depend on a number of factors that present significant opportunities for us but also pose risks and challenges, including, but not limited to, those associated with: our ability to negotiate and enter into binding energy services or power offtake agreements at prices and on terms sufficient to support project financing and an FID; our ability to agree on the relocation of, and to resume work under, the EPC Agreement and to fund the related payments; the timing and outcome of permitting, including the pause in the issuance of permits for data center projects directed by the Governor of Texas on September 21, 2026, and the policies of the administration taking office in January 2027; our ability to obtain site rights for our projects; the decisions of our prospective customer and of the third-party developer of the site regarding the timing and location of the data center that our Initial Project would serve; and our access to the capital needed to finance the development of our projects. These and other factors are described in “Cautionary Note Regarding Forward-Looking Statements” and Part II, Item 1A “Risk Factors.”

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Commencing Commercial Operations

We are developing our initial natural gas power generation project to supply power behind the meter, without a connection to the ERCOT grid, to a co-located data center at a site in Texas that we have not yet secured and that is separate from our Project Permian site (the “Initial Project”). In August 2026, we acquired the owner’s position under the EPC Agreement with Saulsbury for ten reciprocating engine generating sets with aggregate nominal capacity of approximately 123 MW, and we intend to use those units in our Initial Project, subject to a change order relocating the work under the EPC Agreement that has not been executed. The configuration we are evaluating for the Initial Project would also require additional generating capacity that we have not secured. We are negotiating an energy services agreement for the Initial Project with a leading developer of frontier artificial intelligence models, the prospective customer that is party to the Cost Reimbursement Agreement, but neither party is obligated to enter into it. We have not obtained site rights, permits, or financing for the Initial Project, and we have not entered into a binding energy services or power offtake agreement for its output.

We previously described the approximately 123 MW reciprocating-engine facility, and the two gas turbine generator sets for which we have contracted, as intended for deployment in the first phase of Project Permian. We now intend to deploy the reciprocating engine equipment at the proposed site described above for our Initial Project, subject to obtaining the necessary site rights, contractual amendments, permits, customer commitments, and financing, and we have not determined the project at which the gas turbine generator sets will be used.

We continue to develop Project Permian in West Texas on a longer timeline than our Initial Project. We lease a portion of the Project Permian site from a subsidiary of Occidental Petroleum, which is a significant stockholder and a related party of the Company. Developing Project Permian beyond the capacity our existing leasehold supports would require additional land rights, which we have not obtained and which are the subject of ongoing negotiations. In addition, future phases may require interconnection to the ERCOT grid, which would be subject to the processes described in Part II, Item 1A. The configuration, carbon capture scope, and timing of any phase of Project Permian will depend on customer requirements, commercial arrangements, the availability of post-combustion carbon capture technology on acceptable terms, permits, equipment availability, and financing.

We have not made a final investment decision for any project. There can be no assurance that we will enter into a binding energy services or power offtake agreement, project-level financing agreement, or definitive site or land-use arrangement for our Initial Project or for any phase of Project Permian beyond our existing lease, that our projects will be developed in the configuration at the sites or on the timelines described, or that carbon capture will be deployed at any project. We do not expect to make an FID for any project during 2026 or before a binding energy services or power offtake arrangement is executed, and the timing of any FID and of the commencement of commercial operations remains uncertain. Any FID will depend on, among other things, execution of one or more binding energy services or power offtake arrangements at pricing and other terms supportive of the project’s economics, and on obtaining the necessary site rights, financing, equipment, permits and other approvals. To meet prospective customer requirements for first power, we have committed, and expect to continue to commit, capital to power generation equipment and engineering before executing a binding energy services or power offtake agreement and reaching FID, as described under “Commitments and Contractual Obligations” below.

Texas Regulatory Developments

On August 3, 2026, the Governor of Texas directed a verification and audit of data centers advancing through ERCOT’s interconnection process. On September 21, 2026, the Governor directed the Texas Commission on Environmental Quality (“TCEQ”) to pause the issuance of all permits related to data center projects until ERCOT completes its review. ERCOT has stated that it intends to publish its report on or before December 10, 2026, but no date has been set for the pause to end. The directive contemplates that TCEQ will then use information from the audits to review proposed permits, so the completion of ERCOT’s review will not by itself determine when permits for data centers will be issued. On October 19, 2026, TCEQ informed the Governor that it had paused the issuance of all permits related to the construction or development of infrastructure directly supporting data centers, that it was screening pending applications and had paused those subject to the directive,

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and that it was suspending, where possible, authorizations for data center activities claimed without an affirmatively issued permit. We expect the pause to apply to the air permits our Initial Project requires. On October 21, 2026, TCEQ announced that it had temporarily shut down its electronic permitting system to modify it to allow staff review before authorizations are issued. On November 9, 2026, TCEQ confirmed that electronic submissions were available for applications under its Construction, Multi-Sector and Concrete Production General Permits. Those applications require staff review to determine whether they relate to data centers and no longer receive automatic approval or provisional coverage. The restoration of electronic submissions does not lift the permitting pause for data center projects or establish when applications for our Initial Project will be processed or authorizations issued. On November 3, 2026, Texas voters elected a new Governor, who will take office in January 2027 and who called during the campaign for a moratorium on new data center approvals until the Texas legislature adopts statewide rules governing them and has reaffirmed that position since the election. The Texas legislature convenes in regular session in January 2027. Whether a moratorium or other restrictions will be adopted, and their scope and timing, are uncertain. We cannot predict when or whether TCEQ will resume issuing permits for data center projects, whether we will obtain the authorizations our Initial Project requires, or whether any authorization we obtain will be affected by later action. If these actions delay or prevent the permitting of our projects or commitments by prospective customers, our final investment decisions could be further delayed or may not occur, and the timing of our capital requirements and project-level financing would be affected. See Part II, Item 1A “Risk Factors.”

Key Components of Results of Operations

We are a pre-revenue company. Because our historical spending was primarily directed toward the Oxy-Combustion Cycle, the La Porte Demonstration Facility and SN1, none of which we are actively developing today, our historical results may not be indicative of future results. The impairment of the Developed Technology Asset Group, indefinite suspension of the BHES JDA, workforce reductions and changes in project development activities materially affect comparability between periods.

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Results of Operations

Comparison of the Three Months Ended September 30, 2026 to the Three Months Ended September 30, 2025

The following table sets forth our condensed consolidated results of operations data for the periods presented:

						Three Months Ended September 30,												$ Change						% Change
$ in thousands						2026						2025
Operating expenses
General and administrative						$	7,096					$	9,108					(2,012)						(22)		%
Sales and marketing						708						1,395						(687)						(49)		%
Research and development						9,187						24,543						(15,356)						(63)		%
Project development						2,622						10,032						(7,410)						(74)		%
Impairment and other charges						813						1,095,839						(1,095,026)						(100)		%
Depreciation, amortization, and accretion						151						15,580						(15,429)						(99)		%
Total operating expenses						20,577						1,156,497
Operating loss						(20,577)						(1,156,497)
Other income (expense)
Interest income, net						2,445						4,835						(2,390)						(49)		%
Change in Earnout Shares liability and Warrant liability						1,562						(9,323)						10,885						n/m
Other income (expense)						(41)						2						(43)						n/m
Net other income (expense)						3,966						(4,486)
Net loss before income tax						(16,611)						(1,160,983)
Income tax benefit						—						1,177						(1,177)						(100)		%
Net loss after income tax						(16,611)						(1,159,806)
Net loss attributable to non-controlling interests						(10,147)						(748,308)
Net loss attributable to NET Power Inc.						$	(6,464)					$	(411,498)

General and administrative

General and administrative expenses consist primarily of personnel-related expenses associated with our general and administrative organization and professional fees for legal, accounting, information technology, and other consulting services. General and administrative expenses decreased by $2.0 million, or 22%, for the three months ended September 30, 2026, as compared to the same period in 2025. This decrease was related to lower stock-based compensation expense primarily because certain awards became fully vested in the second quarter of 2026 and no longer generate expense, as well as lower overall compensation expense due to headcount reduction during the first quarter of 2026. In addition, there were lower professional fees primarily related to decreased engineering consulting, partially offset by increased legal and severance costs.

Sales and marketing

Sales and marketing expenses consist primarily of personnel-related and consultant costs directly associated with our sales and marketing activities, which include general publicity efforts for the Company. Sales and marketing expenses decreased by $0.7 million, or 49%, for the three months ended September 30, 2026, as compared to the same period in 2025. This decrease was primarily related to lower professional fees and compensation costs due to employee terminations during 2026.

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Research and development

Research and development (“R&D”) expenses in the current period primarily reflect engineering costs for post-combustion carbon capture, including the Gas Power Product, and for the Oxy-Combustion Cycle, which continued to be incurred for a period after our decision to suspend development of the Oxy-Combustion Cycle and to develop our Initial Project without carbon capture, whereas the prior-year period primarily reflected work on and testing of specific aspects of our technology at the La Porte Demonstration Facility. R&D expenses decreased by $15.4 million, or 63%, for the three months ended September 30, 2026, as compared to the same period in 2025. This decrease was primarily due to the Company suspending development activities under the BHES JDA in December 2025, resulting in a decrease of $13.1 million. Additionally, plant expenses were lower by $2.9 million due to the suspension of R&D at the La Porte Demonstration Facility in December 2025. This decrease was partially offset by $1.6 million that we accrued for costs Entropy has claimed under the reimbursement provision of our letter of intent with Entropy regarding post-combustion carbon capture technology, which survives the letter’s expiration in July 2026, and by higher engineering consulting costs of $0.3 million.

Project development

Project development expenses consist of labor expenses and fees paid to third parties developing commercial-scale projects. Project development expenses decreased by $7.4 million, or 74%, for the three months ended September 30, 2026, as compared to the same period in 2025. The decrease was due to the Company ceasing development work and related expenditures for SN1 during the fourth quarter of 2025. This decrease was partially offset by current-period expenses related to our natural gas power generation projects.

Impairment and other charges

During the third quarter of 2026, the Company recognized an impairment loss of $0.8 million related to additional construction-in-progress expenditures during the quarter related to the La Porte Demonstration Facility that is part of the Developed Technology Asset Group, which was fully impaired during the second quarter of 2026. The factors leading to the full impairment during the second quarter of 2026 remained throughout the third quarter of 2026.

During the third quarter of 2025, the Company recognized an impairment loss of $1,095.8 million related to its long-lived assets as a result of feedback from potential customers, the estimated cost reductions achieved through the SN1 value engineering process, which, although significant, did not reduce costs to an economic level, and the resulting revisions to the Company’s forecasted future unit deployments and related cash flows based upon the perceived marketability and commercial viability of the Company’s Oxy-Combustion Cycle technology.

Depreciation, amortization, and accretion

Depreciation, amortization, and accretion expenses consist primarily of accretion on the asset retirement obligation and amortization of capitalized software. In the prior-year period, they primarily consisted of depreciation on our La Porte Demonstration Facility and amortization of intangible assets. Depreciation, amortization, and accretion expense decreased by $15.4 million, or 99%, for the three months ended September 30, 2026, as compared to the same period in 2025, primarily due to the reduction in depreciable and amortizable carrying amounts following the third-quarter 2025 impairment and the full impairment of the Developed Technology Asset Group in the second quarter of 2026.

Interest income, net

Interest income decreased by $2.4 million, or 49%, for the three months ended September 30, 2026, as compared to the same period in 2025. Interest income decreased due to lower interest-bearing cash and investment balances, partially offset by higher investment accretion.

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Change in Earnout Shares liability and Warrant liability

The change in Earnout Shares liability and Warrant liability relates to movements in the fair value of earnout shares and warrants. The changes are primarily due to fluctuations in the market price of our Class A Common Stock and related volatility.

Income tax benefit

The Company recognized no income tax expense or benefit for the three months ended September 30, 2026, compared to an income tax benefit of $1.2 million for the same period in 2025. During 2025, the Company moved out of a deferred tax liability and into an overall deferred tax asset position as impairments reduced the book basis of its investment in OpCo below its tax basis. This deferred tax asset was offset by a valuation allowance. For the three months ended September 30, 2026, the Company has maintained the deferred tax asset position, which was fully offset by a valuation allowance.

Net loss attributable to non-controlling interests

Net loss attributable to non-controlling interests was 60.6% of OpCo’s net loss before income tax for the three months ended September 30, 2026, as compared to 64.5% of OpCo’s net loss for the same period in 2025. The allocation reflects the non-controlling holders’ weighted-average participation in OpCo’s pretax results, as described in Note 8 to our condensed consolidated financial statements. The change in the non-controlling interests was due to exchanges by OpCo members of Class A OpCo Units for shares of Class A Common Stock, partially offset by the effect of Class A OpCo Units previously issued under the BHES JDA.

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Results of Operations

Comparison of the Nine Months Ended September 30, 2026 to the Nine Months Ended September 30, 2025

The following table sets forth our condensed consolidated results of operations data for the periods presented:

						Nine Months Ended September 30,
$ in thousands						2026						2025						$ Change						% Change
Operating expenses
General and administrative						22,401						31,378						(8,977)						(29)		%
Sales and marketing						2,912						4,074						(1,162)						(29)		%
Research and development						33,108						73,761						(40,653)						(55)		%
Project development						4,752						41,719						(36,967)						(89)		%
Impairment and other charges						194,520						1,511,735						(1,317,215)						(87)		%
Depreciation, amortization, and accretion						7,017						58,936						(51,919)						(88)		%
Total operating expenses						264,710						1,721,603
Operating loss						(264,710)						(1,721,603)
Other income (expense)
Interest income, net						8,752						16,179						(7,427)						(46)		%
Change in Earnout Shares liability and Warrant liability						6,642						66,257						(59,615)						(90)		%
Change in Tax Receivable Agreement liability						—						21,317						(21,317)						(100)		%
Other income (expense)						(35)						8						(43)						n/m
Net other income						15,359						103,761
Net loss before income tax						(249,351)						(1,617,842)
Income tax (expense) benefit						(2)						2,403						(2,405)						(100)		%
Net loss after income tax						(249,353)						(1,615,439)
Net loss attributable to non-controlling interests						(152,741)						(1,056,449)
Net loss attributable to NET Power Inc.						$	(96,612)					$	(558,990)

General and administrative

General and administrative expenses decreased by $9.0 million, or 29%, for the nine months ended September 30, 2026, as compared to the nine months ended September 30, 2025. This decrease was primarily related to lower overall compensation expense due to a reduction in employee headcount. During the nine months ended September 30, 2026, the Company terminated certain employees, resulting in severance costs of $2.6 million and accelerated stock-based compensation of $0.9 million. During the second quarter of 2025, the Company terminated certain members of executive management, resulting in $3.1 million in severance payments to these employees, as well as $1.1 million of stock-based compensation for related vesting accelerations. Additionally, professional fees decreased by $2.8 million, primarily for engineering and tax consulting costs. This decrease was partially offset by increased IT costs.

Sales and marketing

Sales and marketing expenses consist primarily of personnel-related costs and consultant costs directly associated with our sales and marketing activities, which include general publicity efforts for the Company. Sales and marketing expenses decreased by $1.2 million, or 29%, for the nine months ended September 30, 2026, as compared to the nine months ended September 30, 2025. This decrease was primarily attributable to lower professional fees and employee headcount.

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Research and development

R&D expenses in the current period primarily reflect engineering costs for post-combustion carbon capture, including the Gas Power Product, and for the Oxy-Combustion Cycle, which continued to be incurred for a period after our decision to suspend development of the Oxy-Combustion Cycle and to develop our Initial Project without carbon capture, whereas the prior-year period primarily reflected work on and testing of specific aspects of our technology at the La Porte Demonstration Facility. R&D expenses decreased by $40.7 million, or 55%, for the nine months ended September 30, 2026, as compared to the nine months ended September 30, 2025. This decrease was primarily due to the Company suspending the development activities under the BHES JDA in December 2025, resulting in a decrease of $38.1 million. Additionally, plant expenses were lower by $7.9 million due to the suspension of R&D at the La Porte Demonstration Facility in December 2025. Lower headcount reduced recurring compensation expense; those savings were partially offset by employee termination costs, including $0.9 million of severance costs and $0.3 million of accelerated stock-based compensation. This decrease was partially offset by higher engineering consulting costs of $4.0 million, primarily related to the development of the Gas Power Product, and by the $1.6 million of Entropy costs described above.

Project development

Project development expenses consist of labor expenses and fees paid to third parties developing commercial-scale projects. Project development expenses decreased by $37.0 million, or 89%, for the nine months ended September 30, 2026, as compared to the nine months ended September 30, 2025. This decrease was due to the Company ceasing development work and related expenditures for SN1 during the fourth quarter of 2025, partially offset by current-period costs of $2.6 million related to our natural gas power generation projects. Additionally, professional fees increased by $0.6 million related to legal fees. For the nine months ended September 30, 2025, the Company incurred $19.5 million under the BHES LNTP related to certain milestones and $21.0 million in costs related to SN1.

Impairment and other charges

During the second quarter of 2026, the Company determined that triggering events had occurred requiring an impairment assessment of its Developed Technology Asset Group as a result of the indefinite suspension of activities under the BHES JDA and related agreements between the Company and Baker Hughes, together with the Company’s plans not to continue development of the Oxy-Combustion Cycle technology. Management determined that no value should be ascribed to the Developed Technology Asset Group. On September 8, 2026, the Company and affiliates of Baker Hughes entered into definitive agreements to, among other things, indefinitely suspend development and commercialization of the utility-scale Oxy-Combustion Cycle technology and amend the related license agreement. Any recovery of the carrying value would be contingent upon a sale, license or other disposition of all or part of the Oxy-Combustion Cycle intellectual property and the La Porte Demonstration Facility. As a result, the Company recognized impairment losses of $194.5 million during the nine months ended September 30, 2026 related to the Developed Technology Asset Group, including $0.8 million incurred in the third quarter of 2026 related to La Porte Demonstration Facility construction-in-progress expenditures.

During the first quarter of 2025, the Company assessed its goodwill for impairment due to a change in the Company’s business plan and related sustained decrease in the Company’s market capitalization. As a result, the Company fully impaired goodwill for a loss of $359.8 million. Also in the first quarter of 2025, the Company expensed $56.1 million of costs associated with the construction of SN1 as management initiated a value engineering process to assess the project’s feasibility and optimize its design and temporarily paused further long-lead equipment releases. In the third quarter of 2025, the Company recognized an impairment loss of $1,095.8 million related to its long-lived assets as a result of feedback from potential customers, the estimated cost reductions achieved through the SN1 value engineering process, which, although significant, did not reduce costs to an economic level, and the resulting revisions to the Company’s forecasted future unit deployments and related cash flows based upon the perceived marketability and commercial viability of the

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Company’s Oxy-Combustion Cycle technology.

Depreciation, amortization, and accretion

Our depreciation, amortization, and accretion expenses consist primarily of depreciation on our La Porte Demonstration Facility and amortization of intangible assets. Depreciation, amortization, and accretion expense decreased by $51.9 million, or 88%, for the nine months ended September 30, 2026, as compared to the same period in 2025, primarily due to the reduction in depreciable and amortizable carrying amounts following the third quarter 2025 impairment and the full impairment of the Developed Technology Asset Group in the second quarter of 2026.

Interest income, net

Interest income decreased by $7.4 million, or 46%, for the nine months ended September 30, 2026, as compared to the same period in 2025. This decrease was due to lower interest-bearing cash and investment balances, partially offset by higher investment accretion.

Change in Earnout Shares liability and Warrant liability

The change in Earnout Shares liability and Warrant liability relates to movements in the fair value of earnout shares and warrants. The changes are primarily due to fluctuations in the market price of our Class A Common Stock and related volatility.

Change in Tax Receivable Agreement liability

In March 2025, the Company reduced the Tax Receivable Agreement (“TRA”) liability of $21.3 million to zero as payments related to the TRA were not considered probable. In May 2025, pursuant to its rights under the TRA, the Company delivered to the agent of the TRA holders notice of the Company’s intent to terminate the TRA (the “Early Termination Notice”). No early termination payment was payable to any TRA holder. The Early Termination Notice became final and binding on June 12, 2025.

Income tax (expense) benefit

The Company recognized income tax expense of less than $0.1 million for the nine months ended September 30, 2026, compared to an income tax benefit of $2.4 million for the same period in 2025. During 2025, the Company moved out of a deferred tax liability and into an overall deferred tax asset position as impairments reduced the book basis of its investment in OpCo below its tax basis. This deferred tax asset was offset by a valuation allowance. For the period ended September 30, 2026, the Company has maintained the deferred tax asset position, which was fully offset by a valuation allowance.

Net loss attributable to non-controlling interests

Net loss attributable to non-controlling interests was 61.0% of OpCo’s net loss before income tax for the nine months ended September 30, 2026, as compared to 64.5% of OpCo’s net loss for the nine months ended September 30, 2025. The allocation reflects the non-controlling holders’ weighted-average participation in OpCo’s pretax results, as described in Note 8 to our condensed consolidated financial statements. The change in the non-controlling interests was due to exchanges by OpCo members of Class A OpCo Units for shares of Class A Common Stock, partially offset by the additional issuance of Class A OpCo Units under the BHES JDA.

Liquidity and Capital Resources

Our principal sources of liquidity are cash and investments in highly liquid available-for-sale securities. Historically, our sources of liquidity have also included raising capital through the sale of equity. We may issue additional equity securities in the future, although our ability to raise capital through equity issuances on

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favorable terms is influenced by the market price of our Class A Common Stock and by any applicable limitations on primary offerings under our shelf registration statement. If we rely on General Instruction I.B.6 of Form 3 while the aggregate market value of our common equity held by non-affiliates is below $75 million, the aggregate value of securities sold under that instruction during the applicable rolling 12-month period generally may not exceed one-third of that market value, calculated under the instruction. Further, any future equity issuances at or near recent trading prices of our Class A Common Stock, which closed at $0.83 per share on November 11, 2026, would result in significant dilution to our existing stockholders. We measure liquidity in terms of our ability to fund the cash requirements of our project development activities and our near-term business operations, including our contractual obligations and other commitments. Our current liquidity needs primarily involve general and administrative costs and costs to develop and procure the equipment necessary for our projects.

The following table summarizes our liquidity position:

						September 30,						December 31,
in thousands						2026						2025
Cash and cash equivalents						$	143,031					$	199,430
Available-for-sale securities						39,858						176,704
Total liquidity						$	182,889					$	376,134

As of September 30, 2026, our available-for-sale securities consisted of U.S. Treasury securities. Additionally, our current liabilities were $24.6 million as of September 30, 2026.

Our contractual cash requirements for the 12 months following September 30, 2026, other than operating expenditures, include approximately $38.9 million of installments under our gas turbine equipment purchase commitments and the $0.9 million reservation deposit under the November 2026 change order described below; approximately $7.6 million of cash reimbursements payable to Baker Hughes, together with the BHES JDA Make-Whole Payment on the equity-settled portion described in Note 12 to our condensed consolidated financial statements; the suspension, standby, preservation and storage charges under the EPC Agreement; the $3.5 million termination payment, which becomes payable on demand if the Post-closing Change Order and a limited notice to proceed are not both executed, and the relevant payments made, on or before November 20, 2026, and otherwise if we do not issue the full notice to proceed by March 31, 2027; approximately $1.1 million of operating lease payments; and the cost of decommissioning the La Porte Demonstration Facility, for which we have recorded an asset retirement obligation of $4.6 million. If we issue the full notice to proceed under the EPC Agreement, our payments under that agreement during that period would be approximately $88.2 million, including the mobilization payment.

Our forecast of cash requirements for the one-year period following issuance of these financial statements assumes that we will not issue the full notice to proceed under the EPC Agreement, provide credit support under an energy services agreement, or enter into additional commitments beyond the limited notice to proceed that we are negotiating with Saulsbury unless we first obtain committed funding sufficient for the resulting obligations. On that basis, we believe our existing cash and available-for-sale securities will be sufficient to meet our obligations during that period. The forecast includes our expected operating expenditures, existing equipment purchase commitments, the payments we would make under that limited notice to proceed, remaining Baker Hughes payment obligations, lease payments, expected La Porte decommissioning expenditures, equipment milestone payments that may become due under the EPC Agreement before the full notice to proceed, and the suspension, storage, and termination payments that would arise if we do not proceed under the EPC Agreement. It excludes any reimbursement under the Cost Reimbursement Agreement described below and any financing that has not been committed. We believe it is reasonably likely that we will seek that funding and, if we obtain it, issue the full notice to proceed and enter into additional commitments during the next 12 months. If we issued the full notice to proceed, provided that credit support or entered into those commitments without first obtaining committed funding, our existing cash and available-for-sale securities would not be sufficient to fund our obligations for the 12 months following the issuance of these financial

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statements: payments under the EPC Agreement alone would then be approximately $88.2 million during the 12 months following September 30, 2026, and funding our Initial Project through commercial operation would require project-level financing, equipment financing, additional equity, partner capital or other financing sources in amounts that substantially exceed our existing liquidity. We are pursuing equipment and project-level financing and partner capital. As of the date of this Report, none of these sources has been committed, and the Cost Reimbursement Agreement does not provide committed funding. Beyond the next 12 months, our capital requirements will depend primarily on the pace and configuration of our projects, which we expect to fund through project-level financing, additional equity or equity-linked capital, partner capital, and cash on hand. See Part II, Item 1A “Risk Factors.”

Cost Reimbursement Agreement

In August 2026, Net Power, LLC, a subsidiary of the Company, entered into the Cost Reimbursement Agreement with a prospective customer in connection with negotiations for an energy services agreement for our Initial Project. The agreement is an interim arrangement pending an energy services agreement, which neither party is obligated to enter into and which, if executed, would terminate it. If an energy services agreement is not executed by February 14, 2027, if the customer earlier gives notice terminating the Cost Reimbursement Agreement, or if financing secured by covered equipment that we obtain with the customer’s approval is not repaid or refinanced by that date, the customer will, at its election, either take assignment of the covered equipment and contracts and pay us our nonrefundable costs for approved expense items, or decline assignment, in which case, unless we elect to retain the covered equipment, it will pay our nonrefundable costs for those items and any losses we realize on their resale. The customer’s aggregate payment obligations are subject to a cap of approximately $180.0 million, which does not represent committed financing or an unconditional payment obligation. Approved expense items include approximately $59.0 million we paid to EMPower, including the premium; financing costs of up to approximately $7.7 million; and the approximately $58.6 million milestone payment made to Saulsbury at closing. Other costs under the EPC Agreement become approved expense items upon the customer’s approval following execution of the Post-closing Change Order, and other expenditures require the customer’s advance approval, except to the extent expressly covered by the agreement. No amount has become payable to us under the Cost Reimbursement Agreement, and we have not recognized any receivable under it. Reimbursement excludes specified costs, and the customer’s payment obligations are suspended while we are in material breach of specified obligations. Until the Cost Reimbursement Agreement expires, we may not solicit or negotiate with third parties for the sale of the covered equipment or for an energy services or power purchase agreement that uses it, and if we fail to fund covered items on schedule, the customer may step in, at our cost, to direct or make payments for them.

Cash Flow Summary

The following table shows our cash flows from operating activities, investing activities, and financing activities for the periods presented:

						Nine Months Ended September 30,
in thousands						2026						2025
Net cash used in operating activities						$	(68,368)					$	(92,980)
Net cash provided by (used in) investing activities						$	10,904					$	(6,735)
Net cash used in financing activities						$	(152)					$	(164)

Operating Activities

Cash used in operating activities decreased $24.6 million for the nine months ended September 30, 2026, as compared to the same period in 2025. Our net cash used in operating activities to date has historically consisted primarily of payroll, materials and supplies, facilities expense, and professional services related to R&D, including the BHES JDA, and general and administrative activities. This decrease was primarily due to lower spending following the suspension of development activities under the BHES JDA and of testing at our La Porte Demonstration Facility, partially offset by $26.1 million in first-quarter 2026 payments for contract cancellation

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costs resulting from the termination of the BHES LNTP during the fourth quarter of 2025. We expect our cash used in operating activities to increase significantly before we start to generate any material cash inflows from our operations.

Investing Activities

During the nine months ended September 30, 2026, net cash provided by investing activities was $10.9 million as compared to net cash used in investing activities of $6.7 million in the same period in 2025. Net cash provided by investing activities in 2026 included $138.6 million of net maturities and sales of available-for-sale securities, offset by $117.6 million paid for the asset acquisition, $9.9 million in property and equipment purchases, and $0.3 million in capitalized software expenditures. Cash used in investing activities for the nine months ended September 30, 2025, primarily reflects the maturity of the Company’s certificate of deposit and the reinvestment of those funds into available-for-sale securities, along with capital expenditures related to the La Porte Demonstration Facility and SN1 during the period in which costs were capitalized.

Financing Activities

Our cash used in financing activities was materially consistent for the nine months ended September 30, 2026, as compared to the same period in 2025. Net cash used in financing activities consists of finance lease obligation payments and income tax payments on vested share-based compensation awards, partially offset by proceeds from the issuance of Class A Common Stock under share-based compensation plans.

Commitments and Contractual Obligations

Asset Retirement Obligation

We hold a lease for approximately 218,900 square feet of land on which the La Porte Demonstration Facility is located. In addition, we have an oxygen supply agreement with the lessor to supply oxygen to the La Porte Demonstration Facility. The lease expires on the earlier of (i) January 1, 2031 and (ii) the termination of our oxygen supply agreement with the lessor. The term of the oxygen supply agreement expires on January 1, 2030, with automatic 12-month renewal terms. The oxygen supply agreement may be terminated by the lessor or by us upon 24 months’ written notice prior to the expiration date of its current term. The underlying lease requires the removal of all equipment and the obligation to restore the land to post-clearing grade level, which has resulted in the recognition of an asset retirement obligation liability of $4.6 million and $3.6 million as of September 30, 2026 and December 31, 2025, respectively. Depending on the alternative we pursue, decommissioning could occur earlier or later than June 2027, which would change our estimate of the asset retirement obligation, or a buyer could assume the removal obligation.

As discussed in Note 14 to our condensed consolidated financial statements, during the second quarter of 2026 we revised the expected decommissioning timing for the La Porte Demonstration Facility to June 2027, based on the Company’s expectations regarding the continued ownership of its Oxy-Combustion Cycle technology assets. We are evaluating alternatives for the facility, including a sale of all or part of the facility or its equipment, and we have begun discussions with the lessor regarding an early termination of the land lease and related arrangements. Any early termination may require us to pay termination costs and to complete our removal and restoration obligations on an accelerated schedule, and there can be no assurance that we will agree to terms for any of these alternatives.

Leases

The Company leases corporate office space in Durham, North Carolina and Houston, Texas. The Company also leases land at its Project Permian site in West Texas from a subsidiary of Occidental Petroleum, which is a

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significant shareholder of the Company, and continues to hold that lease. Additionally, the Company leases a warehouse in La Porte, Texas.

As of September 30, 2026, future minimum lease payments attributable to the Company’s operating lease arrangements are approximately $3.6 million.

EPC Agreement

In connection with the Assignment Agreement discussed in Note 6 to our condensed consolidated financial statements, we assumed the owner’s payment obligations under the EPC Agreement. As of September 30, 2026, remaining payments under the EPC Agreement, including the mobilization payment of approximately $10.2 million, totaled approximately $119.1 million, of which approximately $88.2 million would become payable during the 12 months following September 30, 2026 if we issue the full notice to proceed on our current schedule. Before that notice is issued, we remain responsible for applicable suspension, standby, preservation and storage charges and any amounts arising under a limited notice to proceed or termination. If we do not issue the full notice to proceed by March 31, 2027 (pursuant to the extension agreed to in October 2026), either party may terminate the EPC Agreement under the applicable contractual provisions. Upon termination, we would owe Saulsbury a termination payment of $3.5 million, which may become payable earlier if the applicable execution and payment conditions are not satisfied, as described in Note 14 — Commitments and Contingencies to our condensed consolidated financial statements, and we could take assignment of the related equipment supply contract, subject to specified conditions, by assuming its remaining payment obligations of approximately $23.3 million. We currently expect to issue the full notice to proceed in connection with obtaining financing for the Initial Project.

Equipment Purchase Commitments

As of September 30, 2026, we have committed to purchase natural gas turbine equipment packages for use in a future natural gas power generation project. The gross commitments totaled $77.7 million, and as of September 30, 2026, there was $54.4 million remaining related to these commitments. These payments are due in installments aligned to contractual milestones through 2028. Of the remaining amounts due under the contract, approximately $38.9 million is due during the 12 months following September 30, 2026, and approximately $15.5 million is due thereafter through 2028. We expect to fund these amounts from existing liquidity and, if obtained, from equipment or project-level financing, none of which has been committed. We do not expect to use these turbine packages for our Initial Project. The option under the November 2026 change order described below would allow us to add emissions control and monitoring equipment to the packages, which we expect would be required for their permitting and operation at most sites; we have not decided whether to exercise it. These amounts exclude the additional commitments described under “Additional Equipment Commitments” below.

In November 2026, we entered into a change order to the contract for these equipment packages. The change order requires us to pay a reservation deposit of $0.9 million and gives us an option, for 30 days after the supplier receives the deposit, to add emissions control and monitoring equipment for $12.5 million, including the deposit. If we exercise the option, our gross commitments under the contract will increase to $90.2 million, and the remaining $11.6 million of the option price will be payable in installments aligned to contractual milestones through final completion, with deliveries scheduled for January and February 2028. If we do not exercise the option, the supplier will retain the deposit.

Additional Equipment Commitments

We expect to enter into additional commitments for power generation equipment, engineering and related long-lead items for our Initial Project before executing a binding energy services agreement and reaching FID, including under a limited notice to proceed under the EPC Agreement that we are negotiating with Saulsbury. Under the Cost Reimbursement Agreement, new commitments are covered only if the customer approves them in advance, subject to the aggregate cap. We do not have committed customer funding, partner capital, or financing for additional commitments, and if we enter into such commitments and our Initial Project does not

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reach FID, we may be unable to recover all of our costs through reimbursement, resale, or redeployment of the equipment.

Off-Balance Sheet Arrangements

As of September 30, 2026 and December 31, 2025, we had not engaged in any off-balance sheet arrangements, such as guarantees of third-party obligations, retained interests in transferred assets or variable interests in unconsolidated entities.

Critical Accounting Policies and Estimates

Our financial statements have been prepared in accordance with US GAAP. Preparation of the financial statements requires our management to make a number of judgments, estimates and assumptions relating to the reported amounts of expenses, assets, and liabilities and the disclosure of contingent assets and liabilities. We consider an accounting judgment, estimate or assumption to be critical when (1) the estimate or assumption is complex in nature or requires a high degree of judgment and (2) the use of different judgments, estimates, and assumptions could have a material impact on our financial statements.

Emerging Growth Company Accounting Election

Section 102(b)(1) of the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”) exempts emerging growth companies (“EGCs”) from being required to comply with new or revised financial accounting standards until private companies are required to comply with the new or revised financial accounting standards. The JOBS Act provides that a company can elect not to take advantage of the extended transition period and comply with the requirements that apply to non-EGCs, and any such election to not take advantage of the extended transition period is irrevocable. We expect to be an EGC until December 31, 2026, which is the last day of the fiscal year in which the fifth anniversary of our initial public offering occurs. As an EGC, we intend to continue to take advantage of the benefits of this extended transition period. After we cease to be an EGC, we will be required to comply with new or revised accounting standards on the effective dates that apply to public business entities.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

We are a smaller reporting company as defined by Rule 12b-2 of the Exchange Act and are not required to provide the information otherwise required under this item.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Under the supervision and with the participation of our management, including our principal executive officer and our principal financial officer, we conducted an evaluation of the effectiveness of our disclosure controls and procedures, as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act, as of the end of the fiscal quarter ended September 30, 2026. Based on this evaluation, our principal executive officer and our principal financial officer concluded that our disclosure controls and procedures were effective as of September 30, 2026.

Disclosure controls and procedures are designed to ensure that information required to be disclosed by us in our Exchange Act reports is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

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Changes in Internal Control over Financial Reporting

No changes in our internal control over financial reporting occurred during the fiscal quarter ended September 30, 2026 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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Part II - Other Information

Item 1. Legal Proceedings

For a description of our material pending legal proceedings, see “Litigation” in Note 14, Commitments and Contingencies, to our condensed consolidated financial statements included in Part I, Item 1 of this Report, which is incorporated herein by reference.

Item 1A. Risk Factors

As a smaller reporting company, we are not required to provide the information called for by this Item. We are nonetheless providing the risk factors set forth below, which reflect risks associated with recent developments in our business and strategy. These risk factors supplement and, to the extent inconsistent, supersede the risk factors disclosed in Part I, Item 1A of our Annual Report, which you should also carefully consider. The risk factors below are not a complete statement of the risks we face.

We may be unable to negotiate and enter into binding energy services or power offtake agreements on acceptable terms, on our anticipated timeline, or at all, which would adversely affect our ability to reach a final investment decision and obtain project financing for our Initial Project.

We are negotiating an energy services agreement for our Initial Project with a prospective customer, a leading developer of frontier artificial intelligence models, and are pursuing power offtake arrangements for other projects. Discussions, indications of interest, requests for proposals, term sheets, memoranda of understanding, and similar instruments do not constitute binding commitments unless and until definitive agreements are executed. If we are unable to execute binding energy services or power offtake agreements at prices and on terms sufficient to support project economics and financing, our final investment decision, construction commencement, and commercial operation dates could be delayed or may not occur, and our liquidity and capital requirements would be adversely affected. We also expect that any energy services or power offtake agreement we enter into would require us to provide substantial reciprocal credit support, in the form of cash, letters of credit or guarantees, scaled to the capacity committed and maintained through development, construction and operations, which would further reduce the liquidity available to us for other purposes.

If we do not enter into an energy services agreement for our Initial Project, our recovery of the related equipment and engineering costs will be limited and conditional, and our reimbursement arrangement restricts our ability to pursue other customers for that equipment.

In August 2026, we entered into the Cost Reimbursement Agreement with a prospective customer as an interim arrangement while we negotiate an energy services agreement for our Initial Project. The customer is not obligated to enter into that agreement. If an energy services agreement is not executed by February 14, 2027, or if the customer terminates the arrangement earlier, it may elect to take assignment of the covered equipment and contracts and reimburse our costs for approved expense items, in which case that equipment would no longer be available for our projects. Alternatively, it could decline to do so, in which case the extent of our recovery will depend on the arrangement’s termination provisions. Reimbursement is subject to an aggregate cap of approximately $180.0 million, extends only to approved expense items, and excludes specified costs. The cap does not represent an unconditional payment obligation. Other than the milestone payment made at closing, costs under the EPC Agreement will be covered only if the customer approves that agreement following execution of a change order relocating the project, and the customer may decline to approve additional equipment or other costs. The customer’s payment obligations are suspended if we are in material breach of specified obligations. Until the arrangement expires, we may not solicit or negotiate with third parties for the sale of the covered equipment or for an energy services or power purchase agreement that uses it, and if we fail to fund covered items on schedule, the customer may step in, at our cost, to direct or make payments for them. If we do not enter into a definitive agreement with the customer, we would bear any costs the arrangement does not cover, and our liquidity, results of operations, and prospects could be materially and adversely affected.

Demand for the power we intend to sell is concentrated in a limited category of large-load customers whose

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electricity requirements depend on capital investment cycles that may not continue at current levels.

Our offtake efforts are directed primarily at data center developers, computing infrastructure providers and other large-load customers whose electricity requirements reflect sustained capital investment in computing capacity. That investment is concentrated among a limited number of counterparties and is discretionary. A reduction, deferral, or geographic reallocation of capital spending by these counterparties (whether resulting from changes in expected returns on computing investment, financing conditions, technological developments that reduce power intensity per unit of computing output, siting, permitting, or community opposition constraints, regulatory or governmental restrictions on the development or interconnection of data centers, including in ERCOT, or general economic conditions) could reduce the number of potential offtakers, extend negotiation timelines, or reduce the pricing, contract tenor, or capacity commitments available to us. Because we expect to rely on long-term offtake agreements to support project-level financing, the concentration, contract tenor, and creditworthiness of our counterparties will also affect our ability to obtain financing on acceptable terms. We may be unable to identify alternative customers for capacity developed in reliance on this demand. Our Initial Project is being developed to serve a single prospective customer on a data center campus being developed by a third party, and its development depends on the commitments of both. Developments affecting that customer, including changes in its plans for computing capacity, its other infrastructure commitments, its financing and legal or governmental actions directed at it, could cause it to delay or decline the commitments the Initial Project requires, and could make lenders, suppliers or contractors less willing to support a project that serves it. We expect lenders to evaluate the Initial Project largely by reference to that customer’s creditworthiness. If they require more credit support than the customer agrees to provide, or price the project debt at levels the project cannot support, we may be unable to finance the Initial Project on acceptable terms or at all.

Our business strategy has changed substantially, and we expect to develop our projects, at least initially, without carbon capture.

We have repositioned our business to focus on natural gas power generation for co-located large-load customers, initially without carbon capture, and we have indefinitely suspended development of the Oxy-Combustion Cycle. We do not currently expect our Initial Project to include carbon capture, and we are not designing it to accommodate the later addition of carbon capture. Any deployment of carbon capture at later projects or phases would depend on definitive technology, customer and financing arrangements. This repositioning reflects, among other things, current market conditions in which many prospective customers prioritize the speed and quantity of reliable power over carbon abatement and may be unwilling to pay a premium for lower-carbon power in the near term. The configuration, capacity and carbon capture scope of each of our projects will depend on customer requirements, commercial arrangements, site rights, permits, equipment availability and financing, and may include natural gas generation deployed in advance of, or without, carbon capture.

We may be unable to realize any value from our Oxy-Combustion Cycle intellectual property and the La Porte Demonstration Facility, which have been fully impaired.

During the second quarter of 2026, we recognized a full impairment of the Developed Technology Asset Group, and those assets are carried at no value. We have no current plans to resume development of the Oxy-Combustion Cycle, and any recovery of value would depend on a sale, license, or other disposition of all or part of the Oxy-Combustion Cycle intellectual property and our improvements, equipment, and lease interests at the La Porte Demonstration Facility, or on a royalty under our license agreement with affiliates of Baker Hughes. The value that a counterparty would ascribe to the intellectual property may be limited because our license from 8 Rivers is exclusive only in the field of carbonaceous gas fuels other than those derived from certain solid fuel sources, and because several of the licensed patents expire beginning in 2030. In September 2026, we entered into agreements with affiliates of Baker Hughes that indefinitely suspend our joint development and commercial agreements with them and amend our license agreement with them. Under those agreements, Baker Hughes’ rights of access to, and exclusivity over, the La Porte Demonstration Facility ended, but Baker Hughes retains its exclusive license to manufacture and sell utility-scale equipment packages for the Oxy-Combustion Cycle. Further, the provision under which that exclusivity could be lost is suspended and would not revive

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automatically if the joint development agreement is reinstated. Baker Hughes also holds a royalty-free license, exclusive subject to rights we retained, to manufacture and sell industrial-scale products incorporating the technology, and a license to install and operate industrial plants incorporating those products, for which the royalty has not been agreed and, absent agreement, would be determined by an independent expert. Baker Hughes is not obligated to deploy any plant, and we may never receive a royalty. These licenses, and our obligation to use commercially reasonable efforts to disclose technical information to Baker Hughes at no charge, may reduce the value of the intellectual property to other counterparties and limit the transactions available to us. We have not entered into any binding agreement for a disposition, and there can be no assurance that any transaction will be agreed or consummated, or as to its terms or timing. In addition, we are evaluating alternatives for the La Porte Demonstration Facility, including a sale of all or part of the facility or its equipment and an early termination of the land lease. Depending on the outcome, the timing and cost of decommissioning the facility, which we currently expect to occur by June 2027, and the treatment of those obligations in any sale or other disposition may differ from our current estimates.

Our pursuit of co-located large-load projects exposes us to execution risks that are new to us and to governmental intervention in Texas, any of which may delay, restrict, or prevent our projects.

We are pursuing the development of power generation projects for co-located large-load facilities such as data centers. Activities of this type are new to us and expose us to risks we have not previously borne, including land acquisition and site-control risk, construction and counterparty risk, contractual performance risk, regulatory risk, and additional capital requirements at a time when we do not have sufficient committed capital to fund our Initial Project through commercial operation. If a co-located facility requires grid-supplied power, whether as a supplement or as backup, our customer or we would be subject to large-load interconnection processes and to competition for available capacity, either of which could delay the project. We may also face competition for sites, interconnection positions and end users from parties with substantially greater resources and relevant experience. We have not obtained the land or development rights that our Initial Project and the broader contemplated build-out at Project Permian would require, and we may change the site, configuration or sequencing of our projects in response to customer, land, permitting and other developments, as we have done for our Initial Project. Our Initial Project depends on site rights that we would obtain from a third-party data center developer and on that developer’s progress in developing its campus. If we do not obtain the necessary rights on acceptable terms, our projects may be limited in size, delayed, reconfigured, or not developed. To preserve our schedule, we have committed, and expect to continue to commit, material capital to power generation equipment and related engineering before binding offtake, land, partner, and project-financing arrangements are in place, including through our acquisition in August 2026 of the owner’s position under the EPC Agreement. If a project does not proceed, a portion of those expenditures may not be recoverable, and we may incur cancellation or other costs. If these activities are unsuccessful, we could incur costs without corresponding benefit, and our results of operations, liquidity, and project timelines could be materially and adversely affected.

An islanded project must meet the customer’s power-quality and reliability requirements without routine support from the ERCOT grid. Doing so may require additional generating capacity, redundancy, fuel-supply arrangements, controls, maintenance coverage and other infrastructure beyond the generating units currently under contract. Equipment outages, fuel interruptions or failure to meet contractual availability and performance requirements could interrupt service, require additional capital expenditures and expose us to damages or other contractual remedies. We have not finalized the technical configuration or contractual allocation of these risks for our Initial Project.

These processes are also subject to intervention by Texas state officials. On August 3, 2026, the Governor of Texas directed the Public Utility Commission of Texas and ERCOT to conduct a comprehensive verification and audit of all data center projects advancing through ERCOT’s interconnection process before any additional data center projects are approved to move forward, and directed that any project failing to comply with applicable requirements be denied connection to the Texas grid. The directive requires the collection of information from each data center project regarding public financial assistance received or expected, projected electricity consumption and any on-site generation, projected water consumption and cooling technology,

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measures to mitigate impacts on neighboring communities, and project ownership and control. The Governor also indicated that he intended to work with the Texas legislature to address concerns regarding data centers. On September 14, 2026, the Governor directed the Texas Water Development Board to seek penalties against data centers that do not respond to the state’s annual water use survey. On September 21, 2026, the Governor directed the Texas Commission on Environmental Quality (“TCEQ”) to pause the issuance of all permits related to data center projects until ERCOT completes its review. The directive does not expressly exclude generation that serves a data center without a connection to the ERCOT grid. On October 19, 2026, TCEQ informed the Governor that it had paused the issuance of all permits related to the construction or development of infrastructure directly supporting data centers, that it was screening pending applications and had paused those subject to the directive, and that it was suspending, where possible, authorizations for data center activities claimed without an affirmatively issued permit. ERCOT has stated that it intends to publish its report on or before December 10, 2026, but no date has been set for the pause to end. On November 3, 2026, Texas voters elected a new Governor, who will take office in January 2027 and who called during the campaign for a moratorium on new data center approvals until the Texas legislature adopts statewide rules governing them and has reaffirmed that position since the election. Whether a moratorium or other restrictions will be adopted, and their scope and timing, are uncertain. The directive contemplates that TCEQ will use information from the audits to review proposed permits, so the completion of ERCOT’s review will not by itself determine when permits for data center projects will be issued.

Our projects require air permits, and we expect the pause to apply to those required for our Initial Project. On October 21, 2026, TCEQ announced that it had temporarily shut down its electronic permitting system, through which applications are ordinarily submitted, so that its staff could review applications to determine whether they relate to data centers. On November 9, 2026, TCEQ confirmed that electronic submissions were available for applications under its Construction, Multi-Sector and Concrete Production General Permits. Those applications require staff review to determine whether they relate to data centers and no longer receive automatic approval or provisional coverage. The restoration of electronic submissions does not lift the permitting pause for data center projects or establish when applications for our Initial Project will be processed or authorizations issued. If TCEQ does not accept an application submitted during the outage, we may be required to resubmit it, which could delay review. TCEQ has also begun suspending, where possible, authorizations for data center activities claimed without an affirmatively issued permit, and any authorization we obtain could be suspended. We cannot predict the scope, duration, or outcome of these processes, the requirements the Public Utility Commission of Texas, ERCOT, or TCEQ may adopt in response, the policies of the new administration, or any resulting legislation, including any moratorium on new data centers or the generation that serves them. These processes may delay or prevent the permitting of our projects or the interconnection or permitting of data centers and other large loads that we expect to serve, extend the timelines on which prospective customers are prepared to commit to energy services or power offtake, alter the criteria on which customers select sites, or reduce the number of prospective customers able to proceed in Texas. Our prospective customer for the Initial Project has indicated that it may defer its commitment, or pursue sites outside Texas, if permits are not obtained on its timeline or it expects further restrictions in Texas, and that it expects to decide before the end of 2026 whether to proceed with its plans in Texas. Any of these outcomes could delay or prevent our reaching a final investment decision for our Initial Project, delay or prevent project-level financing, and adversely affect our business, financial condition, results of operations, and prospects.

Grid interconnection and related regulatory processes, including ERCOT’s batch framework for interconnecting large loads, may delay or restrict our projects.

Our Initial Project is being designed to serve co-located load without a connection to the ERCOT grid, and we are no longer pursuing the generation interconnection request we previously submitted for Project Permian. Our projects and our customers’ facilities may nonetheless depend on the large-load interconnection processes applicable to co-located loads, including for supplemental or backup grid-supplied power, whether those loads are developed, owned, or contracted for by our customers, our partners, or us, and future projects or phases, including at Project Permian, may require interconnection to the ERCOT grid. These processes are new, evolving and subject to eligibility criteria, timelines, financial-security requirements and allocation decisions

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outside of our control. Delays or adverse outcomes could delay project development, increase project costs, reduce the attractiveness of our projects to customers and adversely affect our results.

Texas’s large-load interconnection rule became effective on October 8, 2026. Covered interconnections require additional disclosures, agreements, financial security, and payments for interconnection facilities. Intermediate-stage financial security generally starts at $50,000 per MW, with additional security potentially required. These requirements could increase the capital needed by customers seeking grid service and delay their commitments to our projects. Applicability depends on the particular load and interconnection configuration; the proposed islanded configuration of our Initial Project does not establish that every future project or customer configuration would fall outside these requirements.

We depend on the availability, cost, and delivery timing of power generation equipment and related long-lead equipment.

Manufacturer backlogs for power generation equipment, including gas turbines and reciprocating engines, and related equipment currently extend multiple years. We have contracted for certain gas turbine equipment and, through our acquisition in August 2026 of the owner’s position under the EPC Agreement, for reciprocating engine generating units and related equipment. The configuration we are evaluating for our Initial Project would require additional generating capacity that we have not secured, and we may be unable to secure it on acceptable terms or timelines, or at all. Changes in delivery schedules, cost escalation, supplier or contractor performance, or the loss of reserved manufacturing slots could delay our projects and increase their cost, and replacement equipment may not be available on acceptable terms or timelines, or at all. Prevailing market prices for equipment comparable to the units for which we have contracted have increased materially since we contracted for them, and any additional equipment we procure is likely to cost more than the equipment we hold.

We do not have a binding agreement for post-combustion carbon capture technology, and we may not deploy carbon capture at our projects.

Our prior letter of intent with Entropy expired by its terms and has not been replaced, and we have not entered into definitive agreements with Entropy or any other provider of post-combustion carbon capture technology. Any definitive arrangement may require capital commitments, licensing fees, or other payments in amounts and on schedules that have not been determined. If we elect to deploy carbon capture at later phases or projects and are unable to enter into definitive agreements on commercially acceptable terms, we would need to identify and qualify an alternative technology provider, which would require additional time and expense, may not be available on terms or timelines supporting our project schedules, and could prevent or delay carbon capture at those phases or projects.

The economics of any carbon capture we deploy would depend in part on carbon capture tax credits, which are subject to availability, transferability, monetization and other restrictions.

The economics of projects incorporating carbon capture depend in part on federal tax credits, including the credit under Section 45Q of the Internal Revenue Code, the value, transferability and monetization of which are subject to statutory and regulatory requirements, including restrictions relating to foreign entities of concern. The credit value available with respect to any project will depend on, among other things, whether construction begins before January 1, 2033, when the applicable facility or equipment is placed in service, whether prevailing wage and apprenticeship requirements are satisfied, and the manner in which captured CO₂ is stored, used, or otherwise disposed of. In addition, legislation enacted in 2025 that increased certain credit values, including for CO₂ used in enhanced oil recovery, may be amended or repealed. If such credits are unavailable, reduced, restricted, or cannot be efficiently monetized, our project economics and offtake pricing could be adversely affected.

Customers may not attribute value to carbon capture, and regulatory developments may reduce requirements

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that would otherwise support demand for lower-carbon generation.

Our long-term strategy contemplates that some customers may eventually value, and pay for, power generated with carbon capture. Our near-term strategy does not assume that customers will pay a premium for lower-carbon power, and our Initial Project is not currently expected to include carbon capture. Recent development activity in our target markets has emphasized speed to power, available capacity, and price, and certain large purchasers of electricity have modified or extended timelines associated with previously announced emissions commitments. In September 2026, the EPA finalized a partial repeal of the 2024 greenhouse gas standards for fossil fuel-fired electric generating units, including the carbon-capture-based Phase 2 standards for new baseload stationary combustion turbines. The final rule is scheduled to become effective on November 16, 2026. The EPA has separately proposed broader rescission of remaining greenhouse gas requirements for these generating units. These actions could reduce regulatory incentives for customers to select generation incorporating carbon capture. If applicable emissions requirements are reduced or eliminated and customers do not independently attribute value to carbon capture, pricing available for lower-carbon power may not exceed pricing for conventional generation by an amount sufficient to recover the incremental capital and operating costs of carbon capture. In that event, we may deploy generation without carbon capture, defer carbon capture investment, or realize returns below those we currently anticipate.

We compete for customers, equipment and capital with substantially larger and better-capitalized participants, including participants pursuing gas generation with carbon capture.

Following the repositioning of our business, we compete directly with integrated energy companies, independent power producers, equipment manufacturers and developers pursuing natural gas generation for large-load customers, including projects incorporating carbon capture. Many of these market participants have greater financial resources, lower costs of capital, established customer relationships, existing carbon dioxide transportation and sequestration infrastructure, priority access to constrained equipment manufacturing capacity, and the ability to commit capital in advance of securing offtake. We may be unable to compete successfully on schedule, price, or credit terms.

We will need substantial additional capital to develop our projects, which may not be available on acceptable terms or at all, and our share price, public float, and changed asset base may limit our access to capital and result in substantial dilution.

Following the impairment of the Developed Technology Asset Group and our acquisition in August 2026 of the owner’s position under the EPC Agreement, our assets consist primarily of cash, cash equivalents and investments, and equipment deposits and other capitalized costs for our projects. We have no revenue and no binding energy services or power offtake agreement; we have not made a final investment decision for our Initial Project, and we do not have sufficient committed capital to fund the project through commercial operation. The capital required to bring the Initial Project to commercial operation substantially exceeds our cash and investments. In addition to the remaining payments under the EPC Agreement and our other equipment commitments, the Initial Project will require additional generating capacity, balance-of-plant, electrical and fuel-supply equipment and infrastructure, credit support under any energy services agreement, and project-level debt and equity, none of which has been committed. Costs that our prospective customer has not approved in advance are not covered by the Cost Reimbursement Agreement. Those costs currently include engineering and other work for the Initial Project, including work under the limited notice to proceed we are negotiating with Saulsbury, and we have incurred, and may continue to incur, such costs to maintain the project schedule. If we cannot obtain the capital we need on acceptable terms and on a timeline that meets our prospective customer’s requirements, we may have to delay, reduce the scope of, or abandon the Initial Project, and we may be unable to recover the amounts we have spent on it. Our Board of Directors may also consider strategic alternatives, which could include partnerships, project-level or corporate transactions, a sale of assets or a reduction or discontinuation of some or all of our development activities, and there can be no assurance that any alternative would be available on acceptable terms or at all or would preserve value for our stockholders.

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Our ability to raise equity capital depends on the market price of our Class A Common Stock and on the aggregate market value of our common equity held by non-affiliates. If we rely on General Instruction I.B.6 of Form S-3 for primary offerings while our public float is below $75 million, the aggregate value of securities sold under that instruction during the applicable rolling 12-month period generally may not exceed one-third of our public float, calculated under the instruction. Prior sales under that instruction reduce the capacity available for additional sales. A decline in the market price of our Class A Common Stock would further reduce the capital available to us through such offerings, increase the dilution to existing stockholders resulting from any equity issuance, and could make equity financing unavailable on acceptable terms or at all. In addition, the remaining consideration for work performed under the BHES JDA through December 31, 2025 is payable partly in shares of our Class B Common Stock and Class A OpCo Units, and share-settled payments made when the ten-day volume-weighted average price of our Class A Common Stock is below $4.00 per share require incremental cash payments, as described in Note 12 to our condensed consolidated financial statements.

The market price of our Class A Common Stock has been below $1.00, and our securities could be delisted from the New York Stock Exchange.

Our Class A Common Stock and warrants are listed on the New York Stock Exchange and are subject to applicable continued listing standards. The price standard applicable to our Class A Common Stock generally requires an average closing price of at least $1.00 over a consecutive 30-trading-day period. The closing price of our Class A Common Stock has been below $1.00 since October 22, 2026. If the NYSE notifies us that we do not meet that standard, we must, within ten business days after receiving the notice, notify the NYSE of our intent to cure the deficiency, and we would generally have six months to regain compliance. Regaining compliance may require a reverse stock split, which would require stockholder approval; in that case, we would need to obtain that approval no later than our next annual meeting and implement the split promptly afterward, and the split may not increase the market price of our Class A Common Stock proportionately or for a sustained period. If our Class A Common Stock again fails the price standard within one year after a reverse stock split, we would not be eligible for a cure period. The NYSE may also suspend trading and begin delisting proceedings without a cure period in certain circumstances, including if the trading price of our Class A Common Stock falls to an abnormally low level. Beginning July 1, 2027, the NYSE will immediately suspend trading in, and begin proceedings to delist, any listed security whose closing price is below $0.25 on any trading day, without a cure period. If we fail to satisfy applicable continued listing standards and do not cure the deficiency within the applicable period, our securities could be suspended from trading and delisted. Delisting would reduce the liquidity of our securities and further impair our access to capital, and could depress their market price, cause us to lose the ability to use Form S-3, and reduce analyst coverage of, and investor interest in, our securities.

We are subject to the risk of becoming an investment company.

We are an energy technology and project development company. We are not primarily engaged in the business of investing, reinvesting or trading in securities, and we do not hold ourselves out as being engaged in those activities; our historical development, our public representations and the activities of our officers and directors support the conclusion that we are an operating company. Under Section 3(a)(1)(C) of the Investment Company Act of 1940, as amended (the “ICA”), an issuer may be an investment company if it owns or proposes to acquire investment securities exceeding 40% of the value of its total assets, excluding Government securities and cash items, determined on an unconsolidated basis, unless an applicable exclusion or exemption is available. Pending its use in our primary business, we hold cash, including cash obtained in connection with our 2023 merger, in bank deposits, United States Treasury securities and government money market funds to conserve capital and liquidity. United States Treasury securities are excluded from the numerator and denominator of the statutory asset test. The treatment of any money market fund shares as cash items depends on the characteristics of the funds and the applicability of SEC staff positions. If those positions do not apply to our holdings, or if our asset composition changes, we could exceed the 40% threshold unless an exclusion or exemption is available. As a result of recently recognized impairment losses, these holdings constitute a larger portion of our total assets than previously, and to maintain compliance with the ICA, we monitor the composition of our assets and may need to make investments that are less advantageous than if we did not have ICA concerns, or forgo otherwise desirable investments or transactions.

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Rule 3a-2 under the ICA provides a one-year grace period for a transient investment company that has a bona fide intent to be engaged primarily in a non-investment business, but the grace period is available no more than once every three years and may not be available when we seek to rely on it, and reliance on it could require us to dispose of securities or limit our investments, joint ventures, or other activities.

We intend to conduct our business so that we are not deemed an investment company, but there can be no assurance that we will succeed. If we were deemed an investment company, we would be required to register under the ICA, obtain exemptive relief, or modify our business and organizational structure to fall outside the definition. Registration would subject us to substantial regulation concerning management, operations, transactions with affiliates and portfolio composition, which would significantly affect our ability to operate as contemplated and could have a material adverse effect on our business, financial condition and results of operations. If we failed to register when required, we could be subject to monetary penalties or injunctive relief in an action brought by the SEC, and we could be unable to enforce contracts with third parties.

We are subject to a pending securities class action, and may become subject to additional litigation or regulatory proceedings, any of which could result in substantial costs and divert management’s attention.

We are a defendant in a putative federal securities class action arising from alleged misstatements concerning the timing and costs of developing our first planned utility-scale power plant incorporating the Oxy-Combustion Cycle, which we then referred to as Project Permian. This matter is described in Part II, Item 1, “Legal Proceedings,” and in Note 14 to our condensed consolidated financial statements. We intend to defend this matter vigorously, but we cannot predict the outcome, and we are unable to estimate a reasonably possible loss or range of loss. We are also a nominal defendant in two stockholder derivative actions, described in the same places, that assert claims on our behalf against certain of our current and former directors and officers based on the same alleged misstatements.

Litigation of this type is expensive, may continue for years, and diverts the attention of management and other personnel from our business, regardless of outcome. An unfavorable ruling or a settlement could require us to pay substantial amounts, and our insurance may be insufficient, subject to significant retentions, or unavailable for some or all of these matters. We also have indemnification and expense-advancement obligations to our current and former officers and directors. The underlying events, these actions, or our disclosures regarding them could give rise to additional litigation or to inquiries or investigations by regulatory authorities.

Cybersecurity incidents could disrupt our operations, compromise our information or expose us to costs and liability.

The third parties on which we rely have been, and will continue to be, targets of cyberattacks. In 2026, unauthorized parties obtained data from a third-party software platform that we used. We have not determined that incident to be material. This or future incidents could result in operational disruption; the loss, theft or misuse of confidential, proprietary or personal information; remediation and other costs; litigation; regulatory inquiries; or reputational harm, any of which could adversely affect our business, financial condition, results of operations and prospects.

Additional risks and uncertainties not presently known to us, or that we currently deem immaterial, may also materially and adversely affect our business, financial condition, results of operations, and prospects.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

During the three months ended September 30, 2026, we issued 108,000 Class A OpCo Units and an equal number of shares of Class B Common Stock to BHES in partial payment for services under the BHES JDA valued at approximately $0.7 million, in reliance on the exemption from registration in Section 4(a)(2) of the Securities Act of 1933, as amended. Each Class A OpCo Unit, together with a share of Class B Common Stock, may be redeemed for one share of Class A Common Stock or, at our election, cash. We did not repurchase any of our equity securities during the three months ended September 30, 2026.

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Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

Insider Trading Arrangements

During the three months ended September 30, 2026, none of our directors or “officers” (as such term is defined in Rule 16a-1(f) under the Exchange Act) adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement” (as each term is defined in Item 408(a) of Regulation S-K).

Correction of Prior Disclosure

The Rule 10b5-1 trading arrangement adopted by Akash Patel, our former Chief Financial Officer, that we described in Part II, Item 5 of our Quarterly Report on Form 10-Q for the quarter ended September 30, 2024 was adopted on August 23, 2024, not August 26, 2024, as reported.

Amendment No. 1 to Agreement to Extend FNTP Date

The following disclosure is provided in lieu of a Current Report on Form 8-K under Item 1.01, Entry into a Material Definitive Agreement. On November 11, 2026, Net Power, LLC, a subsidiary of the Company, and Saulsbury Industries, Inc. entered into Amendment No. 1 to Agreement to Extend FNTP Date, which amends their Agreement to Extend FNTP Date, effective as of October 15, 2026, described in our Current Report on Form 8-K filed on October 22, 2026. The amendment extends from November 15, 2026 to November 20, 2026 the date by which the Post-closing Change Order (referred to in that report as the Fourth Amendment) and a limited notice to proceed must be executed, and the payments required under the limited notice to proceed made, for the $3.5 million contract termination payment to remain deferred. In the amendment, Saulsbury also confirmed that it had not demanded the termination payment, that the termination payment was not payable, and that it remained deferred under the Agreement to Extend FNTP Date as amended. The other terms of the Agreement to Extend FNTP Date are unchanged. The foregoing description is qualified in its entirety by reference to the amendment, which is filed as Exhibit 10.24 to this Report.

Item 6. Exhibits

Exhibit Number			Description
2.1+			Business Combination Agreement, dated as of December 13, 2022, by and among Rice Acquisition Corp. II, Rice Acquisition Holdings II LLC, Topo Buyer Co, LLC, Topo Merger Sub, LLC and NET Power, LLC (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed with the SEC on December 14, 2022).
2.2			First Amendment to the Business Combination Agreement, dated as of April 23, 2023, by and among Topo Buyer Co, LLC and NET Power, LLC (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed with the SEC on April 24, 2023).
3.1			Certificate of Incorporation of NET Power Inc. (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed with the SEC on June 14, 2023).
3.2			Bylaws of NET Power Inc. (incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K filed with the SEC on June 14, 2023).

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10.1+			Deposit and Exclusivity Agreement, dated as of August 13, 2026, between EMPower USA, LLC and Net Power, LLC.
10.2+, †			Assignment and Assumption Agreement, dated as of August 31, 2026, between EMPower USA, LLC and Net Power, LLC.
10.3+, ++			Consent to Assignment and Acknowledgment, dated as of August 27, 2026, by Saulsbury Industries, Inc., acknowledged and agreed by EMPower USA, LLC and Net Power, LLC.
10.4+, ++			Acknowledgment of Wärtsilä North America, Inc., dated as of August 28, 2026.
10.5+, ++			Engineering, Procurement and Construction Agreement, dated as of December 15, 2025, between EMPower USA, LLC and Saulsbury Industries, Inc.
10.6+			First Amendment to Engineering, Procurement and Construction Agreement, dated March 6, 2026, between EMPower USA, LLC and Saulsbury Industries, Inc.
10.7+			Second Amendment to Engineering, Procurement and Construction Agreement, dated May 13, 2026, between EMPower USA, LLC and Saulsbury Industries, Inc.
10.8+, ++			Third Amendment to Engineering, Procurement and Construction Agreement, dated as of June 30, 2026, between EMPower USA, LLC and Saulsbury Industries, Inc.
10.9+, ++, †			Equipment Supply Contract, dated as of December 15, 2025, between Saulsbury Industries, Inc. and Wärtsilä North America, Inc.
10.10			First Amendment to Equipment Supply Contract, dated as of March 6, 2026, between Wärtsilä North America, Inc. and Saulsbury Industries, Inc.
10.11			Second Amendment to Equipment Supply Contract, dated as of June 30, 2026, between Wärtsilä North America, Inc. and Saulsbury Industries, Inc.
10.12+			Suspension Agreement, dated September 8, 2026, among Net Power, LLC, Nuovo Pignone S.r.l., Rice Acquisition Holdings II LLC, Nuovo Pignone International S.r.l. and Rice Acquisition Corp. II, relating to the Amended and Restated Joint Development Agreement dated December 13, 2022.
10.13			Suspension Agreement, dated September 8, 2026, between Net Power, LLC and Nuovo Pignone International S.r.l., relating to the Commercial Agreement effective May 12, 2022.
10.14+			First Amendment to License Agreement, dated September 8, 2026 and effective as of January 1, 2026, among Net Power, LLC, Nuovo Pignone S.r.l. and Nuovo Pignone International S.r.l.
10.15+, ++			Variation Agreement No. 1, dated March 31, 2026, among Net Power, LLC, NET Power Inc., Net Power Operations LLC, Nuovo Pignone International S.r.l., Nuovo Pignone S.r.l. and Baker Hughes Energy Services LLC, including the letter agreement dated January 22, 2026 attached as Schedule 1 thereto.
10.16+			Variation Agreement No. 2, dated June 4, 2026, among Net Power, LLC, NET Power Inc., Net Power Operations LLC, Nuovo Pignone International S.r.l., Nuovo Pignone S.r.l. and Baker Hughes Energy Services LLC.
10.17+, ++, #			Offer Letter between Net Power, LLC and Lee Shuman, accepted March 18, 2026, including the Employee Confidentiality and Invention Assignment Agreement.
10.18			Agreement to Extend FNTP Date, dated October 16, 2026 and effective as of October 15, 2026, between Saulsbury Industries, Inc. and Net Power, LLC.
10.19#			Amendment to Stock Option Agreements, adopted by the Compensation Committee of the Board of Directors effective October 17, 2026, and approved by the Board of Directors as to the President and Chief Operating Officer on November 4, 2026 (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on November 10, 2026).
10.20++, †			Equipment Supply Agreement, dated as of November 12, 2025, between Net Power Canaveral, LLC and Relevant Power Solutions, LLC (refiled to include the statement required by Item 601(b)(10)(iv) of Regulation S-K; originally filed as Exhibit 10.25 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2025).

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10.21+, ++, †			Change Order No. 1, dated April 2, 2026, to the Equipment Supply Agreement, dated as of November 12, 2025, between Net Power Canaveral, LLC and Relevant Power Solutions, LLC.
10.22+, ++			Change Order No. 2, dated September 2, 2026, to the Equipment Supply Agreement, dated as of November 12, 2025, between Net Power Canaveral, LLC and Relevant Power Solutions, LLC.
10.23+, ++			Change Order No. 3, dated November 4, 2026, to the Equipment Supply Agreement, dated as of November 12, 2025, between Net Power Canaveral, LLC and Relevant Power Solutions, LLC.
10.24			Amendment No. 1 to Agreement to Extend FNTP Date, dated November 11, 2026, between Saulsbury Industries, Inc. and Net Power, LLC.
31.1			Certification of Principal Executive Officer Pursuant to Rules 13a-14(a) and 15d-14(a) under the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2			Certification of Principal Financial Officer Pursuant to Rules 13a-14(a) and 15d-14(a) under the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1			Certification of Chief Executive Officer (Principal Executive Officer) Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2			Certification of Chief Financial Officer (Principal Financial Officer) Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS			Inline XBRL Instance Document.
101.SCH			Inline XBRL Taxonomy Extension Schema Document.
101.CAL			Inline XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF			Inline XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB			Inline XBRL Taxonomy Extension Label Linkbase Document.
101.PRE			Inline XBRL Taxonomy Extension Presentation Linkbase Document.
104			Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).

+			Certain schedules or similar attachments to this exhibit have been omitted pursuant to Item 601(a)(5) of Regulation S-K. The Company agrees to provide a copy of any omitted schedule or similar attachment to the SEC upon request.
++			Certain provisions or terms of this exhibit have been omitted pursuant to Item 601(b)(10)(iv) of Regulation S-K. Redactions and omissions are designated with brackets containing asterisks. The Company agrees to provide on a supplemental basis an unredacted copy of the exhibit and its materiality and privacy or confidentiality analyses to the SEC upon request.
†			Certain personally identifiable information has been omitted from this exhibit pursuant to Item 601(a)(6) of Regulation S-K.
#			Indicates a management contract or compensatory arrangement.

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Signatures

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

Dated: November 12, 2026                        NET Power Inc.     

    

                                By:      /s/ Ned Leland Shuman

                                Name:     Ned Leland Shuman

                                Title:    Chief Financial Officer

(Duly Authorized Officer and Principal Financial Officer)

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