Blue Dolphin Energy (BDCO) 10-K 3 Apr 23 2023 FY Annual report Financial data

Cover

Cover - USD ($)	12 Months Ended
	Dec. 31, 2022	Mar. 31, 2023	Jun. 30, 2022
Cover [Abstract]
Entity Registrant Name	BLUE DOLPHIN ENERGY COMPANY
Entity Central Index Key	0000793306
Document Type	10-K
Amendment Flag	false
Entity Voluntary Filers	No
Current Fiscal Year End Date	--12-31
Entity Well Known Seasoned Issuer	No
Entity Small Business	true
Entity Shell Company	false
Entity Emerging Growth Company	false
Entity Current Reporting Status	Yes
Document Period End Date	Dec. 31, 2022
Entity Filer Category	Non-accelerated Filer
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2023
Entity Common Stock Shares Outstanding		14,921,968
Entity Public Float			$ 2,919,215
Document Annual Report	true
Document Transition Report	false
Entity File Number	0-15905
Entity Incorporation State Country Code	DE
Entity Tax Identification Number	73-1268729
Entity Address Address Line 1	801 Travis Street
Entity Address Address Line 2	Suite 2100
Entity Address City Or Town	Houston
Entity Address State Or Province	TX
Entity Address Postal Zip Code	77002
City Area Code	713
Local Phone Number	568-4725
Security 12b Title	Common Stock, par value $0.01 per share
Entity Interactive Data Current	Yes
Icfr Auditor Attestation Flag	false
Auditor Name	UHY LLP
Auditor Location	Sterling Heights, Michigan
Auditor Firm Id	1195

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
CURRENT ASSETS
Cash and cash equivalents	$ 520	$ 9
Restricted cash	0	48
Accounts receivable, net	1,148	126
Prepaid expenses and other current assets	3,466	2,433
Deposits	110	110
Inventory	19,844	3,098
Total current assets	25,088	5,824
LONG-TERM ASSETS
Total property and equipment, net	57,436	59,923
Operating lease right-of-use assets, net	149	332
Restricted cash, noncurrent	1,001	0
Surety bonds	230	230
Total long-term assets	58,816	60,485
TOTAL ASSETS	83,904	66,309
CURRENT LIABILITIES
Long-term debt less unamortized debt issue costs, current portion (in default)	42,155	42,953
Long-term debt, related party, current portion (in default)	5,211	20,042
Interest payable (in default)	6,271	8,689
Interest payable, related party (in default)	4,094	3,454
Accounts payable	2,161	2,548
Accounts payable, related party	155	155
Current portion of lease liabilities	156	215
Income taxes payable	307	0
Asset retirement obligations, current portion	3,710	0
Accrued expenses and other current liabilities	6,114	6,225
Total current liabilities	70,334	84,281
LONG-TERM LIABILITIES
Asset retirement obligations	0	3,461
Long-term lease liabilities, net of current	0	156
Unearned contract renewal income, net of current	660	1,200
Long-term debt, net of current portion	2,322	838
Total long-term liabilities	2,982	5,655
TOTAL LIABILITIES	73,316	89,936
STOCKHOLDERS' EQUITY (DEFICIT)
Common stock ($0.01 par value, 20,000,000 shares authorized; 14,921,968 and 12,693,514 shares issued at December 31, 2022 and 2021, respectively)(1)	149	127
Additional paid-in capital	39,758	38,457
Accumulated deficit	(29,319)	(62,211)
TOTAL STOCKHOLDERS' EQUITY (DEFICIT)	10,588	(23,627)
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)	$ 83,904	$ 66,309

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2022	Dec. 31, 2021
STOCKHOLDERS' DEFICIT
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	20,000,000	20,000,000
Common stock, shares issued	14,921,968	12,693,514

Consolidated Statements of Inco

Consolidated Statements of Income - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
REVENUE FROM OPERATIONS
Refinery operations	$ 483,061	$ 297,103
Tolling and terminaling	4,443	3,717
Total revenue from operations	487,504	300,820
COST OF GOODS SOLD
Crude oil, fuel use, and chemicals	429,723	292,438
Other conversion costs	11,710	7,468
Total cost of goods sold	441,433	299,906
Gross profit	46,071	914
COST OF OPERATIONS
LEH operating fee, related party	744	522
Other operating expenses	221	198
General and administrative expenses	2,915	3,021
Depreciation and amortization	2,798	2,780
Impairment of assets	114	1,092
Bad debt expense	62	0
Accretion of asset retirement obligations	134	0
Total cost of operations	6,988	7,613
Income (loss) from operations	39,083	(6,699)
OTHER INCOME (EXPENSE)
Easement, interest and other income	1	2
Interest and other expense	(5,885)	(6,199)
Gain on extinguishment of debt	0	55
Total other income (expense)	(5,884)	(6,142)
Income (loss) before income taxes	33,199	(12,841)
Income tax expense	(307)	0
Net Income (loss)	$ 32,892	$ (12,841)
Income (loss) per common share:
Basic	$ 2.34	$ (1.01)
Diluted	$ 2.34	$ (1.01)
Weighted average number of common shares outstanding:
Basic1	14,079,327	12,693,514
Diluted1	14,079,327	12,693,514

Consolidated Statements of Stoc

Consolidated Statements of Stockholders' Equity (Deficit) - USD ($) $ in Thousands	Total	Common Stock	Additional Paid-In Capital	Retained Earnings (Accumulated Deficit)
Balance, shares at Dec. 31, 2020		12,693,514
Balance, amount at Dec. 31, 2020	$ (10,786)	$ 127	$ 38,457	$ (49,370)
Net income (loss)	(12,841)			(12,841)
Balance, shares at Dec. 31, 2021		12,693,514
Balance, amount at Dec. 31, 2021	(23,627)	$ 127	38,457	(62,211)
Net income (loss)	32,892	$ 0	0	32,892
Common stock issued for payment of debt, shares		1,951,416
Common stock issued for payment of debt, amount	1,162	$ 20	1,142	0
Common stock issued for services, shares		277,038
Common stock issued for services, amount	161	$ 2	159	0
Balance, shares at Dec. 31, 2022		14,921,968
Balance, amount at Dec. 31, 2022	$ 10,588	$ 149	$ 39,758	$ (29,319)

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
OPERATING ACTIVITIES
Net income (loss)	$ 32,892	$ (12,841)
used in operating activities:
Depletion, depreciation and amortization	2,798	2,780
Accretion of asset retirement obligations	134	0
Amortization of debt issue costs	204	147
Guaranty fees paid in kind	605	608
Related-party interest expense paid in kind	598	1,116
Deferred revenues and expenses	(540)	(320)
Loss on issuance of shares	357	0
Bad debt	62	0
Impairment of assets	114	1,092
Gain on extinguishment of debt	0	(55)
Changes in operating assets and liabilities
Accounts receivable	(1,084)	88
Prepaid expenses and other current assets	(1,033)	1,131
Deposits and other assets	0	14
Inventory	(16,746)	(2,036)
Accounts payable, accrued expenses and other liabilities	(2,089)	2,220
Net cash provided by (used in) operating activities	16,272	(6,056)
INVESTING ACTIVITIES
Capital expenditures	(102)	0
Net cash used in investing activities	(102)	0
FINANCING ACTIVITIES
Proceeds from debt	1,500	10,500
Payments on debt principal	(1,017)	(4,738)
Payments of debt issuance costs	0	(750)
Net activity on related-party debt	(15,189)	(10)
Net cash provided by (used in) financing activities	(14,706)	5,002
Net change in cash, cash equivalents, and restricted cash	1,464	(1,054)
CASH, CASH EQUIVALENTS, AND RESTRICTED CASH AT BEGINNING OF PERIOD	57	1,111
CASH, CASH EQUIVALENTS, AND RESTRICTED CASH AT END OF PERIOD	1,521	57
Non-cash investing and financing activities:
Financing of line of credit via related-party debt	0	2,331
Issuance of shares for services and/or to extinguish debt	966	0
Line of credit financed by offsetting tank leases less interest	0	289
Interest paid	5,534	1,252
Income taxes paid (refunded)	$ 0	$ 0

Organization

Organization	12 Months Ended
	Dec. 31, 2022
Organization
Organization	(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 United States. Operations primarily consist of a light sweet-crude, 15,000-bpd crude distillation tower, and approximately 1.2 million bbls of petroleum storage tank capacity in Nixon, Texas. Blue Dolphin trades on the OTCQX under the ticker symbol “BDCO.” Assets are organized in two business segments: ‘refinery operations’ (owned by LE) and ‘tolling and terminating services’ (owned by LRM and NPS). ‘Corporate and other’ includes Blue Dolphin subsidiaries BDPL (inactive pipeline and facilities assets), BDPC (inactive leasehold interests in 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. An Affiliate, combined with Jonathan Carroll, controlled approximately 83% 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 of our refined products. Blue Dolphin and certain of its subsidiaries are currently parties to a variety of 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. Going Concern In accordance with GAAP accounting standards, we evaluated whether there are conditions and events, considered in the aggregate, that raise substantial doubt about our ability to continue as a going concern within one year after the date that our consolidated financial statements are issued. While results of operations were significantly improved for the twelve months ended December 31, 2022 versus the prior twelve month period, management determined that certain factors continue to present substantial doubt about our ability to continue as a going concern. These factors include significant current debt, which impacts our ability to meet debt covenants, and historical net losses and working capital deficits. Our consolidated financial statements assume we will continue as a going concern and do not include any adjustments that might result from this uncertainty. Management is working to alleviate these factors by entering into forbearance agreements with lenders, maximizing operation of the Nixon refinery given favorable refining margins, and pursuing opportunities to obtain capital and/or refinance debt. Our significant current debt is the result of certain third-party and related-party loan agreements being classified within the current portion of long-term debt on our consolidated balance sheets at December 31, 2022 and 2021. Excluding accrued interest, we had current debt of $47.4 million and $63.0 million, respectively, as of December 31, 2022 and 2021. Our significant current debt consists of bank debt to Veritex and GNCU, investor debt to John Kissick, and related party debt to LEH. Forbearance Agreement. Other Defaults. Favorable Refining Margins. Our results of operations and liquidity are highly dependent upon the margins that we receive for our refined products. The dollar per bbl 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. While refining margins and liquidity improved significantly during 2022, the general outlook for the oil and natural gas industry for 2023 remains unclear given uncertainty surrounding the Russian military conflict with Ukraine, COVID-19, recession, and inflation. We can provide no assurances that refining margins and demand will remain at current levels. Working Capital Improvements. Our ability to continue as a going concern depends on sustained positive operating margins and adequate working capital for, amongst other requirements, purchasing crude oil and condensate and making payments on long-term debt. If we are unable to process crude oil and condensate into sellable refined products or make required debt payments, we may consider other options. These options could include selling assets, raising additional debt or equity capital, cutting costs, reducing cash requirements, restructuring debt obligations, or filing bankruptcy. Operating Risks Successful execution of our business strategy depends on several critical factors, including having adequate working capital, favorable refining margins, and maintaining operation of the Nixon refinery. · Working Capital – As noted above, we have historically had working capital deficits primarily due to having significant current debt. Having sufficient working capital is necessary to meet contractual, operational, regulatory, and safety 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 Amended and Restated Operating Agreement, (iii) servicing debt, (iv) maintaining and improving the Nixon facility through capital expenditures, and (v) meeting regulatory compliance requirements. Our long-term working capital needs are primarily related to repayment of long-term debt obligations. To avoid business disruptions and manage cash flow, we optimize receivables and payables by prioritizing payments, optimize inventory levels based on demand, monitor discretionary spending, and carefully manage capital expenditures. · Refining Margins – 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. Crude oil refining is primarily a margin-based business. To improve margins, we must maximize yields of higher value finished petroleum products and minimize costs of feedstocks and operating expenses. When the spread between these commodity prices decreases, our margins are negatively affected. Although an increase or decrease in the commodity price for crude oil and other feedstocks generally results in a similar increase or decrease in commodity prices for finished petroleum products, typically there is a time lag between the two. The effect of crude oil commodity price changes on our finished petroleum product commodity prices therefore 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. To remain competitive in a volatile commodity price environment, we adjust throughput and production based on market conditions and adjust our product slate based on commodities pricing. · Nixon Refinery Operation – We maintain relationships with suppliers that source and repair key components of the Nixon refinery. We expect our suppliers to maintain an adequate supply of component products and, when components are sent out for repair, to timely deliver components. However, in some cases, increases in demand or supply chain disruptions have led to part and component constraints. We use several suppliers and monitor supplier financial viability to mitigate supply-based risks that could cause a business disruption. The Russian military conflict with Ukraine, COVID-19, recession, and inflation continue to evolve, and the extent to which these factors may impact working capital, commodity prices, refined product demand, our 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. 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 third parties exercise their rights and remedies under secured loan agreements that are in default, or if Tartan terminates the Crude Supply Agreement, our business, financial condition, and results of operations will be materially adversely affected.

Principles of Consolidation and

Principles of Consolidation and Significant Accounting Policies	12 Months Ended
	Dec. 31, 2022
Principles of Consolidation and Significant Accounting Policies
Principles of Consolidation and Significant Accounting Policies	(2) Principles of Consolidation and Significant Accounting Policies Basis of Presentation The accompanying consolidated financial statements, which include Blue Dolphin and its subsidiaries, have been prepared in accordance with U.S. generally accepted accounting principles and the rules and regulations of the SEC. These rules and regulations conform to the accounting principles contained in FASB’s ASC, the single source of GAAP. All significant intercompany items have been eliminated in consolidation. Additionally, any material subsequent events that occurred after the date through which this report covers have been properly recognized or disclosed in our financial statements. In management’s opinion, all adjustments considered necessary for a fair presentation have been included, disclosures are adequate, and the presented information is not misleading. Significant Accounting Policies The summary of significant accounting policies of Blue Dolphin is presented to assist in understanding our consolidated financial statements. Our consolidated financial statements and accompanying notes are representations of management, who is responsible for their integrity and objectivity. These accounting policies conform to GAAP and have been consistently applied in the preparation of our consolidated financial statements. Use of Estimates We assessed certain accounting matters that require consideration of forecasted financial information in context with information reasonably available to us as of December 31, 2022 and through the filing date of this report. The accounting matters assessed included, but not limited to, our allowance for doubtful accounts, inventory, and related reserves, and the carrying value of long-lived assets. Cash, Cash Equivalents, and Restricted Cash The following table provides a reconciliation of cash, cash equivalents, and restricted cash as reported in the consolidated statements of cash flows: December 31, 2022 2021 (in thousands) Cash and cash equivalents $ 520 $ 9 Restricted cash - 48 Restricted cash, noncurrent 1,001 - $ 1,521 $ 57 Accounts Receivable and Allowance for Doubtful Accounts Financial Instruments Inventory Property and Equipment. Refinery and Facilities Pipelines and Facilities Oil and Gas Properties CIP Leases. For operating leases, we record lease cost on a straight-line basis over the lease term; we record lease expenses in the appropriate line on the income statement based on the leased asset’s intended use. For finance leases (previously referred to under GAAP as capital leases), we amortize lease payments for the ROU asset on a straight-line basis over the lesser of the leased asset’s useful life or the lease term; we record amortization expenses on the income statement in ‘depreciation and amortization expense;’ we record interest expense on the income statement in ‘interest and other expense.’ Revenue Recognition Refinery Operations Revenue 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 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 services are considered optional to the customer. 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 Unearned Contract Renewal Income. Income Taxes Income taxes are calculated utilizing the applicable rates on items included in the determination of income for income tax purposes. Our effective tax rate may be different than what would be expected if the federal and state statutory rates were applied to income from continuing operations primarily because of amounts expensed for financial reporting that are not deductible for tax purposes. The benefit of an uncertain tax position is recognized in the financial statements if it meets a minimum recognition threshold. A determination is first made as to whether it is more likely than not that the income tax position will be sustained, based upon technical merits, upon examination by the taxing authorities. If the income tax position is expected to meet the more-likely-than-not criteria, the benefit recorded in the financial statements equals the largest amount that is greater than 50% likely to be realized upon its ultimate settlement. At December 31, 2022 and 2021, there were no uncertain tax positions for which a reserve or liability is necessary. Deferred Taxes Impairment or Disposal of Long-Lived Assets Commodity price market volatility associated with the Russian military conflict with Ukraine, recession, inflation, and COVID-19 could affect the value of certain of our long-lived assets. Management evaluated refinery and facilities assets for impairment as of December 31, 2022. We did not record any impairment of our long-lived assets for the periods presented. However, impairment may be required in the future if losses are material, or as new opportunities arise, such as reconfiguration of the Nixon refinery into a renewable fuels facility. Asset Retirement Obligations Refinery and Facilities Pipeline and Facilities; Oil and Gas Properties Computation of Earnings Per Share New Pronouncements Adopted New Pronouncements Issued, Not Yet Effective .

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2022
Related Party Transactions
Related-Party Transactions	(3) Related-Party Transactions Affiliate Financial and Operational Agreements Blue Dolphin and certain of its subsidiaries are parties to several financial and operational agreements with Affiliates. Management believes that these related-party agreements are arm's-length transactions. Agreement/Transaction Parties Effective Date Key Terms Jet Fuel Sales Agreement (1) LEH LE 04/01/2022 1-year term expiring earliest to occur of 03/31/2024 plus 30-day carryover or delivery of maximum jet fuel quantity; LEH bids on jet fuel contracts under preferential pricing terms due to a HUBZone certification Office Sub-Lease Agreement LEH BDSC 01/01/2018 68-month term expiring 08/31/2023; office lease Houston, Texas; includes 6-month rent abatement period; rent approximately $0.01 million per month Amended and Restated Operating Agreement (2) LEH Blue Dolphin LE LRM NPS BDPL BDPC BDSC 04/01/2020 1-year term; expires 04/01/2024 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, excluding crude costs, depreciation, amortization, and interest, of Blue Dolphin, LE, LRM, NPS, BDPL, BDPC and BDSC LE Amended and Restated Guaranty Fee Agreement (3) LE Jonathan Carroll 04/01/2017 Related to payoff of LE $25.0 million Veritex loan; Jonathan Carroll receives fee equal to 2.00% per annum of outstanding principal balance owed under LE Term Loan Due 2034 LRM Amended and Restated Guaranty Fee Agreement (3) LRM Jonathan Carroll 04/01/2017 Related to payoff of LRM $10.0 million Veritex loan; Jonathan Carroll receives fee equal to 2.00% per annum of outstanding principal balance owed under LRM Term Loan Due 2034 (1) See “Note (16)” for additional disclosures related to renewal of the Jet Fuel Sales Agreement; renewed at substantially similar terms. (2) See “Note (16)” for additional disclosures related to renewal of the Amended and Restated Operating Agreement; renewed for one-year term; all other terms substantially similar. (3) Jonathan Carroll was required to personally guarantee repayment of borrowed funds and accrued interest. See “Note (16)” for disclosures related to modification of the LE Amended and Restated Guaranty Fee Agreement and LRM Amended and Restated Guaranty Fee Agreement; as modified, Jonathan Carroll receives fee payable 100% in cash instead of 50% in stock and 50% in cash. See “Note (16)” for additional disclosures related to new related-party agreements approved subsequent to December 31, 2022. Working Capital We historically relied on Affiliates for funding during periods of working capital deficits. We reflect such borrowings in our consolidated balance sheets in accounts payable, related party, or long-term debt, related party. During the twelve months ended December 31, 2022, continued liquidity improvement related to favorable market conditions enabled us to increasingly meet our needs through cash flow from operations. Affiliate Long-Term Debt Blue Dolphin and certain of its subsidiaries are parties to the following debt agreements with Affiliates: Loan Description Parties Maturity Date Interest Rate Loan Purpose June LEH Note (in default) LEH Blue Dolphin Jan 2019 8.00% Blue Dolphin working capital; reflects amounts owed to LEH under the Second Amended and Restated Operating Agreement BDPL-LEH Loan Agreement (in default) LEH BDPL Aug 2018 16.00% Original principal amount of $4.0 million; Blue Dolphin working capital Pursuant to the Assignment Agreement, the March Ingleside Note and March Carroll Note were assigned to LEH under the June LEH Note effective December 31, 2022. See “Note (16) Subsequent Events” for additional disclosures related to related-party debt. See “Notes (1) and (10)” to our consolidated financial statements for additional information regarding defaults under our secured loan agreements and their potential effects on our business, financial condition, and results of operations. Guarantees, Security, and Defaults Loan Description Guarantees Security Event(s) of Default June LEH Note (in default) --- --- Failure to pay past due obligations at maturity (loan matured January 2019) BDPL-LEH Loan Agreement (in default) --- Certain BDPL property Failure to pay past due obligations at maturity (loan matured August 2018) Covenants The BDPL-LEH Loan Agreement contains representations and warranties, affirmative and negative covenants, and events of default that we consider usual and customary for a credit facility of this type. There are no covenants associated with the June LEH Note. Related-Party Financial Impact Consolidated Balance Sheets Accounts payable, related party Long-term debt, related party, current portion (in default) and accrued interest payable, related party . December 31, 2022 2021 (in thousands) LEH June LEH Note (in default) $ 1,211 $ 12,672 BDPL-LEH Loan Agreement (in default) 8,094 7,454 LEH Total 9,305 20,126 Ingleside March Ingleside Note - 1,066 Jonathan Carroll March Carroll Note - 2,304 9,305 23,496 Less: Long-term debt, related party, current portion (in default) (5,211 ) (20,042 ) Less: Accrued interest payable, related party (in default) (4,094 ) (3,454 ) $ - $ - June LEH Note (in default) (in thousands) Balance at December 31, 2021 $ 12,672 Related-party receivables settled against related-party provided working capital (21,076 ) Blue Dolphin operating costs and related LEH management fee under Amended and Restated Operating Agreement 9,615 Balance at December 31, 2022 $ 1,211 The amount owed under the June LEH Note reflects amounts net settled against related-party accounts receivable derived from the Jet Fuel Sales Agreement and the Amended and Restated Operating Agreement, as well as long-term debt. Consolidated Statements of Operations Total revenue from operations. Twelve Months Ended December 31, 2022 2021 (in thousands, except percent amounts) Refinery operations LEH $ 173,646 35.6 % $ 90,062 29.9 % Third-Parties 309,415 63.5 % 207,041 68.8 % Tolling and terminaling LEH 360 0.1 % - - Third-Parties 4,083 0.8 % 3,717 1.2 % $ 487,504 100.0 % $ 300,820 100.0 % Interest expense. Twelve Months Ended December 31, 2022 2021 (in thousands) Jonathan Carroll Guaranty Fee Agreements First Term Loan Due 2034 (in default) $ 428 $ 430 Second Term Loan Due 2034 (in default) 177 178 March Carroll Note 146 132 LEH BDPL-LEH Loan Agreement (in default) 480 640 June LEH Note (in default) 383 928 Ingleside March Ingleside Note 69 56 $ 1,683 $ 2,364 Other.

Revenue and Segment Information

Revenue and Segment Information	12 Months Ended
	Dec. 31, 2022
Revenue and Segment Information
Revenue and Segment Information	(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’ as presented in the segment information includes BDSC, BDPL, and BDPC. Revenue from Contracts with Customers Disaggregation of Revenue Receivables from Contracts with Customers Contract Liabilities Remaining Performance Obligations Contract Balances. December 31, 2022 2021 Accounts receivable (including related-party), beginning of year $ 126 $ 214 Accounts receivable (including related-party), end of year 1,148 126 Unearned revenue, beginning of year $ 4,388 $ 3,421 Unearned revenue, end of year 3,888 4,388 Segment Information Twelve Months Ended December 31, 2022 2021 (in thousands) Refinery operations $ 483,061 $ 297,103 Tolling and terminating 4,443 3,717 Total revenue from operations 487,504 300,820 Intercompany processing fees (1) Refinery operations (2,583 ) (2,457 ) Tolling and terminating 2,583 2,457 Total intercompany processing fees - - Operation costs and expenses (2) Refinery operations (439,292 ) (298,082 ) Tolling and terminating (2,142 ) (1,825 ) Corporate and other (221 ) (197 ) Total operation costs and expenses (441,655 ) (300,104 ) Segment contribution margin (deficit) Refinery operations 41,186 (3,436 ) Tolling and terminating (3) 4,884 4,349 Corporate and other (221 ) (197 ) Total segment contribution margin (deficit) 45,849 716 General and administrative expenses (4) Refinery operations (1,682 ) (1,549 ) Tolling and terminating (427 ) (343 ) Corporate and other (1,860 ) (2,742 ) Total general and administrative expenses (3,969 ) (4,634 ) Depreciation and amortization Refinery operations (1,224 ) (1,214 ) Tolling and terminating (1,368 ) (1,362 ) Corporate and other (206 ) (204 ) Total depreciation and amortization (2,798 ) (2,780 ) Interest and other non-operating expenses, net (5) Refinery operations (2,753 ) (2,779 ) Tolling and terminating (1,433 ) (1,649 ) Corporate and other (1,697 ) (1,715 ) Total interest and other non-operating expenses, net (5,883 ) (6,143 ) Income (loss) before income taxes Refinery operations 35,527 (8,978 ) Tolling and terminating 1,656 995 Corporate and other (3,984 ) (4,858 ) Total income (loss) before income taxes 33,199 (12,841 ) Income tax expense (307 ) - Net income (loss) $ 32,892 $ (12,841 ) (1) Fees associated with an intercompany tolling agreement related to naphtha volumes. (2) Operation costs include cost of goods sold. Also, operation costs within: (a) tolling and terminaling includes terminal operating expenses and an allocation of other costs (e.g., insurance and maintenance) and (b) corporate and other includes expenses related to BDSC, BDPC and BDPL. (3) Tolling and terminaling segment contribution margin is based on fees associated with an intercompany tolling agreement related to naphtha volumes. (4) General and administrative expenses within refinery operations include the LEH operating fee, impairment expense, and bad debt expense. (5) Corporate and other within interest and other non-operating expenses, net primarily reflects interest expense for the LE Amended and Restated Guaranty Fee Agreement, LRM Amended and Restated Guaranty Fee Agreement, June LEH Note, March Carroll Note, and March Ingleside Note. See “Note (3)” and “Note (15)” to our consolidated financial statements for additional information regarding guaranty fee agreements. Twelve Months Ended December 31, 2022 2021 (in thousands) Capital expenditures Refinery operations $ 102 $ - Tolling and terminating - - Corporate and other - - Total capital expenditures $ 102 $ - December 31, 2022 2021 (in thousands) Identifiable assets Refinery operations $ 64,359 $ 47,047 Tolling and terminating 17,836 17,594 Corporate and other 1,709 1,668 Total identifiable assets $ 83,904 $ 66,309

Concentration of Risk

Concentration of Risk	12 Months Ended
	Dec. 31, 2022
Concentration of Risk
Concentration of Risk	(5) Concentration of Risk 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 December 31, 2022 and 2021, our cash balances (including restricted cash) exceeded the FDIC insurance limit per depositor by $0.9 million and $0, respectively. Key Supplier Operation of the Nixon refinery depends on our ability to purchase adequate amounts of crude oil and condensate. We have a long-term crude supply agreement in place with Tartan. The volume-based Crude Supply Agreement expires when we receive 24.8 million net bbls of crude oil. After that, the Crude Supply Agreement automatically renews for successive one-year terms (each such term, a renewal term). Tartan must provide notice of non-renewal at least 60 days before the expiration of any renewal term. For the twelve months ended December 31, 2022 and 2021, we received approximately 4.5 million bbls, or 18.4%, and 4.2 million bbls, or 17.0%, respectively, of the contracted volume under the Crude Supply Agreement. As of December 31, 2022, we received approximately 13.6 million bbls, or 54.8%, of the total allowable contracted volume under the Crude Supply Agreement. At December 31, 2022, accounts payable for crude oil and condensate was $0. As of December 31, 2022, 100% of our crude oil was sourced from Tartan under the Crude Supply Agreement. Related to the Crude Supply Agreement, Tartan stores crude oil at the Nixon facility under a terminal services agreement dated as of June 1, 2019. Under the terminal services agreement, crude oil is stored at the Nixon facility at a specified rate per bbl of the storage tank’s shell capacity. The terminal services agreement renews on a one-year evergreen basis. Tartan must provide notice of non-renewal at least 60 days before the expiration of any renewal term. However, the terminal services agreement will automatically terminate upon expiration or termination of the Crude Supply Agreement. Our financial health has been materially and adversely affected by significant current debt, certain of which is in default, historical net losses and working capital deficits, and margin volatility. If Tartan terminates the Crude Supply Agreement or terminal services agreement, our ability to acquire crude oil and condensate could be adversely affected. 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 would result in refinery downtime and could materially affect our business, financial condition, and results of operations. To mitigate this risk, we are exploring other crude supply sources. Significant Customers 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. Twelve Months Ended Number Significant Customers % Total Revenue from Operations Portion of Accounts Receivable at December 31, December 31, 2022 2 60.4 % $ 0 December 31, 2021 3 71.9 % $ 0 One of our significant customers is LEH, an Affiliate. Due to a HUBZone certification, the Affiliate purchases our jet fuel under a Jet Fuel Sales Agreement and bids on jet fuel contracts under preferential pricing terms. For the twelve months ended December 31, 2022 and 2021, the Affiliate accounted for approximately 35.6% and 29.9% of total revenue from operations, respectively. Concentration of Customers Refined Product Sales Twelve Months Ended December 31, 2022 2021 (in thousands, except percent amounts) LPG mix $ 122 0.0 % $ 21 0.0 % Naphtha 99,946 20.7 % 74,683 25.2 % Jet fuel 173,646 35.9 % 90,062 30.3 % HOBM 88,472 18.3 % 65,386 22.0 % AGO 120,875 25.1 % 66,951 22.5 % $ 483,061 100.0 % $ 297,103 100.0 % An Affiliate, LEH, purchases all of our jet fuel. See “Notes (3) and (15)” to our consolidated financial statements for additional disclosures related to Affiliate agreements and arrangements.

Prepaid Expenses and Other Curr

Prepaid Expenses and Other Current Assets	12 Months Ended
	Dec. 31, 2022
Prepaid Expenses and Other Current Assets
Prepaid Expenses and Other Current Assets	(6) Prepaid Expenses and Other Current Assets Prepaid expenses and other current assets as of the dates indicated consisted of the following: December 31, 2022 2021 (in thousands) Prepaid crude oil and condensate $ 2,183 $ 1,368 Prepaid insurance 1,066 953 Other prepaids 163 36 Prepaid easement renewal fees 54 76 $ 3,466 $ 2,433

Inventory

Inventory	12 Months Ended
	Dec. 31, 2022
Inventory
Inventory	(7) Inventory Inventory as of the dates indicated consisted of the following: December 31, 2022 2021 (in thousands) HOBM $ 14,879 $ 1,749 Crude oil and condensate 3,458 660 Naphtha 1,056 189 AGO 301 338 Chemicals 116 121 Propane 27 27 LPG mix 7 14 $ 19,844 $ 3,098

Property Plant and Equipment Ne

Property Plant and Equipment Net	12 Months Ended
	Dec. 31, 2022
Property Plant and Equipment Net
Property, Plant and Equipment, Net	(8) Property, Plant and Equipment, Net Property, plant and equipment, net, as of the dates indicated consisted of the following: December 31, 2022 2021 (in thousands) Refinery and facilities $ 72,675 $ 72,583 Land 566 566 Other property and equipment 913 903 74,154 74,052 Less: Accumulated depreciation and amortiation (20,387 ) (17,795 ) 53,767 56,257 CIP 3,669 3,666 $ 57,436 $ 59,923

Accrued Expenses and Other Curr

Accrued Expenses and Other Current Liabilities	12 Months Ended
	Dec. 31, 2022
Accrued Expenses and Other Current Liabilities
Accrued Expenses and Other Current Liabilities	(9) Accrued Expenses and Other Current Liabilities Accrued expenses and other current liabilities as of the dates indicated consisted of the following: December 31, 2022 2021 (in thousands) Unearned revenue from contracts with customers $ 3,888 $ 4,388 Insurance 568 273 Unearned contract renewal income 480 400 Accrued fines and penalties 407 407 Other payable 324 218 Board of director fees payable 210 230 Customer deposits 173 173 Taxes payable 64 136 $ 6,114 $ 6,225

ThirdParty LongTerm Debt

ThirdParty LongTerm Debt	12 Months Ended
	Dec. 31, 2022
ThirdParty LongTerm Debt
Third-Party Long-Term Debt	(10) Third-Party Long-Term Debt Loan Agreements Summary Loan Description Parties Principal (in millions) Origination / Maturity Monthly Principal and Interest Payment Interest Rate Loan Purpose Veritex Loans LE Term Loan Due 2034 ( in default (1) LE Veritex $25.0 Jun 2015/ Jun 2034 $0.2 million WSJ Prime + 2.75% Refinance loan; capital improvements LRM Term Loan Due 2034 ( in default (1) LRM Veritex $10.0 Dec 2015/ Dec 2034 $0.1 million WSJ Prime + 2.75% Refinance bridge loan; capital improvements Kissick Debt ( in default (2)(3) LE Kissick $11.7 June 2006/ Jan 2018 No payments to date; payment rights subordinated 16.00% Working capital; reduced GEL obligation GNCU Loan ( in default NPS Term Loan Due 2031 (4) NPS GNCU $10.0 Oct 2021/ Oct 2031 $0.1 million 5.75% Working capital SBA EIDLs BDEC Term Loan Due 2051 (as modified) (5) Blue Dolphin SBA $2.0 May 2021/ Jun 2051 $0.01 million 3.75% Working capital LE Term Loan Due 2050 (6) LE SBA $0.15 Aug 2020/ Aug 2050 $0.0007 million 3.75% Working capital NPS Term Loan Due 2050 (6) NPS SBA $0.15 Aug 2020/ Aug 2050 $0.0007 million 3.75% Working capital Equipment Loan Due 2025 (7) LE Texas First $0.07 Oct 2020/ Oct 2025 $0.0013 million 4.50% Equipment Lease Conversion (1) At December 31, 2022 and 2021, restricted cash, noncurrent was $1.0 million and $0, respectively; restricted cash, noncurrent represents amounts held by Veritex in a payment reserve account. (2) Original principal amount was $8.0 million; debt currently held by John Kissick. Pursuant to a 2017 sixth amendment, principal under the Kissick Debt increased by $3.7 million. (3) Under a 2015 subordination agreement, John Kissick agreed to subordinate his right to payments, as well as any security interest and liens on the Nixon facility’s business assets, in favor of Veritex as holder of the LE Term Loan Due 2034. (4) Loan requires monthly interest-only payments for the first thirty-six (36) months. Afterwards, principal and interest payments due monthly through loan maturity. First payment due in November 2024. (5) Original principal amount was $0.5 million; the BDEC Term Loan Due 2051 was modified to increase the principal amount by $1.5 million. Payments deferred for thirty (30) months; first payment due December 2023; interest accrues during deferral period; loan not forgivable. (6) Payments deferred for thirty (30) months; first payment due March 2023; interest accrued during deferral period; loan not forgivable. (7) In May 2019, LE entered into 12-month equipment rental agreement with option to purchase backhoe at maturity; equipment rental agreement matured in May 2020; in October 2020, LE entered into the Equipment Loan Due 2025 to finance the backhoe purchase; backhoe used at the Nixon facility. Outstanding Principal, Debt Issue Costs, and Accrued Interest Third-party long-term debt, including outstanding principal and accrued interest, as of the dates indicated was as follows: December 31, 2022 2021 (in thousands) Veritex Loans LE Term Loan Due 2034 (in default) $ 20,801 $ 23,789 LRM Term Loan Due 2034 (in default) 8,671 9,861 Kissick Debt (in default) 11,006 10,210 GNCU Loan NPS Term Loan Due 2031 ( in default 9,975 10,094 SBA EIDLs BDEC Term Loan Due 2051 2,082 512 LE Term Loan Due 2050 162 156 NPS Term Loan Due 2050 162 156 Equipment Loan Due 2025 38 53 52,897 54,831 Less: Current portion of long-term debt, net (42,155 ) (42,953 ) Less: Unamortized debt issue costs (2,149 ) (2,351 ) Less: Accrued interest payable (6,271 ) (8,689 ) $ 2,322 $ 838 Unamortized debt issue costs associated with the Veritex and GNCU loans as of the dates indicated consisted of the following: December 31, 2022 2021 (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 (1,023 ) (821 ) $ 2,149 $ 2,351 Amortization expense was $0.2 million and $0.1 million for twelve-month periods ended December 31, 2022 and 2021, respectively. 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: December 31, 2022 2021 (in thousands) Kissick Debt (in default) $ 6,028 $ 5,232 Veritex Loans LE Term Loan Due 2034 (in default) 53 2,338 LRM Term Loan Due 2034 (in default) 66 959 GNCU Loan NPS Term Loan Due 2031 ( in default 17 136 SBA EIDLs BDEC Term Loan Due 2051 82 12 LE Term Loan Due 2050 12 6 NPS Term Loan Due 2053 12 6 Equipment Loan Due 2025 1 - 6,271 8,689 Less: Accrued interest payable (in default) (6,271 ) (8,689 ) Long-term Interest Payable, Net of Current Portion $ - $ - The debt associated with the LE Term Loan Due 2034, LRM Term Loan Due 2034, NPS Term Loan Due 2031, and Kissick Debt was classified within the current portion of long-term debt on our consolidated balance sheets at December 31, 2022 and 2021. Forbearance and Defaults Forbearance Agreement Other Defaults 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, and NPS will be able to refinance or restructure the debt, and/or (iii) third parties will provide future default waivers. 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. See “Notes (1) and (3)” to our consolidated financial statements for additional information regarding defaults under our secured loan agreements and their potential effects on our business, financial condition, and results of operations. Guarantees and Security Loan Description Guarantees Security Veritex Loans LE Term Loan Due 2034 ( in default · · First priority lien on Nixon facility’s business assets (excluding accounts receivable and inventory) · (1) · Assignment of all Nixon facility contracts, permits, and licenses · · 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 · · Second priority lien on rights of LE in crude distillation tower and other collateral of LE · (1) · First priority lien on real property interests of LRM · · 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 ( in default (2) --- · Subordinated deed of trust that encumbers the crude distillation tower and general assets of LE GNCU Loan NPS Term Loan Due 2031 (in default) · · Deed of trust lien on approximately 56 acres of land and improvements owned by LE · (1) · Leasehold deed of trust lien on certain property leased by NPS from LE · · Assignment of leases and rents and certain personal property SBA EIDLs 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). (1) Jonathan Carroll was required to personally guarantee repayment of borrowed funds and accrued interest. (2) Pursuant to a 2015 subordination agreement, the holder of the Kissick Debt agreed to subordinate their right to payments, as well as any security interest and liens on the Nixon facility’s business assets, in favor of Veritex as holder of the LE Term Loan Due 2034. 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 contains quarterly debt service coverage and total combined current assets ratios and annual current and debt to net worth ratios; in addition, LE must maintain quarterly total combined debt and total combined tangible net worth ratios. The First Term Loan Due 2034 also requires that a $1.0 million payment reserve account be maintained. The Second Term Loan Due 2034 contains quarterly total combined current assets, total combined current liabilities, and total combined debt ratios and annual current and debt to net worth ratios. The NPS Term Loan Due 2031 requires 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, and the Equipment Loan Due 2025. Future annual third-party long-term debt payments, certain of which are reflected as current due to defaults, are as follows: Years Ending December 31, Principal Debt Issue Costs Total (in thousands) 2023 $ 44,304 $ (2,149 ) $ 42,155 2024 16 - 16 2025 5 - 5 2026 - - - 2027 35 - 35 Subsequent to 2027 2,266 - 2,266 $ 46,626 $ (2,149 ) $ 44,477

AROs

AROs	12 Months Ended
	Dec. 31, 2022
AROs
AROs	(11) AROs Refinery and Facilities Management has concluded that there is no legal or contractual obligation to dismantle or remove refinery and facilities assets. Management believes that 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 plugging and abandoning our oil and gas properties. We recorded a discounted liability for the fair value of an ARO with a corresponding increase to the carrying value of the related long-lived asset at the time the asset was installed or placed in service, and we depreciated the amount added to property and equipment. During the twelve months ended December 31, 2021, we determined that the estimated future cost and timing of decommissioning these assets changed. As a result, we recorded an increase in liability at December 31, 2021. We recorded an additional increase in liability during the twelve months ended December 31, 2022 due to a further change in timing; BSEE mandated that decommissioning must occur prior to June 1, 2023. We will recognize accretion expense through the anticipated decommissioning date. ARO liability as of the dates indicated was as follows: December 31, 2022 2021 (in thousands) AROs, at the beginning of the period $ 3,461 $ 2,370 Changes in estimates of existing obligations 114 1,091 Accretion expense 135 - - 3,461 Less: AROs, current portion (3,710 ) - Long-term AROs, at the end of the period $ - $ 3,461 See “Note (15)” to our consolidated financial statements for disclosures related to decommissioning of our offshore pipelines and platform assets and related risks.

Lease Obligations

Lease Obligations	12 Months Ended
	Dec. 31, 2022
Lease Obligations
Lease Obligations	(12) Lease Obligations Lease Obligations Office Lease In March 2021, BDSC defaulted on the office lease due to non-payment of rent. In May 2021, BDSC and TR 801 Travis LLC (“Building Lessor”) reached an agreement to cure BDSC’s office lease default. Under a Fourth Amendment to Lease dated May 27, 2021 (the “Fourth Amendment”), Building Lessor agreed to defer BDSC’s past due obligations, including rent installments and other charges totaling approximately $0.1 million (the “Past Due Obligations”), in equal monthly installments beginning in June 2021, and continuing through lease expiration The Past Due Obligations were subject to an annual percentage rate of 4.50%. As revised under the Fourth Amendment, BDSC’s base rent including the prorated portion of the Past Due Obligations was $0.02 million per month. Subsequent to the Fourth Amendment, Building Lessor notified BDSC of a new default under the office lease due to non-payment of rent. As a result of the subsequent default, Building Lessor deemed the Fourth Amendment invalid. On June 9, 2022, BDSC paid all past due amounts totaling approximately $0.2 million to Building Lessor and Building Lessor considered the office lease default cured. An Affiliate, LEH, subleases a portion of the Houston office space. BDSC received sublease income from LEH totaling $0.03 million for both twelve-month periods ended December 31, 2022 and 2021. See “Note (3)” to our consolidated financial statements for additional disclosures related to the Affiliate sub-lease. The following table presents the lease-related assets and liabilities recorded on the consolidated balance sheet: December 31, Balance Sheet Location 2022 2021 (in thousands) Assets Operating lease ROU assets Operating lease ROU assets $ 787 $787 Less: Accumulated amortization on operating lease assets Operating lease ROU assets (638 ) (455) Total lease assets 149 332 Liabilities Current Operating lease Current portion of lease liabilities 156 215 Noncurrent Operating lease Long-term lease liabilities, net of current - 156 $ 156 $371 Weighted average remaining lease term in years Operating lease 0.67 Weighted average discount rate Operating lease 8.25 % The following table presents information related to lease costs incurred for operating and finance leases: Twelve Months Ended December 31, 2022 2021 (in thousands) Operating lease costs $ 206 $ 206 Total lease cost $ 206 $ 206 The table below presents supplemental cash flow information related to leases as follows: Twelve Months Ended December 31, 2022 2021 (in thousands) Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows for operating lease $ 237 $ 233 As of December 31, 2022, maturities of lease liabilities for the periods indicated were as follows: December 31, Operating Lease (in thousands) 2023 $ 156 $ 156 Future minimum annual lease commitments that are non-cancelable: Operating December 31, Lease (in thousands) 2023 $ 161 $ 161

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2022
Income Taxes
Income Taxes	(13) Income Taxes The Inflation Reduction Act ("IRA") was enacted into law 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 category of “applicable corporations” and are therefore exempt from payment of an alternative minimum tax. Tax Provision The provision for income tax benefit (expense) for the periods indicated was as follows: Twelve Months Ended December 31, 2022 2021 (in thousands) Current Federal $ - $ - State 307 - Deferred Federal 7,223 2,335 State - - Change in valuation allowance (7,223 ) (2,335 ) Total provision for income taxes $ 307 $ - 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. Effective Tax Rate Our effective tax rate was as follows: December 31, 2022 2021 Expected tax rate $ 7,223 21.00 % $ 2,335 21.00 % Permanent differences - 0.00 % 0.00 % State tax 307 0.92 % 0.00 % Federal tax 0.00 % 0.00 % Change in valuation allowance (7,223) (21.00 %) (2,335) (21.00 %) 307 0.92 % - 0.00 % Our effective tax rate differed from the U.S. federal statutory rate primarily due to AMT credits made refundable by the Tax Cuts and Jobs Act. At the date of enactment of the Tax Cuts and Jobs Act, we re-measured our deferred tax assets and liabilities using a rate of 21%, which is the rate expected to be in place when such deferred assets and liabilities are expected to reverse in the future. The re-measurement was offset by a change in our valuation allowance, resulting in there being no impact on our net deferred tax assets. Deferred income taxes as of the dates indicated consisted of the following: December 31, 2022 2021 (in thousands) Deferred tax assets: NOL and capital loss carryforwards $ 11,088 $ 16,818 Business interest expense 3,524 4,680 Start-up costs (crude oil and condensate processing facility) 339 424 ARO liability/deferred revenue 779 727 Other 43 12 Total deferred tax assets 15,773 22,661 Deferred tax liabilities: Basis differences in property and equipment (8,216 ) (7,945 ) Total deferred tax liabilities (8,216 ) (7,945 ) 7,557 14,716 Valuation allowance (7,557 ) (14,716 ) Deferred tax assets, net $ - $ - 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. NOL Carryforwards 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 roughly $0.6 million per year. We may use 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. 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 that were generated beginning in 2018 may only be used to offset 80% of taxable income and are carried forward indefinitely. NOL Carryforwards Net Operating Loss Carryforward Pre-Ownership Change Post-Ownership Change Total (in thousands) Balance at December 31, 2020 9,614 56,363 65,977 Net operating losses used and expired (1,717 ) 9,148 7,431 Balance at December 31, 2021 $ 7,897 $ 65,511 $ 73,408 Net operating losses used and expired (6,127 ) (22,384 ) (28,511 ) Balance at December 31, 2022 $ 1,770 $ 43,127 $ 44,897 Valuation Allowance We have NOL carryforwards that remain available for future use. At December 31, 2022 and 2021, there were no uncertain tax positions for which a reserve or liability was necessary.

Earnings and Dividends Per Shar

Earnings and Dividends Per Share	12 Months Ended
	Dec. 31, 2022
Earnings and Dividends Per Share
Earnings Per Share	(14) Earnings and Dividends Per Share A reconciliation between basic and diluted income per share for the periods indicated was as follows: Twelve Months Ended December 31, 2022 2021 (in thousands, except share and per share amounts) Net income (loss) $ 32,892 $ (12,841 ) Earnings per share Basic and diluted income (loss) per share $ 2.34 $ (1.01 ) Basic and diluted shares used in computing earnings per share 14,079,327 12,693,514 Diluted EPS for the twelve months ended December 31, 2022 and 2021 was the same as basic EPS as there were no stock options or other dilutive instruments outstanding. Diluted EPS is computed by dividing net income available to common stockholders by the weighted average number of shares of common stock outstanding. Shareholders are entitled to receive such dividends as may be declared by our Board out of funds legally available for such purpose. However, no dividend may be declared or paid unless after-tax profit was made in the preceding fiscal year, we are in compliance with covenants in our secured loan agreements, we are current on all required debt payments, and we have received prior written concurrence from certain of our lenders.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2022
Commitments and Contingencies
Commitments and Contingencies	(15) Commitments and Contingencies 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 Amended and Restated Operating Agreement. BSEE Offshore Pipelines and Platform Decommissioning BDPL has pipelines and platform assets that are subject to BSEE’s idle iron regulations. Idle iron regulations mandate lessees and rights-of-way holders to permanently abandon and/or 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. In December 2018, BSEE issued an INC to BDPL for failing to flush and fill Pipeline Segment No. 13101. Management met with BSEE in August 2019 to address BDPL’s plans with respect to decommissioning its offshore pipelines and platform assets. BSEE proposed that BDPL re-submit pipeline and platform decommissioning permit applications, including a safe boarding plan, by February 2020. BDPL submitted permit applications to BSEE in February 2020 and the USACOE in March 2020. In April 2020, BSEE issued another INC to BDPL for failing to perform the required structural surveys for the GA-288C Platform. BDPL completed the required platform surveys in June 2020. In August 2022, BSEE issued an INC to BDPL for failing to complete decommissioning its main offshore pipeline and anchor platform. In addition, pursuant to a September 2022 letter, BSEE ordered BDPL to complete pipeline decommissioning and removal of the anchor platform by June 1, 2023. BDPL is examining the feasibility of completing decommissioning operations by BSEE’s deadline. In March 2023, BSEE issued an INC to BDPL for failing to perform the required structural surveys for the GA-288C platform for 2021 and 2022, and for failing to provide BSEE with such survey results. BDPL is obtaining vendor quotes for the performance of the required surveys and intends to submit a corrective action plan to BSEE. If BDPL fails to complete decommissioning of the offshore pipeline and platform assets and/or remedy the INCs within the timeframe mandated by BSEE, BDPL could be subject to regulatory oversight and enforcement, including but not limited to failing to correct an INC, civil penalties, and revocation of BDPL’s operator designation, which could have a material adverse effect on our earnings, cash flows, and liquidity. We cannot currently estimate when decommissioning may occur or predict the outcome of the BSEE INCs. Accordingly, we did not record a liability related to potential penalties on our consolidated balance sheets as of December 31, 2022 and 2021. At December 31, 2022 and 2021, BDPL maintained $3.7 million and $3.5 million, respectively, in AROs related to abandonment of these assets, which amount does not include potential penalties. Defaults Under Secured Loan Agreements with Third Parties and Related Parties See “Notes (1), (3), and (10)” to our consolidated financial statements for additional disclosures related to defaults under our secured and unsecured debt agreements. Financing Agreements and Guarantees Indebtedness Guarantees 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. Share Issuances We are obligated to issue shares of our Common Stock to: (i) Jonathan Carroll pursuant to the Guaranty Fee Agreements and (ii) non-employee directors for services rendered to the Board. Set forth below is information regarding the issuance of Common Stock related to these obligations during the twelve months ended December 31, 2022 and 2021: Services · On October 27, 2022, we issued an aggregate of 24,591 restricted shares of Common Stock to certain of our non-employee, independent directors, which represents payment for services rendered to the Board for the three-month period ended September 30, 2022. The cost basis was $1.22. · On May 12, 2022, we issued an aggregate of 252,447 restricted shares of Common Stock to certain of our non-employee, independent directors, which represents payment for services rendered to the Board for the three-month periods ended September 30, 2020, March 31, 2021, September 30, 2021, and March 31, 2022. The average cost basis was $0.55, the low was $0.33, and the high was $0.91. Payment of Debt · On September 6, 2022, we issued an aggregate of 98,336 restricted shares of Common Stock to Jonathan Carroll, which represents payment of the common stock component under the LE Amended and Restated Guaranty Fee Agreement and LRM Amended and Restated Guaranty Fee Agreement for monthly periods from April 2022 to June 2022. The average cost basis was $0.86, the low was $0.58, and the high was $1.26. · On May 12, 2022, we issued an aggregate of 1,853,080 restricted shares of Common Stock to Jonathan Carroll, which represents payment of the common stock component under the LE Amended and Restated Guaranty Fee Agreement and LRM Amended and Restated Guaranty Fee Agreement for monthly periods from April 2020 through March 2022. The average cost basis was $0.42, the low was $0.27, and the high was $0.64. The securities issuances were exempt from registration under the Securities Act in reliance on Section 4(a)(2) of the Securities Act. We recognized a loss on the issuance of shares of approximately $0.4 million and $0 for the twelve months ended December 31, 2022 and 2021, respectively. See “Notes (1), (3) and (15)” to our consolidated financial statements for additional disclosures related to Affiliates and working capital deficits, as well as for information related to the LE Amended and Restated Guaranty Fee Agreement and LRM Amended and Restated Guaranty Fee Agreement. 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 may also become party to lawsuits, administrative proceedings, and governmental investigations, including environmental, regulatory, and other matters. Large, and sometimes unspecified, damages or penalties may be sought from us in some matters and certain matters 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. Unresolved Matters. Pilot Dispute Related to Terminal Services Agreement . Effective May 9, 2019, NPS and Pilot entered into a Terminal Services Agreement, pursuant to which NPS agreed to store jet fuel purchased by Pilot at the Nixon facility. On August 25, 2022, Pilot provided the required 60-days’ notice of its intent to terminate the Terminal Services Agreement, which became effective on October 24, 2022. As of the Terminal Services Agreement termination date, approximately 185,000 bbls of Pilot’s jet fuel remained at the Nixon facility. On October 28, 2022, Pilot commenced an action and application for a temporary restraining order (“TRO”) against NPS in Harris County District Court (the “Texas Action”). After a hearing on the application on October 28, 2022, Pilot’s application for the TRO was denied the same day. On December 2, 2022, NPS filed its answer in the Texas Action. On December 6, 2022, NPS provided notice under Section 7.206(a) of the Texas Business and Commerce Code (“TBCC”) of its intent to sell the remaining inventory of Pilot’s jet fuel at the Nixon facility by January 7, 2023. After a series of negotiations, NPS agreed to forbear from exercising its remedies under the TBCC while the parties explored a potential compromise of the dispute. The parties entered a Forbearance and Accommodation Agreement on January 12, 2023, with the forbearance period terminating on February 28, 2023. As part of the Forbearance and Accommodation Agreement, Pilot paid NPS approximately $1.481 million on January 13, 2023. On March 31, 2023, NPS and Pilot executed an Amendment to the Forbearance and Accommodation Agreement (“March 31 Amendment”) with the forbearance term extending to June 15, 2023. The March 31 Amendment requires an additional payment by Pilot to NPS of approximately $1.08 million on April 3, 2023 and a conditional payment of $0.18 million on June 1, 2023. Pursuant to the March 31 Amendment all deadlines in the Texas Action have been tolled through June 15, 2023. As of the filing date of this report, no settlement has been reached. BOEM Additional Financial Assurance (Supplemental Pipeline Bonds) BDPL historically maintained $0.9 million in financial assurance to BOEM for the decommissioning of its trunk pipeline offshore in federal waters. Following an agency restructuring of the financial assurance program, in March 2018 BOEM ordered BDPL to provide additional financial assurance totaling approximately $4.8 million for five (5) existing pipeline rights-of-way. In June 2018, BOEM issued BDPL INCs for each right-of-way that failed to comply. BDPL appealed the INCs to the IBLA. Although the IBLA granted multiple extension requests, the Office of the Solicitor of the U.S. Department of the Interior indicated that BOEM would not consent to further extensions. The solicitor’s office signaled that BDPL’s adherence to milestones identified in an August 2019 meeting between management and BSEE may help in future discussions with BOEM related to the INCs. Decommissioning of these assets will significantly reduce or eliminate the amount of financial assurance required by BOEM, which may serve to partially or fully resolve the INCs. 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 financial assurance (supplemental pipeline bond) requirements. If BDPL is required by BOEM to provide significant additional financial assurance (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 are currently unable to predict the outcome of the BOEM INCs. Accordingly, we did not record a liability on our consolidated balance sheets as of December 31, 2022 and 2021. At both December 31, 2022 and 2021, BDPL maintained approximately $0.9 million in pipeline rights-of-way surety bonds issued to BOEM through RLI Corp. Of the pipeline rights-of-way bonds, $0.7 million was credit-backed and $0.2 million was cash-backed. OSHA Settlement Agreement TCEQ Proposed Agreed Order Pilot Dispute Related to Set-Off Payments Defaults under Secured Loan Agreements Counterparty Contract-Related Dispute

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2022
Subsequent Events
Subsequent Events	(16) Subsequent Events Second Amended and Restated Operating Agreement The Second Amended and Restated Operating Agreement was renewed with an effective date of April 1, 2023, and was executed on March 14, 2023. The renewal term begins on the effective date and expires upon the earliest to occur of the following: (a) upon the first anniversary of the effective date, which termination date shall be April 1, 2024, (b) upon written notice of either party upon the material breach of the agreement by the other party, or (c) upon 90 days’ notice by the Board if the Board determines that the Second Amended and Restated Operating Agreement is not in the best interest of Blue Dolphin, LE, LRM, NPS, BDPL, BDPC and/or BDSC. With the exception of the term length, terms of the Second Amended and Restated Operating Agreement were the same as the Amended and Restated Operating Agreement. For services rendered: (a) Blue Dolphin, LE, LRM, NPS, BDPL, BDPC and BDSC shall reimburse LEH at cost for all direct expenses, either paid directly by LEH or financed with LEH’s credit card. Amounts payable to LEH shall be invoiced by LEH weekly but may be reimbursed sooner and (b) Blue Dolphin shall also pay to LEH a management fee equal to 5% of all consolidated operating costs, excluding crude costs, depreciation, amortization, and interest. Guaranty Fee Agreements Jonathan Carroll was required to provide his personal guarantee on certain of our secured loan agreements. · BDEC Guaranty Fee Agreement – The BDEC Guaranty Fee Agreement, with an effective date of January 1, 2023, was executed on March 14, 2023. Under the BDEC Guaranty Fee Agreement, Jonathan Carroll shall receive a fee equal to 2.00% per annum of the outstanding principal balance owed under the BDEC Term Loan Due 2051, payable 100% in cash. · NPS Guaranty Fee Agreement – The NPS Guaranty Fee Agreement, with an effective date of January 1, 2023, was executed on March 14, 2023. Under the NPS Guaranty Fee Agreement, Jonathan Carroll shall receive a fee equal to 2.00% per annum of the outstanding principal balance owed under the NPS Term Loan Due 2031, payable 100% in cash. · LE Amended and Restated Guaranty Fee Agreement – The LE Amended and Restated Guaranty Fee Agreement was further amended and restated with an effective date of January 1, 2023; the agreement was executed on March 14, 2023. As further amended and restated, Jonathan Carroll shall receive a fee equal to 2.00% per annum of the outstanding principal balance owed under the LE Term Loan Due 2034, payable 100% in cash. · LRM Amended and Restated Guaranty Fee Agreement – The LRM Amended and Restated Guaranty Fee Agreement was further amended and restated with an effective date of January 1, 2023; the agreement was executed on March 14, 2023. As further amended and restated, Jonathan Carroll shall receive a fee equal to 2.00% per annum of the outstanding principal balance owed under the LRM Term Loan Due 2034, payable 100% in cash. The amounts expensed related to the guaranty fee agreements are reflected within interest and other expense in our consolidated statements of operations. Master Services Agreement Effective March 1, 2023, LE entered a Master Services Agreement with Ingleside for storage of products intended for customer receipt by barge. The agreement has a three-year term. The tank rental fee is $0.50 per bbl per month. The agreement was executed on March 14, 2023. Jet Fuel Sales Agreement Effective April 1, 2023, LE entered into a renewed Jet Fuel Sales Agreement with LEH. The agreement has a one year term expiring on the earliest to occur of March 31, 2024 plus a 30-day carryover or delivery of the maximum jet fuel quantity. The agreement was executed on March 24, 2023. Together, Jonathan Carroll and LEH own approximately 83% of Blue Dolphin’s Common Stock. See “Note (3)” of our consolidated financial statements for additional disclosures related to agreements with Affiliates. Terminal Services Agreement Effective November 1, 2022, NPS entered a Terminal Services Agreement with LEH for the storage of jet fuel by LEH. The agreement has a one year term with one-year automatic renewals. The tank rental fee is approximately $0.2 million per month. The agreement was ratified by the Board on March 7, 2023. Master Service Agreement Effective March 1, 2023, LE entered a Master Service Agreement with Ingleside for the storage of product intended for customer receipt by barge. The agreement has a three-year term. The tank rental fee is $0.50 per bbl per month. The agreement was approved by the Board on March 7, 2023.

Principles of Consolidation a_2

Principles of Consolidation and Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2022
Principles of Consolidation and Significant Accounting Policies
Basis of Presentation	The accompanying consolidated financial statements, which include Blue Dolphin and its subsidiaries, have been prepared in accordance with U.S. generally accepted accounting principles and the rules and regulations of the SEC. These rules and regulations conform to the accounting principles contained in FASB’s ASC, the single source of GAAP. All significant intercompany items have been eliminated in consolidation. Additionally, any material subsequent events that occurred after the date through which this report covers have been properly recognized or disclosed in our financial statements. In management’s opinion, all adjustments considered necessary for a fair presentation have been included, disclosures are adequate, and the presented information is not misleading.
Significant Accounting Policies	The summary of significant accounting policies of Blue Dolphin is presented to assist in understanding our consolidated financial statements. Our consolidated financial statements and accompanying notes are representations of management, who is responsible for their integrity and objectivity. These accounting policies conform to GAAP and have been consistently applied in the preparation of our consolidated financial statements.
Use of Estimates	Use of Estimates We assessed certain accounting matters that require consideration of forecasted financial information in context with information reasonably available to us as of December 31, 2022 and through the filing date of this report. The accounting matters assessed included, but not limited to, our allowance for doubtful accounts, inventory, and related reserves, and the carrying value of long-lived assets.
Cash, Cash Equivalents, and Restricted Cash	Cash, Cash Equivalents, and Restricted Cash The following table provides a reconciliation of cash, cash equivalents, and restricted cash as reported in the consolidated statements of cash flows: December 31, 2022 2021 (in thousands) Cash and cash equivalents $ 520 $ 9 Restricted cash - 48 Restricted cash, noncurrent 1,001 - $ 1,521 $ 57
Accounts Receivable, Allowance for Doubtful Accounts	Accounts Receivable and Allowance for Doubtful Accounts
Financial Instruments	Financial Instruments
Inventory	Inventory
Property and Equipment	Refinery and Facilities Pipelines and Facilities Oil and Gas Properties CIP
Leases	Leases. For operating leases, we record lease cost on a straight-line basis over the lease term; we record lease expenses in the appropriate line on the income statement based on the leased asset’s intended use. For finance leases (previously referred to under GAAP as capital leases), we amortize lease payments for the ROU asset on a straight-line basis over the lesser of the leased asset’s useful life or the lease term; we record amortization expenses on the income statement in ‘depreciation and amortization expense;’ we record interest expense on the income statement in ‘interest and other expense.’
Revenue Recognition	Refinery Operations Revenue 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 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 services are considered optional to the customer. 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 Unearned Contract Renewal Income.
Income Taxes	Income Taxes Income taxes are calculated utilizing the applicable rates on items included in the determination of income for income tax purposes. Our effective tax rate may be different than what would be expected if the federal and state statutory rates were applied to income from continuing operations primarily because of amounts expensed for financial reporting that are not deductible for tax purposes. The benefit of an uncertain tax position is recognized in the financial statements if it meets a minimum recognition threshold. A determination is first made as to whether it is more likely than not that the income tax position will be sustained, based upon technical merits, upon examination by the taxing authorities. If the income tax position is expected to meet the more-likely-than-not criteria, the benefit recorded in the financial statements equals the largest amount that is greater than 50% likely to be realized upon its ultimate settlement. At December 31, 2022 and 2021, there were no uncertain tax positions for which a reserve or liability is necessary.
Deferred Taxes	Deferred Taxes
Impairment or Disposal of Long-Lived Assets	Impairment or Disposal of Long-Lived Assets Commodity price market volatility associated with the Russian military conflict with Ukraine, recession, inflation, and COVID-19 could affect the value of certain of our long-lived assets. Management evaluated refinery and facilities assets for impairment as of December 31, 2022. We did not record any impairment of our long-lived assets for the periods presented. However, impairment may be required in the future if losses are material, or as new opportunities arise, such as reconfiguration of the Nixon refinery into a renewable fuels facility.
Asset Retirement Obligations	Asset Retirement Obligations Refinery and Facilities Pipeline and Facilities; Oil and Gas Properties
Computation of Earnings Per Share	Computation of Earnings Per Share
New Pronouncements Adopted	New Pronouncements Adopted
New Pronouncements Issued, Not Yet Effective	New Pronouncements Issued, Not Yet Effective .

Principles of Consolidation a_3

Principles of Consolidation and Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2022
Principles of Consolidation and Significant Accounting Policies
Schedule of reconciliation of cash, cash equivalents, and restricted cash	December 31, 2022 2021 (in thousands) Cash and cash equivalents $ 520 $ 9 Restricted cash - 48 Restricted cash, noncurrent 1,001 - $ 1,521 $ 57

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2022
Related Party Transactions
Affiliate agreements/transactions	Agreement/Transaction Parties Effective Date Key Terms Jet Fuel Sales Agreement (1) LEH LE 04/01/2022 1-year term expiring earliest to occur of 03/31/2024 plus 30-day carryover or delivery of maximum jet fuel quantity; LEH bids on jet fuel contracts under preferential pricing terms due to a HUBZone certification Office Sub-Lease Agreement LEH BDSC 01/01/2018 68-month term expiring 08/31/2023; office lease Houston, Texas; includes 6-month rent abatement period; rent approximately $0.01 million per month Amended and Restated Operating Agreement (2) LEH Blue Dolphin LE LRM NPS BDPL BDPC BDSC 04/01/2020 1-year term; expires 04/01/2024 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, excluding crude costs, depreciation, amortization, and interest, of Blue Dolphin, LE, LRM, NPS, BDPL, BDPC and BDSC LE Amended and Restated Guaranty Fee Agreement (3) LE Jonathan Carroll 04/01/2017 Related to payoff of LE $25.0 million Veritex loan; Jonathan Carroll receives fee equal to 2.00% per annum of outstanding principal balance owed under LE Term Loan Due 2034 LRM Amended and Restated Guaranty Fee Agreement (3) LRM Jonathan Carroll 04/01/2017 Related to payoff of LRM $10.0 million Veritex loan; Jonathan Carroll receives fee equal to 2.00% per annum of outstanding principal balance owed under LRM Term Loan Due 2034 Loan Description Parties Maturity Date Interest Rate Loan Purpose June LEH Note (in default) LEH Blue Dolphin Jan 2019 8.00% Blue Dolphin working capital; reflects amounts owed to LEH under the Second Amended and Restated Operating Agreement BDPL-LEH Loan Agreement (in default) LEH BDPL Aug 2018 16.00% Original principal amount of $4.0 million; Blue Dolphin working capital Loan Description Guarantees Security Event(s) of Default June LEH Note (in default) --- --- Failure to pay past due obligations at maturity (loan matured January 2019) BDPL-LEH Loan Agreement (in default) --- Certain BDPL property Failure to pay past due obligations at maturity (loan matured August 2018)
Accounts payable, related party	December 31, 2022 2021 (in thousands) LEH June LEH Note (in default) $ 1,211 $ 12,672 BDPL-LEH Loan Agreement (in default) 8,094 7,454 LEH Total 9,305 20,126 Ingleside March Ingleside Note - 1,066 Jonathan Carroll March Carroll Note - 2,304 9,305 23,496 Less: Long-term debt, related party, current portion (in default) (5,211 ) (20,042 ) Less: Accrued interest payable, related party (in default) (4,094 ) (3,454 ) $ - $ - June LEH Note (in default) (in thousands) Balance at December 31, 2021 $ 12,672 Related-party receivables settled against related-party provided working capital (21,076 ) Blue Dolphin operating costs and related LEH management fee under Amended and Restated Operating Agreement 9,615 Balance at December 31, 2022 $ 1,211
Refinery operating expenses	Twelve Months Ended December 31, 2022 2021 (in thousands, except percent amounts) Refinery operations LEH $ 173,646 35.6 % $ 90,062 29.9 % Third-Parties 309,415 63.5 % 207,041 68.8 % Tolling and terminaling LEH 360 0.1 % - - Third-Parties 4,083 0.8 % 3,717 1.2 % $ 487,504 100.0 % $ 300,820 100.0 %
Accrued interest expenses	Twelve Months Ended December 31, 2022 2021 (in thousands) Jonathan Carroll Guaranty Fee Agreements First Term Loan Due 2034 (in default) $ 428 $ 430 Second Term Loan Due 2034 (in default) 177 178 March Carroll Note 146 132 LEH BDPL-LEH Loan Agreement (in default) 480 640 June LEH Note (in default) 383 928 Ingleside March Ingleside Note 69 56 $ 1,683 $ 2,364

Revenue and Segment Informati_2

Revenue and Segment Information (Tables)	12 Months Ended
	Dec. 31, 2022
Revenue and Segment Information
Schedule of business segment Infirmation	Twelve Months Ended December 31, 2022 2021 (in thousands) Refinery operations $ 483,061 $ 297,103 Tolling and terminating 4,443 3,717 Total revenue from operations 487,504 300,820 Intercompany processing fees (1) Refinery operations (2,583 ) (2,457 ) Tolling and terminating 2,583 2,457 Total intercompany processing fees - - Operation costs and expenses (2) Refinery operations (439,292 ) (298,082 ) Tolling and terminating (2,142 ) (1,825 ) Corporate and other (221 ) (197 ) Total operation costs and expenses (441,655 ) (300,104 ) Segment contribution margin (deficit) Refinery operations 41,186 (3,436 ) Tolling and terminating (3) 4,884 4,349 Corporate and other (221 ) (197 ) Total segment contribution margin (deficit) 45,849 716 General and administrative expenses (4) Refinery operations (1,682 ) (1,549 ) Tolling and terminating (427 ) (343 ) Corporate and other (1,860 ) (2,742 ) Total general and administrative expenses (3,969 ) (4,634 ) Depreciation and amortization Refinery operations (1,224 ) (1,214 ) Tolling and terminating (1,368 ) (1,362 ) Corporate and other (206 ) (204 ) Total depreciation and amortization (2,798 ) (2,780 ) Interest and other non-operating expenses, net (5) Refinery operations (2,753 ) (2,779 ) Tolling and terminating (1,433 ) (1,649 ) Corporate and other (1,697 ) (1,715 ) Total interest and other non-operating expenses, net (5,883 ) (6,143 ) Income (loss) before income taxes Refinery operations 35,527 (8,978 ) Tolling and terminating 1,656 995 Corporate and other (3,984 ) (4,858 ) Total income (loss) before income taxes 33,199 (12,841 ) Income tax expense (307 ) - Net income (loss) $ 32,892 $ (12,841 )
Total capital expenditure	Twelve Months Ended December 31, 2022 2021 (in thousands) Capital expenditures Refinery operations $ 102 $ - Tolling and terminating - - Corporate and other - - Total capital expenditures $ 102 $ - December 31, 2022 2021 (in thousands) Identifiable assets Refinery operations $ 64,359 $ 47,047 Tolling and terminating 17,836 17,594 Corporate and other 1,709 1,668 Total identifiable assets $ 83,904 $ 66,309
Contract Balances	December 31, 2022 2021 Accounts receivable (including related-party), beginning of year $ 126 $ 214 Accounts receivable (including related-party), end of year 1,148 126 Unearned revenue, beginning of year $ 4,388 $ 3,421 Unearned revenue, end of year 3,888 4,388

Concentration of Risk (Tables)

Concentration of Risk (Tables)	12 Months Ended
	Dec. 31, 2022
Concentration of Risk
Schedule of significant customers	Twelve Months Ended Number Significant Customers % Total Revenue from Operations Portion of Accounts Receivable at December 31, December 31, 2022 2 60.4 % $ 0 December 31, 2021 3 71.9 % $ 0
Schedule of percentages of all refined petroleum products sales to total sales	Twelve Months Ended December 31, 2022 2021 (in thousands, except percent amounts) LPG mix $ 122 0.0 % $ 21 0.0 % Naphtha 99,946 20.7 % 74,683 25.2 % Jet fuel 173,646 35.9 % 90,062 30.3 % HOBM 88,472 18.3 % 65,386 22.0 % AGO 120,875 25.1 % 66,951 22.5 % $ 483,061 100.0 % $ 297,103 100.0 %

Prepaid Expenses and Other Cu_2

Prepaid Expenses and Other Current Assets (Tables)	12 Months Ended
	Dec. 31, 2022
Prepaid Expenses and Other Current Assets
Schedule of Prepaid Expenses & other current assets	December 31, 2022 2021 (in thousands) Prepaid crude oil and condensate $ 2,183 $ 1,368 Prepaid insurance 1,066 953 Other prepaids 163 36 Prepaid easement renewal fees 54 76 $ 3,466 $ 2,433

Inventory (Tables)

Inventory (Tables)	12 Months Ended
	Dec. 31, 2022
Inventory
Schedule of inventory	December 31, 2022 2021 (in thousands) HOBM $ 14,879 $ 1,749 Crude oil and condensate 3,458 660 Naphtha 1,056 189 AGO 301 338 Chemicals 116 121 Propane 27 27 LPG mix 7 14 $ 19,844 $ 3,098

Property Plant and Equipment _2

Property Plant and Equipment Net (Tables)	12 Months Ended
	Dec. 31, 2022
Property Plant and Equipment Net
Schedule of property, plant and equipment	December 31, 2022 2021 (in thousands) Refinery and facilities $ 72,675 $ 72,583 Land 566 566 Other property and equipment 913 903 74,154 74,052 Less: Accumulated depreciation and amortiation (20,387 ) (17,795 ) 53,767 56,257 CIP 3,669 3,666 $ 57,436 $ 59,923

Accrued Expenses and Other Cu_2

Accrued Expenses and Other Current Liabilities (Tables)	12 Months Ended
	Dec. 31, 2022
Accrued Expenses and Other Current Liabilities
Schedule of accrued expenses and other current liabilities	December 31, 2022 2021 (in thousands) Unearned revenue from contracts with customers $ 3,888 $ 4,388 Insurance 568 273 Unearned contract renewal income 480 400 Accrued fines and penalties 407 407 Other payable 324 218 Board of director fees payable 210 230 Customer deposits 173 173 Taxes payable 64 136 $ 6,114 $ 6,225

ThirdParty LongTerm Debt (Table

ThirdParty LongTerm Debt (Tables)	12 Months Ended
	Dec. 31, 2022
ThirdParty LongTerm Debt
Schedule of long term debt	December 31, 2022 2021 (in thousands) Veritex Loans LE Term Loan Due 2034 (in default) $ 20,801 $ 23,789 LRM Term Loan Due 2034 (in default) 8,671 9,861 Kissick Debt (in default) 11,006 10,210 GNCU Loan NPS Term Loan Due 2031 ( in default 9,975 10,094 SBA EIDLs BDEC Term Loan Due 2051 2,082 512 LE Term Loan Due 2050 162 156 NPS Term Loan Due 2050 162 156 Equipment Loan Due 2025 38 53 52,897 54,831 Less: Current portion of long-term debt, net (42,155 ) (42,953 ) Less: Unamortized debt issue costs (2,149 ) (2,351 ) Less: Accrued interest payable (6,271 ) (8,689 ) $ 2,322 $ 838
Schedule of unamortized debt issue cost	December 31, 2022 2021 (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 (1,023 ) (821 ) $ 2,149 $ 2,351
Schedule of accrued interest related to our long-term debt, net	December 31, 2022 2021 (in thousands) Kissick Debt (in default) $ 6,028 $ 5,232 Veritex Loans LE Term Loan Due 2034 (in default) 53 2,338 LRM Term Loan Due 2034 (in default) 66 959 GNCU Loan NPS Term Loan Due 2031 ( in default 17 136 SBA EIDLs BDEC Term Loan Due 2051 82 12 LE Term Loan Due 2050 12 6 NPS Term Loan Due 2053 12 6 Equipment Loan Due 2025 1 - 6,271 8,689 Less: Accrued interest payable (in default) (6,271 ) (8,689 ) Long-term Interest Payable, Net of Current Portion $ - $ -
Future annual third-party long-term debt payments	Years Ending December 31, Principal Debt Issue Costs Total (in thousands) 2023 $ 44,304 $ (2,149 ) $ 42,155 2024 16 - 16 2025 5 - 5 2026 - - - 2027 35 - 35 Subsequent to 2027 2,266 - 2,266 $ 46,626 $ (2,149 ) $ 44,477

AROs (Tables)

AROs (Tables)	12 Months Ended
	Dec. 31, 2022
AROs
Schedule of asset retirement obligations	December 31, 2022 2021 (in thousands) AROs, at the beginning of the period $ 3,461 $ 2,370 Changes in estimates of existing obligations 114 1,091 Accretion expense 135 - - 3,461 Less: AROs, current portion (3,710 ) - Long-term AROs, at the end of the period $ - $ 3,461

Lease Obligations (Tables)

Lease Obligations (Tables)	12 Months Ended
	Dec. 31, 2022
Lease Obligations
Schedule of lease-related assets and liabilities	December 31, Balance Sheet Location 2022 2021 (in thousands) Assets Operating lease ROU assets Operating lease ROU assets $ 787 $787 Less: Accumulated amortization on operating lease assets Operating lease ROU assets (638 ) (455) Total lease assets 149 332 Liabilities Current Operating lease Current portion of lease liabilities 156 215 Noncurrent Operating lease Long-term lease liabilities, net of current - 156 $ 156 $371 Weighted average remaining lease term in years Operating lease 0.67 Weighted average discount rate Operating lease 8.25 %
Schdule of lease cost	Twelve Months Ended December 31, 2022 2021 (in thousands) Operating lease costs $ 206 $ 206 Total lease cost $ 206 $ 206
Schedule of supplemental cash flow information related to leases	Twelve Months Ended December 31, 2022 2021 (in thousands) Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows for operating lease $ 237 $ 233
Schedule of maturities of operating lease liabilities	December 31, Operating Lease (in thousands) 2023 $ 156 $ 156
Schedule of future minimum annual lease commitments	Operating December 31, Lease (in thousands) 2023 $ 161 $ 161

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2022
Income Taxes
Schedule of provision for income tax expense benefit	Twelve Months Ended December 31, 2022 2021 (in thousands) Current Federal $ - $ - State 307 - Deferred Federal 7,223 2,335 State - - Change in valuation allowance (7,223 ) (2,335 ) Total provision for income taxes $ 307 $ -
Schedule of effective tax rate	December 31, 2022 2021 Expected tax rate $ 7,223 21.00 % $ 2,335 21.00 % Permanent differences - 0.00 % 0.00 % State tax 307 0.92 % 0.00 % Federal tax 0.00 % 0.00 % Change in valuation allowance (7,223) (21.00 %) (2,335) (21.00 %) 307 0.92 % - 0.00 %
Schedule of deferred tax assets and deferred tax liabilities	December 31, 2022 2021 (in thousands) Deferred tax assets: NOL and capital loss carryforwards $ 11,088 $ 16,818 Business interest expense 3,524 4,680 Start-up costs (crude oil and condensate processing facility) 339 424 ARO liability/deferred revenue 779 727 Other 43 12 Total deferred tax assets 15,773 22,661 Deferred tax liabilities: Basis differences in property and equipment (8,216 ) (7,945 ) Total deferred tax liabilities (8,216 ) (7,945 ) 7,557 14,716 Valuation allowance (7,557 ) (14,716 ) Deferred tax assets, net $ - $ -
Schedule of NOL carryforwards	Net Operating Loss Carryforward Pre-Ownership Change Post-Ownership Change Total (in thousands) Balance at December 31, 2020 9,614 56,363 65,977 Net operating losses used and expired (1,717 ) 9,148 7,431 Balance at December 31, 2021 $ 7,897 $ 65,511 $ 73,408 Net operating losses used and expired (6,127 ) (22,384 ) (28,511 ) Balance at December 31, 2022 $ 1,770 $ 43,127 $ 44,897

Earnings and Dividends Per Sh_2

Earnings and Dividends Per Share (Tables)	12 Months Ended
	Dec. 31, 2022
Earnings and Dividends Per Share
Schedule of earnings per share	Twelve Months Ended December 31, 2022 2021 (in thousands, except share and per share amounts) Net income (loss) $ 32,892 $ (12,841 ) Earnings per share Basic and diluted income (loss) per share $ 2.34 $ (1.01 ) Basic and diluted shares used in computing earnings per share 14,079,327 12,693,514

Organization (Details Narrative

Organization (Details Narrative) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Substantial Current Debt	$ 47,400	$ 63,000
Net income	32,900
Net loss	12,800
Working capital deficit	(45,200)	(78,500)
Working capital deficit, excluding the current portion of long-term debt	(2,100)	(15,500)
Cash and cash equivalents	1,500	$ 10,500
Restricted cash non current portion	$ 1,200
Ownership percentage	5%
Interest incurred	$ 4,300
Veritex Loans
Payment reserve account	1,000
Attorney fees	40
Payment for late fees	$ 400
Affiliates [Member]
Ownership percentage	83%

Principles of Consolidation a_4

Principles of Consolidation and Significant Accounting Policies (Details) - USD ($)	Dec. 31, 2022	Dec. 31, 2021
Principles of Consolidation and Significant Accounting Policies
Cash and cash equivalents	$ 520,000	$ 9,000
Restricted cash	0	48,000
Restricted cash, noncurrent	1,001	0
Total	$ 1,521,000	$ 57,000

Principles of Consolidation a_5

Principles of Consolidation and Significant Accounting Policies (Details Narrative) - USD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Allowance for doubtful accounts	$ 600	$ 0
Impairment loss	$ 10,000	$ 1,100,000
Uncertain tax position , description	benefit recorded in the financial statements equals the largest amount that is greater than 50% likely to be realized upon its ultimate settlement.
Minimum [Member]
Estimated useful life	10 years
Maximum [Member]
Estimated useful life	22 years
Refinery and Facilities
Estimated useful life	25 years

RelatedParty Transactions (Deta

RelatedParty Transactions (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Long-term debt - net of current portion, related party	$ 9,305	$ 23,496
Less: Long-term debt, related party, current portion, in default	(5,211)	(20,042)
Less: Interest payable, related party, in default	(4,094)	(3,454)
LEH
Prepaid operating expenses, related party	9,305	20,126
June LEH Note (in default) | LEH
Prepaid operating expenses, related party	1,211	12,672
BDPL Loan Agreement (in default) | LEH
Prepaid operating expenses, related party	8,094	7,454
March Ingleside Note (in default) | Ingleside
Prepaid operating expenses, related party	0	1,066
March Carroll Note (in default) | Jonathan Carroll
Prepaid operating expenses, related party	$ 0	$ 2,304

RelatedParty Transactions (De_2

RelatedParty Transactions (Details 1)	12 Months Ended
	Dec. 31, 2022 USD ($)
Related Party Transactions
Balance at beginning, related parties	$ 12,672,000
Related-party receivables settled against related-party provided working capital	(21,076,000)
Blue Dolphin operating costs and related LEH management fee	9,615
Balance at ending, related parties	$ 1,211

RelatedParty Transactions (De_3

RelatedParty Transactions (Details 2) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Total revenues	$ 487,504	$ 300,820
Total revenues, percent	100%	100%
LEH
Refinery operations revenues	$ 173,646	$ 90,062
Refinery operations revenues, percent	35.60%	29.90%
LEH | Tolling And Terminating
Tolling and terminaling revenues	$ 360	$ 0
Tolling and terminaling revenues, percent	0.10%
Third Parties
Refinery operations revenues	$ 309,415	$ 207,041
Refinery operations revenues, percent	63.50%	68.80%
Third Parties | Tolling And Terminating
Tolling and terminaling revenues	$ 4,083	$ 3,717
Tolling and terminaling revenues, percent	0.80%	1.20%

RelatedParty Transactions (De_4

RelatedParty Transactions (Details 3) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Interest expenses under loan and guarantee, related party	$ 1,683	$ 2,364
June LEH Note (in default) | LEH
Interest expenses under loan and guarantee, related party	383	928
BDPL Loan Agreement (in default) | LEH
Interest expenses under loan and guarantee, related party	480	640
March Ingleside Note (in default) | Ingleside
Interest expenses under loan and guarantee, related party	69	56
March Carroll Note (in default) | Jonathan Carroll
Interest expenses under loan and guarantee, related party	146	132
Term Loan Due 2034 | Jonathan Carroll
Interest expenses under loan and guarantee, related party	428	430
Second Term Loan Due 2034 | Jonathan Carroll
Interest expenses under loan and guarantee, related party	$ 177	$ 178

RelatedParty Transactions (De_5

RelatedParty Transactions (Details Narrative) - USD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
LEH operating fee	$ 700,000	$ 500,000
Refinery equipment	200,000	$ 200,000
June LEH Note (in default) | LEH
Restated guaranty fee	$ 30,000

Revenue and Segment Informati_3

Revenue and Segment Information (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 30, 2021
Revenue and Segment Information
Accounts receivable (including related-party), beginning of year	$ 126	$ 214
Accounts receivable (including related-party), end of year	1,148	126
Unearned revenue, beginning of year	4,388	3,421
Unearned revenue, end of year	$ 3,888	$ 4,388

Revenue and Segment Informati_4

Revenue and Segment Information (Details 1) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Refinery operations	$ 483,061	$ 297,103
Tolling and terminaling	4,443	3,717
Total revenue from operations	487,504	300,820
Income tax expense	307	0
Net income (loss)	32,892	(12,841)
Intercompany processing fees	0	0
Operation costs and expenses	(441,655)	(300,104)
Segment contribution margin (deficit)	45,849	716
General and administrative expenses	(2,915)	(3,021)
General and administrative expenses	(3,969)	(4,634)
Depreciation and amortization	(2,798)	(2,780)
Total interest and other non-operating expenses, net	(5,883)	(6,143)
Identifiable assets	83,904	66,309
Capital expenditures	102	0
Total loss before income taxes	(33,199)	12,841
Total loss before income taxes	33,199	(12,841)
Refinery Operations
Intercompany processing fees	(2,583)	(2,457)
Operation costs and expenses	(439,292)	(298,082)
Segment contribution margin (deficit)	41,186	(3,436)
General and administrative expenses	(1,682)	(1,549)
Depreciation and amortization	(1,224)	(1,214)
Interest and other non-operating expenses, net	(2,753)	(2,779)
Identifiable assets	64,359	47,047
Capital expenditures	102	0
Total loss before income taxes	(35,527)	8,978
Total loss before income taxes	35,527	(8,978)
Tolling and Terminaling
Intercompany processing fees	2,583	2,457
Operation costs and expenses	(2,142)	(1,825)
Segment contribution margin (deficit)	4,884	4,349
General and administrative expenses	(427)	(343)
Depreciation and amortization	(1,368)	(1,362)
Interest and other non-operating expenses, net	(1,433)	(1,649)
Identifiable assets	17,836	17,594
Capital expenditures	0	0
Total loss before income taxes	(1,656)	(995)
Total loss before income taxes	1,656	995
Corporate and Other
Operation costs and expenses	(221)	(197)
Segment contribution margin (deficit)	(221)	(197)
General and administrative expenses	(1,860)	(2,742)
Depreciation and amortization	(206)	(204)
Interest and other non-operating expenses, net	(1,697)	(1,715)
Identifiable assets	1,709	1,668
Capital expenditures	0	0
Total loss before income taxes	3,984	4,858
Total loss before income taxes	$ (3,984)	$ (4,858)

Concentration of Risk (Details)

Concentration of Risk (Details) - USD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Total Revenue from Operations	0.92%	0%
Customer Concentration Risk [Member]
Portion of accounts receivable	$ 0	$ 0
Total Revenue from Operations	60.40%	71.90%
Number Significant Customers	2	3

Concentration of Risk (Details

Concentration of Risk (Details 1) - Customer Concentration Risk [Member] - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
AGO
Total refined petroleum product sales	$ 120,875	$ 66,951
Concentration risk	25.10%	22.50%
Jet Fuel
Total refined petroleum product sales	$ 173,646	$ 90,062
Concentration risk	35.90%	30.30%
HOBM
Total refined petroleum product sales	$ 88,472	$ 65,386
Concentration risk	18.30%	22%
3 Significant Customers
Total refined petroleum product sales	$ 483,061	$ 297,103
Concentration risk	100%	100%
Naphtha
Total refined petroleum product sales	$ 99,946	$ 74,683
Concentration risk	20.70%	25.20%
LPG Mix
Total refined petroleum product sales	$ 122	$ 21
Concentration risk	0%	0%

Concentration of Risk (Detail_2

Concentration of Risk (Details Narrative)	12 Months Ended
	Dec. 31, 2022 USD ($) bbl	Dec. 31, 2021 USD ($) bbl
Concentration of Risk
Total revenue percentage	35.60%	29.90%
Balances in excess of FDIC insurance limit	$ 90,000	$ 0
Cash FDIC insured amount	$ 250,000
Crude oil, received | bbl	4,500	136,000
Description of total volume of contract	18.4%, and 4.2 million bbls, or 17.0%, respectively, of the contracted volume under the Crude Supply Agreement	54.8%, of the total allowable contracted volume under the Crude Supply Agreement.
Accounts payable	$ 0	$ 0
Net bbl amount | bbl	248,000

Prepaid Expenses and Other Cu_3

Prepaid Expenses and Other Current Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Prepaid Expenses and Other Current Assets
Prepaid crude oil and condensate	$ 2,183	$ 1,368
Prepaid insurance	1,066	953
Other prepaids	163	36
Prepaid easement renewal fees	54	76
Prepaid expenses, net	$ 3,466	$ 2,433

Inventory (Details)

Inventory (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Inventory	$ 19,844	$ 3,098
Crude Oil and Condensate
Inventory	3,458	660
AGO
Inventory	301	338
Chemicals
Inventory	116	121
Propane
Inventory	27	27
HOBM
Inventory	14,879	1,749
Naphtha
Inventory	1,056	189
LPG Mix
Inventory	$ 7	$ 14

Property Plant and Equipment _3

Property Plant and Equipment Net (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Total	$ 74,154	$ 74,052
Less: Accumulated depletion, depreciation, and amortization	(20,387)	(17,795)
Property, plant and equipment, net excluding CIP	53,767	56,257
CIP	3,669	3,666
Property, plant and equipment, net	57,436	59,923
Refinery and Facilities
Total	72,675	72,583
Land
Total	566	566
Other Property and Equipment
Total	$ 913	$ 903

Accrued Expenses and Other Cu_3

Accrued Expenses and Other Current Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Accrued Expenses and Other Current Liabilities
Unearned revenue from contracts with customers	$ 3,888	$ 4,388
Insurance	568	273
Unearned contract renewal income	480	400
Accrued fines and penalties	407	407
Taxes payable	64	136
Other payable	324	218
Board of director fees payable	210	230
Customer deposits	173	173
Total	$ 6,114	$ 6,225

ThirdParty LongTerm Debt (Detai

ThirdParty LongTerm Debt (Details)	12 Months Ended
	Dec. 31, 2022 USD ($)
LE Term Loan Due 2034
Original principal amount	$ 25,000,000
Maturity date	Jun 2015/ Jun 2034
Monthly principal and interest payment	$ 200,000
Interest rate	WSJ Prime + 2.75%
LRM Term Loan Due 2034
Original principal amount	$ 10,000,000
Maturity date	Dec 2015/ Dec 2034
Monthly principal and interest payment	$ 100,000
Interest rate	WSJ Prime + 2.75%
Kissick Debt
Original principal amount	$ 11,700,000
Maturity date	June 2006/ Jan 2018
Interest rate	16%
NPS Term Loan Due 2031
Original principal amount	$ 10,000,000
Maturity date	Oct 2021/ Oct 2031
Interest rate	5.75%
Monthly principal and interest payment	$ 100,000
BDEC Term Loan Due 2051
Original principal amount	$ 2,000,000
Maturity date	May 2021/ Jun 2051
Interest rate	3.75%
Monthly principal and interest payment	$ 10,000
LE Term Loan Due 2050
Original principal amount	$ 150,000
Maturity date	Aug 2020/ Aug 2050
Interest rate	3.75%
Monthly principal and interest payment	$ 700
NPS Term Loan Due 2050
Original principal amount	$ 150,000
Maturity date	Aug 2020/ Aug 2050
Interest rate	3.75%
Monthly principal and interest payment	$ 700
Equipment Loan Due 2025
Original principal amount	$ 700
Maturity date	Oct 2020/ Oct 2025
Interest rate	4.50%
Monthly principal and interest payment	$ 1,300

ThirdParty LongTerm Debt (Det_2

ThirdParty LongTerm Debt (Details 1) - USD ($)	Dec. 31, 2022	Dec. 31, 2021
Long-term debt, carrying amount	$ 46,626,000
Less: current portion of long-term debt, net	(42,155,000)	$ (42,953,000)
Less: unamortized debt issue costs	(2,149,000)	(2,351,000)
Less: accrued interest payable (in default)	(6,271,000)	(8,689,000)
Long-term debt, noncurrent	2,322,000	838,000
LE Term Loan Due 2034
Long-term debt, carrying amount	20,801,000	23,789,000
Less: accrued interest payable (in default)	(53,000)	(2,338,000)
LRM Term Loan Due 2034
Long-term debt, carrying amount	8,671,000	9,861,000
Less: accrued interest payable (in default)	(66,000)	(959,000)
Kissick Debt
Long-term debt, carrying amount	11,006,000	10,210,000
NPS Term Loan Due 2031
Long-term debt, carrying amount	9,975	10,094,000
Less: accrued interest payable (in default)	(17)	(136,000)
BDEC Term Loan Due 2051
Long-term debt, carrying amount	2,082	512,000
Less: accrued interest payable (in default)	(82)	(12,000)
LE Term Loan Due 2050
Long-term debt, carrying amount	162,000	156,000
Less: accrued interest payable (in default)	(12,000)	(6,000)
NPS Term Loan Due 2050
Long-term debt, carrying amount	162,000	156,000
Less: accrued interest payable (in default)	(12,000)	(6,000)
Equipment Loan Due 2025
Long-term debt, carrying amount	38,000	53,000
Less: accrued interest payable (in default)	$ (1,000)	$ 0

ThirdParty LongTerm Debt (Det_3

ThirdParty LongTerm Debt (Details 2) - USD ($)	Dec. 31, 2022	Dec. 31, 2021
Less: accumulated amortization	$ (1,023,000)	$ (821,000)
Unamortized debt issue costs, net	2,149,000	2,351,000
LE Term Loan Due 2034
Unamortized debt issue costs, gross	1,674,000	1,674,000
LRM Term Loan Due 2034
Unamortized debt issue costs, gross	768,000	768,000
NPS Term Loan Due 2031
Unamortized debt issue costs, gross	$ 730	$ 730,000

ThirdParty LongTerm Debt (Det_4

ThirdParty LongTerm Debt (Details 3) - USD ($)	Dec. 31, 2022	Dec. 31, 2021
Accrued interest payable	$ 6,271,000	$ 8,689,000
Less: accrued interest payable (in default)	(6,271,000)	(8,689,000)
Long-term interest payable, net of current portion	0	0
Accrued interest payable	6,271,000	8,689,000
LE Term Loan Due 2034
Accrued interest payable	53,000	2,338,000
LRM Term Loan Due 2034
Accrued interest payable	66,000	959,000
NPS Term Loan Due 2031
Accrued interest payable	17	136,000
BDEC Term Loan Due 2051
Accrued interest payable	82	12,000
LE Term Loan Due 2050
Accrued interest payable	12,000	6,000
NPS Term Loan Due 2050
Accrued interest payable	12,000	6,000
Equipment Loan Due 2025
Accrued interest payable	1,000	0
Notre Dame Debt
Accrued interest payable	$ 6,028,000	$ 5,232,000

ThirdParty LongTerm Debt (Det_5

ThirdParty LongTerm Debt (Details 4)	Dec. 31, 2022 USD ($)
2023	$ 42,155,000
2024	16,000
2025	5,000
2026	0
2027	35,000
Subsequent to 2027	2,266,000
Debt, principal amount, current	44,477,000
Long-term debt	(2,149,000)
Debt, principal amount	46,626,000
2026
Debt, issuance costs	0
Debt, principal amount	0
2023
Debt, issuance costs	(2,149)
Debt, principal amount	44,304,000
2024
Debt, issuance costs	0
Debt, principal amount	16,000
2025
Debt, issuance costs	0
Debt, principal amount	5,000
2027
Debt, issuance costs	0
Debt, principal amount	35,000
Subsequent to 2027
Debt, issuance costs	0
Debt, principal amount	$ 2,266,000

ThirdParty LongTerm Debt (Det_6

ThirdParty LongTerm Debt (Details Narrative) - USD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2017
Amortization expense	$ 200,000	$ 100,000
Restricted cash, noncurrent	$ 1,001	0
Kissick
Restricted cash, current			$ 8,000,000
Amount paid into payment reserve account			$ 3,700,000
Veritex
Description of payment agreement	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. In the event that LE and LRM pay off all amounts due under the LE Term Loan Due 2034 and LRM Term Loan Due 2034 on or before September 30, 2023, Veritex also agreed to waive late fees totaling approximately $0.4 million in the aggregate
Restricted cash, noncurrent	$ 1,000,000	$ 0
BDEC Term Loan Due 2051
Debt, increase (decrease), net	150,000
Original principal amount, before modification	$ 500,000

AROS (Details)

AROS (Details) - USD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
AROs
AROs, at the beginning of the period	$ 3,461,000	$ 2,370,000
Changes in estimates of existing obligations	114,000	1,091,000
Accretion expense	135,000	0
Liabilities settled	0	3,461,000
Less: AROs, current portion	3,710,000	0
Long-term AROs, at the end of the period	$ 0	$ 3,461,000

Lease Obligations (Details)

Lease Obligations (Details) - USD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Lease Obligations
Operating lease ROU assets	$ 787,000	$ 787,000
Less: accumulated amortization on operating lease assets	638,000	455,000
Total lease assets	149,000	332,000
Current portion of operating lease	156,000	215,000
Long-term portion of operating lease	0	156,000
Total lease liabilities	$ 156,000	$ 371,000
Weighted average remaining lease term in years - operating lease	8 months 1 day
Weighted average discount rate - operating lease	8.25%

Lease Obligations (Details 1)

Lease Obligations (Details 1) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Lease Obligations
Operating lease costs	$ 206	$ 206
Total lease cost	$ 206	$ 206

Lease Obligations (Details 2)

Lease Obligations (Details 2) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Lease Obligations
Operating cash flows for operating lease	$ 237	$ 233

Lease Obligations (Details 3)

Lease Obligations (Details 3) $ in Thousands	Dec. 31, 2022 USD ($)
Operating Lease [Member]
2023	$ 156
Total minimum rental payments	156
Annual Lease [Member]
2023	161
Total minimum rental payments	$ 161

Lease Obligations (Details Narr

Lease Obligations (Details Narrative) - USD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Lease Obligations
Lease term	5 years
Annual percentage rate	4.50%
Rent installments and other charges	$ 10,000
Past obligations of rent	20,000
Sublease income	$ 30,000	$ 30,000

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Income Taxes
Current federal	$ 0	$ 0
Current state	(307)	0
Deferred federal	7,223	2,335
Deferred state	0	0
Change in valuation allowance	(7,223)	(2,335)
Income tax expense	$ 307	$ 0

Income Taxes (Details 1)

Income Taxes (Details 1) - USD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Income Taxes
Expected tax rate	21%	21%
Expected tax	$ 7,223	$ 2,335
Permanent differences	0%	0%
Permanent difference	$ 0
State tax	0.92%	0%
State tax	$ 307
Federal tax	0%	0%
Change in valuation allowance	(21.00%)	(21.00%)
Change in valuation allowance	$ (7,223)	$ (2,335)
Effective tax rate	0.92%	0%
Effective tax	$ 307	$ 0

Income Taxes (Details 2)

Income Taxes (Details 2) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Deferred tax assets:
NOL and capital loss carryforwards	$ 11,088	$ 16,818
Business interest expense	3,524	4,680
Start-up costs (crude oil and condensate processing facility)	339	424
ARO liability/deferred revenue	779	727
Other	43	12
Total deferred tax assets	15,773	22,661
Deferred tax liabilities:
Basis differences in property and equipment	(8,216)	(7,945)
Total deferred tax liabilities	(8,216)	(7,945)
Deferred tax assets, gross	7,557	14,716
Valuation allowance	(7,557)	(14,716)
Deferred tax assets, net	$ 0	$ 0

Income Taxes (Details 3)

Income Taxes (Details 3) - USD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Beginning balance	$ 73,408,000	$ 65,977,000
Net operating losses used and expired	(28,511,000)	7,431,000
Ending balance	44,897,000	73,408,000
Pre-Ownership Change
Beginning balance	7,897,000	9,614,000
Net operating losses used and expired	(6,127)	(1,717)
Ending balance	1,770,000	7,897,000
Post-Ownership Change
Beginning balance	65,511,000	56,363,000
Net operating losses used and expired	(22,384,000)	9,148,000
Ending balance	$ 43,127,000	$ 65,511,000

Income Taxes (Details Narrative

Income Taxes (Details Narrative) $ in Millions	12 Months Ended
	Dec. 31, 2022 USD ($)
Income Taxes
Ownership percentage	5%
Description of Inflation Reduction Act ("IRA") law	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
NOL and capital loss carryforwards	$ 16.3
Annual use limitation	$ 0.6
Description of net loss carryforwards	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 that were generated beginning in 2018 may only be used to offset 80% of taxable income and are carried forward indefinitely
NOL carryforwards, annual use limitation	$ 6.7

Earnings and Dividends Per Sh_3

Earnings and Dividends Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Earnings and Dividends Per Share
Net loss	$ 32,892	$ (12,841)
Basic and diluted income (loss) per share	$ 2.34	$ (1.01)
Basic and Diluted
Weighted average number of shares of common stock outstanding and potential dilutive shares of common stock	14,079,327	12,693,514

Commitments and Contingencies (

Commitments and Contingencies (Details Narrative) - USD ($) $ / shares in Units, shares in Millions				1 Months Ended	3 Months Ended		9 Months Ended	12 Months Ended
	Sep. 06, 2022	May 12, 2022	Oct. 04, 2021	Oct. 27, 2022	Sep. 30, 2022	Sep. 30, 2021	Sep. 30, 2021	Dec. 31, 2022	Dec. 31, 2021	Mar. 31, 2018
Restricted shares of Common Stock	9,833.6	25,244.7		2,459.1
Monthly average cost for fees	$ 0.86	$ 0.55		$ 1.22
Monthly low cost for fees	0.58	0.33
Monthly high cost for fees	$ 1.26	$ 0.91
NPS disputed payment			$ 300,000
Additional financial assurance provided by BDPL										$ 4,800,000
Cash-backed								$ 20,000
Credit-backed								700,000
Loss on issuance of shares					$ 100,000	$ 0	$ 0	400,000	$ 0
Accrued expenses and other current liabilities penalty								50,000
Accrued expenses and other current liabilities								400,000	400,000
BSEE INCs [Member]
Trunk pipeline, federal waters								3,700,000	3,500,000
BOEM INCs [Member]
Trunk pipeline, federal waters								$ 900,000	$ 900,000
Sales of Unregistered Securities [Member]
Restricted shares of Common Stock		185,308
Monthly average cost for fees		$ 0.42
Monthly low cost for fees		0.27
Monthly high cost for fees		$ 0.64

Subsequent Events (Details Narr

Subsequent Events (Details Narrative) - Subsequent Event [Member]	Apr. 02, 2023	Mar. 02, 2023	Jan. 02, 2023
BDEC Guaranty Fee Agreement
Subsequent Events description			effective date of January 1, 2023, was executed on March 14, 2023. Under the BDEC Guaranty Fee Agreement, Jonathan Carroll shall receive a fee equal to 2.00% per annum of the outstanding principal balance owed under the BDEC Term Loan Due 2051, payable 100% in cash
NPS Guaranty Fee Agreement
Subsequent Events description			effective date of January 1, 2023, was executed on March 14, 2023. Under the NPS Guaranty Fee Agreement, Jonathan Carroll shall receive a fee equal to 2.00% per annum of the outstanding principal balance owed under the NPS Term Loan Due 2031, payable 100% in cash
LE Amended and Restated Guaranty Fee Agreement
Subsequent Events description	The agreement has a one year term expiring on the earliest to occur of March 31, 2024 plus a 30-day carryover or delivery of the maximum jet fuel quantity. The agreement was executed on March 24, 2023	The agreement has a three-year term. The tank rental fee is $0.50 per bbl per month. The agreement was executed on March 14, 2023	effective date of January 1, 2023; the agreement was executed on March 14, 2023. As further amended and restated, Jonathan Carroll shall receive a fee equal to 2.00% per annum of the outstanding principal balance owed under the LE Term Loan Due 2034, payable 100% in cash
LRM Amended and Restated Guaranty Fee Agreement
Subsequent Events description			effective date of January 1, 2023; the agreement was executed on March 14, 2023. As further amended and restated, Jonathan Carroll shall receive a fee equal to 2.00% per annum of the outstanding principal balance owed under the LRM Term Loan Due 2034, payable 100% in cash
Kissick Forbearance Agreement
Subsequent Events description			Jonathan Carroll and LEH own approximately 83% of Blue Dolphin’s Common Stock
Terminal Services Agreement
Subsequent Events description			The agreement has a one year term with one-year automatic renewals. The tank rental fee is approximately $0.2 million per month. The agreement was ratified by the Board on March 7, 2023
Master Service Agreement
Subsequent Events description			The agreement has a three-year term. The tank rental fee is $0.50 per bbl per month. The agreement was approved by the Board on March 7, 2023