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UNITED STATES<br> <br>SECURITIES AND EXCHANGE COMMISSION<br> <br>Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 2025

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

For the transition period from to

Commission File No. 0-15905

BLUE DOLPHIN ENERGY COMPANY
(Exact name of registrant as specified in its charter)
Delaware	73-1268729
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(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
801 Travis Street, Suite 2100, Houston, Texas	77002
(Address of principal executive offices)	(Zip Code)
713-568-4725
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(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act: None

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

Common Stock, par value $0.01 per share
(Title of class)

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 ☑ No ☐

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 ☑ No ☐

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

Large accelerated filer	☐	Accelerated filer	☐
Non-accelerated filer	☑	Smaller reporting company	☑
		Emerging growth company	☐

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. ☐

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

Number of shares of common stock, par value $0.01 per share, outstanding at May 15, 2025: 14,921,968

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PART I - FINANCIAL INFORMATION
ITEM 1.	FINANCIAL STATEMENTS	7
	Consolidated Balance Sheets (Unaudited)	7
	Consolidated Statements of Income (Unaudited)	8
	Consolidated Statements of Stockholders’ Equity (Deficit) (Unaudited)	9
	Consolidated Statements of Cash Flows (Unaudited)	10
	Notes to Consolidated Financial Statements	11
ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	29
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	42
ITEM 4.	CONTROLS AND PROCEDURES	42
PART II - OTHER INFORMATION		42
ITEM 1.	LEGAL PROCEEDINGS	42
ITEM 1A.	RISK FACTORS	44
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	44
ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	44
ITEM 4.	MINE SAFETY DISCLOSURES	44
ITEM 5.	OTHER INFORMATION	44
ITEM 6.	EXHIBITS	44
SIGNATURES		45

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Glossary of Terms

Throughout this Quarterly Report on Form 10-Q, we have used the following terms:

Affiliate. Refers, either individually or collectively, to certain related parties including Jonathan Carroll, Chairman and Chief Executive Officer of Blue Dolphin, and his affiliates (including Ingleside and Lazarus Capital) and LEH and its affiliates (including LMT and LTRI). Together, Jonathan Carroll and LEH owned 83% of the Common Stock as of the filing date of this report. AMT. Alternative Minimum Tax. API Gravity. American Petroleum Institute (API) gravity; measures how heavy or light petroleum liquids are compared to water; standard used in the oil and gas industry to classify crude oil. ARO. Asset retirement obligations. ASU. Accounting Standards Update issued by FASB. AGO. Atmospheric gas oil (also known as atmospheric tower bottoms) is the heaviest product boiled by a crude distillation tower operating at atmospheric pressure. This fraction ordinarily sells as distillate fuel oil, either in pure form or blended with cracked stocks. Certain ethylene plants, called heavy oil crackers, can take AGO as feedstock. bbl(s). Barrel; a unit of volume equal to 42 U.S. gallons. BDEX. Blue Dolphin Exploration Company, a wholly owned subsidiary of Blue Dolphin. BDPC. Blue Dolphin Petroleum Company, a wholly owned subsidiary of Blue Dolphin. BDPL. Blue Dolphin Pipe Line Company, a wholly owned subsidiary of Blue Dolphin. BDSC. Blue Dolphin Services Co., a wholly owned subsidiary of Blue Dolphin. Blue Dolphin. Blue Dolphin Energy Company, one or more of its consolidated subsidiaries, or all of them taken as a whole. bpd. Barrel per day; a measure of the bbls of daily output produced in a refinery or transported through a pipeline. Board. Board of Directors of Blue Dolphin. BOEM. Bureau of Ocean Energy Management; an agency within the U.S. Department of the Interior. BSEE. Bureau of Safety and Environmental Enforcement; an agency within the U.S. Department of the Interior. CIP. Construction in progress. Common Stock. Blue Dolphin common stock, par value $0.01 per share. Blue Dolphin has 20,000,000 shares of Common Stock authorized and 14,921,968 shares of Common Stock issued and outstanding as of the filing date of this report. Complexity. A numerical score that denotes, for a given refinery, the extent, capability, and capital intensity of the refining processes downstream of the crude distillation tower. Refinery complexities range from the relatively simple crude distillation tower (“topping unit”), which has a complexity of 1.0, to the more complex deep conversion (“coking”) refineries, which have a complexity of 12.0. Condensate. Liquid hydrocarbons that are produced in conjunction with natural gas. Although condensate is sometimes like crude oil, it is usually lighter. Consolidated EBITDA. Income (loss) before interest, taxes, and depreciation and amortization on a consolidated basis. Cost of goods sold. For refinery operations, calculated as crude oil, fuel use, and chemicals plus other conversion costs plus intercompany processing fees plus associated depreciation and amortization. For tolling and terminaling, calculated as tolling and terminaling costs plus associated depreciation and amortization. Crude distillation tower. A tall column-like vessel in which crude oil and condensate is heated and its vaporized components are distilled by means of distillation trays. This process refines crude oil and other inputs into intermediate and finished petroleum products; commonly referred to as a crude distillation unit or an atmospheric distillation unit. Crude oil. A mixture of thousands of chemicals and compounds, primarily hydrocarbons. Crude oil quality is measured in terms of density (light to heavy) and sulfur content (sweet to sour). Light crude oil is thinner, has a high API Gravity, and requires less processing; heavy crude oil is thicker, has a low API Gravity, and requires more processing. Sweet crude contains sulfur content of less than 0.5% while sour crude contains sulfur content of greater than 0.5%. Crude oil must be broken down into its various components (distillates) by distillation before use as fuels or conversion to other products. Depropanizer unit. A distillation column that isolates propane from a mixture containing butane and other heavy components. Distillates. The result of crude distillation and therefore any refined oil product. Distillate is more commonly used as an abbreviated form of middle distillate. There are mainly four (4) types of distillates: (i) very light oils or light distillates (such as naphtha), (ii) light oils or middle distillates (such as our jet fuel), (iii) medium oils, and (iv) heavy oils (such as our low-sulfur diesel and HOBM, reduced crude, and AGO).

Distillation. The first step in the refining process whereby crude oil and condensate are heated at atmospheric pressure in the base of a distillation tower. As the temperature increases, the various compounds vaporize in succession at their various boiling points and then rise to prescribed levels within the tower based on their densities (from lightest to heaviest). They then condense in distillation trays and are drawn off individually for further refining. Distillation is also used at other points in the refining process to remove impurities. DLA. Defense Logistics Agency. Downtime. Scheduled and unscheduled periods in which the crude distillation tower is not operating. Downtime may occur for a variety of reasons, including severe weather, power failures, and preventive maintenance. EIA. Energy Information Administration. EIDL. Economic Injury Disaster Loan; an SBA program that provides economic relief to businesses within a declared disaster area. EPA. Environmental Protection Agency. Eagle Ford Shale. A **** hydrocarbon-producing geological formation extending across South Texas from the Mexican border into East Texas; crude oil is typically characterized as light, sweet crude with a high API Gravity; particularly suitable for refining into gasoline and other light products. Exchange Act. Securities Exchange Act of 1934, as amended. FASB. Financial Accounting Standards Board. FDIC. Federal Deposit Insurance Corporation. Feedstocks. Crude oil and other hydrocarbons, such as condensate and intermediate products, used as basic input materials in a refining process. Feedstocks are transformed into one or more finished products. Finished petroleum products. Materials or products which have received the final increments of value through processing operations, and which are being held in inventory for delivery, sale, or use. Freeport facility. Onshore terminal facility consisting of processing units for: (i) crude oil and natural gas separation and dehydration, (ii) natural gas processing, treating, and redelivery, and (iii) vapor recovery; also includes the onshore portion of a 20-inch, 34 mile gathering pipeline originating at an offshore anchor platform in Galveston Area Block 288, a 16-inch natural gas pipeline connecting the Freeport facility to the Dow Chemical Plant complex, and 162 acres of land; facility is currently inactive. GNCU. Greater Nevada Credit Union. Greenhouse gases (GHGs). Molecules in the Earth’s atmosphere, such as carbon dioxide, methane, and chlorofluorocarbons that warm the atmosphere because they absorb some of the thermal radiation emitted from the Earth’s surface. GHG process emissions from the petroleum refining sector include emissions from venting, flares, and fugitive leaks from equipment (e.g., valves, flanges, pumps); GHG emissions also include combustion emissions from stationary combustion units. Gross profit (deficit). **** Calculated as total revenue less total cost of goods sold; reflected as a dollar ($) amount. HOBM. Heavy oil-based mud blendstock; see also “distillates.” HUBZone. Historically Underutilized Business Zones program established by the SBA to help small businesses in both urban and rural communities. IBLA. Interior Board of Land Appeals; an appellate review body within the U.S. Department of the Interior. INC. Incident of Noncompliance issued by BOEM or BSEE. Ingleside. Ingleside Crude, LLC, an affiliate of Jonathan Carroll. Intercompany processing fees. Fees associated with an intercompany tolling agreement related to naphtha volumes. Intermediate petroleum products. A petroleum product that might require further processing before being saleable to the ultimate consumer; further processing might be done by the producer or by another processor. Thus, an intermediate petroleum product might be a final product for one company and an input for another company to process it further. IRC Section 382. Title 26, Internal Revenue Code, Subtitle A – Income Taxes, Subchapter C – Corporate Distributions and Adjustments, Part V Carryovers, § 382. Limits NOL carryforwards and certain built-in losses following ownership change. IRS. Internal Revenue Service.

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Glossary of Terms (Continued)
Jet fuel. A high-quality kerosene product primarily used in aviation. Kerosene-type jet fuel (including Jet A and Jet A-1) has a carbon number distribution between 8 and 16 carbon atoms per molecule; wide-cut or naphtha-type jet fuel (including Jet B) has between 5 and 15 carbon atoms per molecule.<br> <br><br> <br>Kissick Noteholder. John H. Kissick.<br> <br><br> <br>Lazarus Capital. Lazarus Capital, LLC, an affiliate of Jonathan Carroll.<br> <br><br> <br>LE. Lazarus Energy, LLC, a wholly owned subsidiary of Blue Dolphin.<br> <br><br> <br>LEH. Lazarus Energy Holdings, LLC, an affiliate of Jonathan Carroll and controlling shareholder of Blue Dolphin as of the date of this report.<br> <br><br> <br>Leasehold interest. The percent interest of a lessee under an oil and gas lease.<br> <br><br> <br>LMT. Lazarus Marine Terminal I, LLC, an affiliate of LEH.<br> <br><br> <br>LRM. Lazarus Refining & Marketing, LLC, a wholly owned subsidiary of Blue Dolphin.<br> <br><br> <br>LTRI. Lazarus Texas Refinery I, an affiliate of LEH.<br> <br><br> <br>Mbbls. One thousand bbls.<br> <br><br> <br>Mbbls/d. One thousand barrels of oil per day; a measure of the barrels of daily output produced in a refinery or transported through a pipeline.<br> <br><br> <br>MVP. MV Purchasing, LLC.<br> <br><br> <br>Naphtha. A refined or partly refined light distillate fraction of crude oil. Blended further or mixed with other materials, it can make high-grade motor gasoline or jet fuel. It is also a generic term for the lightest and most volatile petroleum fractions.<br> <br><br> <br>Natural gas. A naturally occurring hydrocarbon gas mixture consisting primarily of methane but commonly including varying amounts of other higher alkanes and sometimes a small percentage of carbon dioxide, nitrogen, hydrogen sulfide, or helium.<br> <br><br> <br>Nixon facility. Encompasses the Nixon refinery, petroleum storage tanks, loading and unloading facilities, and 56 acres of land in Nixon, Texas.<br> <br><br> <br>Nixon refinery. The 15,000-bpd crude distillation tower and associated processing units in Nixon, Texas.<br> <br><br> <br>NOL. Net operating losses.<br> <br><br> <br>NPS. Nixon Product Storage, LLC, a wholly owned subsidiary of Blue Dolphin.<br> <br><br> <br>Operating days. Represents the number of days in a period in which the crude distillation tower operated; operating days are calculated by subtracting downtime in a period from calendar days in the same period.<br> <br><br> <br>OSHA. Occupational Safety and Health Administration.<br> <br><br> <br>Other conversion costs. Represents the combination of direct labor costs and manufacturing overhead costs. These are the costs that are necessary to convert our raw materials into refined products.<br> <br><br> <br>PADD. Petroleum Administration for Defense Districts; PADD regions enable regional analysis of petroleum product supply and movements by the EIA.	Petroleum. A naturally occurring flammable liquid consisting of a complex mixture of hydrocarbons of various molecular weights and other liquid organic compounds. The name petroleum covers both the naturally occurring unprocessed crude oils and petroleum products that are made up of refined crude oil.<br> <br><br> <br>PHMSA. Pipeline and Hazardous Materials Safety Administration of the U.S. Department of Transportation.<br> <br><br> <br>Preferred Stock. Blue Dolphin preferred stock, par value $0.10 per share. Blue Dolphin has 2,500,000 shares of Preferred Stock authorized and no shares of Preferred Stock issued and outstanding as of the filing date of this report.<br> <br><br> <br>Production. The volume processed as output from the crude distillation tower. Refinery production includes finished petroleum products, such as jet fuel, and intermediate petroleum products, such as naphtha, HOBM and AGO.<br> <br><br> <br>Product slate. Represents type and quality of products produced.<br> <br><br> <br>Propane. A by-product of natural gas processing and petroleum refining. Propane is one of a group of liquified petroleum gases. Others include butane, propylene, butadiene, butylene, isobutylene, and mixtures thereof.<br> <br><br> <br>Refined products. Hydrocarbon compounds, such as jet fuel and residual fuel, produced by a refinery.<br> <br><br> <br>Refinery. Within the oil and gas industry, a refinery is an industrial processing plant where crude oil, condensate, and intermediate feeds are separated and transformed into petroleum products.<br> <br><br> <br>Refining EBITDA. Income (loss) before interest, taxes, and depreciation and amortization for our refinery operations business segment.<br> <br><br> <br>Refining operations EBITDA per bbl. Refining EBITDA divided by sales (Mbbls) for the reporting period.<br> <br><br> <br>ROU. Right-of-use.<br> <br><br><br> <br>SBA. Small Business Administration.<br> <br><br><br> <br>SEC. Securities and Exchange Commission.<br><br> <br><br><br> <br>Securities Act. The Securities Act of 1933, as amended.<br><br> <br>Significant customer. A customer who represents more than 10% of our total revenue from operations.<br><br> <br><br><br> <br>Stabilizer unit. A distillation column intended to remove the lighter boiling compounds, such as butane or propane, from a product.<br><br> <br><br><br> <br>Sulfur. Present at various levels of concentration in many hydrocarbon deposits, such as petroleum, coal, or natural gas. Also, produced as a by-product of removing sulfur-containing contaminants from natural gas and petroleum. Some of the most commonly used hydrocarbon deposits are categorized based on their sulfur content, with lower sulfur fuels (e.g., ultra low sulfur diesel) selling at a higher, premium price and higher sulfur fuels (e.g., HOBM) selling at a lower, discounted price.<br><br> <br><br><br> <br>Texas First. Texas First Rentals, LLC.<br><br> <br><br><br> <br>TCEQ. Texas Commission on Environmental Quality.<br><br> <br><br><br> <br>Throughput. The volume processed as input through the crude distillation tower. Refinery throughput includes crude oil or condensate.<br><br> <br><br><br> <br>Tolling and terminaling EBITDA. Income (loss) before interest, taxes, and depreciation and amortization for our tolling and terminaling business segment.<br><br> <br><br><br> <br>Topping unit. A type of petroleum refinery that engages in only the first step of the refining process crude distillation. A topping unit uses atmospheric distillation to separate crude oil and condensate into constituent petroleum products. A topping unit has a refinery complexity range of 1.0 to 2.0.
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Glossary of Terms (Continued)

Jet fuel. A high-quality kerosene product primarily used in aviation. Kerosene-type jet fuel (including Jet A and Jet A-1) has a carbon number distribution between 8 and 16 carbon atoms per molecule; wide-cut or naphtha-type jet fuel (including Jet B) has between 5 and 15 carbon atoms per molecule. Kissick Noteholder. John H. Kissick. Lazarus Capital. Lazarus Capital, LLC, an affiliate of Jonathan Carroll. LE. Lazarus Energy, LLC, a wholly owned subsidiary of Blue Dolphin. LEH. Lazarus Energy Holdings, LLC, an affiliate of Jonathan Carroll and controlling shareholder of Blue Dolphin as of the date of this report. Leasehold interest. The percent interest of a lessee under an oil and gas lease. LMT. Lazarus Marine Terminal I, LLC, an affiliate of LEH. LRM. Lazarus Refining & Marketing, LLC, a wholly owned subsidiary of Blue Dolphin. LTRI. Lazarus Texas Refinery I, an affiliate of LEH. Mbbls. One thousand bbls. Mbbls/d. One thousand barrels of oil per day; a measure of the barrels of daily output produced in a refinery or transported through a pipeline. MVP. MV Purchasing, LLC. Naphtha. A refined or partly refined light distillate fraction of crude oil. Blended further or mixed with other materials, it can make high-grade motor gasoline or jet fuel. It is also a generic term for the lightest and most volatile petroleum fractions. Natural gas. A naturally occurring hydrocarbon gas mixture consisting primarily of methane but commonly including varying amounts of other higher alkanes and sometimes a small percentage of carbon dioxide, nitrogen, hydrogen sulfide, or helium. Nixon facility. Encompasses the Nixon refinery, petroleum storage tanks, loading and unloading facilities, and 56 acres of land in Nixon, Texas. Nixon refinery. The 15,000-bpd crude distillation tower and associated processing units in Nixon, Texas. NOL. Net operating losses. NPS. Nixon Product Storage, LLC, a wholly owned subsidiary of Blue Dolphin. Operating days. Represents the number of days in a period in which the crude distillation tower operated; operating days are calculated by subtracting downtime in a period from calendar days in the same period. OSHA. Occupational Safety and Health Administration. Other conversion costs. Represents the combination of direct labor costs and manufacturing overhead costs. These are the costs that are necessary to convert our raw materials into refined products. PADD. Petroleum Administration for Defense Districts; PADD regions enable regional analysis of petroleum product supply and movements by the EIA.

Petroleum. A naturally occurring flammable liquid consisting of a complex mixture of hydrocarbons of various molecular weights and other liquid organic compounds. The name petroleum covers both the naturally occurring unprocessed crude oils and petroleum products that are made up of refined crude oil. PHMSA. Pipeline and Hazardous Materials Safety Administration of the U.S. Department of Transportation. Preferred Stock. Blue Dolphin preferred stock, par value $0.10 per share. Blue Dolphin has 2,500,000 shares of Preferred Stock authorized and no shares of Preferred Stock issued and outstanding as of the filing date of this report. Production. The volume processed as output from the crude distillation tower. Refinery production includes finished petroleum products, such as jet fuel, and intermediate petroleum products, such as naphtha, HOBM and AGO. Product slate. Represents type and quality of products produced. Propane. A by-product of natural gas processing and petroleum refining. Propane is one of a group of liquified petroleum gases. Others include butane, propylene, butadiene, butylene, isobutylene, and mixtures thereof. Refined products. Hydrocarbon compounds, such as jet fuel and residual fuel, produced by a refinery. Refinery. Within the oil and gas industry, a refinery is an industrial processing plant where crude oil, condensate, and intermediate feeds are separated and transformed into petroleum products. Refining EBITDA. Income (loss) before interest, taxes, and depreciation and amortization for our refinery operations business segment. Refining operations EBITDA per bbl. Refining EBITDA divided by sales (Mbbls) for the reporting period. ROU. Right-of-use. SBA. Small Business Administration. SEC. Securities and Exchange Commission. Securities Act. The Securities Act of 1933, as amended. Significant customer. A customer who represents more than 10% of our total revenue from operations. Stabilizer unit. A distillation column intended to remove the lighter boiling compounds, such as butane or propane, from a product. Sulfur. Present at various levels of concentration in many hydrocarbon deposits, such as petroleum, coal, or natural gas. Also, produced as a by-product of removing sulfur-containing contaminants from natural gas and petroleum. Some of the most commonly used hydrocarbon deposits are categorized based on their sulfur content, with lower sulfur fuels (e.g., ultra low sulfur diesel) selling at a higher, premium price and higher sulfur fuels (e.g., HOBM) selling at a lower, discounted price. Texas First. Texas First Rentals, LLC. TCEQ. Texas Commission on Environmental Quality. Throughput. The volume processed as input through the crude distillation tower. Refinery throughput includes crude oil or condensate. Tolling and terminaling EBITDA. Income (loss) before interest, taxes, and depreciation and amortization for our tolling and terminaling business segment. Topping unit. A type of petroleum refinery that engages in only the first step of the refining process crude distillation. A topping unit uses atmospheric distillation to separate crude oil and condensate into constituent petroleum products. A topping unit has a refinery complexity range of 1.0 to 2.0.

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Glossary of Terms (Continued)
Turnaround. A planned period of time when an industrial plant shuts down one or more units (and sometimes an entire facility) to perform maintenance, inspections, repairs, or upgrades.<br> <br><br><br> <br>USDA. U.S. Department of Agriculture.<br> <br><br><br> <br>USDOI. U.S. Department of the Interior.<br> <br><br><br> <br>U.S. GAAP. Accounting principles generally accepted in the United States of America.	Veritex. Veritex Community Bank, successor in interest to Sovereign Bank by merger.<br> <br><br> <br>WSJ Prime rate. The base rate on corporate loans posted by at least 70% of the ten largest U.S. as published by the Wall Street Journal. Effective December 19, 2024, the WSJ Prime rate decreased to 7.50%.<br> <br><br> <br>XBRL. eXtensible Business Reporting Language.<br> <br><br> <br>Yield. The percentage of refined products that is produced from crude oil and other feedstocks.
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Glossary of Terms (Continued)

Turnaround. A planned period of time when an industrial plant shuts down one or more units (and sometimes an entire facility) to perform maintenance, inspections, repairs, or upgrades. USDA. U.S. Department of Agriculture. USDOI. U.S. Department of the Interior. U.S. GAAP. Accounting principles generally accepted in the United States of America.

Veritex. Veritex Community Bank, successor in interest to Sovereign Bank by merger. WSJ Prime rate. The base rate on corporate loans posted by at least 70% of the ten largest U.S. as published by the Wall Street Journal. Effective December 19, 2024, the WSJ Prime rate decreased to 7.50%. XBRL. eXtensible Business Reporting Language. Yield. The percentage of refined products that is produced from crude oil and other feedstocks.

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Important Information Regarding Forward-Looking Statements

This report (including information incorporated by reference) contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Exchange Act, including, but not limited to, those under “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.” All statements other than statements of historical fact, including without limitation statements regarding expectations regarding revenue, cash flows, capital expenditures, and other financial items, our business strategy, goals, and expectations concerning our market position, future operations, and profitability, are forward-looking statements. Forward-looking statements may be identified by use of the words “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “plan,” “predict,” “project,” “will,” “would” and similar terms and phrases. Although we believe our assumptions concerning future events are reasonable, several risks, uncertainties, and other factors could cause actual results and trends to differ materially from those projected, including but not limited to:

Business and Industry ● Significant debt in current liabilities, certain of which is in default. ● Inability to meet financial covenants under certain loan agreements. ● Restrictive covenants in our debt instruments that limit our ability to undertake certain types of transactions. ● Increased costs of capital or a reduction in the availability of credit. ● Affiliate Common Stock ownership and transactions that could cause conflicts of interest. ● Operational hazards inherent in transporting, processing, and storing crude oil and condensate and refined products. ● Geographical concentration of our assets and customers in West Texas. ● Competition from companies with more significant financial and other resources. ● Market changes in insurance that impact premium costs and available coverages. ● Industry technological developments that outpace our ability to keep up. ● Use of NOL carryforwards to offset future taxable income for U.S. federal income tax purposes, which is subject to limitation. ● Variable interest rates on certain of our debt. Downstream and Midstream Operations ● Commodity price and refined product demand volatility, which can adversely affect our refining margins. ● Crude oil, other feedstocks, and refined products commodity price volatility. ● Availability and cost of crude oil and other feedstocks to operate the Nixon facility. ● Downtime at the Nixon refinery. ● Reliable supply and price of electricity to operate the Nixon facility. ● Potential impairment in the carrying value of long-lived assets, which could negatively affect our operating results. ● Adverse changes in operational cash flow and working capital, shortfalls for which Affiliates may not fund. ● Critical personnel loss, labor actions, and workplace safety issues. ● Market share loss, an unfavorable financial condition shift, or the bankruptcy or insolvency of a significant customer. ● Increases in the cost or availability of third-party vessels, pipelines, trucks, and other means of delivering and transporting our crude oil and condensate, feedstocks, and refined products. ● Sourcing of a substantial amount, if not all, of our crude oil and condensate from the Eagle Ford Shale. ● Geographical concentration of our refining operations and customers within the Eagle Ford Shale. ● Severe weather or other climate-related events that affect our facilities or those of our vendors, suppliers, or customers. ● Our ability to implement a new business strategy, such as renewable fuels, may be materially and adversely affected by many known and unknown factors. ● Our ability to effect and integrate potential acquisitions.

Legal, Government, and Regulatory ● Environmental laws and regulations that may require us to make substantial capital improvements to remain compliant or remediate current or future contamination that could lead to material liabilities. ● Strict laws and regulations regarding personnel and process safety. ● Uncertainty regarding the impact of current and future sanctions (including tariffs) imposed by governments, including the U.S., and other authorities in response to economic and geopolitical tensions. ● General economic, political, or regulatory developments, including recession, inflation, tariffs, interest rates, or changes in governmental policies relating to refined petroleum products, crude oil, or taxation. ● Assessment of penalties by regulatory agencies, such as BOEM, BSEE, OSHA and the TCEQ for violations. ● Our estimates of future AROs related to our pipeline and facilities assets, which may increase. ● Regulatory changes and other measures related to GHG emissions, climate change, and an ongoing desire to transition to greater renewable energy solutions. Security ● A terrorist attack or armed conflict. ● Increased activism against oil and gas companies. ● Actual or potential cybersecurity threats or loss of data privacy. Common Stock ● Fluctuations in our stock price that may result in a substantial investment loss. ● Increasing attention to environmental, social, and governance matters. ● Declines in our stock price due to share sales. ● Dilution of the equity of current stockholders and the potential decline of our stock price due to the issuance of new Common Stock or Preferred Stock from the pool of authorized shares that we have available to issue. ● The potential sale of shares in accordance with Rule 144, which may adversely affect the market. ● The lack of dividend payments.

See also the risk factors described in greater detail under “Item 1A.” of our Annual Report on Form 10-K for the fiscal year ended December 31, 2024 as filed with the SEC and elsewhere in our subsequent quarterly and periodic reports, including this report. All forward-looking statements included in this report are based on information available to us on the date of this report. We undertake no obligation to revise or update any forward-looking statements as a result of new information, future events, or otherwise.

Unless the context otherwise requires, references in this report to “Blue Dolphin,” “we,” “us,” “our,” or “ours” refer to Blue Dolphin Energy Company, one or more of its consolidated subsidiaries, or all of them taken as a whole.

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PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Consolidated Balance Sheets (Unaudited)

	March 31,			December 31,
			2024

ASSETS		****			****
CURRENT ASSETS
Cash and cash equivalents	1,291		$	81
Restricted cash, current	1,000			1,000
Accounts receivable, net	189			713
Accounts receivable, related party	8,312			5,247
Prepaid expenses and other current assets	1,881			2,059
Inventory	37,777			35,662
Total current assets	50,450			44,762
LONG-TERM ASSETS
Total property and equipment, net	51,931			52,433
Operating lease right-of-use assets, net	391			456
Surety bonds	350			1,255
Deferred tax assets, net	2,462			2,990
Total long-term assets	55,134			57,134
TOTAL ASSETS	105,584		$	101,896
LIABILITIES AND STOCKHOLDERS' EQUITY		****			****
CURRENT LIABILITIES
Long-term debt less unamortized debt issue costs, current portion (in default)	33,868		$	35,920
Line of credit, related party	8,305			3,250
Long-term debt, related party, current portion	1,190			1,459
Interest payable	223			235
Interest payable, related party	1,625			1,437
Accounts payable	11,422			11,630
Current portion of lease liabilities	268			264
Income taxes payable	125			18
Asset retirement obligations, current portion	2,999			2,999
Accrued expenses and other current liabilities	4,971			6,689
Total current liabilities	64,996			63,901
LONG-TERM LIABILITIES
Long-term lease liabilities, net of current	147			191
Long-term debt, net of current portion (in default)	2,424			2,300
Long-term debt, related party, net of current portion	2,810			2,541
Total long-term liabilities	5,381			5,032
TOTAL LIABILITIES	70,377			68,933
Commitments and contingencies (Note 14)
STOCKHOLDERS' EQUITY
Common stock (0.01 par value, 20,000,000 shares authorized; 14,921,968 shares issued and outstanding at March 31, 2025 and December 31, 2024, respectively) (1)	149			149
Additional paid-in capital	39,758			39,758
Retained deficit	(4,700	)		(6,944	)
TOTAL STOCKHOLDERS' EQUITY	35,207			32,963
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	105,584		$	101,896

All values are in US Dollars.

^(1)^	Blue Dolphin has 2,500,000 shares of preferred stock, par value $0.10 per share, authorized. At March 31, 2025 and December 31, 2024, there were no shares of preferred stock issued and outstanding.

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

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Financial Statements (Continued)

Consolidated Statements of Income (Unaudited)

	Three Months Ended March 31,
	2025			2024
	(in thousands, except share and per-share amounts)
REVENUE FROM OPERATIONS
Refinery operations	$	82,868		$	89,915
Tolling and terminaling		824			1,107
Total revenue from operations		83,692			91,022
COSTS AND EXPENSES
Crude oil, fuel use, and chemicals		74,576			76,668
Other conversion costs		2,281			2,114
Tolling and terminaling costs		122			410
Depreciation and amortization		640			642
Total cost of goods sold		77,619			79,834
Other operating costs
LEH operating fee, related party		182			172
Other operating expenses		119			140
General and administrative expenses		1,355			983
Depreciation and amortization		74			62
Total cost of operations		79,349			81,191
Income from operations		4,343			9,831
OTHER INCOME (EXPENSE)
Interest and other income		-			148
Interest and other expense		(1,464	)		(1,514	)
Total other expense		(1,464	)		(1,366	)
Income before income taxes		2,879			8,465
Income tax expense		(635	)		(1,841	)
Net income	$	2,244		$	6,624
Income per common share:
Basic	$	0.15		$	0.44
Diluted	$	0.15		$	0.44
Weighted average number of common shares outstanding:
Basic		14,921,968			14,921,968
Diluted		14,921,968			14,921,968

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

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Financial Statements (Continued)

Consolidated Statements of Stockholders ’ Equity (Deficit) (Unaudited)

	Common Stock
	Shares Issued and				Additional Paid-In		Retained Earnings			Total Stockholders'
	Outstanding		Par Value		Capital		(Deficit)			Equity (Deficit)
	(in thousands except share amounts)
Balance at December 31, 2023		14,921,968	$	149	$	39,758	$	1,692		$	41,599
Net income		-		-		-		6,624			6,624
Balance at March 31, 2024		14,921,968	$	149	$	39,758	$	8,316		$	48,223
	Common Stock
	Shares Issued and				Additional Paid-In		Retained Earnings			Total Stockholders'
	Outstanding		Par Value		Capital		(Deficit)			Equity (Deficit)
	(in thousands except share amounts)
Balance at December 31, 2024		14,921,968	$	149	$	39,758	$	(6,944	)	$	32,963
Net income		-		-		-		2,244			2,244
Balance at March 31, 2025		14,921,968	$	149	$	39,758	$	(4,700	)	$	35,207

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

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Financial Statements (Continued)

Consolidated Statements of Cash Flows (Unaudited)

	Three Months Ended March 31,
	2025			2024
	(in thousands)
OPERATING ACTIVITIES
Net income	$	2,244		$	6,624
Adjustments to reconcile net income to net cash used in operating activities:
Depreciation and amortization		714			704
Deferred income tax		528			1,545
Amortization of debt issue costs		51			50
Changes in operating assets and liabilities
Accounts receivable		524			12
Accounts receivable, related party		(3,065	)		(7,538	)
Prepaid expenses and other current assets		1,083			469
Inventory		(2,115	)		(4,081	)
Asset retirement obligations		-			(1,505	)
Accounts payable, accrued expenses and other liabilities		(1,691	)		(1,646	)
Accounts payable, related party		-			(884	)
Net cash used in operating activities		(1,727	)		(6,250	)
INVESTING ACTIVITIES
Net cash used in investing activities		-			-
FINANCING ACTIVITIES
Payments on debt principal		(2,118	)		(345	)
Net activity on related-party debt		5,055			-
Net cash provided by (used in) financing activities		2,937			(345	)
Net change in cash, cash equivalents, and restricted cash		1,210			(6,595	)
CASH, CASH EQUIVALENTS, AND RESTRICTED CASH AT BEGINNING OF PERIOD		1,081			18,718
CASH, CASH EQUIVALENTS, AND RESTRICTED CASH AT END OF PERIOD	$	2,291		$	12,123
Supplemental Information:
Non-cash investing and financing activities:
Financing of capital expenditures via long-term note	$	139		$	-
Interest paid	$	996		$	2,674

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

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Notes to Consolidated Financial Statements
(1)	Organization
---	---

Company Overview. Blue Dolphin was formed in 1986 as a Delaware corporation. The company is an independent downstream energy company operating in the Gulf Coast region of the U.S. Operations primarily consist of a light sweet-crude, 15,000-bpd crude distillation tower, and approximately 1.25 million bbls of petroleum storage tank capacity in Nixon, Texas. Blue Dolphin trades on the OTCQX under the ticker symbol “BDCO.”

Assets are organized into two business segments: ‘refinery operations’ (owned by LE) and ‘tolling and terminaling services’ (owned by LRM and NPS). ‘Corporate and other’ includes Blue Dolphin subsidiaries BDPL (inactive pipeline and facilities assets), BDPC (inactive leasehold interests in offshore oil and gas wells), and BDSC (administrative services). See “Note ( 4)” to our consolidated financial statements for more information about our business segments.

Unless the context otherwise requires, references in this report to “we,” “us,” “our,” or “ours” refer to Blue Dolphin, one or more of its consolidated subsidiaries, or all of them taken as a whole.

Jonathan Carroll, our Chief Executive Officer, and an Affiliate together controlled 84.1% of the voting power of our Common Stock as of the filing date of this report. An Affiliate also operates and manages all Blue Dolphin properties, funds working capital requirements during periods of working capital deficits, guarantees certain of our third-party secured debt, and is a significant customer. Blue Dolphin and certain subsidiaries are currently parties to various agreements with Affiliates. See “Note ( 3)” to our consolidated financial statements for additional disclosures related to Affiliate agreements, arrangements, and risks associated with working capital deficits.

Working Capital. As of March 31, 2025 and the filing date of this report, certain conditions and events existed, in the aggregate, that caused management to evaluate Blue Dolphin's ability to continue as a going concern. Those conditions and events included historical and current working capital deficits and significant debt in default. Management believes that we have sufficient liquidity to meet our obligations as they become due through the generation of cash flows from operations and liquidation of current working capital amounts for a reasonable period (defined as one year from the issuance of these financial statements). Management acknowledges that uncertainty remains related to future operating margins; however, management has a reasonable expectation of Blue Dolphin's ability to generate adequate working capital for, amongst other requirements, purchasing crude oil and condensate and making payments on our long-term debt.

(2)	Principles of Consolidation and Significant Accounting Policies

Basis of Presentation. We prepared the accompanying unaudited consolidated financial statements, which include Blue Dolphin and its subsidiaries, in accordance with U.S. GAAP for interim consolidated financial information pursuant to the rules and regulations of the SEC under Article 10 of Regulation S-X and the instructions to Form 10-Q. Accordingly, we condensed or omitted certain information and footnote disclosures normally included in our audited financial statements pursuant to the SEC’s rules and regulations. We eliminated significant intercompany transactions in the consolidation. Management believes all adjustments considered necessary for a fair presentation are included, disclosures are adequate, and the presented information is not misleading.

We derived the consolidated balance sheet as of December 31, 2024 from the audited financial statements at that date. The accompanying consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2024 as filed with the SEC. Operating results for the three months ended March 31, 2025 are not necessarily indicative of the results that maybe expected for the fiscal year ending December 31, 2025, or for any other period.

Reclassifications. When necessary, we reclassified prior period financial information to conform to the current year's presentation.

Significant Accounting Policies. We present a summary of significant Blue Dolphin accounting policies to assist investors and other stakeholders in understanding our consolidated financial statements. Our consolidated financial statements and accompanying notes are representations of management, who are responsible for their integrity and objectivity. These accounting policies conform to U.S. GAAP and management consistently applied these accounting policies in the preparation of our consolidated financial statements.

Use of Estimates. The nature of our business requires that we make estimates and assumptions in accordance with U.S.GAAP. These estimates and assumptions affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements, as well as the reported amounts of revenue and expenses during the reporting period. We assessed certain accounting matters that require consideration of forecasted financial information in context with information reasonably available to us as of March 31, 2025 and through the filing date of this report. We base our estimates and judgments on historical experience, various assumptions, and information we believe to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be perceived with certainty and, accordingly, we may adjust estimates as the operating environment changes, new events occur, or we gain greater insights or experience. While we believe the estimates and assumptions used to prepare these consolidated financial statements are appropriate, actual results could differ from our estimates.

Cash, Cash Equivalents, and Restricted Cash. Cash and cash equivalents represent liquid investments with an original maturity of three months or less. Cash balances are maintained in depository and overnight investment accounts with financial institutions that, at times, may exceed insured deposit limits. Although management historically deemed this a normal business risk, management continues to evaluate options to limit risk given current capital, credit, and commodity markets and financial institution health. Restricted cash, current and restricted cash, noncurrent at March 31, 2025 and December 31, 2024, if any, reflected amounts held in a payment reserve account by Veritex as security for payments under the LE Term Loan Due 2034. In the event that banks in which we maintain our cash balances (including restricted cash) fail, there can be no assurance that the federal government and the Federal Reserve would intervene. See "Notes ( 3) and ( 9)" to our consolidated financial statements for additional disclosures associated with covenants related to our secured loan agreements with related parties and third parties.

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Notes to Consolidated Financial Statements (Continued)

The following table provides a reconciliation of cash, cash equivalents, and restricted cash as reported in the consolidated statements of cash flows:

		March 31,		December 31,
	2025		2024
	(in thousands)
Cash and cash equivalents	$	1,291	$	81
Restricted cash, current		1,000		1,000
	$	2,291	$	1,081

Accounts Receivable and Allowance for Credit Losses. Accounts receivable are presented net of any necessary allowance(s) for credit losses. Receivables are recorded at the invoiced amount and generally do not bear interest. When necessary, an allowance for credit losses is established based on prior experience and other factors which, in management’s judgment, deserve consideration in estimating bad debts. Management assesses the collectability of the customer’s account based on current aging status, collection history, and financial condition. Based on a review of these factors, management establishes or adjusts the allowance for specific customers and the entire accounts receivable portfolio. We had an allowance for credit losses of $0 and $0.06 million at March 31, 2025 and December 31, 2024, respectively.

Financial Instruments and Fair Value Measurements. Our financial instruments consist of cash and cash equivalents, restricted cash, accounts receivable, accounts payable, and long-term debt. As of March 31, 2025 and December 31, 2024, the carrying amounts of cash and cash equivalents, restricted cash, accounts receivable and accounts payable approximated their fair values because they are highly liquid or due to the short-term nature of these instruments. The carrying value of long-term debt approximates fair value as it carries interest rates that fluctuate with the prime rate.

We established a three-tier hierarchy that classifies fair value amounts recognized in the financial statements based on the observability of inputs used to estimate these fair values. The hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3). At each balance sheet reporting date, we categorize our financial assets and liabilities using this hierarchy. The fair value of our debt was $50.2 million and $47.2 million, at March 31, 2025 and December 31, 2024, respectively.

Inventory. Inventory primarily consists of refined products, crude oil and condensate, and chemicals. We value inventory at the lower of cost or net realizable value with cost determined by the average cost method, and net realizable value determined based on estimated selling prices less associated delivery costs. If the net realizable value of our refined products inventory declines to an amount less than our average cost, we record a write-down of inventory and an associated adjustment to cost of goods sold. See “Note ( 6)” to our consolidated financial statements for additional disclosures related to inventory.

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Notes to Consolidated Financial Statements (Continued)

Revenue Recognition.

Refinery Operations Revenue. We recognize revenue from refined products sales when we meet our performance obligation to the customer. We meet our performance obligation when the customer receives control of the product. The customer accepts control of the product when the product is lifted. Under bill and hold arrangements, the customer takes control of the product when added to the customer’s bulk inventory as stored at the Nixon facility. We allocate a transaction price to each separately identifiable refined product load.

We consider a variety of facts and circumstances in assessing the point of a control transfer, including but not limited to: whether the purchaser can direct the use of the refined product, the transfer of significant risks and rewards, our rights to payment, and transfer of legal title. In each case, the term between the sale and when payment is due is not significant. We include incurred transportation, shipping, and handling costs in the cost of goods sold. We do not include excise and other taxes collected from customers and remitted to governmental authorities in revenue.

Tolling and Terminaling Revenue. Tolling and terminaling revenue represents fees under (i) terminal services agreements whereby a customer agrees to pay a certain fee per storage tank based on tank size over time for the storage of products and (ii) tolling agreements, whereby a customer agrees to pay a certain fee per gallon or barrel for throughput volumes moving through the naphtha stabilizer unit and a fixed monthly reservation fee for the use of the naphtha stabilizer unit.

We typically satisfy performance obligations for tolling and terminaling operations over time. We determine the transaction price at agreement inception based on the guaranteed minimum amount of revenue over the agreement term. We allocate the transaction price to the single performance obligation that exists under the agreement. We recognize revenue in the amount for which we have a right to invoice. Generally, payment terms do not exceed 30 days.

Revenue from storage tank customers may, from time to time, include fees for ancillary services, such as in-tank and tank-to-tank blending. These are optional customer services. The fixed cost under the customer’s storage tank agreement does not include ancillary services fees. We consider ancillary services as a separate performance obligation under the storage tank agreement. We satisfy the performance obligation and recognize the associated fee when we complete the requested service.

Deferred Revenue. Deferred revenue represents a liability related to a revenue-producing activity as of the balance sheet date. We record unearned revenue, which usually consists of customer prepayments, when we receive the cash payment. Once we satisfy the performance obligation, we recognize revenue in conformity with U.S. GAAP.

Contract Balances. The timing of revenue recognition, billings, and cash collections results in billed accounts receivable and customer pre-payments and deposits (contract liabilities) on our consolidated balance sheet. We bill amounts as customers lift products or upon signing of bulk sales contracts. We sometimes receive advances or deposits from our customers before revenue is recognized, resulting in contract liabilities. These deposits liquidate when we recognize the revenue.

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Notes to Consolidated Financial Statements (Continued)

Computation of Earnings Per Share. We present basic and diluted EPS. Basic EPS excludes dilution and is computed by dividing net income available to common stockholders by the weighted average number of shares of common stock outstanding for the period. We calculate diluted EPS by dividing net income available to common stockholders by the diluted weighted average number of common shares outstanding. Diluted EPS includes the potential dilution that could occur if securities or other contracts to issue shares of common stock were converted to common stock that then shared in the entity’s earnings. We do not currently have issued options, warrants, or similar instruments. Convertible shares, if granted, are not included in the computation of earnings per share if anti-dilutive. See "Note ( 13)” for additional information related to EPS.

New Accounting Standards and Disclosures

New Pronouncements Adopted. During the three months ended March 31, 2025 we did not adopt any ASUs.

New Pronouncements Issued, Not Yet Effective. We expect to adopt the following ASUs in future periods:

●	ASU 2024-03 — Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures (Subtopic 220-40) ("ASU 2024-03"). In November 2024, the FASB issued ASU 2024-03, requiring additional disclosure of certain costs and expenses within the notes to the consolidated financial statements. This ASU is effective for annual periods beginning after December 15, 2026, and interim periods beginning after December 15, 2027, with early adoption permitted. We are currently evaluating the provisions of ASU 2024-03 and the incremental disclosures that will be required in our consolidated financial statements.
●	ASU 2023-09 — Income Taxes (Topic 740): Improvements to Income Tax Disclosures ("ASU 2023-09"). In December 2023, the FASB issued ASU 2023-09, requiring us to disclose specified additional information in our income tax rate reconciliation and provide additional information for reconciling items that meet a quantitative threshold. ASU 2023-09 will also require us to disaggregate our income taxes paid disclosure by federal and state taxes, with further disaggregation required for significant individual jurisdictions. ASU 2023-09 allows for adoption using either a prospective or retrospective transition method. We will adopt ASU 2023-09 for our financial statements covering the annual period ending December 31, 2025.We are currently evaluating the impact of adopting this ASU.
---	---
(3)	Related-Party Transactions
---	---

Affiliate Agreements.

Financial and Operating Agreements. During 2024 and 2023, Blue Dolphin and certain subsidiaries were parties to the following financial and operating agreements with Affiliates:

Agreement/Transaction	Parties	Effective Date	Key Terms
Fourth Amended and Restated Operating Agreement	Blue Dolphin and subsidiaries<br> <br>LEH	04/01/2025	For LEH operation and management of all Blue Dolphin’s assets; 1-year term; expires 04/01/2026 or notice by either party at any time of material breach or 90 days Board notice; LEH receives management fee of 5% of all consolidated operating costs of Blue Dolphin and its subsidiaries, excluding crude costs, depreciation, amortization, and interest; LEH-provided services include personnel serving in a variety of capacities across all Blue Dolphin entities, including, but not limited to corporate executives such as the principal executive officer and principal financial and accounting officer; as a result, Blue Dolphin and its subsidiaries have no employees for reporting purposes; all personnel are employed and paid by LEH.
Amended and Restated Jet Fuel Sales Agreement	LE<br> <br>LEH	04/01/2023	Jet fuel sales by LE to LEH; 1-year automatic renewals; LEH lifts the jet fuel from LE as needed and sells it to the DLA under preferential pricing terms due to LEH's HUBZone certification.
NPS Terminal Services Agreement	NPS<br> <br>LEH	11/01/2022	LEH pays NPS a tank rental fee of $0.2 million per month to store jet fuel at the Nixon facility; 1-year evergreen term; either party may cancel upon 60 days’ prior written notice.
Second Amended and Restated Master Services Agreement	LE<br> <br>Ingleside	03/01/2025	For storage of LE products intended for customer receipt by barge; LE pays Ingleside a tank rental fee of $0.1 million per month; the agreement expires 03/01/2026.
LE Amended and Restated Guaranty Fee Agreement	LE<br> <br>Jonathan Carroll	01/01/2023	Relates to payoff of LE $25.0 million Veritex loan; as consideration for providing his personal guarantee, Jonathan Carroll receives a cash fee equal to 2.00% per annum of outstanding principal balance owed under the LE Term Loan Due 2034.
NPS Guaranty Fee Agreement	NPS<br> <br>Jonathan Carroll	01/01/2023	Relates to payoff of NPS $10.0 million GNCU loan; as consideration for providing his personal guarantee, Jonathan Carroll receives a cash fee equal to 2.00% per annum of outstanding principal balance owed under the NPS Term Loan Due 2031.
LRM Amended and Restated Guaranty Fee Agreement	LRM<br> <br>Jonathan Carroll	01/01/2023	Relates to payoff of LRM $10.0 million Veritex loan; as consideration for providing his personal guarantee, Jonathan Carroll receives a cash fee equal to 2.00% per annum of outstanding principal owed under the LRM Term Loan Due 2034.
Blue Dolphin Guaranty Fee Agreement	Blue Dolphin<br> <br>Jonathan Carroll	01/01/2023	Relates to payoff of Blue Dolphin $2.0 million SBA loan; as consideration for providing his personal guarantee, Jonathan Carroll receives a cash fee equal to 2.00% per annum of outstanding principal balance owed under the Blue Dolphin Term Loan Due 2051.
Office Sub-Lease Agreement	LEH<br> <br>BDSC	09/01/2024	LEH office space in Houston, Texas; sub-lease executed 10/30/24; 24-month extension of prior office sub-lease agreement; term expires 08/31/2026; rent approximately $0.003 million per month.

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Notes to Consolidated Financial Statements (Continued)

Debt Agreements. Blue Dolphin and certain subsidiaries are parties to the following debt agreements with Affiliates:

		Original		Monthly
		Principal		Payment
Loan Description	Parties	(in millions)	Maturity Date	(in millions)	Interest Rate	Loan Purpose
Amended and Restated Affiliate Revolving Credit Agreement	Blue Dolphin and Subsidiaries	$10 million maximum^(1)^	April 2027	Set-off against other obligations Borrower owes to Lender	WSJ Prime + 2.00%	Working capital
	LEH and Subsidiaries
Amended and Restated BDPL-LEH Loan Agreement	LEH	$4.0 million	April 2027	$0.25	12.00%	Working capital
	BDPL
^(1)^	As of March 31, 2025, $8.3 million was drawn under the agreement.
---	---

Covenants, Guarantees and Security. The Amended and Restated BDPL-LEH Loan Agreement contains representations and warranties and affirmative and negative covenants that we consider usual and customary for a credit facility of this type. There are no financial covenants in the Amended and Restated BDPL-LEH Loan Agreement. Certain BDPL property serves as collateral under the Amended and Restated BDPL-LEH Loan Agreement.

Related-Party Financial Impact

Consolidated Balance Sheets.

Accounts receivable and accounts payable, related party. We net settle amounts owed between Blue Dolphin and its subsidiaries and Affiliates under financial and operating agreements (as discussed elsewhere within this "Note ( 3)"). Amounts owed between the parties can vary significantly from period to period even if underlying transactions remain relatively stable based on settlement dates. We reflect any excess amounts owed by Affiliates to Blue Dolphin and its subsidiaries on our consolidated balance sheets within accounts receivable—related party. Except for debt, we reflect any excess amounts owed by Blue Dolphin and its subsidiaries to Affiliates on our consolidated balance sheets within accounts payable, related party. Accounts receivable and accounts payable, related-party as of the dates indicated was as follows:

		March 31,		December 31,
	2025		2024
	(in thousands)
Current assets
Accounts receivable, related party	$	8,312	$	5,247
Current liabilities
Accounts payable, related party		-		-

Accounts receivable, related party at March 31, 2025 reflected amounts owed by LEH to LE under the Amended and Restated Jet Fuel Sales Agreement. Accounts payable, related party at December 31, 2024 reflected amounts owed by LE to Ingleside under the Second Amended and Restated Master Services Agreement.

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Notes to Consolidated Financial Statements (Continued)

*Related-Party Debt.*We reflect the amounts owed by Blue Dolphin and its subsidiaries to Affiliates under debt agreements on our consolidated balance sheets within long-term debt, related party and interest payable, related party. Related-party long-term debt, including outstanding original principal, as of the dates indicated was as follows:

		March 31,			December 31
	2025			2024
	(in thousands)
LEH
Amended and Restated BDPL-LEH Loan Agreement	$	4,000		$	4,000
Line of credit, related party		8,305			3,250
LEH Total		12,305			7,250
Less: Long-term debt, related party, current portion		(1,190	)		(1,459	)
Less: Line of credit, related party		(8,305	)		(3,250	)
	$	2,810		$	2,541

Related-party accrued interest associated with long-term debt as of the dates indicated was as follows:

		March 31,			December 31
	2025			2024
	(in thousands)
LEH
Amended and Restated BDPL-LEH Loan Agreement	$	1,308		$	1,308
Line of credit, related party		-			-
LEH Total		1,308			1,308
Jonathan Carroll
Guaranty fee agreements		317			129
		1,625			1,437
Less: Long-term debt, related party, current portion		(1,625	)		(1,437	)
Long-term interest payable, related party, net of current portion	$	-		$	-

Consolidated Statements of Income.

*Total revenue from operations.*Revenue from Affiliates under the Amended and Restated Jet Fuel Sales Agreement and the NPS Terminal Services Agreement as of the dates indicated was as follows:

	Three Months Ended March 31,
	2025				2024
	(in thousands, except percent amounts)
Refinery operations
LEH	$	24,948	35.8	%	$	27,394	30.1	%
Third-Parties		57,920	62.9	%		62,521	68.7	%
Tolling and terminaling
LEH		540	0.7	%		540	0.6	%
Third-Parties		284	0.6	%		567	0.6	%
	$	83,692	100.0	%	$	91,022	100.0	%

*Interest expense.*Interest expense associated with guaranty fee agreements and a debt agreement with Affiliates as of the dates indicated was as follows:

	Three Months Ended March 31,
	2025		2024
	(in thousands)
Jonathan Carroll
Guaranty Fee Agreements
Tied to First Term Loan Due 2034	$	93	$	98
Tied to NPS Term Loan Due 2031		39		50
Tied to Second Term Loan Due 2034		46		41
Tied to Blue Dolphin Term Loan Due 2051		10		10
LEH
Amended and Restated BDPL-LEH Loan Agreement		106		106
	$	294	$	305

*Other.*BDSC received sub-lease income from LEH totaling $0.01 million and $0.02 million for both the three months ended March 31, 2025 and 2024, respectively.

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Notes to Consolidated Financial Statements (Continued)

The LEH operating fee, related party under the Fourth Amended and Restated Operating Agreement totaled $0.2 million for both the three months ended March 31, 2025 and 2024.

Lease expense associated with the Second Amended and Restated Master Services Agreement (as discussed elsewhere within this "Note ( 3)" and in "Note ( 12)" to our consolidated financial statements) totaled $0.3 million both the three months ended March 31, 2025 and 2024, respectively.

(4)	Revenue and Segment Information

We have two reportable business segments: (i) refinery operations, which derives revenue from refined product sales, and (ii) tolling and terminaling, which derives revenue from storage tank rental fees, ancillary services fees (such as for in-tank blending) and tolling and reservation fees for use of the naphtha stabilizer at the Nixon refinery. ‘Corporate and other’ includes information for BDSC, BDPL, and BDPC.

Our chief operating decision maker ("CODM"), is our Chief Executive Officer. For our refining segment, significant expenses relate to crude oil, fuel use, and chemicals, other conversion costs, and the LEH operating fee. For our tolling and terminaling segment, significant expenses relate to fees associated with an intercompany tolling agreement. The CODM reviews segment profit or loss on a monthly and quarterly basis and considers trend analyses as well as other market factors when making decisions about resource allocation. The measure of segment assets reported on our consolidated balance sheets and reviewed by our CODM is total assets.

Revenue from Contracts with Customers.

Disaggregation of Revenue. We present revenue in the table below under ‘Segment Information’ separated by business segment because management believes this presentation is beneficial to users of our financial information.

Receivables from Contracts with Customers. We present accounts receivable from contracts with customers as accounts receivable, net on our consolidated balance sheets.

Contract Liabilities. Our contract liabilities consist of unearned revenue from customers in the form of prepayments. We include unearned revenue in accrued expenses and other current liabilities on our consolidated balance sheets. See “Note ( 8)” to our consolidated financial statements for more information related to unearned revenue.

Remaining Performance Obligations. Most of our customer contracts are settled immediately and therefore have no remaining performance obligations.

Contract Balances.

		March 31,		December 31,
	2025		2024
	(in thousands)
Accounts receivable (including related-party), beginning of period	$	5,960	$	4,300
Accounts receivable (including related-party), end of period		8,501		5,960
Unearned revenue, beginning of period	$	2,727	$	3,243
Unearned revenue, end of period		1,525		2,727

Segment Information. We modified our segment presentation to incorporate applicable depreciation and amortization into our cost of goods sold subtotal. We believe this provides a more complete representation of our cost of goods sold. Prior periods were modified to conform with this presentation.

Blue Dolphin Energy Company

March 31, 2025 | Page 17

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Notes to Consolidated Financial Statements (Continued)

Business segment information for the periods indicated (and as of the dates indicated) was as follows:

	Three Months Ended
	March 31,
	2025													2024
	Refinery Operations		Tolling & Terminaling		Corporate & Other			Intercompany Elimination ^(1)^			Consolidated			Refinery Operations		Tolling & Terminaling		Corporate & Other			Intercompany Elimination			Consolidated
	(in thousands)
Segment revenue	$	82,868	$	1,391	$	-		$	(567	)	$	83,692		$	89,915	$	1,610	$	-		$	(503	)	$	91,022
Total revenue from operations		82,868		1,391		-			(567	)		83,692			89,915		1,610		-			(503	)		91,022
Crude oil, fuel use, and chemicals		74,576		-		-			-			74,576			76,668		-		-			-			76,668
Other conversion costs		2,848		-		-			(567	)		2,281			2,617		-		-			(503	)		2,114
Intercompany processing fees		-		-		-			-			-			-		-		-			-			-
Tolling and terminaling costs		-		122		-			-			122			-		410		-			-			410
Depreciation and amortization		298		342		-			-			640			301		341		-			-			642
Total costs of goods sold		77,722		464		-			(567	)		77,619			79,586		751		-			(503	)		79,834
LEH operating fee, related party		182		-		-			-			182			172		-		-			-			172
General and administrative expenses		339		88		928			-			1,355			237		23		723			-			983
Other operating expenses(2)		-		-		119			-			119			-		-		140			-			140
Depreciation and amortization		-		-		74			-			74			-		-		62			-			62
Interest, net		836		477		151			-			1,464			734		496		136			-			1,366
Total costs and expenses		79,079		1,029		1,272			(567	)		80,813			80,729		1,270		1,061			(503	)		82,557
Income (loss) before income taxes		3,789		362		(1,272	)		-			2,879			9,186		340		(1,061	)		-			8,465
Income tax expense		-		-		(635	)		-			(635	)		-		-		(1,841	)		-			(1,841	)
Net income (loss)	$	3,789	$	362	$	(1,907	)	$	-		$	2,244		$	9,186	$	340	$	(2,902	)	$	-		$	6,624
^(1)^	Fees associated with an intercompany tolling agreement related to naphtha volumes.
---	---
^(2)^	Includes costs and expenses associated with our pipeline and facilities assets.
---	---
	Three Months Ended
---	---	---	---	---
	March 31,
	2025		2024
	(in thousands)
Capital expenditures
Refinery operations ^(1)^	$	139	$	-
Total capital expenditures	$	139	$	-
^(1)^	The $0.1 million capital expenditure was vendor financed.
---	---
		March 31,		December 31,
---	---	---	---	---
	2025		2024
	(in thousands)
Identifiable assets
Refinery operations	$	84,008	$	78,996
Tolling and terminaling		16,370		16,904
Corporate and other		5,206		5,996
Total identifiable assets	$	105,584	$	101,896
(5)	Prepaid Expenses and Other Current Assets
---	---

Prepaid expenses and other current assets, as of the dates indicated, consisted of the following:

		March 31,		December 31
	2025		2024
	(in thousands)
Surety bonds, current portion	$	905	$	-
Other prepaids		510		668
Prepaid easement renewal fees		4		9
Prepaid insurance		462		1,382
	$	1,881	$	2,059

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Notes to Consolidated Financial Statements (Continued)
(6)	Inventory
---	---

Inventory, as of the dates indicated, consisted of the following:

		March 31,		December 31
	2025		2024
	(in thousands)
HOBM	$	24,171	$	28,364
Jet fuel		3,699		3,403
Naphtha		8,501		2,814
Crude oil and condensate		1,024		754
AGO		134		157
Chemicals		219		154
Propane		9		13
LPG mix		20		3
	$	37,777	$	35,662

We incurred an inventory impairment expense of $0.3 million and $0.0 million for the three months ended March 31, 2025 and 2024, respectively.

(7)	Property, Plant and Equipment, Net

Property, plant and equipment, net, as of the dates indicated, consisted of the following:

		March 31,			December 31
	2025			2024
	(in thousands)
Refinery and facilities	$	72,776		$	72,776
Land		566			566
Other property and equipment		913			913
		74,255			74,255
Less: Accumulated depreciation and amortization		(26,178	)		(25,537	)
		48,077			48,718
Construction in progress		3,854			3,715
	$	51,931		$	52,433
(8)	Accrued Expenses and Other Current Liabilities
---	---

Accrued expenses and other current liabilities, as of the dates indicated, consisted of the following:

		March 31,		December 31
	2025		2024
	(in thousands)
Unearned revenue from contracts with customers	$	1,525	$	2,727
Accrued fines and penalties		2,613		2,146
Insurance		233		793
Taxes payable		220		427
Other payable		154		308
Customer deposits		163		163
Board of director fees payable		63		125
	$	4,971	$	6,689

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Notes to Consolidated Financial Statements (Continued)
(9)	Third-Party Long-Term Debt
---	---

Debt Agreements.****Blue Dolphin and certain subsidiaries are currently parties to the following debt agreements with third parties:

		Original		Monthly Principal
		Principal		and Interest Payment
Loan Description	Parties	(in millions)	Maturity	(in millions)	Interest Rate	Loan Purpose
Veritex Loans
LE Term Loan Due 2034 (in default)^(1)^	LE	$25.0	June 2034	$0.3	WSJ Prime + 2.75%	Capital improvements
	Veritex
LRM Term Loan Due 2034 (in default)^(1)^	LRM	$10.0	December 2034	$0.1	WSJ Prime + 2.75%	Capital improvements
	Veritex
Kissick Debt^(2)^	LE	$11.7	March 2025	$0.5	6.25%	Working capital
	Kissick Noteholder
GNCU Loan
NPS Term Loan Due 2031 (in default)^(3)^	NPS	$10.0	October 2031	$0.1	5.75%	Working capital
	GNCU
SBA Economic Injury Disaster Loans
Blue Dolphin Term Loan Due 2051^(4)^	Blue Dolphin	$2.0	June 2051	$0.01	3.75%	Working capital
	SBA
LE Term Loan Due 2050^(5)^	LE	$0.15	August 2050	$0.0007	3.75%	Working capital
	SBA
NPS Term Loan Due 2050^(5)^	NPS	$0.15	August 2050	$0.0007	3.75%	Working capital
	SBA
Equipment Loan Due 2025^(6)^	LE	$0.07	October 2025	$0.0013	4.5%	Equipment Purchase
	Texas First
Equipment Loan Due 2025 ^(7)^	LE	$0.138	March 2031	$0.0028	12.7%	Equipment Purchase
	Ritchie Bros. Financial Services
^(1)^	Our secured loan agreements with Veritex are subject to certain financial and non-financial covenants. As of March 31, 2025, LE and LRM were in default related to financial covenants under the LE Term Loan Due 2034 and LRM Term Loan Due 2034. With respect to non-financial covenants, we are required to have a balance of $1.0 million in a payment reserve account held by Veritex. At March 31, 2025 and December 31, 2024 restricted cash totaled $1.0 million.
---	---
^(2)^	Original principal amount was $8.0 million; pursuant to a 2017 sixth amendment, principal under the Kissick Debt increased by $3.7 million.
---	---
^(3)^	Loan requires monthly interest-only payments for the first thirty-six (36) months. Afterwards, principal and interest payments are due monthly through loan maturity. First principal payment commenced in November 2024. As of March 31, 2025 and the filing date of this report, the NPS Term Loan Due 2031 was in default due to non-financial covenant violations.
---	---
^(4)^	Original principal amount was $0.5 million; the Blue Dolphin Term Loan Due 2051 was modified to increase the principal amount by $1.5 million. Payments deferred for thirty (30) months; first payment commenced in November 2023; interest accrued during deferral period; loan not forgivable.
---	---
^(5)^	Payments deferred for thirty (30) months; first payment commenced in February 2023; interest accrued during deferral period; loan not forgivable.
---	---
^(6)^	In October 2020, LE entered into the Equipment Loan Due 2025 to purchase a backhoe; the backhoe is used at the Nixon facility.
---	---
^(7)^	In March 2025, LE entered into the Equipment Loan Due 2031 to purchase mobile offices; the mobile offices are used at the Nixon facility.

Outstanding Principal, Debt Issue Costs, and Accrued Interest. Third-party long-term debt, including outstanding original principal, as of the dates indicated, was as follows:

		March 31,			December 31,
	2025			2024
	(in thousands)
Veritex Loans
LE Term Loan Due 2034 (in default)	$	18,456		$	18,753
LRM Term Loan Due 2034 (in default)		7,679			7,793
Kissick Debt		-			1,432
GNCU Loan
NPS Term Loan Due 2031 (in default)		9,400			9,671
SBA Economic Injury Disaster Loans
Blue Dolphin Term Loan Due 2051		2,000			2,000
LE Term Loan Due 2050		150			150
NPS Term Loan Due 2050		150			150
Equipment Loan Due 2025		10			14
Equipment Loan Due 2031		139			-
		37,984			39,963
Less: Long-term debt, net, current portion		(33,868	)		(35,920	)
Less: Unamortized debt issue costs		(1,692	)		(1,743	)
	$	2,424		$	2,300

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Notes to Consolidated Financial Statements (Continued)

Unamortized debt issue costs associated with the Veritex and GNCU loans, as of the dates indicated, consisted of the following:

		March 31,			December 31,
	2025			2024
	(in thousands)
Veritex Loans
LE Term Loan Due 2034 (in default)	$	1,674		$	1,674
LRM Term Loan Due 2034 (in default)		768			768
GNCU Loan
NPS Term Loan Due 2031 (in default)		730			730
Less: Accumulated amortization		(1,480	)		(1,429	)
	$	1,692		$	1,743

Amortization expense was $0.1 million for both the three months ended March 31, 2025 and 2024.

Accrued interest related to third-party long-term debt, reflected as accrued interest payable in our consolidated balance sheets, as of the dates indicated, consisted of the following:

		March 31,			December 31,
	2025			2024
	(in thousands)
SBA Economic Injury Disaster Loans
Blue Dolphin Term Loan Due 2051	$	81		$	93
LE Term Loan Due 2050		8			8
NPS Term Loan Due 2053		8			8
Veritex Loans
LE Term Loan Due 2034 (in default)		48			48
LRM Term Loan Due 2034 (in default)		61			61
GNCU Loan
NPS Term Loan Due 2031 (in default)		17			17
Kissick Debt (in forbearance)		-			-
Equipment Loan Due 2025		-			-
		223			235
Less: Accrued interest payable, current portion		(223	)		(235	)
Long-term interest payable, net of current portion	$	-		$	-

We classified the debt associated with the LE Term Loan Due 2034, LRM Term Loan Due 2034, and NPS Term Loan Due 2031 within long-term debt, current portion on our consolidated balance sheets at March 31, 2025 and December 31, 2024 due to being in default.

Forbearance Agreements and Default.

Veritex Forbearance Agreements and Waivers. Under a November 2022 forbearance agreement, LE and LRM paid Veritex: (i) $4.3 million in past due principal and interest at the non-default rate (excluding late fees), (ii) $1.0 million into a payment reserve account, and (iii) $0.04 million in Veritex attorney fees. The Veritex forbearance agreement expired in September 2023, and was superseded by a first amendment. The first amendment expired in December 2023, and was superseded by a second amendment. The second amendment expired in March 2024. During each of these forbearance periods, Veritex agreed to forbear from testing borrowers’ compliance with financial covenants as specified in the LE Term Loan Due 2034 and LRM Term Loan Due 2034 and forbear from exercising its rights or remedies with respect to non-compliance with the financial covenants. On July 8, 2024, LE and LRM received a confirmation letter from Veritex dated July 2, 2024 waiving all covenant violations under the LE Term Loan Due 2034 and LRM Term Loan Due 2034 for calendar years 2021, 2022, and 2023. Pursuant to a letter dated June 25, 2024, the USDA approved Veritex's April 18, 2024 letter request for a waiver for the same periods.

Kissick Payment Agreement. Pursuant to a Payment Agreement between LE and the Kissick Noteholder dated April 30, 2023, the Kissick Noteholder agreed to forbear from exercising any of its rights and remedies related to a default pertaining to previous payment violations under the Kissick Debt. Under the terms of the Kissick payment agreement, LE agreed to make monthly principal and interest payments totaling $0.5 million beginning in April 2023, continuing on the first of each month through February 2025, with a final payment in March 2025. As of the filing date of this report, the Kissick Debt was paid in full.

Defaults. As of March 31, 2025 and through the filing date of this report, LE and LRM were in default related to financial covenants under the LE Term Loan Due 2034 and LRM Term Loan Due 2034, respectively. NPS was in default related to non-financial covenants under the NPS Term Loan Due 2031. Defaults may permit lenders to declare the amounts owed under the related loan agreements immediately due and payable, exercise their rights with respect to collateral securing obligors’ obligations, and exercise any other rights and remedies available. We can provide no assurance that: (i) our assets or cash flow will be sufficient to fully repay borrowings under secured loan agreements that are in default, either upon maturity or if accelerated, (ii) LE, LRM, or NPS will be able to refinance or restructure the debt, or (iii) third parties will provide future forbearances or default waivers, particularly if the banks with whom we have relationships fail. If one or more banks fail, we could be exposed to additional events of default (if not cured or waived) under existing secured loan agreements. Defaults under our secured loan agreements and any exercise by third parties of their rights and remedies related to such defaults may have a material adverse effect on our business, the trading price of our Common Stock, and on the value of an investment in our Common Stock, and holders of our Common Stock could lose their investment in our Common Stock in its entirety. If the debt associated with secured loan agreements is accelerated and we are unable to refinance or restructure the debt or obtain default waivers, we may have to consider other options, including selling assets, raising additional debt or equity capital, cutting costs, reducing cash requirements, filing bankruptcy, or ceasing operating. See “Notes (3) and (10)” to our consolidated financial statements for additional information regarding defaults under our secured loan agreements with related parties and third parties and their potential effects on our business, financial condition, and results of operations.

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Notes to Consolidated Financial Statements (Continued)

Guarantees and Security.

Loan Description	Guarantees	Security
Veritex Loans
LE Term Loan Due 2034 (in default)	● USDA	●	First priority lien on Nixon facility’s business assets (excluding accounts receivable and inventory)
	● Jonathan Carroll^(1)^	●	Assignment of all Nixon facility contracts, permits, and licenses
	● Affiliate cross-guarantees	●	Absolute assignment of Nixon facility rents and leases, including tank rental income
		●	$5.0 million life insurance policy on Jonathan Carroll
LRM Term Loan Due 2034 (in default)	● USDA	●	Second priority lien on rights of LE in crude distillation tower and other collateral of LE
	● Jonathan Carroll^(1)^	●	First priority lien on real property interests of LRM
	● Affiliate cross-guarantees	●	First priority lien on all LRM fixtures, furniture, machinery, and equipment
		●	First priority lien on all LRM contractual rights, general intangibles, and instruments, except with respect to LRM rights in its leases of certain specified tanks for which Veritex has second priority lien
		●	Substantially all assets
Kissick Debt	---	●	Subordinated deed of trust that encumbers the crude distillation tower and general assets of LE
GNCU Loan
NPS Term Loan Due 2031 (in default)	● USDA	●	Deed of trust lien on approximately 56 acres of land and improvements owned by LE
	● Jonathan Carroll^(1)^	●	Leasehold deed of trust lien on certain property leased by NPS from LE
	● Affiliate cross-guarantees	●	Assignment of leases and rents and certain personal property
SBA EIDL
BDEC Term Loan Due 2051	---	●	Business assets (e.g., machinery and equipment, furniture, fixtures, etc.)
LE Term Loan Due 2050	---	●	Business assets (e.g., machinery and equipment, furniture, fixtures, etc.)
NPS Term Loan Due 2050	---	●	Business assets (e.g., machinery and equipment, furniture, fixtures, etc.)
Equipment Loan Due 2025	---	●	First priority security interest in the equipment (backhoe)
Equipment Loan Due 2031	---	●	First priority security interest in the equipment (mobile offices)
^(1)^	Veritex required Jonathan Carroll to personally guarantee repayment of borrowed funds and accrued interest.
---	---

Representations, Warranties, and Covenants. The First Term Loan Due 2034, Second Term Loan Due 2034, NPS Term Loan Due 2031, BDEC Term Loan Due 2051, LE Term Loan Due 2050, and NPS Term Loan Due 2050 contain representations and warranties, affirmative and negative covenants, and events of default that we consider usual and customary for bank facilities of these types. Specifically, The First Term Loan Due 2034 and Second Term Loan Due 2034 contain quarterly debt service coverage, total combined current assets, total combined current liabilities, and total combined debt ratios and annual current and debt to net worth ratios. The First Term Loan Due 2034 also requires that a $1.0 million payment reserve account be maintained. The NPS Term Loan Due 2031 requires NPS to have an active deposit account with the lender, provide standalone audited financial statements for NPS, a wholly owned subsidiary, and meet annual maintenance of debt service coverage and current ratios. There are no covenants associated with the Kissick Debt, BDEC Term Loan Due 2051, LE Term Loan Due 2050, NPS Term Loan Due 2050, the Equipment Loan Due 2025, and the Equipment Loan Due 2031.

(10)	AROs

Refinery and Facilities. Management has concluded that there is no legal or contractual obligation to dismantle or remove our refinery and facilities assets. Management believes that our refinery and facilities assets have indeterminate lives under FASB ASC guidance for estimating AROs because dates or ranges of dates upon which we would retire these assets cannot reasonably be estimated at this time. When a legal or contractual obligation to dismantle or remove refinery and facilities assets arises and a date or range of dates can reasonably be estimated for the retirement of these assets, we will estimate the cost of performing the retirement activities and record a liability for the fair value of that cost using present value techniques.

Pipelines and Facilities and Oil and Gas Properties. We have AROs associated with decommissioning our pipelines and facilities assets, as well as for plugging and abandoning our oil and gas properties. We recorded a liability for the fair value of an ARO at the time the asset was installed or placed in service. From time to time we adjust the liability due to changes in estimates or the timing of decommissioning the assets. ARO liability as of the dates indicated was as follows:

		March 31,		December 31
	2025		2024
	(in thousands)
AROs, at the beginning of the period	$	2,999	$	4,504
Liabilities settled		-		(1,505	)
		2,999		2,999
Less: AROs, current portion		2,999		2,999
Long-term AROs, at the end of the period	$	-	$	-

BDPL maintained $3.0 million in AROs related to decommissioning pipeline and facilities assets at both March 31, 2025 and December 31, 2024, respectively. During the three months ended March 31, 2024, we settled ARO liabilities totaling $1.5 million related to our pipeline and facilities assets. We also incurred approximately $0.9 million in additional decommissioning related expenses during the three months ended March 31, 2024due to the impact of poor weather conditions.

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Notes to Consolidated Financial Statements (Continued)

BSEE mandated that our pipelines and facilities assets offshore in federal waters be decommissioned due to their extended period of inactivity. In October 2023, management met with BSEE to discuss BDPL’s path forward for meeting decommissioning requirements. Management worked with a consultant to develop a decommissioning plan, and BDPL completed Phase I of the project from late December 2023to mid- February 2024. However, in July 2024, BDPL requested a BSEE extension to decommission the remaining phases of the project until the second quarter of 2025 due to significant cost overruns. BDPL’s extension request was denied by BSEE in *September 2024.*On March 17, 2025, BSEE issued BDPL an INC for failing to comply with certain of its decommissioning obligations. Management is currently assessing the feasibility and cost of performing remaining decommissioning work. Separately, management is also exploring alternatives to reactivate the assets under a potential alternate Right-of-Use and Easement (RUE). BDPL's delay in decommissioning its offshore assets does not relieve BDPL of its obligations to comply with BSEE's mandate or of BSEE's authority to impose civil penalties. Further, there can be no assurance that BDPL will be able to complete the anticipated work or predict the outcome of BSEE INCs. If BDPL is unable to perform its decommissioning obligations, BOEM may exercise its rights under supplemental pipeline bonds or exercise any other rights and remedies it has available.

BSEE Civil Penalties. BDPL has the following open civil penalty referrals from BSEE:

●	Civil Penalty G-2024-054. In August 2024,BDPL received a civil penalty referral letter from BSEE for failing to timely remove its GA-288C junction platform offshore in federal waters. The civil penalty referral is associated with BSEE INC No. G-114 issued in October 2023.In March 2025,BSEE calculated a proposed civil penalty of $1.0 million against BDPL, and BSEE reserved its rights to assess additional civil penalties in the amount of $3,097 per day until the referenced INC is fully remediated. In April 2025, BDPL exercised its right to request a meeting with the penalty reviewing officer to submit additional information for consideration. This meeting has not yet been scheduled. At March 31, 2025, we accrued $0.7 million on our balance sheet within accrued expenses and other current liabilities related to this matter. We will record a liability of approximately $0.3 million per quarter related to potential penalties associated with Civil Penalty G-2024-054.
●	Civil Penalty G-2024-056. In August 2024,BDPL received a civil penalty referral letter from BSEE for failing to timely flush, fill, and abandon its lateral pipeline from GA-245 to the GA-273 subsea tie-in (Pipeline Segment No. 15635) offshore in federal waters. The civil penalty referral is associated with BSEE INC No. G-802 issued in November 2023.In January 2025,BSEE calculated a proposed civil penalty of $0.4 million against BDPL, and BSEE reserved its right to assess additional civil penalties in the amount of $3,097 per day until the referenced INC is fully remediated. In March 2025,BDPL exercised its right to request a meeting with the penalty reviewing officer to submit additional information for consideration. This meeting has not yet been scheduled. At March 31, 2025, we accrued $0.4 million on our balance sheet within accrued expenses and other current liabilities related to this matter. We will record a liability of approximately $0.3 million per quarter related to potential penalties associated with Civil Penalty G-2024-056. 2024
	---	---
	●	Civil Penalty G--010. In April 2024,BDPL received a civil penalty referral letter from BSEE for failing to remediate certain BSEE INCs issued in September 2023associated with its GA-288C junction platform offshore in federal waters. Specifically, remediation is associated with BSEE INC Nos. E120 (physically boarding platform monthly, performing visual inspections for environmental pollution, and maintaining monthly inspection records), G112 (timely removing 55-gallon drum leaking oil on platform deck), L141 (timely flushing and filling Pipeline Segment No. 13101 with inhibited seawater), and L142 (timely decommissioning in place Pipeline Segment No. 13101). In March 2025,BSEE calculated a proposed civil penalty of $1.1 million against BDPL. In April 2025, BDPL exercised its right to request a meeting with the penalty reviewing officer to submit additional information for consideration. This meeting has not yet been scheduled. At March 31, 2025, we accrued $1.1 million on our balance sheet within accrued expenses and other current liabilities related to this matter.
---	---

See "Note ( 14)" for additional disclosures related to AROs and BSEE civil penalties.

(11)	Lease Obligations

Lease Obligations

Office Lease. We maintain our corporate headquarters in Houston, Texas. In October 2024, BDSC signed a new 24-month extension, the sixth amendment, to its operating lease. The sixth amendment was deemed to be a separate contract and not a lease modification.

An Affiliate, LEH, sub-leases a portion of the Houston office space. BDSC received sub-lease income from LEH totaling $0.03 million for both three months ended March 31, 2025 and 2024. See “Notes ( 3)” to our consolidated financial statements for additional disclosures related to the Affiliate sub-lease.

Tank Lease. LE leases tanks from Ingleside under the Second Amended and Restated Master Services Agreement. Lease expense associated with the Second Amended and Restated Master Services Agreement totaled $0.3 million for both the three months ended March 31, 2025 and 2024. Due to its one-year term, the lease is being treated as short term. As a result, the lease was not recorded on our balance sheet. See “Note ( 3)” to our consolidated financial statements for additional disclosures related to the Second Amended and Restated Master Services Agreement.

The following table presents the lease-related assets and liabilities recorded on the consolidated balance sheet:

			March 31,			December 31
	Balance Sheet Location	2025			2024
		(in thousands)
Assets
Operating lease ROU assets	Operating lease ROU assets	$	497		$	497
Less: Accumulated amortization on operating lease assets	Operating lease ROU assets		(106	)		(41	)
Total lease assets			391			456
Liabilities
Current
Operating lease	Current portion of lease liabilities		268			264
Noncurrent
Operating lease	Long-term lease liabilities, net of current		147			191
Total lease liabilities		$	415		$	455

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Notes to Consolidated Financial Statements (Continued)
Weighted average remaining lease term in years
---	---
Operating lease	1.42
Weighted average discount rate
Operating lease	8.25%

The following table presents information related to lease costs incurred for operating and finance leases:

	Three Months Ended
	March 31,
	2025		2024
	(in thousands)
Operating lease costs	$	64	$	62
Short-term lease expense, related party		300		300
Total lease cost	$	364	$	362

The table below presents supplemental cash flow information related to leases as follows:

	Three Months Ended
	March 31,
	2025		2024
	(in thousands)
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows for operating lease	$	72	$	54

As of March 31, 2025, maturities of lease liabilities for the periods indicated was as follows:

March 31,	Operating Lease
	(in thousands)
2025	$	224
2026		191
	$	415

Future minimum annual lease commitments that are non-cancelable:

March 31,	Operating Lease
	(in thousands)
2025	$	224
2026		191
	$	415
(12)	Income Taxes
---	---

The Inflation Reduction Act ("IRA") was enacted in August 2022. The IRA imposes a 15% alternative minimum tax on corporations whose average annual adjusted financial statement income during the most recently completed three-year period exceeds $1.0 billion. We do not fall within the “applicable corporations” category and are therefore exempt from paying an alternative minimum tax.

Tax Provision. The provision for income tax benefit (expense) for the periods indicated was as follows:

	Three Months Ended
	March 31,
	2025			2024
	(in thousands)
Current
Federal	$	(69	)	$	(215	)
State		(38	)		(81	)
Deferred
Federal		(528	)		(1,545	)
Change in valuation allowance		-			-
Total provision for income taxes	$	(635	)	$	(1,841	)

We record income tax related interest and penalties, if applicable, as a component of the provision for income tax expense. Furthermore, none of our federal and state income tax returns are currently under examination by the IRS or state authorities. As of the three months ended March 31, 2025, fiscal years 2021 and later remain subject to examination by the IRS and fiscal years 2020 and later remain subject to examination by the State of Texas. We believe there are no uncertain tax positions for both federal and state income taxes.

U.S. GAAP treats Texas margins tax, a form of business tax imposed on an entity’s gross profit rather than its net income, like an income tax for financial reporting purposes.

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Notes to Consolidated Financial Statements (Continued)

Deferred income taxes as of the dates indicated consisted of the following:

		March 31,			December 31,
	2025			2024
	(in thousands)
Deferred tax assets:
NOL and capital loss carryforwards	$	6,226		$	6,771
Business interest expense		3,833			3,792
Start-up costs (crude oil and condensate processing facility)		148			169
ARO liability/deferred revenue		630			630
Other		71			76
Total deferred tax assets		10,908			11,438
Deferred tax liabilities:
Basis differences in property and equipment		(8,446	)		(8,448	)
Deferred tax assets, net	$	2,462		$	2,990

Deferred Income Taxes. Balances for deferred income tax represent the effects of temporary differences between carrying amounts and the actual income tax basis of our assets and liabilities; the balances also reflect NOL carryforwards. We record the balances based on tax rates we expect to be in effect when paid. NOL carryforwards and deferred tax assets represent amounts available to reduce future taxable income.

Valuation Allowance. As of each reporting date, management considers new evidence, both positive and negative, to determine the realizability of deferred tax assets. This assessment (of whether there is more than a 50% probability that our deferred tax asset is realizable) depends on the generation of future taxable income before the expiration of any NOL carryforwards. We recorded no valuation allowance against our deferred tax assets as of March 31, 2025 and December 31, 2024.

At March 31, 2025, there were no uncertain tax positions for which a reserve or liability was necessary.

NOL Carryforwards. Under IRC Section 382, a corporation that undergoes an “ownership change” is subject to limitations on using pre-change NOL carryforwards to offset future taxable income. Within the meaning of IRC Section 382, an “ownership change” occurs when the aggregate stock ownership of stockholders who own more than 5% (after applying certain look-through rules) increases by more than fifty percent [50% over such stockholders’ lowest percentage ownership during the testing period (generally three years)]. Based on the tax rule, ownership changes occurred in 2005 and 2012. The 2005 ownership change related to a series of private placements; the 2012 ownership change related to a reverse acquisition.

The 2005 and 2012 ownership changes limit the use of pre-change NOL carryforwards to offset future taxable income. The annual use limitation generally equals the value of the common stock, on an aggregate basis, when the ownership change occurred multiplied by a specified tax-exempt interest rate. The 2012 ownership change will subject approximately $16.3 million in NOL carryforwards generated before the ownership change to an annual use limitation of approximately $0.6 million per year. We mayuse any unused portions of the limitation in subsequent years. Because of the yearly restriction, approximately $6.7 million in NOL carryforwards generated before the 2012 ownership change will expire unused and are excluded in the NOL carryforward presented below. NOL carryforwards generated after the 2012 ownership change but before 2018 are not subject to an annual use limitation; we can use these NOL carryforwards for 20 years in addition to NOL carryforward amounts generated before the ownership change. NOL carryforwards generated beginning in 2018 mayonly be used to offset 80% of taxable income and are carried forward indefinitely.

NOL carryforwards that remained available for future use for the periods indicated was as follows (amounts shown are net of NOLs that will expire unused because of the IRC Section 382 limitation):

	Net Operating Loss Carryforward
	Pre-Ownership			Post-Ownership
	Change			Change			Total
	(in thousands)
Balance at December 31, 2023	$	4,509		$	24,131		$	28,640
Net operating losses used and expired		(638	)		4,243			3,605
Balance at December 31, 2024	$	3,871		$	28,374		$	32,245
Net operating losses		(1,276	)		(1,320	)		(2,596	)
Balance at March 31, 2025	$	2,595		$	27,054		$	29,649

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Notes to Consolidated Financial Statements (Continued)
(13)	Earnings and Dividends Per Share
---	---

A reconciliation between basic and diluted income per share for the periods indicated was as follows:

	Three Months Ended
	March 31,
	2025		2024
	(in thousands,
	except share and per share amounts)
Net income	$	2,244	$	6,624
Basic and diluted earnings per share	$	0.15	$	0.44
Basic and diluted shares used in computing earnings per share		14,921,968		14,921,968

Diluted EPS for the three months ended March 31, 2025 and 2024 was the same as basic EPS as there were no stock options or other dilutive instruments outstanding. Basic and diluted EPS is computed by dividing net income (loss) available to common stockholders by the weighted average number of shares of common stock outstanding.

Stockholders are entitled to receive such dividends as maybe declared by our Board out of funds legally available for such purpose. However, no dividend maybe declared or paid unless after-tax profit was made in the preceding fiscal year, we comply with covenants in our secured loan agreements, we are current on all required debt payments, and we have received prior written concurrence from certain lenders.

(14)	Commitments and Contingencies

Fourth Amended and Restated Operating Agreement. See “Note (3)” to our consolidated financial statements for additional disclosures related to operation and management of all Blue Dolphin assets by an Affiliate under the Fourth Amended and Restated Operating Agreement and modifications to this agreement.

Defaults Under Secured Loan Agreements. See “Note ( 9)” to our consolidated financial statements for additional information regarding defaults under secured loan agreements with related parties and third parties and their potential effects on our business, financial condition, and results of operations.

Financing Agreements and Guarantees

Indebtedness. See “Notes ( 3) and ( 9)” to our consolidated financial statements for disclosures related to related-party and third-party indebtedness and defaults thereto.

Guarantees. Affiliates provided guarantees on certain debt of Blue Dolphin and its subsidiaries. The maximum amount of any guarantee is equal to the principal amount and accrued interest, which amounts are reduced as payments are made. See “Notes ( 3) and ( 9)” to our consolidated financial statements for additional disclosures related to related-party and third-party guarantees associated with indebtedness and defaults thereto.

Health, Safety and Environmental Matters. The operations of certain Blue Dolphin subsidiaries are subject to extensive federal, state, and local environmental, health, and safety regulations governing, among other things, the generation, storage, handling, use and transportation of petroleum products and hazardous substances; the emission and discharge of materials into the environment; waste management; characteristics and composition of jet fuel and other products; and the monitoring, reporting and control of air emissions. These operations also require numerous permits and authorizations under various environmental, health, and safety laws and regulations. Failing to obtain and comply with these permits or environmental, health, or safety laws could result in fines, penalties or other sanctions, or a revocation of our permits.

Legal Matters. In the ordinary course of business, we are involved in legal matters incidental to the routine operation of our business, such as mechanic’s liens and contract-related disputes. We mayalso become party to lawsuits, administrative proceedings, and governmental investigations, including environmental, regulatory, and other matters. Large, sometimes unspecified, damages or penalties maybe sought from us in some matters, which mayrequire years to resolve. Although we cannot provide assurance, we believe that an adverse resolution of the matters described below would not have a material impact on our liquidity, consolidated financial position, or consolidated results of operations.

Resolved Matters .

RLI Corp. Surety Bonds. Blue Dolphin currently has several surety bonds through RLI Corp. as required by different regulatory agencies, including BOEM and the Railroad Commission of Texas. The bonds total approximately $1.25 million in the aggregate. In *February 2024,*RLI Corp. filed suit against Blue Dolphin, BDPL, and BDEX seeking an injunction to fully collateralize the bonds in cash, representing an increase of $1.0 million. Although BDPL filed its answer to RLI Corp.'s lawsuit in April 2024 denying RLI Corp.'s claims, in July 2024 BDPL presented a settlement proposal to RLI Corp. to resolve the matter through a series of cash payments. In July 2024, RLI Corp. informed the court that the parties reached a settlement in principle, and the parties executed a settlement agreement in September 2024. From September 2024 to March 31, 2025, BDPL made payments to RLI Corp. under the settlement agreement totaling $1.0 million, bringing the total surety bond amount to $1.2 million in cash. Once BDPL’s offshore pipeline and platform assets have been decommissionined, BDPL can request that BOEM cancel the associated supplemental pipeline bonds. As a result, RLI Corp. would release the cash collateral tied to the associated supplemental pipeline bonds to BDPL.

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Notes to Consolidated Financial Statements (Continued)

TCEQ Final Agreed Order. In October 2021, LRM received a proposed agreed order from the TCEQ for alleged solid and hazardous waste violations discovered during an investigation from January to March 2020. The proposed agreed order assessed an administrative penalty of $0.4 million and identified actions needed to correct the alleged violations. In September 2023, TCEQ presented its final penalty offer of $0.35 million, which LRM accepted. Although LRM believed the penalty matter was resolved in *September 2023,*TCEQ referred the matter to the State Office of Administrative Hearings ("SOAH"). A preliminary hearing, the purpose of which was to set a hearing schedule, was held on August 8, 2024; management participated in the hearing. Although a follow-up hearing was scheduled for January 2025, TCEQ presented, and LRM signed, a revised draft Agreed Order in November 2024. Under the terms of the revised draft Agreed Order, TCEQ acknowledged that LRM had ceased unauthorized disposal of industrial solid waste and industrial hazardous waste and LRM accepted a final penalty amount of approximately $0.4 million, which will be paid in monthly installments over a three-year period. The SOAH case was dismissed and the matter was remanded back to the TCEQ in December 2024; TCEQ finalized the Agreed Order in February 2025.

Unresolved Matters

BOEM Supplemental Pipeline Bonds. To cover the various obligations of lessees and rights-of-way holders operating in federal waters of the U.S. Gulf of America, BOEM evaluates an operator’s financial ability to carry out present and future obligations to determine whether the operator must provide additional security beyond the statutory bonding requirements. Such obligations include the cost of plugging and abandoning wells and decommissioning pipelines and platforms at the end of production or service activities. Once plugging and abandonment work has been completed, the collateral backing the financial assurance is released by BOEM. In *March 2018,*BOEM ordered BDPL to provide additional financial assurance totaling approximately $5.7 million for five ( 5) existing pipeline rights-of-way, representing an increase of $4.8 million. Historically, BDPL maintained $0.9 million in pipeline bonds with BOEM to decommission its trunk pipeline offshore in federal waters. In *June 2018,*BOEM issued BDPL INCs for each right-of-way that failed to comply. In *June 2018,*BDPL appealed the INCs to the IBLA, filing its statement of reasons in *July 2018.*In *February 2025,*the USDOI directed BOEM and BDPL to submit either a joint status report, or separate status reports, to update the court relative to the facts in the case. If joint, submissions were due by *March 11, 2025;*if separate, BOEM’s submission was due by March 11, 2025and BDPL’s response to BOEM’s submission was due by March 25, 2025. Although BOEM submitted its report by its respective deadline, BDPL missed its deadline as notifications were sent to BDPL’s former counsel in the matter. On *March 10, 2025,*the USDOI notified BDPL by letter that the agency granted BDPL until March 31, 2025to submit its response; however, management was not in receipt of the USDOI’s notification letter until March 25, 2025. On *March 27, 2025,*BDPL filed a motion through new counsel requesting an extension of its deadline to file its status report response no later than April 30, 2025; BDPL filed the required status report response to the court on April 24, 2025.

BDPL’s pending appeal of the BOEM INCs does not relieve BDPL of its obligations to provide additional financial assurance or of BOEM’s authority to impose financial penalties. There can be no assurance that we will be able to meet additional supplemental pipeline bond requirements. If BDPL is required by BOEM to provide significant additional supplemental pipeline bonds or is assessed significant penalties under the INCs, we will experience a significant and material adverse effect on our operations, liquidity, and financial condition. We cannot predict the outcome of the supplemental pipeline bond INCs. Accordingly, we did not record a liability on our consolidated balance sheets as of March 31, 2025 and December 31, 2024. At both March 31, 2025 and December 31, 2024, BDPL maintained $0.9 million in cash-backed pipeline bonds issued to the BOEM through RLI Corp.

BSEE Offshore Platform Inspections, Decommissioning Obligations, and Civil Penalties. BDPL has pipelines and platform assets subject to BSEE’s idle iron regulations. Idle iron regulations require lessees and rights-of-way holders to permanently abandon and remove platforms and other structures when they are no longer useful for operations. Until such structures are abandoned or removed, lessees and rights-of-way holders are required to inspect and maintain the assets in accordance with regulatory requirements.

Platform Inspection Obligation. For our offshore platform in federal waters, we are required by BSEE to perform annual structural inspections and monthly navigational aid, fog horn, lifesaving equipment, and pollution checks. On *April 9, 2025,*BSEE issued BDPL an INC for failing to conduct monthly platform pollution inspections; BDPL corrected the INC on April 22, 2025.

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Notes to Consolidated Financial Statements (Continued)

Decommissioning Obligations. BSEE mandated that our pipelines and facilities assets offshore in federal waters be decommissioned due to their extended period of inactivity. In October 2023, management met with BSEE to discuss BDPL’s path forward for meeting decommissioning requirements. Management worked with a consultant to develop a decommissioning plan, and BDPL completed Phase I of the project from late December 2023to mid- February 2024. However, in July 2024, BDPL requested a BSEE extension to decommission the remaining phases of the decommissioning project until the second quarter of 2025 due to significant cost overruns. BDPL’s extension request was denied by BSEE in *September 2024.*On March 17, 2025, BSEE issued BDPL an INC for failing to comply with certain of its decommissioning obligations. Management is currently assessing the feasibility and cost of performing remaining decommissioning work. Separately, management is also exploring alternatives to reactivate the assets under a potential alternate Right-of-Use and Easement (RUE). BDPL's delay in decommissioning its offshore assets does not relieve BDPL of its obligations to comply with BSEE's mandate or of BSEE's authority to impose civil penalties. Further, there can be no assurance that BDPL will be able to complete the anticipated work or predict the outcome of BSEE INCs. If BDPL is unable to perform its decommissioning obligations, BOEM may exercise its rights under supplemental pipeline bonds or exercise any other rights and remedies it has available.

BSEE Civil Penalties. BDPL has the following open civil penalty referrals from BSEE:

●	Civil Penalty G-2024-054. In August 2024,BDPL received a civil penalty referral letter from BSEE for failing to timely remove its GA-288C junction platform offshore in federal waters. The civil penalty referral is associated with BSEE INC No. G-114 issued in October 2023.In March 2025,BSEE calculated a proposed civil penalty of $1.0 million against BDPL, and BSEE reserved its rights to assess additional civil penalties in the amount of $3,097 per day until the referenced INC is fully remediated. In April 2025, BDPL exercised its right to request a meeting with the penalty reviewing officer to submit additional information for consideration. This meeting has not yet been scheduled. At March 31, 2025, we accrued $0.7 million on our balance sheet within accrued expenses and other current liabilities related to this matter. We will record a liability of approximately $0.3 million per quarter related to potential penalties associated with Civil Penalty G-2024-054.
●	Civil Penalty G-2024-056. In August 2024,BDPL received a civil penalty referral letter from BSEE for failing to timely flush, fill, and abandon its lateral pipeline from GA-245 to the GA-273 subsea tie-in (Pipeline Segment No. 15635) offshore in federal waters. The civil penalty referral is associated with BSEE INC No. G-802 issued in November 2023.In January 2025,BSEE calculated a proposed civil penalty of $0.4 million against BDPL, and BSEE reserved its right to assess additional civil penalties in the amount of $3,097 per day until the referenced INC is fully remediated. In March 2025,BDPL exercised its right to request a meeting with the penalty reviewing officer to submit additional information for consideration. This meeting has not yet been scheduled. At March 31, 2025, we accrued $0.4 million on our balance sheet within accrued expenses and other current liabilities related to this matter. We will record a liability of approximately $0.3 million per quarter related to potential penalties associated with Civil Penalty G-2024-056.
---	---
●	Civil Penalty G-2024-010. In April 2024,BDPL received a civil penalty referral letter from BSEE for failing to remediate certain BSEE INCs issued in September 2023associated with its GA-288C junction platform offshore in federal waters. Specifically, remediation is associated with BSEE INC Nos. E120 (physically boarding platform monthly, performing visual inspections for environmental pollution, and maintaining monthly inspection records), G112 (timely removing 55-gallon drum leaking oil on platform deck), L141 (timely flushing and filling Pipeline Segment No. 13101 with inhibited seawater), and L142 (timely decommissioning in place Pipeline Segment No. 13101). In March 2025,BSEE calculated a proposed civil penalty of $1.1 million against BDPL. In April 2025, BDPL exercised its right to request a meeting with the penalty reviewing officer to submit additional information for consideration. This meeting has not yet been scheduled. At March 31, 2025, we accrued $1.1 million on our balance sheet within accrued expenses and other current liabilities related to this matter.
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis is management’s perspective of our current financial condition and results of operations, as well as significant trends that may affect future performance. All statements in this section, other than statements of historical fact, are forward-looking statements that are inherently uncertain. See "Important Information Regarding Forward-Looking Statements” for a discussion of the factors that could cause actual results to differ materially from those projected in these statements. You should read the following discussion together with the financial statements and the related notes included elsewhere in this report, as well as with the business strategy, risk factors, and financial statements and related notes included thereto in our Annual Report on Form 10-K for the fiscal year ended December 31, 2024.

Company Overview

Blue Dolphin was formed in 1986 as a Delaware corporation. The company is an independent downstream energy company operating in the Gulf Coast region of the U.S. Operations primarily consist of a light sweet-crude, 15,000-bpd crude distillation tower, and approximately 1.25 million bbls of petroleum storage tank capacity in Nixon, Texas. Blue Dolphin trades on the OTCQX under the ticker symbol “BDCO.”

Unless the context otherwise requires, references in this report to “we,” “us,” “our,” or “ours” refer to Blue Dolphin, one or more of its consolidated subsidiaries, or all of them taken as a whole.

Jonathan Carroll, our Chief Executive Officer, and an Affiliate together controlled 84.1% of the voting power of our Common Stock as of the filing date of this report. An Affiliate also operates and manages all Blue Dolphin properties, funds working capital requirements during periods of working capital deficits, guarantees certain of our third-party secured debt, and is a significant customer. Blue Dolphin and certain subsidiaries are currently parties to various agreements with Affiliates. See “Part I, Item 1. Financial Statements – Note (3)” for additional disclosures related to Affiliate agreements, arrangements, and risks associated with working capital deficits.

Business Operations Update

For the three months ended March 31, 2025, refining margins were less favorable compared to the three months ended March 31, 2024. Less favorable refining margins on lower sales volumes contributed to Blue Dolphin reporting net income of $2.2 million, or $0.15 per share, for the three months ended March 31, 2025 ("2025") compared net income of $6.6 million, or $0.44 per share, for the three months ended March 31, 2024 (“2024”).

Our full operating results for the three ended March 31, 2025 and March 31, 2024, including results by segment, can be found within ‘Results of Operations.’

We used cash flow from operations of $1.7 million for the three months ended March 31, 2025. The use of cash flow from operations was primarily due to a buildup of inventory. Inventory increased due primarily to unfavorable product pricing, limited opportunities for customers who export to Mexico, and an intentional buildup of inventory by us during periods of low refining margins. At March 31, 2025, we had $1.3 million in cash and cash equivalents. The components of our liquidity and descriptions of our cash flows, capital investments, and other matters impacting our liquidity and capital resources can be found within ‘Liquidity and Capital Resources.’

General Trends and Outlook

Uncertainties remain surrounding general macroeconomic conditions related to inflation, tariffs, interest rates, capital and credit markets, and geopolitical tensions (including military conflicts in Ukraine and Israel and escalations in the Middle East). We do not operate or own assets in Russia, Ukraine, or the Middle East. However, the extent to which these factors impact our working capital, commodity prices, refined product demand, supply chain, financial condition, liquidity, results of operations, and future prospects will depend on future developments, which cannot be predicted with any degree of confidence. While it is difficult to predict the ultimate economic impacts of these factors on our operations, below are key factors that impacted our results of operations so far in 2025 and will likely impact our results of operations for the rest of 2025:

●	Light crude oil commodity pricing and demand.
●	Jet fuel commodity pricing and demand.
●	Naphtha commodity pricing and demand.
---	---

We can provide no guarantees that: our business strategy will be successful, Affiliates will continue to fund our working capital needs when we experience working capital deficits, we will meet regulatory requirements to provide additional financial assurance (supplemental pipeline bonds) and decommission offshore pipelines and platform assets, we can obtain additional financing on commercially reasonable terms or at all, or margins on our refined products will be favorable. Further, if lenders exercise their rights and remedies under secured loan agreements that are in default, our business, financial condition, and results of operations will be materially adversely affected.

Liquidity and Access to Capital Markets

We continue efforts to improve our balance sheet. In March 2025, we fully repaid our debt obligation to the Kissick Noteholder, and we continue to engage with potential lenders to obtain additional funding to refinance and restructure our debt. There can be no assurance that we will be able to raise additional capital on acceptable terms, if at all, or refinance existing debt. If we are unable to refinance or restructure our debt, certain of which is currently in default, or forbear or waive defaults and lenders exercise their rights with respect to the debt, we may not, in the short term, be able to purchase crude oil and condensate or meet debt payment obligations. In the long term, we may not be able to manage business disruptions or execute our business strategy. We may have to consider other options, such as selling assets, raising additional debt or equity capital, filing bankruptcy, or ceasing operations.

Regulation Changes

Our operations and the operations of our customers have been, and will continue to be, affected by political developments and federal, state, tribal, local, and other laws and regulations that are increasing in number and becoming more stringent and complex. These laws and regulations include, among other things, permitting requirements, environmental protection measures such as limitations on methane and other GHG emissions, and renewable fuels standards. The number and scope of the regulations with which we and our customers must comply has a meaningful impact on our and their businesses, and new or revised regulations, reinterpretations of existing regulations, and permitting delays or denials could adversely affect the profitability of our assets.

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Management’s Discussion and Analysis (Continued)

Business Strategy and Accomplishments

We have outlined the below strategic business objectives to improve our financial profile and refining margins. These objectives are modified, as necessary, to reflect changing economic conditions and other circumstances.

Optimize Existing Asset Base	● Maintain safe operations and enhance health, safety, and environmental systems.<br> <br>● Plan and manage turnarounds and downtime.
Improve Operational Efficiencies	● Reduce or streamline variable costs incurred in production.<br> <br>● Increase throughput capacity and optimize product slate.<br> <br>● Increase tolling and terminaling revenue.
Seize Market Opportunities	● Leverage existing infrastructure to engage in renewable energy projects.<br> <br>● Take advantage of market opportunities as they arise.

Successful execution of our business strategy depends on multiple factors. These factors include (i) having adequate working capital to meet operational needs and regulatory requirements, (ii) maintaining safe and reliable operations at the Nixon facility, (iii) meeting contractual obligations, (iv) having favorable margins on refined products, and (v) collaborating with new partners to develop and finance clean energy projects. Our business strategy involves risks. Accordingly, we cannot assure investors that our plans will be successful. If we are unsuccessful, we would likely have to consider other options, such as selling assets, raising additional debt or equity capital, cutting costs, or otherwise reducing our cash requirements, negotiating with our creditors to restructure our applicable obligations, filing bankruptcy, or ceasing operating. In such a case, the trading price of our common stock and the value of an investment in our common stock could significantly decrease, which could lead to holders of our common stock losing their investment in our common stock in its entirety.

Optimize Existing Asset Base. During the three months ended March 31, 2025, the Nixon facility performed optimally, experiencing only one day of downtime. Comparatively, the Nixon facility experienced 5 days of downtime for the three months ended March 31, 2024 due to frigid weather (3 days) and repairs and maintenance (2 days).

Improve Operational Efficiencies. During the three months ended March 31, 2025 we optimized the efficiency of the Nixon refinery's flare gas monitoring system. Improvements to the flare gas system will reduce greenhouse gas emissions, optimize combustion efficiency, and lower operational costs.

Seize Market Opportunities. In 2021, we announced plans to leverage our existing infrastructure to establish adjacent lines of business, capture growing market opportunities, and capitalize on renewable energy growth. Management continues to explore renewable opportunities with potential commercial partners. However, reductions or modifications to, or the elimination of, governmental incentives or policies that support renewable energy or the imposition of additional taxes, tariffs, duties, or other assessments on renewable energy projects, could result in, among other things, the lack of a satisfactory market for the development or financing of new renewable energy projects and us abandoning the development of renewable energy projects.

Our Operations

Our assets are organized into two business segments:

●	refinery operations (also referred to herein as downstream operations), which is owned by LE; and
●	tolling and terminaling services (also referred to herein as midstream operations), which is owned by LRM and NPS
---	---

Downstream Operations. The refinery operations business segment consists of the following assets and operations:

Property	Key Products Handled	Operating Subsidiary	Location
Nixon facility<br> <br>● Crude distillation tower (15,000 bpd)<br> <br>● Petroleum storage tanks<br> <br>● Loading and unloading facilities<br> <br>● Land (56 acres)	Crude Oil<br> <br><br> <br>Refined Products	LE	Nixon, Texas

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Management’s Discussion and Analysis (Continued)

Crude Oil and Condensate Supply. On December 29, 2023, we entered a crude supply agreement with MVP, effective January 1, 2024. This agreement provides a firm source of light-sweet Eagle Ford crude oil to the Nixon facility under improved credit terms, and the crude supply agreement renews on a quarterly evergreen basis. Related to the crude supply agreement, MVP stores crude oil at the Nixon facility under a terminal services agreement. Management believes that MVP can provide us with adequate amounts of crude oil and condensate for the foreseeable future. Because we obtain our crude oil and condensate without the benefit of a long-term crude supply agreement, our exposure to the risks associated with volatile crude oil prices may increase, crude oil transportation costs could increase, and our liquidity may be reduced. Similarly, if producers experience crude supply constraints and increased transportation costs, our crude acquisition costs may rise, or we may not receive sufficient amounts to meet our needs, which could result in refinery downtime and could materially affect our business, financial condition, and results of operations. If we are unable to manage this, we may have to consider other options, such as selling assets, raising additional debt or equity capital, filing bankruptcy, or ceasing operations.

Products and Markets. Our market is the Gulf Coast region of the U.S., which is represented by the EIA as PADD 3. We sell our products primarily in the U.S. within PADD 3. Occasionally, we sell refined products to customers that export to other countries, such as naphtha and HOBM to Mexico. The Nixon refinery’s product slate is adjusted based on market demand. We currently produce a single finished product – jet fuel – and several intermediate products, including naphtha, HOBM, and AGO. An Affiliate, LEH, purchases most of our jet fuel under the Amended and Restated Jet Fuel Sales Agreement; LEH then sells the jet fuel to the DLA under preferential pricing terms due to the Affiliate's HUBZone certification. The agreement with LEH has a one-year term with automatic renewals. Our intermediate products are primarily sold in nearby markets to wholesalers and refiners as a feedstock for further blending and processing.

Customer s. Customers for our refined products include distributors, wholesalers, and refineries primarily in the lower portion of the Texas Triangle (the Houston – San Antonio – Dallas/Fort Worth area). An Affiliate, LEH, is a significant customer. Most of our contracts require our customers to prepay, with us selling them fixed quantities or minimum quantities of finished and intermediate petroleum products. Many of these arrangements are subject to periodic renegotiation on a forward-looking basis, which could result in higher or lower relative prices on future sales of our refined products.

Competition. Most of our competitors are larger than us and are engaged on a national or international level in many segments of the oil and gas industry, including exploration and production, gathering and transportation, and marketing. These competitors may have greater flexibility in responding to or absorbing market changes occurring in one or more of these business segments. We compete primarily based on cost. Due to the low complexity of our simple “topping unit” refinery, we can be relatively nimble in adjusting our refined products slate because of changing commodity prices, market demand, and refinery operating costs.

Safety and Downtime. We operate the refinery in a manner that is materially consistent with industry safety practices and standards. EPA, OSHA, and comparable state and local regulatory agencies provide oversight for personnel safety, process safety management, and risk management to prevent or minimize the accidental release of toxic, reactive, flammable, or explosive chemicals. Our storage tanks are equipped with leak detection devices. We also have response and control plans in place for spill prevention and emergencies.

The Nixon refinery periodically undergoes planned and unplanned temporary shutdowns. We periodically complete a planned turnaround to repair, restore, refurbish, or replace refinery equipment. The timing of planned turnarounds is adjusted to capitalize on favorable market conditions. Occasionally, unplanned shutdowns occur. Unplanned downtime can occur for a variety of reasons. Common reasons for unplanned downtime include repair/replacement of disabled equipment, crude deficiencies associated with cash constraints, extreme temperatures (high or low), and power outages.

We are particularly vulnerable to operational disruptions because all our refining operations occur at a single facility. Shutdowns for maintenance may result in lost margin opportunity, potential increased maintenance expense, and reduced refined products inventory, which could adversely impact our ability to meet our payment obligations.

Midstream Operations. Our tolling and terminaling segment consists of the following assets and operations:

Property	Key Products Handled	Operating Subsidiary	Location
Nixon facility<br> <br>● Petroleum storage tanks (third-party leasing)<br> <br>● Loading and unloading facilities	Crude Oil<br> <br>Refined Products	LRM, NPS	Nixon, Texas

Products and Customers. The Nixon facility’s petroleum storage tanks and infrastructure are primarily suited for crude oil and condensate and refined products, such as naphtha, jet fuel, diesel, and fuel oil. Our storage customers are typically from the lower portion of the Texas Triangle (the Houston – San Antonio – Dallas/Fort Worth area). Shipments are received and redelivered from the Nixon facility via third party trucks.

Operations Safety. Our midstream operations are operated in a manner materially consistent with industry safe practices and standards. These operations are subject to OSHA regulations and comparable state and local regulators. Storage tanks used for terminal operations are designed for crude oil and condensate and refined products, and most are equipped with appropriate controls that minimize emissions and promote safety. Our terminal operations have response and control plans, spill prevention and other programs to respond to emergencies.

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Management’s Discussion and Analysis (Continued)

Inactive Operations. We own pipeline and facilities assets and have leasehold interests in offshore oil and gas properties. These assets are inactive. Our pipeline assets were fully impaired in 2016 and our leasehold interests in offshore oil and gas wells were fully impaired in 2011. Our pipeline assets and oil and gas leasehold interests had no revenue during three months ended March 31, 2025 and 2024.

Property	Operating Subsidiary	Location
Freeport facility<br> <br>● Crude oil and natural gas separation and dehydration<br> <br>● Natural gas processing, treating, and redelivery<br> <br>● Vapor recovery unit<br> <br>● Two onshore pipelines (the onshore portion of the 20-inch offshore pipeline and a 16-inch natural gas pipeline connecting the Freeport facility to the Dow Chemical Plant complex)<br> <br>● Land (162 acres)	BDPL	Freeport, Texas
Offshore Pipelines<br> <br>● 20-inch, 34 mile gathering pipeline with lateral lines originating at an offshore anchor platform in Galveston Area Block 288<br> <br>● 8-inch, 13-mile offshore pipeline extending from Galveston Area Block 350 to an interconnect at a transmission pipeline in Galveston Area Block 391	BDPL	U.S. Gulf of America
Leasehold Interests in Offshore Oil and Gas Wells	BDPC	U.S. Gulf of America

Pipeline and Facilities Safety. Although our pipeline and facility assets are inactive, they require upkeep and maintenance and are subject to safety regulations under OSHA, PHMSA, BOEM, BSEE, and comparable state and local regulators. We have response and control plans, spill prevention and other programs to respond to emergencies related to these assets.

Results of Operations

Below is a discussion and analysis of the factors contributing to our consolidated financial results of operations. This information should be read in conjunction with our financial statements in “Part I, Item 1. Financial Statements.” While management intends for the financial statements, together with the following information, to provide investors with a reasonable basis for assessing our historical operations, they should not serve as the only criteria for predicting future performance.

Major Influences on Results of Operations. Our results of operations and liquidity are highly dependent upon the margins that we receive for our refined products. The dollar per barrel commodity price difference between crude oil and condensate (input) and refined products (output) is the most significant driver of refining margins, and they have historically been subject to wide fluctuations. When the spread between these commodity prices decreases, our margins are negatively affected. To improve margins, we must maximize yields of higher-value finished petroleum products and minimize costs of feedstocks and operating expenses. Although an increase or decrease in the commodity price for crude oil and other feedstocks generally result in a similar increase or decrease in commodity prices for finished petroleum products, typically there is a time lag between the two. For example, if the price per barrel of crude oil increases, the price of jet fuel per barrel will also generally increase, as jet fuel is a refined product derived from crude oil. Therefore, the effect of crude oil commodity price changes on our finished petroleum product commodity prices depends, in part, on how quickly and how fully the market adjusts to reflect these changes. Unfavorable margins may have a material adverse effect on our earnings, cash flows, and liquidity.

The general outlook for the oil and natural gas industry for the remainder of 2025 remains unclear given uncertainties surrounding general macroeconomic conditions related to inflation, tariffs, interest rates, capital and credit markets, and geopolitical tensions (including military conflicts in Ukraine and Israel and escalations in the Middle East). We can provide no assurances that refining margins will be positive and demand will increase.

How We Evaluate Our Operations. Management uses certain financial and operating measures to analyze segment performance. These measures are significant factors in assessing our operating results and profitability and include: Earnings before interest, income taxes, and depreciation and amortization ("EBITDA") on a consolidated and segment basis, refinery throughput, production and sales data, refinery downtime, tolling and terminaling revenue, and intercompany processing fees. We modified our segment presentation to incorporate applicable depreciation and amortization into our cost of goods sold subtotal. We believe this provides a more complete representation of our cost of goods sold. Prior periods have been modified to conform with this presentation.

Consolidated Results. Our consolidated results of operations include certain other unallocated corporate activities and the elimination of intercompany transactions and therefore do not equal the sum of the operating results of our refinery operations and tolling and terminaling business segments.

2025 Versus 2024.

Overview. Net income for 2025 was $2.2 million, or $0.15 per share, compared to net income of $6.6 million, or $0.44 per share, in 2024. The $4.4 million, or $0.29 per share, decrease in net income between the periods was the result of less favorable refining margins.

Total Revenue from Operations. Total revenue from operations was $83.7 million for 2025 compared to total revenue from operations of $91.0 million for 2024, representing a decrease of 8.1%. The decrease in 2025 related to declines in both refinery operations and tolling and terminaling revenue. Refinery operations revenue in 2025 decreased primarily due to lower market pricing; tolling and terminaling revenue in 2025 declined primarily due to lower tank rental fees.

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Management’s Discussion and Analysis (Continued)

Total Cost of Goods Sold. Total cost of goods sold was $77.6 million for 2025 compared to total cost of goods sold of $79.8 million for 2024, representing a decrease of 2.8%. The decrease in 2025 related to market pricing associated with product sales mix, partially offset by a 3%, or $2.5 million increase in sales volumes.

Gross Profit. Gross profit totaled $6.1 million for 2025 compared to gross profit of $11.2 million for 2024. Less favorable refining margins adversely impacted refinery operations gross profit in 2025 compared to 2024.

LEH Operating Fee, Related Party. For 2025 the LEH operating fee, related party totaled $0.2 million compared to $0.2 million for 2024.

General and Administrative Expenses. General and administrative expenses totaled $1.4 million in 2025 compared to other operating and general and administrative expenses of $1.0 million in 2024. The $0.4 million, or 37.8%, increase in 2025 primarily related to regulatory penalties, as well as professional service fees and insurance.

Interest and Other Non-Operating Expenses, Net. Total other expense in 2025 was flat compared to 2024, totaling $1.5 million for both periods.

Consolidated EBITDA. Consolidated EBITDA in 2025 totaled $5.1 million compared to $10.5 million in 2024 representing a decrease of $5.5 million. The decrease in 2025 was related to less favorable refining margins and lower tolling and terminaling total revenue. See Non-GAAP Measures, below, for a reconciliation to GAAP.

	Three Months Ended
	March 31,
	2025			2024
Total revenue from operations	$	83,692		$	91,022
Total costs of good sold		77,619			79,834
Gross profit		6,073			11,188
LEH operating fee, related party		182			172
Other operating expenses		119			140
General and administrative expenses		1,355			983
Depreciation and amortization		74			62
Interest, net		1,464			1,366
Total costs and expenses		3,194			2,723
Income before income taxes		2,879			8,465
Income tax expense		(635	)		(1,841	)
Net income	$	2,244		$	6,624
Income per common share
Basic	$	0.15		$	0.44
Diluted	$	0.15		$	0.44
	Three Months Ended
---	---	---	---	---
	March 31,
	2025		2024
Income before income taxes	$	2,879	$	8,465
Add: depreciation and amortization		714		704
Add: interest, net		1,464		1,366
Consolidated EBITDA	$	5,057	$	10,535

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Management’s Discussion and Analysis (Continued)

Downstream Operations. Our refinery operations business segment is owned by LE. Assets within this segment consist of a light sweet-crude, 15,000-bpd crude distillation tower, petroleum storage tanks, loading and unloading facilities, and approximately 56 acres of land. Refinery operations revenue is derived from refined product sales.

2025 Versus 2024

Total refined product sales by distillation (from light to heavy) for the periods indicated consisted of the following:

	Three Months Ended March 31,
	2025				2024
	(in thousands, except percent amounts)
LPG mix	$	-	0.0	%	$	61	0.1	%
Naphtha		15,881	19.2	%		18,113	20.1	%
Jet fuel		28,223	34.1	%		27,394	30.5	%
HOBM		17,745	21.4	%		20,535	22.8	%
AGO		21,019	25.5	%		23,812	26.5	%
	$	82,868	100.0	%	$	89,915	100.0	%

Refinery Downtime. Refinery downtime decreased from 5 days in Q1 2024 to 1 day in Q1 2025. Refinery downtime in Q1 2025 related to maintenance and repairs. Refinery downtime in Q1 2024 related to weather (3 days of freezing temperatures in January 2024) and 2 days related to maintenance and repairs.

Refinery Operations Revenue. Refinery operations revenue was $82.9 million for Q1 2025 compared to $89.9 million for Q1 2024, representing a decrease of 7.8%. The decrease in 2025 related to lower market pricing.

Cost of Goods Sold. Cost of goods sold for refinery operations was $77.7 million for Q1 2025 compared to $79.6 million for Q1 2024, representing a decrease of 2.3%. The decrease in Q1 2025 was related to the product sales mix and lower crude pricing.

LEH Operating Fee, Related Party. For 2025 and 2024 the LEH operating fee, related party totaled $0.2

Refining EBITDA. Refining EBITDA was $4.9 million in Q1 2025 compared to $10.2 million in Q1 2024, representing a decrease of 51.8%. The significant decrease in 2025 was related to less favorable refining margins. See Non-GAAP Measures, below, for a reconciliation to GAAP.

Refining Operations EBITDA per Bbl. On a per barrel basis, refining EBITDA was $5.04 for 2025 compared to $10.77 for 2024, representing a decrease of $5.73 per barrel. The decrease in 2025 related to less favorable refining margins.

	Three Months Ended
	March 31,
	2025		2024
	(in thousands)
Refinery operations revenue	$	82,868	$	89,915
Crude oil, fuel use, and chemicals		74,576		76,668
Other conversion costs		2,848		2,617
Depreciation and amortization		298		301
Cost of goods sold		77,722		79,586
LEH operating fee, related party		182		172
General and administrative expenses		339		237
Interest, net		836		734
Total costs and expenses		79,079		80,729
Income before income taxes		3,789		9,186
Add: depreciation and amortization		298		301
Add: interest, net		836		734
Refining EBITDA	$	4,923	$	10,221
Sales (Mbbls)		976		949
Refining operations EBITDA per bbl	$	5.04	$	10.77

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Management’s Discussion and Analysis (Continued)

Midstream Operations**.** Our tolling and terminaling business segment is owned by LRM and NPS. Assets within this segment include petroleum storage tanks and loading and unloading facilities. Tolling and terminaling revenue is derived from storage tank rental fees, ancillary services fees (such as in-tank blending), and tolling and reservation fees for use of the naphtha stabilizer.

2025 Versus 2024

Tolling and Terminaling Total Revenue. Tolling and terminaling total revenue was $1.4 million in Q1 2025 compared to $1.6 million in Q1 2024, representing a decrease of 13.6%. The decrease in Q1 2025 related to lower tank rental fees and a decrease in the number of tanks rented.

Tolling and Terminaling EBITDA. We had tolling and terminaling EBITDA of $1.2 million in Q1 2025 compared to $1.2 million in Q1 2024.

	Three Months Ended
	March 31,
	2025		2024
	(in thousands)
Tolling and terminaling revenue	$	1,391	$	1,610
Total tolling and terminaling revenue		1,391		1,610
Tolling and terminaling costs		122		410
Depreciation and amortization		342		341
Cost of goods sold		464		751
General and administrative expenses		88		23
Interest, net		477		496
Total costs and expenses		1,029		1,270
Income before income taxes		362		340
Add: depreciation and amortization		342		341
Add: interest, net		477		496
Tolling and terminaling EBITDA	$	1,181	$	1,177

Non-U.S. GAAP Measures.

The following are non-U.S. GAAP measures we present for the years ended March 31, 2025 and December 31, 2024:

Consolidated EBITDA. Income before interest, taxes, and depreciation and amortization on a consolidated basis.

Refining EBITDA. Income before interest, taxes, and depreciation and amortization for our refinery operations business segment.

Refining operations EBITDA per bbl. Refining EBITDA divided by sales (Mbbls) for the reporting period.

Tolling and terminaling EBITDA. Income before interest, taxes, and depreciation and amortization for our tolling and terminaling business segment.

We present these measures because they provide management and investors with (i) important supplemental indicators of the operational performance of our business, (ii) additional criteria for evaluation of our performance relative to our peers, and (iii) supplemental information to investors about certain material non-cash and other items that may not continue at the same level in the future. EBITDA has limitations as an analytical tool and should not be considered in isolation or as substitutes for analysis of our results as reported under U.S. GAAP or as alternatives to net income, operating income, gross margin, or any other measure of financial performance presented in accordance with U.S. GAAP.

	Three Months Ended
	March 31,
	2025									2024
	Refinery Operations		Tolling & Terminaling		Corporate & Other			Total		Refinery Operations		Tolling & Terminaling		Corporate & Other			Total
	(in thousands)
Income (loss) before income taxes	$	3,789	$	362	$	(1,272	)	$	2,879	$	9,186	$	340	$	(1,061	)	$	8,465
Add: depreciation and amortization		298		342		74			714		301		341		62			704
Add: interest, net		836		477		151			1,464		734		496		136			1,366
EBITDA	$	4,923	$	1,181	$	(1,047	)	$	5,057	$	10,221	$	1,177	$	(863	)	$	10,535

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Management’s Discussion and Analysis (Continued)

Capital Resources and Liquidity

Working Capital.

As of March 31, 2025 and the filing date of this report, certain conditions and events existed, in the aggregate, that caused management to evaluate Blue Dolphin's ability to continue as a going concern. Those conditions and events included historical and current working capital deficits and significant debt in default. Management believes that we have sufficient liquidity to meet our obligations as they become due through the generation of cash flows from operations and liquidation of current working capital amounts for a reasonable period (defined as one year from the issuance of these financial statements). Management acknowledges that uncertainty remains related to future operating margins; however, management has a reasonable expectation of Blue Dolphin's ability to generate adequate working capital for, amongst other requirements, purchasing crude oil and condensate and making payments on our long-term debt.

Liquidity. Cash and cash equivalents totaled $1.3 million and $0.1 million at March 31, 2025 and December 31, 2024, respectively, representing an increase of $1.2 million. A significant portion of our liquidity at March 31, 2025 was invested in inventory. Restricted cash, current totaled $1.0 million at both March 31, 2025 and December 31, 2024. Restricted cash, current related to a Veritex payment reserve account. Accounts receivable—related party, which was associated with the sale of jet fuel to LEH, totaled $8.3 million and $5.2 million at March 31, 2025 and December 31, 2024, respectively.

We generally rely on revenue from operations, including sales of refined products and rental of petroleum storage tanks, Affiliates, and financing to meet our liquidity needs. Our short-term working capital needs are primarily related to: (i) purchasing crude oil and condensate to operate the Nixon refinery, (ii) reimbursing LEH for direct operating expenses and paying the LEH operating fee under the Fourth Amended and Restated Operating Agreement, (iii) servicing debt, (iv) maintaining and improving the Nixon facility through capital expenditures, and (v) meeting regulatory compliance requirements and associated civil penalties. Our long-term working capital needs are primarily related to repayment of long-term debt obligations.

Refining margins, which are affected by commodity prices and refined product demand, are volatile, and a reduction in refining margins will adversely affect the amount of cash we will have available for working capital. Similarly, capital, credit, and commodity markets, tariffs, as well as armed conflicts in the Middle East and Europe continue to evolve, and the extent to which these factors may impact our working capital, commodity prices, refined product demand, supply chain, financial condition, liquidity, results of operations, and prospects will depend on future developments, which cannot be predicted with any degree of confidence. In the long term, we may not be able to manage business disruptions or execute our business strategy. We may have to consider other options, such as selling assets, raising additional debt or equity capital, filing bankruptcy, or ceasing operations.

Sources and Use of Cash.

Components of Cash Flows.

	Three Months Ended
	March 31,
	2025			2024
	(in thousands)
Cash Flows Provided By (Used In):
Operating activities	$	(1,727	)	$	(6,250	)
Financing activities		2,937			(345	)
Increase (decrease) in Cash and Cash Equivalents	$	1,210		$	(6,595	)

Cash Flow from Operations. We used $1.7 million in cash flow from operations during the three months ended March 31, 2025 compared to using $6.3 million in cash flow from operations during the three months ended March 31, 2024. The $4.5 million decrease in cash flow used from operations between the periods was primarily due to smaller buildup of inventory in 2025, as well as smaller increase in Accounts receivable, Accounts receivable, related party, and no expenditures for asset retirement obligations. Inventory increased due primarily to unfavorable product pricing, limited opportunities for customers who export to Mexico, and an intentional buildup of inventory by us during periods of low refining margins.

Capital Expenditures. We spent $0.0 in capital expenditures for both the three months ended three months ended March 31, 2025 and 2024, however, we incurred $0.1 million in vendor financed capital expenditures. Due to continued uncertainties surrounding general macroeconomic conditions related to inflation, tariffs, interest rates, capital and credit markets, and geopolitical tensions (including military conflicts in Ukraine and Israel and escalations in the Middle East), we anticipate continuing to limit capital expenditures for the remainder of 2025. However, to the extent we can capitalize on green energy growth opportunities, we may finance capital expenditures through project-based government loans.

We account for capital expenditures in accordance with U.S. GAAP. We also classify capital expenditures as ‘maintenance’ if the expenditure maintains capacity or throughput or as ‘expansion’ if the expenditure increases capacity or throughput capabilities. Although classification is generally a straightforward process, in certain circumstances the determination is a matter of management judgment and discretion. We budget for maintenance capital expenditures throughout the year on a project-by-project basis. Management determines projects based on maintaining safe and efficient operations, meeting customer needs, complying with operating policies and applicable law, and producing economic benefits, such as increasing efficiency or lowering future expenses.

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Management’s Discussion and Analysis (Continued)

Financing Activities. During the three months ended March 31, 2025, Blue Dolphin made payments on debt principal totaling $2.1 million compared to payments on debt principal totaling $0.3 million for the three months ended March 31, 2024. Proceeds from debt totaled $5.1 million for the three months ended March 31, 2025 compared to proceeds from debt totaling $0.0 for the three months ended March 31, 2024. In 2025, proceeds from debt related to the Amended and Restated Affiliate Revolving Credit Agreement.

Debt and Lease Obligations.

Debt Agreements.

Related-Party Agreements Summary. Blue Dolphin and certain subsidiaries are parties to the following debt agreements with related parties:

		Original		Monthly
		Principal		Payment
Loan Description	Parties	(in millions)	Maturity Date	(in millions)	Interest Rate	Loan Purpose
Amended and Restated Affiliate Revolving Credit Agreement	Blue Dolphin and Subsidiaries	$10 million maximum^(1)^	April 2027	Set-off against other obligations Borrower owes to Lender	WSJ Prime + 2.00%	Working capital
	LEH and Subsidiaries
Amended and Restated BDPL-LEH Loan Agreement	LEH	$4.0 million	April 2027	$0.25	12.00%	Working capital
	BDPL
^(1)^	As of March 31, 2025, $8.3 million was drawn under the agreement.
---	---

Third-Party Agreements Summary. Blue Dolphin and certain subsidiaries are parties to the following debt agreements with third parties:

		Original		Monthly Principal
		Principal		and Interest Payment
Loan Description	Parties	(in millions)	Maturity	(in millions)	Interest Rate	Loan Purpose
Veritex Loans
LE Term Loan Due 2034 (in default)^(1)^	LE	$25.0	June 2034	$0.3	WSJ Prime + 2.75%	Capital improvements
	Veritex
LRM Term Loan Due 2034 (in default)^(1)^	LRM	$10.0	December 2034	$0.1	WSJ Prime + 2.75%	Capital improvements
	Veritex
Kissick Debt^(2)^	LE	$11.7	March 2025	$0.5	6.25%	Working capital
	Kissick Noteholder
GNCU Loan
NPS Term Loan Due 2031 (in default)^(3)^	NPS	$10.0	October 2031	$0.1	5.75%	Working capital
	GNCU
SBA Economic Injury Disaster Loans
Blue Dolphin Term Loan Due 2051^(4)^	Blue Dolphin	$2.0	June 2051	$0.01	3.75%	Working capital
	SBA
LE Term Loan Due 2050^(5)^	LE	$0.15	August 2050	$0.0007	3.75%	Working capital
	SBA
NPS Term Loan Due 2050^(5)^	NPS	$0.15	August 2050	$0.0007	3.75%	Working capital
	SBA
Equipment Loan Due 2025^(6)^	LE	$0.07	October 2025	$0.0013	4.5%	Equipment Purchase
	Texas First
Equipment Loan Due 2025 ^(7)^	LE	$0.138	March 2031	$0.0028	12.7%	Equipment Purchase
	Ritchie Bros. Financial Services
^(1)^	Our secured loan agreements with Veritex are subject to certain financial and non-financial covenants. As of March 31, 2025, LE and LRM were in default related to financial covenants under the LE Term Loan Due 2034 and LRM Term Loan Due 2034. With respect to non-financial covenants, we are required to have a balance of $1.0 million in a payment reserve account held by Veritex. At both March 31, 2025 and December 31, 2024 restricted cash totaled $1.0 million.
---	---
^(2)^	Original principal amount was $8.0 million; pursuant to a 2017 sixth amendment, principal under the Kissick Debt increased by $3.7 million.
---	---
^(3)^	Loan required monthly interest-only payments for the first thirty-six (36) months. Afterwards, principal and interest payments are due monthly through loan maturity. First payment commenced in November 2024. As of March 31, 2025 and the filing date of this report, the NPS Term Loan Due 2031 was in default due to non-financial covenant violations.
---	---
^(4)^	Original principal amount was $0.5 million; the Blue Dolphin Term Loan Due 2051 was modified to increase the principal amount by $1.5 million. Payments deferred for thirty (30) months; first payment commenced in November 2023; interest accrues during deferral period; loan not forgivable.
---	---
^(5)^	Payments deferred for thirty (30) months; first payment commenced in February 2023; interest accrued during deferral period; loan not forgivable.
---	---
^(6)^	In October 2020, LE entered into the Equipment Loan Due 2025 to purchase a backhoe; the backhoe is used at the Nixon facility.
---	---
^(7)^	In March 2025, LE entered into the Equipment Loan Due 2031 to purchase mobile offices; the mobile offices are used at the Nixon facility.

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Management’s Discussion and Analysis (Continued)

Guarantees and Security.

Loan Description	Guarantees	Security
Veritex Loans
LE Term Loan Due 2034 (in default)	● USDA	●	First priority lien on Nixon facility’s business assets (excluding accounts receivable and inventory)
	● Jonathan Carroll^(1)^	●	Assignment of all Nixon facility contracts, permits, and licenses
	● Affiliate cross-guarantees	●	Absolute assignment of Nixon facility rents and leases, including tank rental income
		●	$5.0 million life insurance policy on Jonathan Carroll
LRM Term Loan Due 2034 (in default)	● USDA	●	Second priority lien on rights of LE in crude distillation tower and other collateral of LE
	● Jonathan Carroll^(1)^	●	First priority lien on real property interests of LRM
	● Affiliate cross-guarantees	●	First priority lien on all LRM fixtures, furniture, machinery, and equipment
		●	First priority lien on all LRM contractual rights, general intangibles, and instruments, except with respect to LRM rights in its leases of certain specified tanks for which Veritex has second priority lien
		●	Substantially all assets
Kissick Debt	---	●	Subordinated deed of trust that encumbers the crude distillation tower and general assets of LE
GNCU Loan
NPS Term Loan Due 2031 (in default)	● USDA	●	Deed of trust lien on approximately 56 acres of land and improvements owned by LE
	● Jonathan Carroll^(1)^	●	Leasehold deed of trust lien on certain property leased by NPS from LE
	● Affiliate cross-guarantees	●	Assignment of leases and rents and certain personal property
Amended and Restated BDPL-LEH Loan Agreement	---		Certain BDPL property
SBA EIDL
Blue Dolphin Term Loan Due 2051	---	●	Business assets (e.g., machinery and equipment, furniture, fixtures, etc.)
LE Term Loan Due 2050	---	●	Business assets (e.g., machinery and equipment, furniture, fixtures, etc.)
NPS Term Loan Due 2050	---	●	Business assets (e.g., machinery and equipment, furniture, fixtures, etc.)
Equipment Loan Due 2025	---	●	First priority security interest in the equipment (backhoe).
Equipment Loan Due 2031	---	●	First priority security interest in the mobile offices.
^(1)^	Jonathan Carroll was required to personally guarantee repayment of borrowed funds and accrued interest.
---	---

Lease Agreements.

Office Lease. We maintain our corporate headquarters in Houston, Texas. In October 2024, BDSC signed a new 24-month extension, the sixth amendment, to its operating lease. The sixth amendment was deemed to be a separate contract and not a lease modification. The first two months of the lease cover the holdover period of September and October 2024 wherein management negotiated the lease with the landlord; BDSC was not subject to a holdover rate during the holdover period. During months 3 through 12, which began on November 1, 2024, the landlord reduced the annual base rent to $29.00 per square foot. During months 13 through 24 the annual base rent will increase to $30.00 per square foot. As additional rent, BDSC will pay a proportionate share of basic building costs (e.g., utilities) up to a maximum of $1,500 per month. The total rental area under the sixth amendment is 9,961 square feet, an increase of 2,268 square feet to accommodate additional personnel. Under the lease amendment, BDSC will receive an improvement allowance of $1.50 per square foot; the improvement allowance will expire six months from the lease signing date. See "Part I, Item 1. Financial Statements —Note (11)" to our consolidated financial statements for additional disclosures related to the BDSC office lease.

An Affiliate, LEH, sub-leases a portion of the Houston office space. BDSC received sub-lease income from LEH totaling $0.03 million for both three months ended March 31, 2025 and 2024.

Tank Lease. LE leases tanks from Ingleside under the Second Amended and Restated Master Services Agreement. Lease expense associated with the Second Amended and Restated Master Services Agreement totaled $0.3 million for both the three months ended March 31, 2025 and 2024, respectively. See "Part I, Item 1. Financial Statements —Note (3)" to our consolidated financial statements for additional disclosures related to the Second Amended and Restated Master Services Agreement.

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Management’s Discussion and Analysis (Continued)

Outstanding Original Principal, Debt Issue Costs, and Accrued Interest. Related-party and third-party long-term debt, including outstanding original principal and accrued interest, as of the dates indicated was as follows:

Outstanding Principal.

		March 31,			December 31,
	2025			2024
	(in thousands)
Veritex Loans
LE Term Loan Due 2034 (in default)	$	18,456		$	18,753
LRM Term Loan Due 2034 (in default)		7,679			7,793
Kissick Debt		-			1,432
GNCU Loan
NPS Term Loan Due 2031 (in default)		9,400			9,671
LEH
Line of credit payable, related party		8,305			3,250
Amended and Restated BDPL-LEH Loan Agreement		4,000			4,000
SBA Economic Injury Disaster Loans
Blue Dolphin Term Loan Due 2051		2,000			2,000
LE Term Loan Due 2050		150			150
NPS Term Loan Due 2050		150			150
Equipment Loan Due 2025		10			14
Equipment Loan Due 2031		139			-
		50,289			47,213
Less: Line of credit, related party		(8,305	)		(3,250	)
Less: Current portion of long-term debt, net		(35,058	)		(37,379	)
Less: Unamortized debt issue costs		(1,692	)		(1,743	)
	$	5,234		$	4,841

We classified the debt associated with the LE Term Loan Due 2034, LRM Term Loan Due 2034, and NPS Term Loan Due 2031 within long-term debt, current portion on our consolidated balance sheets at March 31, 2025 and December 31, 2024 due to being in default.

Debt Issue Costs. Unamortized debt issue costs associated with the Veritex and GNCU loans as of the dates indicated consisted of the following:

		March 31,			December 31,
	2025			2024
	(in thousands)
Veritex Loans
LE Term Loan Due 2034 (in default)	$	1,674		$	1,674
LRM Term Loan Due 2034 (in default)		768			768
GNCU Loan
NPS Term Loan Due 2031 (in default)		730			730
Less: Accumulated amortization		(1,480	)		(1,429	)
	$	1,692		$	1,743

Amortization expense was $0.1 million for both three months ended March 31, 2025 and 2024.

Accrued Interest. Related-party and third-party accrued interest payable associated with long-term debt in our consolidated balance sheets, as of the dates indicated consisted of the following:

		March 31,			December 31,
	2025			2024
	(in thousands)
LEH
Amended and Restated BDPL-LEH Loan Agreement	$	1,308		$	1,308
Jonathan Carroll
Guaranty fee agreements		317			129
Veritex Loans
LE Term Loan Due 2034 (in default)		48			48
LRM Term Loan Due 2034 (in default)		61			61
GNCU Loan
NPS Term Loan Due 2031 (in default)		17			17
SBA Economic Injury Disaster Loans
Blue Dolphin Term Loan Due 2051		81			93
LE Term Loan Due 2050		8			8
NPS Term Loan Due 2053		8			8
Kissick Debt		-			-
Equipment Loan Due 2025		-			-
		1,848			1,672
Less: Accrued interest payable, current portion		(1,848	)		(1,672	)
Long-term interest payable, net of current portion	$	-		$	-

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Management’s Discussion and Analysis (Continued)

Forbearance Agreements, Waivers, and Default.

Kissick Payment Agreement. Pursuant to a Payment Agreement between LE and the Kissick Noteholder dated April 30, 2023, the Kissick Noteholder agreed to forbear from exercising any of its rights and remedies related to a default pertaining to previous payment violations under the Kissick Debt. Under the terms of the Kissick payment agreement, LE agreed to make monthly principal and interest payments totaling $0.5 million beginning in April 2023, continuing on the first of each month through February 2025, with a final payment in March 2025. As of the filing date of this report, the Kissick Debt was paid in full.

Defaults. As of March 31, 2025 and through the filing date of this report, LE and LRM were in default related to financial covenants under the LE Term Loan Due 2034 and LRM Term Loan Due 2034. NPS was in default related to non-financial covenants under the NPS Term Loan Due 2031. Defaults may permit lenders to declare the amounts owed under the related loan agreements immediately due and payable, exercise their rights with respect to collateral securing obligors’ obligations, and exercise any other rights and remedies available. We can provide no assurance that: (i) our assets or cash flow will be sufficient to fully repay borrowings under the secured loan agreements that are in default, either upon maturity or if accelerated, (ii) LE or NPS will be able to refinance or restructure the debt, or (iii) the third party will provide a future forbearance or default waiver. Any exercise by lenders of their rights and remedies under secured loan agreements that are in default could have a material adverse effect on our business operations, including crude oil and condensate procurement and our customer relationships; financial condition; and results of operations. In such a case, the trading price of our Common Stock and the value of an investment in our Common Stock could significantly decrease, which could lead to holders of our Common Stock losing their investment in our Common Stock in its entirety. If we are unable to manage this, we may have to consider other options, such as selling assets, raising additional debt or equity capital, filing bankruptcy, or ceasing operations.

Proceeds from Debt. Proceeds from debt totaled $5.1 million for the three months ended March 31, 2025 compared to proceeds from debt totaling $0.0 for the three months ended March 31, 2024. In 2025, proceeds from debt related to the Amended and Restated Affiliate Revolving Credit Agreement.

Concentration of Customer Risk

We routinely assess the financial strength of our customers. To date, we have not experienced significant write-downs in accounts receivable balances. We believe that our accounts receivable credit risk exposure is limited.

						Portion of
						Accounts
	Number of		% Total			Receivable at
	Significant		Revenue			December 31,
Three Months Ended	Customers		from Operations			(in millions)
March 31, 2025		3		67.7	%	$	8.3
March 31, 2024		3		81.3	%	$	11.7

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Management’s Discussion and Analysis (Continued)

One of our significant customers is LEH, an Affiliate. LEH purchases most of our jet fuel under the Amended and Restated Jet Fuel Sales Agreement and sells the jet fuel to the DLA under preferential pricing terms due to its HUBZone certification. The Affiliate lifts the jet fuel, which is stored at the Nixon Facility, as needed. LEH accounted for 30.8% and 31.7% of our total revenue from operations for the three months ended March 31, 2025 and 2024, respectively. The Affiliate represented $8.3 million and $5.2 million in accounts receivable, related party at March 31, 2025 and December 31, 2024, respectively.

Bank Accounts. Financial instruments that potentially subject us to concentrations of risk consist primarily of cash, trade receivables and payables. We maintain cash balances at financial institutions in Houston, Texas. The FDIC insures certain financial products up to a maximum of $250,000 per depositor. At March 31, 2025 and December 31, 2024, our cash balances (including restricted cash) exceeded the FDIC insurance limit per depositor by $2.0 million and $0.7 million, respectively. Instability and volatility in the capital, credit, and commodity markets, as well as with financial institutions, could adversely affect our cash balances (including restricted cash) in excess of FDIC insurance limits per depositor. In the event that banks in which we maintain our cash balances (including restricted cash) fail, there can be no assurance that the federal government and the Federal Reserve would intervene.

Regulatory Activities.

BOEM. See "Part II, Item 1. Legal Proceedings —Unresolved Matters—BOEM Supplemental Pipeline Bonds" and "Part II, Item 1. Legal Proceedings—Unresolved Matters—RLI Corp. Surety Bonds."

BSEE. See "Part II, Item 1. Legal Proceedings—Unresolved Matters—BSEE Offshore Platform Inspections, Decommissioning Obligations, and Civil Penalties" and "Part II, Item 1. Financial Statements —Notes (11) and (15)."

TCEQ. See "Part II, Item 1. Legal Proceedings—Resolved Matters—TCEQ Final Agreed Order."

Off-Balance Sheet Arrangements. None.

Accounting Standards.

Critical Accounting Policies and Estimates

Significant Accounting Policies. Our significant accounting policies relate to use of estimates; cash, cash equivalents, and restricted cash; accounts receivable and allowance for credit losses; financial instruments and fair value measurements; inventory; property and equipment; leases; revenue recognition; income taxes; impairment or disposal of long-lived assets; asset retirement obligations; contract balances; and computation of earnings per share.

Estimates. The nature of our business requires that we make estimates and assumptions in accordance with U.S. GAAP. These estimates and assumptions affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements, as well as the reported amounts of revenue and expenses during the reporting period. Although commodity price volatility, recession, inflation, tariffs, armed conflicts in the Middle East and Europe and associated sanctions on Russian crude products, and severe weather resulting from climate change may impact our estimates and assumptions, we are continually working to mitigate future risks. However, the extent to which these factors may impact our business, financial condition, liquidity, results of operations, and prospects will depend on future developments, which cannot be predicted with any degree of certainty.

We assessed certain accounting matters that require consideration of forecasted financial information in context with information reasonably available to us as of March 31, 2025 and through the filing date of this report. The accounting matters assessed included, but not limited to, our allowance for credit losses, inventory, and related reserves, and the carrying value of long-lived assets.

New Accounting Standards and Disclosures

New Pronouncements Adopted. During the three months ended March 31, 2025 we did not adopt any ASUs.

New Pronouncements Issued, Not Yet Effective. We expect to adopt the following ASUs in future periods:

●

ASU 2024-03 — Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures (Subtopic 220-40) ("ASU 2024-03"). In November 2024, the FASB issued ASU 2024-03, requiring additional disclosure of certain costs and expenses within the notes to the consolidated financial statements. This ASU is effective for annual periods beginning after December 15, 2026, and interim periods beginning after December 15, 2027, with early adoption permitted. We are evaluating the provisions of ASU 2024-03 and the incremental disclosures that will be required in our consolidated financial statements.

●

ASU 2023-09 — Income Taxes (Topic 740): Improvements to Income Tax Disclosures ("ASU 2023-09"). In December 2023, the FASB issued ASU 2023-09, requiring us to disclose specified additional information in our income tax rate reconciliation and provide additional information for reconciling items that meet a quantitative threshold. ASU 2023-09 will also require us to disaggregate our income taxes paid disclosure by federal and state taxes, with further disaggregation required for significant individual jurisdictions. ASU 2023-09 allows for adoption using either a prospective or retrospective transition method. We will adopt ASU 2023-09 for our financial statements covering the annual period ending December 31, 2025. We are currently evaluating the impact of adopting this ASU.

---

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ITEM 3.

     QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Not applicable.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Under the supervision of, and with the participation of our management, including our Chief Executive Officer (principal executive officer) and Treasurer (principal financial officer and principal accounting officer), we conducted an evaluation of the effectiveness of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Based on our evaluation, our Chief Executive Officer (principal executive officer) and Treasurer (principal financial officer and principal accounting officer) concluded that our disclosure controls and procedures were effective as of the end of the period covered by this report to ensure that information required to be disclosed by us in reports that we file or submit under the Exchange Act, are recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms.

Changes in Internal Control over Financial Reporting

No change occurred in our internal control over financial reporting (as defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) during the three months ended March 31, 2025 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II - OTHER INFORMATION

ITEM 1.

  LEGAL PROCEEDINGS

In the ordinary course of business, we are involved in legal matters incidental to the routine operation of our business, such as mechanic’s liens and contract-related disputes. We may also become party to lawsuits, administrative proceedings, and governmental investigations, including environmental, regulatory, and other matters. Large, sometimes unspecified, damages or penalties may be sought from us in some matters, which may require years to resolve. Although we cannot provide assurance, we believe that an adverse resolution of the matters described below would not have a material impact on our liquidity, consolidated financial position, or consolidated results of operations.

Resolved Matters

RLI Corp. Surety Bonds. Blue Dolphin currently has several surety bonds through RLI Corp. as required by different regulatory agencies, including BOEM and the Railroad Commission of Texas. The bonds total approximately $1.25 million in the aggregate. In February 2024, RLI Corp. filed suit against Blue Dolphin, BDPL, and BDEX seeking an injunction to fully collateralize the bonds in cash, representing an increase of $1.0 million. Although BDPL filed its answer to RLI Corp.'s lawsuit in April 2024 denying RLI Corp.'s claims, in July 2024 BDPL presented a settlement proposal to RLI Corp. to resolve the matter through a series of cash payments. In July 2024, RLI Corp. informed the court that the parties reached a settlement in principle, and the parties executed a settlement agreement in September 2024. From September 2024 to March 31, 2025, BDPL made payments to RLI Corp. under the settlement agreement totaling $1.0 million, bringing the total surety bond amount to $1.2 million in cash. Once BDPL’s offshore pipeline and platform assets have been decommissioned, BDPL can request that BOEM cancel the associated supplemental pipeline bonds. As a result, RLI Corp. would release the cash collateral tied to the associated supplemental pipeline bonds to BDPL.

TCEQ Final Agreed Order. In October 2021, LRM received a proposed agreed order from the TCEQ for alleged solid and hazardous waste violations discovered during an investigation from January to March 2020. The proposed agreed order assessed an administrative penalty of $0.4 million and identified actions needed to correct the alleged violations. In September 2023, TCEQ presented its final penalty offer of $0.35 million, which LRM accepted. Although LRM believed the penalty matter is resolved in September 2023, TCEQ referred the matter to the State Office of Administrative Hearings ("SOAH"). A preliminary hearing, the purpose of which was to set a hearing schedule, was held on August 8, 2024; management participated in the hearing. Although a follow-up hearing was scheduled for January 2025, TCEQ presented, and LRM signed, a revised draft Agreed Order in November 2024. Under the terms of the revised draft Agreed Order, TCEQ acknowledged that LRM had ceased unauthorized disposal of industrial solid waste and industrial hazardous waste and LRM accepted a final penalty amount of approximately $0.4 million, which will be paid in monthly installments over a three-year period. The SOAH case was dismissed and the matter was remanded back to the TCEQ December 2024; TCEQ finalized the Agreed Order in February 2025.

Unresolved Matters

BOEM Supplemental Pipeline Bonds. To cover the various obligations of lessees and rights-of-way holders operating in federal waters of the U.S. Gulf of America, BOEM evaluates an operator’s financial ability to carry out present and future obligations to determine whether the operator must provide additional security beyond the statutory bonding requirements. Such obligations include the cost of plugging and abandoning wells and decommissioning pipelines and platforms at the end of production or service activities. Once plugging and abandonment work has been completed, the collateral backing the financial assurance is released by BOEM. In March 2018, BOEM ordered BDPL to provide additional financial assurance totaling approximately $5.7 million for five (5) existing pipeline rights-of-way, representing an increase of $4.8 million. Historically, BDPL maintained $0.9 million in pipeline bonds with BOEM to decommission its trunk pipeline offshore in federal waters. In June 2018, BOEM issued BDPL INCs for each right-of-way that failed to comply. In June 2018, BDPL appealed the INCs to the IBLA, filing its statement of reasons in July 2018. In February 2025, the USDOI directed BOEM and BDPL to submit either a joint status report, or separate status reports, to update the court relative to the facts in the case. If joint, submissions were due by March 11, 2025; if separate, BOEM’s submission was due by March 11, 2025 and BDPL’s response to BOEM’s submission was due by March 25, 2025. Although BOEM submitted its report by its respective deadline, BDPL missed its deadline as notifications were sent to BDPL’s former counsel in the matter. On March 10, 2025, the USDOI notified BDPL by letter that the agency granted BDPL until March 31, 2025 to submit its response; however, management was not in receipt of the USDOI’s notification letter until March 25, 2025. On March 27, 2025, BDPL filed a motion through new counsel requesting an extension of its deadline to file its status report response no later than April 30, 2025; BDPL filed the required status report response to the court on April 24, 2025.

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Legal Proceedings (Continued)

BDPL’s pending appeal of the BOEM INCs does not relieve BDPL of its obligations to provide additional financial assurance or of BOEM’s authority to impose financial penalties. There can be no assurance that we will be able to meet additional supplemental pipeline bond requirements. If BDPL is required by BOEM to provide significant additional supplemental pipeline bonds or is assessed significant penalties under the INCs, we will experience a significant and material adverse effect on our operations, liquidity, and financial condition. We cannot predict the outcome of the supplemental pipeline bond INCs. Accordingly, we did not record a liability on our consolidated balance sheets as of March 31, 2025 and December 31, 2024. At both March 31, 2025 and December 31, 2024, BDPL maintained $0.9 million in cash-backed pipeline bonds issued to the BOEM through RLI Corp.

BSEE Offshore Platform Inspections, Decommissioning Obligations, and Civil Penalties. BDPL has pipelines and platform assets subject to BSEE’s idle iron regulations. Idle iron regulations require lessees and rights-of-way holders to permanently abandon and remove platforms and other structures when they are no longer useful for operations. Until such structures are abandoned or removed, lessees and rights-of-way holders are required to inspect and maintain the assets in accordance with regulatory requirements.

Platform Inspection Obligation. For our offshore platform in federal waters, we are required by BSEE to perform annual structural inspections and monthly navigational aid, fog horn, lifesaving equipment, and pollution checks. On April 9, 2025, BSEE issued BDPL an INC for failing to conduct monthly platform pollution inspections; BDPL corrected the INC on April 22, 2025.

Decommissioning Obligations. BSEE mandated that our pipelines and facilities assets offshore in federal waters be decommissioned due to their extended period of inactivity. In October 2023, management met with BSEE to discuss BDPL’s path forward for meeting decommissioning requirements. Management worked with a consultant to develop a decommissioning plan, and BDPL completed Phase I of the project from late December 2023 to mid-February 2024. However, in July 2024, BDPL requested a BSEE extension to decommission the remaining phases of the decommissioning project until the second quarter of 2025 due to significant cost overruns. BDPL’s extension request was denied by BSEE in September 2024. On March 17, 2025, BSEE issued BDPL an INC for failing to comply with certain of its decommissioning obligations. Management is currently assessing the feasibility and cost of performing remaining decommissioning work. Separately, management is also exploring alternatives to reactivate the assets under a potential alternate Right-of-Use and Easement (RUE). BDPL's delay in decommissioning its offshore assets does not relieve BDPL of its obligations to comply with BSEE's mandate or of BSEE's authority to impose civil penalties. Further, there can be no assurance that BDPL will be able to complete the anticipated work or predict the outcome of BSEE INCs. If BDPL is unable to perform its decommissioning obligations, BOEM may exercise its rights under supplemental pipeline bonds or exercise any other rights and remedies it has available.

BSEE Civil Penalties. BDPL has the following open civil penalty referrals from BSEE:

●	Civil Penalty G-2024-054. In August 2024, BDPL received a civil penalty referral letter from BSEE for failing to timely remove its GA-288C junction platform offshore in federal waters. The civil penalty referral is associated with BSEE INC No. G-114 issued in October 2023. In March 2025, BSEE calculated a proposed civil penalty of $1.0 million against BDPL, and BSEE reserved its rights to assess additional civil penalties in the amount of $3,097 per day until the referenced INC is fully remediated. In April 2025, BDPL exercised its right to request a meeting with the penalty reviewing officer to submit additional information for consideration. This meeting has not yet been scheduled. At March 31, 2025, we accrued $0.7 million on our balance sheet within accrued expenses and other current liabilities related to this matter. We will record a liability of approximately $0.3 million per quarter related to potential penalties associated with Civil Penalty G-2024-054.
●	Civil Penalty G-2024-056. In August 2024, BDPL received a civil penalty referral letter from BSEE for failing to timely flush, fill, and abandon its lateral pipeline from GA-245 to the GA-273 subsea tie-in (Pipeline Segment No. 15635) offshore in federal waters. The civil penalty referral is associated with BSEE INC No. G-802 issued in November 2023. In January 2025, BSEE calculated a proposed civil penalty of $0.4 million against BDPL, and BSEE reserved its right to assess additional civil penalties in the amount of $3,097 per day until the referenced INC is fully remediated. In March 2025, BDPL exercised its right to request a meeting with the penalty reviewing officer to submit additional information for consideration. This meeting has not yet been scheduled. At March 31, 2025, we accrued $0.4 million on our balance sheet within accrued expenses and other current liabilities related to this matter. We will record a liability of approximately $0.3 million per quarter related to potential penalties associated with Civil Penalty G-2024-056.
---	---
●	Civil Penalty G-2024-010. In April 2024, BDPL received a civil penalty referral letter from BSEE for failing to remediate certain BSEE INCs issued in September 2023 associated with its GA-288C junction platform offshore in federal waters. Specifically, remediation is associated with BSEE INC Nos. E120 (physically boarding platform monthly, performing visual inspections for environmental pollution, and maintaining monthly inspection records), G112 (timely removing 55-gallon drum leaking oil on platform deck), L141 (timely flushing and filling Pipeline Segment No. 13101 with inhibited seawater), and L142 (timely decommissioning in place Pipeline Segment No. 13101). In March 2025, BSEE calculated a proposed civil penalty of $1.1 million against BDPL. In April 2025, BDPL exercised its right request a meeting with the penalty reviewing officer to submit additional information for consideration. This meeting has not yet been scheduled. At March 31, 2025, we accrued $1.1 million on our balance sheet within accrued expenses and other current liabilities related to this matter.
---	---

Default under a Secured Loan Agreement. As of March 31, 2025 and the filing date of this report, certain of our bank debt to Veritex was in default related to a financial covenant violation, and bank debt to GNCU was in default related to non-financial covenant violations. See “Note (10)” to our consolidated financial statements for additional disclosures related to third-party debt, default on such debt, and the potential effects of such a default on our business, financial condition, and results of operations. If the lenders exercises their rights and remedies due to the defaults under our secured loan agreement, our business, financial condition, and results of operations will be materially adversely affected.

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ITEM 1A.

     RISK FACTORS

In addition to the other information set forth in this Quarterly Report, careful consideration should be given to the risk factors discussed under “Part I, Item 1A. Risk Factors” and elsewhere in our Annual Report on Form 10-K for the fiscal year ended December 31, 2024 as filed with the SEC. These risks and uncertainties could materially and adversely affect our business, financial condition, and results of operations. Our operations could also be affected by additional factors that are not presently known to us or by factors that we currently consider immaterial to our business. There have been no material changes in our assessment of our risk factors from those set forth in our Annual Report on Form 10-K for the fiscal year ended December 31, 2024.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

Exhibits Index

No.	Description
31.1*	Jonathan P. Carroll Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to section 302 of the Sarbanes-Oxley Act of 2002
31.2*	Bryce D. Klug Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to section 302 of the Sarbanes-Oxley Act of 2002
32.1*	Jonathan P. Carroll Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002
32.2*	Bryce D. Klug Certification 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 - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL Document.
---	---
101.SCH**	Inline XBRL Taxonomy Extension Schema Document.
101.CAL**	Inline XBRL Taxonomy Extension Calculation Linkbase Document.
101.LAB**	Inline XBRL Taxonomy Extension Label Linkbase Document.
101.PRE**	Inline XBRL Taxonomy Extension Presentation Linkbase Document.
101.DEF**	Inline XBRL Taxonomy Extension Definition Linkbase Document.
104**	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).

* Filed herewith.

** Submitted electronically herewith.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	BLUE DOLPHIN ENERGY COMPANY
	(Registrant)
May 15, 2025	By:	/s/ BRYCE D. KLUG
		Bryce D. Klug<br> <br>Treasurer and Assistant Secretary
		(Principal Financial and Accounting Officer)

March 31, 2025 | Page 45

ex_803184.htm

EXHIBIT 31.1

I, Jonathan P. Carroll, certify that:

1.	I have reviewed this quarterly report on Form 10-Q of Blue Dolphin Energy Company (the “Registrant”).
2.	Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the periods covered by this quarterly report;
---	---
3.	Based on my knowledge, the financial statements and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the Registrant as of, and for, the periods presented in this quarterly report;
---	---
4.	I am responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the Registrant and I have:
---	---
a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under my supervision, to ensure that material information relating to the Registrant, including its consolidated subsidiaries, is made known to me by others within those entities, particularly during the period in which this quarterly report is being prepared;
---	---
b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under my supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)	Evaluated the effectiveness of the Registrant’s disclosure controls and procedures and presented in this quarterly report my conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this quarterly report based on such evaluation; and
d)	Disclosed in this quarterly report any change in the Registrant’s internal control over financial reporting that occurred during the Registrant’s most recent fiscal quarter (the Registrant’s fourth fiscal quarter in the case of this quarterly report) that has materially affected, or is reasonably likely to materially affect, the Registrant’s internal control over financial reporting; and
5.	I have disclosed, based on my most recent evaluation of internal control over financial reporting, to the Registrant’s auditors and the Audit Committee of the Registrant’s Board of Directors:
---	---
(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Registrant’s ability to record, process, summarize and report financial information; and
---	---
(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrant’s internal control over financial reporting.

Date: May 15, 2025

/s/ JONATHAN P. CARROLL
Jonathan P. Carroll

Chief Executive Officer, President, Assistant Treasurer, and Secretary

(Principal Executive Officer)

ex_803185.htm

Exhibit 31.2

I, Bryce D. Klug, certify that:

1.	I have reviewed this quarterly report on Form 10-Q of Blue Dolphin Energy Company (the “Registrant”).
2.	Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the periods covered by this quarterly report;
---	---
3.	Based on my knowledge, the financial statements and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the Registrant as of, and for, the periods presented in this quarterly report;
---	---
4.	I am responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the Registrant and I have:
---	---

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under my supervision, to ensure that material information relating to the Registrant, including its consolidated subsidiaries, is made known to me by others within those entities, particularly during the period in which this quarterly report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under my supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the Registrant’s disclosure controls and procedures and presented in this quarterly report my conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this quarterly report based on such evaluation; and

d) Disclosed in this quarterly report any change in the Registrant’s internal control over financial reporting that occurred during the Registrant’s most recent fiscal quarter (the Registrant’s fourth fiscal quarter in the case of this quarterly report) that has materially affected, or is reasonably likely to materially affect, the Registrant’s internal control over financial reporting; and

5.	I have disclosed, based on my most recent evaluation of internal control over financial reporting, to the Registrant’s auditors and the Audit Committee of the Registrant’s Board of Directors:

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrant’s internal control over financial reporting.

Date: May 15, 2025

/s/ BRYCE D. KLUG
Bryce D. Klug

Treasurer and Assistant Secretary

(Principal Financial and Accounting Officer)

ex_803186.htm

EXHIBIT 32.1

CERTIFICATION OF

PRINCIPAL EXECUTIVE OFFICER AND

PRINCIPAL FINANCIAL OFFICER

PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Blue Dolphin Energy Company (the “Blue Dolphin”) on Form 10-Q for the period ended March 31, 2025 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, Jonathan P. Carroll, Chief Executive Officer, President, and Assistant Treasurer (Principal Executive Officer) of Blue Dolphin, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:

1.	The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and
2.	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Blue Dolphin.
/s/ JONATHAN P. CARROLL
---
Jonathan P. Carroll

Chief Executive Officer, President, Assistant Treasurer, and Secretary

(Principal Executive Officer)

May 15, 2025

ex_803187.htm

Exhibit 32.2

CERTIFICATION OF

PRINCIPAL EXECUTIVE OFFICER AND

PRINCIPAL FINANCIAL OFFICER

PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Blue Dolphin Energy Company (the “Blue Dolphin”) on Form 10-Q for the period ended March 31, 2025 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, Bryce D. Klug, Treasurer and Assistant Secretary (Principal Financial and Accounting Officer) of Blue Dolphin, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:

The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Blue Dolphin.

/s/ BRYCE D. KLUG
Bryce D. Klug

Treasurer and Assistant Secretary

(Principal Financial and Accounting Officer)

May 15, 2025