BLUE DOLPHIN ENERGY COMPANY |
|
FORM 10-Q 6/30/16 |
Delaware |
|
73-1268729 |
(State or other jurisdiction of
incorporation or organization) |
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(I.R.S. Employer
Identification No.) |
Large accelerated filer |
☐ |
Accelerated filer |
☐ |
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Non-accelerated filer |
☐
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Smaller reporting company |
☒ |
(Do not check if a smaller reporting company) |
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BLUE DOLPHIN ENERGY COMPANY |
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FORM 10-Q 6/30/16 |
GLOSSARY OF SELECTED OIL AND GAS TERMS |
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3 |
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PART I. FINANCIAL INFORMATION |
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5 |
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ITEM 1. FINANCIAL STATEMENTS |
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5 |
Consolidated Balance Sheets (Unaudited) |
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5 |
Consolidated Statements of Operations (Unaudited) |
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6 |
Consolidated Statements of Cash Flows (Unaudited) |
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7 |
Notes to Consolidated Financial Statements |
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8 |
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ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
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34 |
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
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53 |
ITEM 4. CONTROLS AND PROCEDURES |
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53 |
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PART II OTHER INFORMATION |
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54 |
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ITEM 1. LEGAL PROCEEDINGS |
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54 |
ITEM 1A. RISK FACTORS |
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54 |
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS |
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56 |
ITEM 3. DEFAULTS UPON SENIOR SECURITIES |
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56 |
ITEM 4. MINE SAFETY DISCLOSURES |
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56 |
ITEM 5. OTHER INFORMATION |
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56 |
ITEM 6. EXHIBITS |
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56 |
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SIGNATURES |
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57 |
BLUE DOLPHIN ENERGY COMPANY |
|
FORM 10-Q 6/30/16 |
BLUE DOLPHIN ENERGY COMPANY |
|
FORM 10-Q 6/30/16 |
BLUE DOLPHIN ENERGY COMPANY |
|
FORM 10-Q 6/30/16 |
|
June 30, |
December 31, |
|
2016 |
2015 |
ASSETS |
|
|
CURRENT ASSETS |
|
|
Cash and cash equivalents |
$2,183,562 |
$1,853,875 |
Restricted cash |
4,186,150 |
3,175,299 |
Accounts receivable, net |
9,132,900 |
5,457,245 |
Prepaid expenses and other current assets |
843,639 |
939,690 |
Deposits |
260,965 |
395,414 |
Inventory |
9,684,121 |
7,808,318 |
Total current assets |
26,291,337 |
19,629,841 |
|
|
|
Total property and equipment, net |
57,597,369 |
48,841,812 |
Restricted cash, noncurrent |
7,953,623 |
15,616,478 |
Surety bonds |
710,000 |
1,022,000 |
Trade name |
303,346 |
303,346 |
Deferred tax assets, net |
6,307,479 |
3,607,237 |
Total long-term assets |
72,871,817 |
69,390,873 |
|
|
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TOTAL ASSETS |
$99,163,154 |
$89,020,714 |
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LIABILITIES AND STOCKHOLDERS' EQUITY |
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CURRENT LIABILITIES |
|
|
Accounts payable |
$32,433,145 |
$14,882,714 |
Accounts payable, related party |
861,963 |
300,000 |
Asset retirement obligations, current portion |
26,399 |
38,644 |
Accrued expenses and other current liabilities |
1,087,654 |
2,990,891 |
Interest payable, current portion |
77,193 |
81,467 |
Long-term debt less unamortized debt issue costs, current portion |
32,551,240 |
1,934,932 |
Total current liabilities |
67,037,594 |
20,228,648 |
|
|
|
Long-term liabilities: |
|
|
Asset retirement obligations, net of current portion |
1,956,590 |
1,947,220 |
Deferred revenues and expenses |
104,237 |
125,085 |
Long-term debt less unamortized debt issue costs, net of current portion |
1,349,324 |
32,846,254 |
Long-term interest payable, net of current portion |
1,586,522 |
1,482,801 |
Total long-term liabilities |
4,996,673 |
36,401,360 |
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TOTAL LIABILITIES |
72,034,267 |
56,630,008 |
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Commitments and contingencies (Note 19) |
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STOCKHOLDERS' EQUITY |
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Common stock ($0.01 par value, 20,000,000 shares authorized; 10,614,715 and |
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10,603,802 shares issued at June 30, 2016 and December 31, 2015, respectively) |
106,148 |
106,038 |
Additional paid-in capital |
36,788,628 |
36,738,737 |
Accumulated deficit |
(8,965,889) |
(3,654,069) |
Treasury stock, 150,000 shares at cost |
(800,000) |
(800,000) |
Total stockholders' equity |
27,128,887 |
32,390,706 |
|
|
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TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY |
$99,163,154 |
$89,020,714 |
BLUE DOLPHIN ENERGY COMPANY |
|
FORM 10-Q 6/30/16 |
|
Three Months Ended June 30,
|
Six Months Ended June 30, | ||
|
2016 |
2015 |
2016 |
2015 |
REVENUE FROM OPERATIONS |
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|
|
|
Refined petroleum product sales |
$41,402,286 |
$58,839,160 |
$72,595,423 |
$119,906,222 |
Tank rental revenue |
615,487 |
286,892 |
906,974 |
573,784 |
Pipeline operations |
24,687 |
35,562 |
52,339 |
73,957 |
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|
|
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|
Total revenue from operations |
42,042,460 |
59,161,614 |
73,554,736 |
120,553,963 |
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COST OF OPERATIONS |
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|
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|
Cost of refined products sold |
42,633,298 |
53,801,698 |
73,626,775 |
103,189,147 |
Refinery operating expenses |
2,877,748 |
2,586,151 |
6,314,763 |
5,467,122 |
Joint Marketing Agreement profit share |
97,527 |
938,661 |
(573,565) |
3,377,298 |
Pipeline operating expenses |
95,195 |
60,887 |
174,485 |
107,483 |
Lease operating expenses |
8,455 |
14,098 |
23,107 |
21,414 |
General and administrative expenses |
255,319 |
400,018 |
612,323 |
745,902 |
Depletion, depreciation and amortization |
470,347 |
402,937 |
910,800 |
802,168 |
Recovery of bad debt |
- |
- |
(139,868) |
- |
Accretion expense |
28,186 |
52,720 |
56,372 |
105,935 |
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Total cost of operations |
46,466,075 |
58,257,170 |
81,005,192 |
113,816,469 |
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|
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Income (loss) from operations |
(4,423,615) |
904,444 |
(7,450,456) |
6,737,494 |
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OTHER INCOME (EXPENSE) |
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|
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Easement, interest and other income |
126,097 |
66,460 |
257,860 |
132,467 |
Interest and other expense |
(399,559) |
(732,296) |
(819,466) |
(940,371) |
Total other expense |
(273,462) |
(665,836) |
(561,606) |
(807,904) |
|
|
|
|
|
Income (loss) before income taxes |
(4,697,077) |
238,608 |
(8,012,062) |
5,929,590 |
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Income tax benefit (expense) |
1,534,341 |
(100,729) |
2,700,242 |
(2,090,347) |
|
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Net income (loss) |
$(3,162,736) |
$137,879 |
$(5,311,820) |
$3,839,243 |
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Income (loss) per common share: |
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|
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Basic |
$(0.30) |
$0.01 |
$(0.51) |
$0.37 |
Diluted |
$(0.30) |
$0.01 |
$(0.51) |
$0.37 |
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Weighted average number of common shares |
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outstanding: |
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|
|
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Basic |
10,459,996 |
10,450,210 |
10,458,895 |
10,449,829 |
Diluted |
10,459,996 |
10,450,210 |
10,458,895 |
10,449,829 |
BLUE DOLPHIN ENERGY COMPANY |
|
FORM 10-Q 6/30/16 |
|
Six Months Ended June 30, | |
|
2016 |
2015 |
OPERATING ACTIVITIES |
|
|
Net income (loss) |
$(5,311,820) |
$3,839,243 |
Loss from discontinued operations |
|
|
Adjustments to reconcile net income (loss) to net cash |
|
|
provided by (used in) operating activities: |
|
|
Depletion, depreciation and amortization |
910,800 |
802,168 |
Unrealized loss (gain) on derivatives |
(385,350) |
467,000 |
Deferred tax expense (benefit) |
(2,700,242) |
1,892,551 |
Amortization of debt issue costs |
64,243 |
500,566 |
Accretion expense |
56,372 |
105,935 |
Common stock issued for services |
50,000 |
19,999 |
Recovery of bad debt |
(139,868) |
- |
Changes in operating assets and liabilities |
|
|
Restricted cash |
|
|
Accounts receivable |
(3,535,787) |
1,195,096 |
Prepaid expenses and other current assets |
298,001 |
349,015 |
Deposits and other assets |
446,449 |
(1,385,751) |
Inventory |
(1,875,803) |
(643,882) |
Accounts payable, accrued expenses and other liabilities |
13,256,568 |
(1,093,032) |
Accounts payable, related party |
561,963 |
(1,174,168) |
Net cash provided by operating activities |
1,695,526 |
4,874,740 |
|
|
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INVESTING ACTIVITIES |
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|
Capital expenditures |
(7,072,978) |
(5,800,487) |
Change in restricted cash for investing activities |
7,662,855 |
(13,500,000) |
Net cash provide by (used in) investing activities |
589,877 |
(19,300,487) |
|
|
|
FINANCING ACTIVITIES |
|
|
Proceeds from issuance of debt |
- |
28,000,000 |
Payments on long-term debt |
(944,865) |
(9,071,159) |
Change in restricted cash for financing activities |
(1,010,851) |
(3,287,813) |
Net cash (used in) provided by financing activities |
(1,955,716) |
15,641,028 |
Net increase in cash and cash equivalents |
329,687 |
1,215,281 |
|
|
|
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD |
1,853,875 |
1,293,233 |
CASH AND CASH EQUIVALENTS AT END OF PERIOD |
$2,183,562 |
$2,508,514 |
|
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Supplemental Information: |
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|
Non-cash investing and financing activities |
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|
Financing of capital expenditures via accounts payable |
$2,593,379 |
$459,007 |
Interest paid |
$988,979 |
$353,833 |
Income taxes paid |
$- |
$95,000 |
BLUE DOLPHIN ENERGY COMPANY |
|
FORM 10-Q 6/30/16 |
BLUE DOLPHIN ENERGY COMPANY |
|
FORM 10-Q 6/30/16 |
(2) |
Basis of Presentation |
(3) |
Significant Accounting Policies |
BLUE DOLPHIN ENERGY COMPANY |
|
FORM 10-Q 6/30/16 |
BLUE DOLPHIN ENERGY COMPANY |
|
FORM 10-Q 6/30/16 |
BLUE DOLPHIN ENERGY COMPANY |
|
FORM 10-Q 6/30/16 |
BLUE DOLPHIN ENERGY COMPANY |
|
FORM 10-Q 6/30/16 |
BLUE DOLPHIN ENERGY COMPANY |
|
FORM 10-Q 6/30/16 |
BLUE DOLPHIN ENERGY COMPANY |
|
FORM 10-Q 6/30/16 |
BLUE DOLPHIN ENERGY COMPANY |
|
FORM 10-Q 6/30/16 |
(4) |
Business Segment Information |
|
Three Months Ended June 30, 2016 |
Three Months Ended June 30, 2015 | ||||||
|
Segment |
|
|
Segment |
|
| ||
|
Refinery |
Pipeline |
Corporate & |
|
Refinery |
Pipeline |
Corporate & |
|
|
Operations |
Transportation |
Other |
Total |
Operations |
Transportation |
Other |
Total |
Revenue from operations |
$42,017,773 |
$24,687 |
$- |
$42,042,460 |
$59,126,052 |
$35,562 |
$- |
$59,161,614 |
Less: cost of operations(1) |
(45,534,109) |
(131,836) |
(232,256) |
(45,898,201) |
(56,504,401) |
(127,704) |
(283,467) |
(56,915,572) |
Other non-interest income(2) |
- |
125,000 |
- |
125,000 |
- |
62,500 |
- |
62,500 |
Adjusted EBITDA(3) |
(3,516,336) |
17,851 |
(232,256) |
(3,730,741) |
2,621,651 |
(29,642) |
(283,467) |
2,308,542 |
Less: JMA Profit Share(4) |
(97,527) |
- |
- |
(97,527) |
(938,661) |
- |
- |
(938,661) |
EBITDA(3) |
$(3,613,863) |
$17,851 |
$(232,256) |
|
$1,682,990 |
$(29,642) |
$(283,467) |
|
|
|
|
|
|
|
|
|
|
Depletion, depreciation, and |
|
|
|
|
|
|
|
|
amortization |
|
|
|
(470,347) |
|
|
|
(402,937) |
Interest expense, net |
|
|
|
(398,462) |
|
|
|
(728,336) |
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes |
|
|
|
(4,697,077) |
|
|
|
238,608 |
|
|
|
|
|
|
|
|
|
Income tax benefit (expense) |
|
|
|
1,534,341 |
|
|
|
(100,729) |
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
|
|
$(3,162,736) |
|
|
|
$137,879 |
|
|
|
|
|
|
|
|
|
Capital expenditures |
$3,433,333 |
$- |
$- |
$3,433,333 |
$4,967,579 |
$- |
$- |
$4,967,579 |
|
|
|
|
|
|
|
|
|
Identifiable assets(5) |
$93,402,963 |
$1,867,687 |
$3,892,504 |
$99,163,154 |
$73,643,964 |
$2,788,381 |
$4,046,157 |
$80,478,502 |
(1) |
Operation cost within the Refinery Operations and Pipeline Transportation segments includes related general, administrative, and accretion expenses. Operation cost within Corporate and Other includes general and administrative expenses associated with corporate maintenance costs, such as accounting fees, director fees, and legal expense. |
(2) |
Other non-interest income reflects FLNG easement revenue. (See “Note (19) Commitments and Contingencies – FLNG Master Easement Agreement” for further discussion related to FLNG.) |
(3) |
Adjusted EBITDA and EBITDA are non-GAAP financial measures. See “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Non-GAAP Financial Measures” for additional information related to adjusted EBITDA and EBITDA. |
(4) |
The JMA Profit Share represents the GEL TEX Marketing, LLC Profit Share plus the Performance Fee for the period pursuant to the Joint Marketing Agreement. (See “Note (19) Commitments and Contingencies – Genesis Agreements” for further discussion related to the Joint Marketing Agreement.) |
(5) |
Identifiable assets for the prior year period reflect reclassification of debt issue costs as a reduction in long-term debt to conform to the 2016 presentation. |
|
|
BLUE DOLPHIN ENERGY COMPANY |
|
FORM 10-Q 6/30/16 |
|
Six Months Ended June 30, 2016 |
Six Months Ended June 30, 2015 | ||||||
|
Segment |
|
|
Segment |
|
| ||
|
Refinery |
Pipeline |
Corporate & |
|
Refinery |
Pipeline |
Corporate & |
|
|
Operations |
Transportation |
Other |
Total |
Operations |
Transportation |
Other |
Total |
Revenue from operations |
$73,502,397 |
$52,339 |
$- |
$73,554,736 |
$120,480,006 |
$73,957 |
$- |
$120,553,963 |
Less: cost of operations(1) |
(79,956,962) |
(253,964) |
(457,031) |
(80,667,957) |
(108,763,871) |
(181,616) |
(691,515) |
(109,637,002) |
Other non-interest income(2) |
- |
255,665 |
- |
255,665 |
- |
125,000 |
- |
125,000 |
Adjusted EBITDA(3) |
(6,454,565) |
54,040 |
(457,031) |
(6,857,556) |
11,716,135 |
17,341 |
(691,515) |
11,041,961 |
Less: JMA Profit Share(4) |
573,565 |
- |
- |
573,565 |
(3,377,298) |
- |
- |
(3,377,298) |
EBITDA(3) |
$(5,881,000) |
$54,040 |
$(457,031) |
|
$8,338,837 |
$17,341 |
$(691,515) |
|
|
|
|
|
|
|
|
|
|
Depleton, depreciation and |
|
|
|
|
|
|
|
|
amortization |
|
|
|
(910,800) |
|
|
|
(802,168) |
Interest expense, net |
|
|
|
(817,271) |
|
|
|
(932,905) |
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes |
|
|
|
(8,012,062) |
|
|
|
5,929,590 |
|
|
|
|
|
|
|
|
|
Income tax benefit (expense) |
|
|
|
2,700,242 |
|
|
|
(2,090,347 ) |
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
|
|
$(5,311,820) |
|
|
|
$3,839,243 |
|
|
|
|
|
|
|
|
|
Capital expenditures |
$7,072,978 |
$- |
$- |
$7,072,978 |
$6,259,494 |
$- |
$- |
$6,259,494 |
|
|
|
|
|
|
|
|
|
Identifiable assets(5) |
$93,402,963 |
$1,867,687 |
$3,892,504 |
$99,163,154 |
$73,643,964 |
$2,788,381 |
$4,046,157 |
$80,478,502 |
(1) |
Operation cost within the Refinery Operations and Pipeline Transportation segments includes related general, administrative, and accretion expenses. Operation cost within Corporate and Other includes general and administrative expenses associated with corporate maintenance costs, such as accounting fees, director fees, and legal expense. |
(2) |
Other non-interest income reflects FLNG easement revenue. (See “Note (19) Commitments and Contingencies – FLNG Master Easement Agreement” for further discussion related to FLNG.) |
(3) |
Adjusted EBITDA and EBITDA are non-GAAP financial measures. See “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Non-GAAP Financial Measures” for additional information related to adjusted EBITDA and EBITDA. |
(4) |
The JMA Profit Share represents the GEL TEX Marketing, LLC Profit Share plus the Performance Fee for the period pursuant to the Joint Marketing Agreement. (See “Note (19) Commitments and Contingencies – Genesis Agreements” for further discussion related to the Joint Marketing Agreement.) |
(5) |
Identifiable assets for the prior year period reflect reclassification of debt issue costs as a reduction in long-term debt to conform to the 2016 presentation. |
(5) |
Prepaid Expenses and Other Current Assets |
|
June 30, |
December 31, |
|
2016 |
2015 |
|
|
|
Prepaid related party operating expenses |
$402,671 |
$624,570 |
Prepaid insurance |
231,518 |
315,120 |
Unrealized hedging gains |
201,950 |
- |
Prepaid listing fees |
7,500 |
- |
|
$843,639 |
$939,690 |
BLUE DOLPHIN ENERGY COMPANY |
|
FORM 10-Q 6/30/16 |
(6) |
Inventory |
|
June 30, |
December 31, |
|
2016 |
2015 |
|
|
|
HOBM |
$6,382,469 |
$5,007,576 |
Jet fuel |
1,438,134 |
2,045,784 |
Crude oil and condensate |
936,301 |
19,041 |
Naphtha |
333,627 |
309,850 |
AGO |
288,707 |
278,278 |
Chemicals |
282,562 |
122,777 |
Propane |
17,299 |
17,860 |
LPG mix |
5,022 |
7,152 |
|
|
|
|
$9,684,121 |
$7,808,318 |
(7) |
Property, Plant and Equipment, Net |
|
June 30, |
December 31, |
|
2016 |
2015 |
|
|
|
Refinery and facilities |
$47,660,502 |
$40,195,928 |
Pipelines and facilities |
2,127,207 |
2,127,207 |
Onshore separation and handling facilities |
325,435 |
325,435 |
Land |
602,938 |
602,938 |
Other property and equipment |
652,795 |
644,795 |
|
51,368,877 |
43,896,303 |
|
|
|
Less: Accumulated depletion, depreciation, and amortization |
(7,144,961) |
(6,234,161) |
|
44,223,916 |
37,662,142 |
|
|
|
Construction in progress |
13,373,453 |
11,179,670 |
|
|
|
|
$57,597,369 |
$48,841,812 |
BLUE DOLPHIN ENERGY COMPANY |
|
FORM 10-Q 6/30/16 |
(8) |
Accounts Payable, Related Party |
|
June 30, |
December 31, |
|
2016 |
2015 |
|
|
|
Ingleside |
$554,389 |
$300,000 |
Jonathan Carroll |
307,574 |
- |
|
|
|
|
$861,963 |
$300,000 |
BLUE DOLPHIN ENERGY COMPANY |
|
FORM 10-Q 6/30/16 |
(9) |
Long-Term Debt, Net |
|
June 30, 2016 |
December 31, 2015 | ||||
|
|
Debt Issue |
Long-Term |
|
Debt Issue |
Long-Term |
|
Principal |
Costs |
Debt, Net |
Principal |
Costs |
Debt, Net |
|
|
|
|
|
|
|
First Term Loan Due 2034 |
$24,289,190 |
$(1,579,769) |
$22,709,421 |
$24,643,081 |
$(1,623,810) |
$23,019,271 |
Second Term Loan Due 2034 |
9,862,663 |
(747,471) |
9,115,192 |
10,000,000 |
(767,672) |
9,232,328 |
Notre Dame Debt |
1,300,000 |
- |
1,300,000 |
1,300,000 |
- |
1,300,000 |
Term Loan Due 2017 |
554,982 |
- |
554,982 |
924,969 |
- |
924,969 |
Capital Leases |
220,969 |
- |
220,969 |
304,618 |
- |
304,618 |
|
$36,227,804 |
$(2,327,240) |
$33,900,564 |
$37,172,668 |
$(2,391,482) |
$34,781,186 |
|
|
|
|
|
|
|
Less: Long-term debt less unamortized |
|
|
|
|
|
|
debt issue costs, current portion |
|
|
(32,551,240) |
|
|
(1,934,932) |
|
|
|
|
|
|
|
|
|
|
$1,349,324 |
|
|
$32,846,254 |
BLUE DOLPHIN ENERGY COMPANY |
|
FORM 10-Q 6/30/16 |
|
June 30, |
December 31, |
|
2016 |
2015 |
|
|
|
Notre Dame Debt |
$1,586,522 |
$1,482,801 |
Second Term Loan Due 2034 |
42,610 |
39,193 |
First Term Loan Due 2034 |
32,226 |
34,883 |
Capital Leases |
1,894 |
2,612 |
Term Loan Due 2017 |
463 |
4,779 |
|
1,663,715 |
1,564,268 |
|
|
|
Less: Interest payable, current portion |
(77,193) |
(81,467) |
|
|
|
|
$1,586,522 |
$1,482,801 |
BLUE DOLPHIN ENERGY COMPANY |
|
FORM 10-Q 6/30/16 |
BLUE DOLPHIN ENERGY COMPANY |
|
FORM 10-Q 6/30/16 |
|
June 30, |
December 31, |
|
2016 |
2015 |
|
|
|
Boiler equipment |
$538,598 |
$538,598 |
Less: accumulated depreciation
|
- |
- |
|
$538,598 |
$538,598 |
(10) |
Accrued Expenses and Other Current Liabilities |
|
June 30, |
December 31, |
|
2016 |
2015 |
|
|
|
Unearned revenue |
$332,055 |
$781,859 |
Excise and income taxes payable |
273,735 |
1,290,101 |
Other payable |
152,914 |
157,714 |
Transportation and inspection |
123,337 |
- |
Board of director fees payable |
101,429 |
86,429 |
Property taxes |
61,178 |
- |
Insurance |
25,756 |
103,024 |
Inspection fees |
17,250 |
- |
Genesis JMA Profit Share payable |
- |
388,364 |
Unrealized hedging loss |
- |
183,400 |
|
|
|
|
$1,087,654 |
$2,990,891 |
(11) |
Asset Retirement Obligations |
BLUE DOLPHIN ENERGY COMPANY |
|
FORM 10-Q 6/30/16 |
|
June 30, |
December 31, |
|
2016 |
2015 |
|
|
|
Asset retirement obligations, at the beginning of the period |
$1,985,864 |
$1,866,770 |
New asset retirement obligations and adjustments |
- |
49 |
Liabilities settled |
(59,247) |
(92,330) |
Accretion expense |
56,372 |
211,375 |
|
1,982,989 |
1,985,864 |
Less: asset retirement obligations, current portion |
(26,399) |
(38,644) |
|
|
|
Long-term asset retirement obligations, at the end of the period |
$1,956,590 |
$1,947,220 |
(12) |
Treasury Stock |
(13) |
Concentration of Risk |
BLUE DOLPHIN ENERGY COMPANY |
|
FORM 10-Q 6/30/16 |
|
Three Months Ended June 30, |
Six Months Ended June 30, | ||||||
|
2016 |
2015 |
2016 |
2015 | ||||
|
|
|
|
|
|
|
|
|
LPG mix |
$133,757 |
0.3% |
$234,184 |
0.4% |
$384,304 |
0.8% |
$291,492 |
0.2% |
Naphtha |
7,287,804 |
17.6% |
13,413,484 |
22.7% |
16,313,325 |
28.9% |
26,829,683 |
22.4% |
Jet fuel |
17,539,473 |
42.4% |
17,411,470 |
29.6% |
26,045,786 |
27.3% |
33,930,973 |
28.3% |
HOBM |
7,889,499 |
19.1% |
13,622,360 |
23.2% |
11,052,994 |
10.1% |
31,031,439 |
25.9% |
Reduced Crude |
546,112 |
1.3% |
- |
0.0% |
3,791,919 |
10.4% |
- |
0.0% |
AGO |
8,005,641 |
19.3% |
14,157,662 |
24.1% |
15,007,095 |
22.5% |
27,822,635 |
23.2% |
|
|
|
|
|
|
|
|
|
|
$41,402,286 |
100.0% |
$58,839,160 |
100.0% |
$72,595,423 |
100.0% |
$119,906,222 |
100.0% |
|
|
|
|
|
|
|
|
|
(14) |
Leases |
BLUE DOLPHIN ENERGY COMPANY |
|
FORM 10-Q 6/30/16 |
(15) |
Income Taxes |
|
Three Months Ended June 30,
|
Six Months Ended June 30, | ||
|
2016 |
2015 |
2016 |
2015 |
Current: |
|
|
|
|
Federal |
$- |
$14,038 |
$- |
$(85,242) |
State |
- |
(29,701) |
- |
(112,554) |
Deferred: |
|
|
|
|
Federal |
1,534,341 |
(85,066) |
2,653,721 |
(1,892,551) |
|
|
|
|
|
|
$1,534,341 |
$(100,729) |
$2,653,721 |
$(2,090,347) |
BLUE DOLPHIN ENERGY COMPANY |
|
FORM 10-Q 6/30/16 |
|
Net Operating Loss Carryforward |
| |
|
Pre-Ownership Change |
Post-Ownership Change |
Total |
|
|
|
|
Balance at December 31, 2014 |
$10,766,912 |
$12,145,789 |
$22,912,701 |
|
|
|
|
Net operating loss carryforwards utilized |
(1,152,463) |
(2,528,848) |
(3,681,311) |
|
|
|
- |
Balance at December 31, 2015 |
$9,614,449 |
$9,616,941 |
$19,231,390 |
|
|
|
|
Net operating losses |
- |
5,871,350 |
5,871,350 |
|
|
|
|
Balance at March 31, 2016 |
$9,614,449 |
$15,488,291 |
$25,102,740 |
|
|
|
|
Net operating losses |
- |
4,230,763 |
4,230,763 |
|
|
|
|
Balance at June 30, 2016 |
$9,614,449 |
$19,719,054 |
$29,333,503 |
|
June 30, |
December 31, |
|
2016 |
2015 |
|
|
|
Deferred tax assets: |
|
|
Net operating loss and capital loss carryforwards |
$12,243,743 |
$8,815,794 |
Start-up costs (Nixon Facility) |
1,442,032 |
1,510,699 |
Asset retirement obligations liability/deferred revenue |
709,657 |
717,723 |
Unrealized hedges |
- |
62,356 |
AMT credit and other |
275,857 |
302,086 |
Total deferred tax assets |
14,671,289 |
11,408,658 |
|
|
|
Deferred tax liabilities: |
|
|
Fair market value adjustments |
(46,116) |
(46,116) |
Unrealized hedges |
(68,663) |
- |
Basis differences in property and equipment |
(5,978,709) |
(5,484,983) |
Total deferred tax liabilities |
(6,093,488) |
(5,531,099) |
|
|
|
|
8,577,801 |
5,877,559 |
|
|
|
Valuation allowance |
(2,270,322) |
(2,270,322) |
|
|
|
Deferred tax assets, net |
$6,307,479 |
$3,607,237 |
BLUE DOLPHIN ENERGY COMPANY |
|
FORM 10-Q 6/30/16 |
(16) |
Earnings Per Share |
|
Three Months Ended June 30, |
Six Months Ended June 30, | ||
|
2016 |
2015 |
2016 |
2015 |
|
|
|
|
|
Net income (loss) |
$(3,162,736) |
$137,879 |
$(5,311,820) |
$3,839,243 |
|
|
|
|
|
Basic and diluted income per share |
$(0.30) |
$0.01 |
$(0.51) |
$0.37 |
|
|
|
|
|
Basic and Diluted |
|
|
|
|
Weighted average number of shares of common stock |
|
|
|
|
outstanding and potential dilutive shares of common stock |
10,459,996 |
10,450,210 |
10,458,895 |
10,444,829 |
(17) |
Fair Value Measurement |
BLUE DOLPHIN ENERGY COMPANY |
|
FORM 10-Q 6/30/16 |
Level 1 |
Inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities. |
|
|
Level 2 |
Inputs are quoted prices for similar assets or liabilities in an active market, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable and market-corroborated inputs, which are derived principally from or corroborated by observable market data. |
|
|
Level 3 |
Inputs are derived from valuation techniques in which one or more significant inputs or value drivers are unobservable and cannot be corroborated by market data or other entity-specific inputs. |
|
|
Fair Value Measurement at June 30, 2016 Using | ||
Financial assets (liabilities): |
Carrying Value at June 30, 2016 |
Quoted Prices in Active Markets for Identical Assets or Liabilities
(Level 1) |
Significant Other Observable Inputs
(Level 2) |
Significant Unobservable Inputs (Level 3) |
|
|
|
|
|
Commodity contracts |
$201,950 |
$201,950 |
$- |
$- |
|
|
Fair Value Measurement at December 31, 2015 Using | ||
Financial assets (liabilities): |
Carrying Value at December 31, 2015 |
Quoted Prices in Active Markets for Identical Assets or Liabilities
(Level 1) |
Significant Other Observable Inputs (Level 2) |
Significant Unobservable Inputs (Level 3) |
|
|
|
|
|
Commodity contracts |
$(183,400) |
$(183,400) |
$- |
$- |
(18) |
Inventory Risk Management |
BLUE DOLPHIN ENERGY COMPANY |
|
FORM 10-Q 6/30/16 |
|
Notional Contract Volumes by Year of Maturity | ||
Inventory positions (futures): |
2016 |
2017 |
2018 |
|
|
|
|
Refined petroleum products and crude oil - |
|
|
|
net short positions |
330,000 |
- |
- |
|
|
|
Fair Value | |
|
|
|
June 30, |
December 31, |
Asset Derivatives |
|
Balance Sheets Location |
2016 |
2015 |
|
|
|
|
|
|
|
Prepaid expenses and other current |
|
|
|
|
assets (accrued expenses and other |
|
|
Commodity contracts |
|
current liabilities) |
$201,950 |
$(183,400) |
|
|
|
Loss Recognized | |||
|
|
|
Three Months Ended June 30, |
Six Months Ended June 30, | ||
Derivatives |
|
Statements of Operations Location |
2016 |
2015 |
2016 |
2015 |
|
|
|
|
|
|
|
Commodity contracts |
|
Cost of refined products sold |
$(3,852,100) |
$(1,370,293) |
$(3,359,572) |
$(442,709) |
BLUE DOLPHIN ENERGY COMPANY |
|
FORM 10-Q 6/30/16 |
(19) |
Commitments and Contingencies |
BLUE DOLPHIN ENERGY COMPANY |
|
FORM 10-Q 6/30/16 |
BLUE DOLPHIN ENERGY COMPANY |
|
FORM 10-Q 6/30/16 |
(20) |
Subsequent Events |
BLUE DOLPHIN ENERGY COMPANY |
|
FORM 10-Q 6/30/16 |
BLUE DOLPHIN ENERGY COMPANY |
|
FORM 10-Q 6/30/16 |
BLUE DOLPHIN ENERGY COMPANY |
|
FORM 10-Q 6/30/16 |
BLUE DOLPHIN ENERGY COMPANY |
|
FORM 10-Q 6/30/16 |
BLUE DOLPHIN ENERGY COMPANY |
|
FORM 10-Q 6/30/16 |
BLUE DOLPHIN ENERGY COMPANY |
|
FORM 10-Q 6/30/16 |
BLUE DOLPHIN ENERGY COMPANY |
|
FORM 10-Q 6/30/16 |
BLUE DOLPHIN ENERGY COMPANY |
|
FORM 10-Q 6/30/16 |
BLUE DOLPHIN ENERGY COMPANY |
|
FORM 10-Q 6/30/16 |
|
Three Months Ended June 30, 2016 |
Three Months Ended June 30, 2015 | ||||||
|
Segment |
|
|
Segment |
|
| ||
|
Refinery |
Pipeline |
Corporate & |
|
Refinery |
Pipeline |
Corporate & |
|
|
Operations |
Transportation |
Other |
Total |
Operations |
Transportation |
Other |
Total |
Revenue from operations |
$42,017,773 |
$24,687 |
$- |
$42,042,460 |
$59,126,052 |
$35,562 |
$- |
$59,161,614 |
Less: cost of operations(1) |
(45,534,109) |
(131,836) |
(232,256) |
(45,898,201) |
(56,504,401) |
(127,704) |
(283,467) |
(56,915,572) |
Other non-interest income(2) |
- |
125,000 |
- |
125,000 |
- |
62,500 |
- |
62,500 |
Adjusted EBITDA |
(3,516,336) |
17,851 |
(232,256) |
(3,730,741) |
2,621,651 |
(29,642) |
(283,467) |
2,308,542 |
Less: JMA Profit Share(3) |
(97,527) |
- |
- |
(97,527) |
(938,661) |
- |
- |
(938,661) |
EBITDA |
$(3,613,863) |
$17,851 |
$(232,256) |
$(3,828,268) |
$1,682,990 |
$(29,642) |
$(283,467) |
$1,369,881 |
|
|
|
|
|
|
|
|
|
Depletion, depreciation and |
|
|
|
|
|
|
|
|
amortization |
|
|
|
(470,347) |
|
|
|
(402,937) |
Interest expense, net |
|
|
|
(398,462) |
|
|
|
(728,336) |
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
|
(4,697,077) |
|
|
|
238,608 |
|
|
|
|
|
|
|
|
|
Net income |
|
|
|
$(3,162,736) |
|
|
|
$137,879 |
(1) |
Operation cost within the Refinery Operations and Pipeline Transportation segments includes related general, administrative, and accretion expenses. Operation cost within Corporate and Other includes general and administrative expenses associated with corporate maintenance costs, such as accounting fees, director fees, and legal expense. |
(2) |
Other non-interest income reflects FLNG easement revenue. (See “Part I, Financial Information, Item 1. Financial Statements – Note (19) Commitments and Contingencies – FLNG Master Easement Agreement” for further discussion related to FLNG.) |
(3) |
The JMA Profit Share represents the GEL Profit Share plus the Performance Fee for the period pursuant to the Joint Marketing Agreement. (See “Part I, Financial Information, Item 1. Financial Statements – Note (19) Commitments and Contingencies – Genesis Agreements” for further discussion of the Joint Marketing
Agreement.) |
BLUE DOLPHIN ENERGY COMPANY |
|
FORM 10-Q 6/30/16 |
|
Six Months Ended June 30, 2016 |
Six Months Ended June 30, 2015 | ||||||
|
Segment |
|
|
Segment |
|
| ||
|
Refinery |
Pipeline |
Corporate & |
|
Refinery |
Pipeline |
Corporate & |
|
|
Operations |
Transportation |
Other |
Total |
Operations |
Transportation |
Other |
Total |
Revenue from operations |
$73,502,397 |
$52,339 |
$- |
$73,554,736 |
$120,480,006 |
$73,957 |
$- |
$120,553,963 |
Less: cost of operations(1) |
(79,956,962) |
(253,964) |
(457,031) |
(80,667,957) |
(108,763,871) |
(181,616) |
(691,515) |
(109,637,002) |
Other non-interest income(2) |
- |
255,665 |
- |
255,665 |
- |
125,000 |
- |
125,000 |
Adjusted EBITDA |
(6,454,565) |
54,040 |
(457,031) |
(6,857,556) |
11,716,135 |
17,341 |
(691,515) |
11,041,961 |
Less: JMA Profit Share(3) |
573,565 |
- |
- |
573,565 |
(3,377,298) |
- |
- |
(3,377,298) |
EBITDA |
$(5,881,000) |
$54,040 |
$(457,031) |
$(6,283,991) |
$8,338,837 |
$17,341 |
$(691,515) |
$7,664,663 |
|
|
|
|
|
|
|
|
|
Depletion, depreciation and |
|
|
|
|
|
|
|
|
amortization |
|
|
|
(910,800) |
|
|
|
(802,168) |
Interest expense, net |
|
|
|
(817,271) |
|
|
|
(932,905) |
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
|
(8,012,062) |
|
|
|
5,929,590 |
|
|
|
|
|
|
|
|
|
Net income |
|
|
|
$(5,311,820) |
|
|
|
$3,839,243 |
(1) |
Operation cost within the Refinery Operations and Pipeline Transportation segments includes related general, administrative, and accretion expenses. Operation cost within Corporate and Other includes general and administrative expenses associated with corporate maintenance costs, such as accounting fees, director fees, and legal expense. |
(2) |
Other non-interest income reflects FLNG easement revenue. (See “Part I, Financial Information, Item 1. Financial Statements – Note (19) Commitments and Contingencies – FLNG Master Easement Agreement” for further discussion related to FLNG.) |
(3) |
The JMA Profit Share represents the GEL Profit Share plus the Performance Fee for the period pursuant to the Joint Marketing Agreement. (See “Part I, Financial Information, Item 1. Financial Statements – Note (19) Commitments and Contingencies – Genesis Agreements” for further discussion of the Joint Marketing
Agreement.) |
BLUE DOLPHIN ENERGY COMPANY |
|
FORM 10-Q 6/30/16 |
|
Three Months Ended June 30, |
Six Months Ended June 30,
| ||
|
2016 |
2015 |
2016 |
2015 |
|
|
|
|
|
Total refined petroleum product sales |
$41,402,286 |
$58,839,160 |
$72,595,423 |
$119,906,222 |
Less: Cost of refined petroleum products sold |
(42,633,298) |
(53,801,698) |
(73,626,775) |
(103,189,147) |
Less: Refinery operating expenses |
(2,877,748) |
(2,586,151) |
(6,314,763) |
(5,467,122) |
Refinery operating income before JMA Profit Share |
(4,108,760) |
2,451,311 |
(7,346,115) |
11,249,953 |
Less: JMA Profit Share |
(97,527) |
(938,661) |
573,565 |
(3,377,298) |
|
|
|
|
|
Refinery operating income (loss) |
$(4,206,287) |
$1,512,650 |
$(6,772,550) |
$7,872,655 |
|
|
|
|
|
Total refined petroleum product sales (bbls) |
855,023 |
896,706 |
1,794,476 |
1,923,590 |
BLUE DOLPHIN ENERGY COMPANY |
|
FORM 10-Q 6/30/16 |
|
Three Months Ended June 30, |
Six Months Ended June 30, | ||
|
2016 |
2015 |
2016 |
2015 |
|
|
|
|
|
Calendar Days |
91 |
91 |
182 |
181 |
Refinery downtime |
(29) |
(11) |
(29) |
(11) |
Operating Days |
62 |
80 |
153 |
170 |
|
|
|
|
|
|
|
|
|
|
Total refinery throughput (bbls) |
710,992 |
914,950 |
1,894,798 |
1,977,338 |
Calendar days: |
|
|
|
|
bpd |
7,813 |
10,054 |
10,411 |
10,925 |
Capacity utilization rate |
52.1% |
67.0% |
69.4% |
72.8% |
Operating days: |
|
|
|
|
bpd |
11,468 |
11,437 |
12,384 |
11,631 |
Capacity utilization rate |
76.5% |
76.2% |
82.6% |
77.5% |
|
|
|
|
|
Total refinery production (bbls) |
687,559 |
896,123 |
1,841,866 |
1,940,333 |
Calendar days: |
|
|
|
|
bpd |
7,556 |
9,848 |
10,120 |
10,720 |
Capacity utilization rate |
50.4% |
65.7% |
67.5% |
71.5% |
Operating days: |
|
|
|
|
bpd |
11,090 |
11,202 |
12,038 |
11,414 |
Capacity utilization rate |
73.9% |
74.7% |
80.3% |
76.1% |
Note: |
The difference between total refinery throughput (volume processed as input) and total refinery production (volume processed as output) represents refinery fuel use and loss. |
BLUE DOLPHIN ENERGY COMPANY |
|
FORM 10-Q 6/30/16 |
BLUE DOLPHIN ENERGY COMPANY |
|
FORM 10-Q 6/30/16 |
BLUE DOLPHIN ENERGY COMPANY |
|
FORM 10-Q 6/30/16 |
|
For Three Months Ended June 30, |
For Six Months Ended June 30, | ||
|
2016 |
2015 |
2016 |
2015 |
|
|
|
|
|
Cash flow from operations |
|
|
|
|
Adjusted income (loss) from operations |
$(3,147,733) |
$1,109,528 |
$(7,455,865) |
$7,627,462 |
Change in assets and current liabilities |
5,245,779 |
1,184,620 |
9,151,391 |
(2,752,722) |
|
|
|
|
|
Total cash flow from operations |
2,098,046 |
2,294,148 |
1,695,526 |
4,874,740 |
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|
|
|
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Cash inflows (outflows) |
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|
|
|
Proceeds from issuance of debt |
- |
28,000,000 |
- |
28,000,000 |
Payments on debt |
(466,434) |
(8,771,053) |
(944,865) |
(9,071,159) |
Change in restricted cash for investing activities |
4,598,125 |
(13,500,000) |
7,662,855 |
(13,500,000) |
Capital expenditures |
(3,433,333) |
(4,508,572) |
(7,072,978) |
(5,800,487) |
Change in restricted cash for financing activities |
(1,173,115) |
(3,285,215) |
(1,010,851) |
(3,287,813) |
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|
|
|
Total cash outflows |
(474,757) |
(2,064,840) |
(1,365,839) |
(3,659,459) |
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Total change in cash flows |
$1,623,289 |
$229,308 |
$329,687 |
$1,215,281 |
BLUE DOLPHIN ENERGY COMPANY |
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FORM 10-Q 6/30/16 |
BLUE DOLPHIN ENERGY COMPANY |
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FORM 10-Q 6/30/16 |
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June 30, |
December 31, |
|
2016 |
2015 |
|
|
|
First Term Loan Due 2034 |
$24,289,190 |
$24,643,081 |
Second Term Loan Due 2034 |
9,862,663 |
10,000,000 |
Capital Leases |
220,969 |
304,618 |
Notre Dame Debt |
1,300,000 |
1,300,000 |
Term Loan Due 2017 |
554,982 |
924,969 |
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36,227,804 |
37,172,668 |
Less: Long-term debt less unamoritized debt |
|
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issue costs, current portion |
(2,327,240) |
(2,391,482) |
|
|
|
|
$33,900,564 |
$34,781,186 |
BLUE DOLPHIN ENERGY COMPANY |
|
FORM 10-Q 6/30/16 |
BLUE DOLPHIN ENERGY COMPANY |
|
FORM 10-Q 6/30/16 |
BLUE DOLPHIN ENERGY COMPANY |
|
FORM 10-Q 6/30/16 |
BLUE DOLPHIN ENERGY COMPANY |
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FORM 10-Q 6/30/16 |
BLUE DOLPHIN ENERGY COMPANY |
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FORM 10-Q 6/30/16 |
BLUE DOLPHIN ENERGY COMPANY |
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FORM 10-Q 6/30/16 |
No. |
Description |
31.1 |
Jonathan P. Carroll Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to section 302 of the Sarbanes-Oxley Act of 2002. |
31.2 |
Tommy L. Byrd Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to section 302 of the Sarbanes-Oxley Act of 2002. |
32.1 |
Jonathan P. Carroll Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002. |
32.2 |
Tommy L. Byrd Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002. |
101.INS |
XBRL Instance Document. |
101.SCH |
XBRL Taxonomy Schema Document. |
101.CAL |
XBRL Calculation Linkbase Document. |
101.LAB |
XBRL Label Linkbase Document. |
101.PRE |
XBRL Presentation Linkbase Document. |
101.DEF |
XBRL Definition Linkbase Document. |
BLUE DOLPHIN ENERGY COMPANY |
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FORM 10-Q 6/30/16 |
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BLUE DOLPHIN ENERGY COMPANY
(Registrant) |
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Date: August 15, 2016 |
By: |
/s/ JONATHAN P. CARROLL |
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Jonathan P. Carroll |
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Chairman of the Board,
Chief Executive Officer, President,
Assistant Treasurer and Secretary
(Principal Executive Officer) |
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Date: August 15, 2016 |
By: |
/s/ TOMMY L. BYRD |
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Tommy L. Byrd |
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Chief Financial Officer,
Treasurer and Assistant Secretary
(Principal Financial Officer) |
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1. |
I have reviewed this Quarterly Report on Form 10-Q of Blue Dolphin Energy Company (the “Registrant”). |
2. |
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. |
Based on my knowledge, the financial statements and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the Registrant as of, and for, the periods presented in this report; |
4. |
The Registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the Registrant and we have: |
a) |
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the Registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
b) |
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
c) |
Evaluated the effectiveness of the Registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
d) |
Disclosed in this report any change in the Registrant’s internal control over financial reporting that occurred during the Registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Registrant’s internal control over financial reporting; |
5. |
The Registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the Registrant’s auditors and the audit committee of the Registrant’s board of directors (or persons performing the equivalent functions): |
a) |
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Registrant’s ability to record, process, summarize and report financial information; and |
b) |
Any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrant’s internal control over financial reporting. |
Date: August 15, 2016 |
By: |
/s/ JONATHAN P. CARROLL |
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Jonathan P. Carroll |
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Chairman of the Board,
Chief Executive Officer, President, Assistant Treasurer and Secretary |
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(Principal Executive Officer) |
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1. |
I have reviewed this Quarterly Report on Form 10-Q of Blue Dolphin Energy Company (the “Registrant”). |
2. |
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. |
Based on my knowledge, the financial statements and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the Registrant as of, and for, the periods presented in this report; |
4. |
The Registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the Registrant and we have: |
a) |
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the Registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
b) |
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
c) |
Evaluated the effectiveness of the Registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
d) |
Disclosed in this report any change in the Registrant’s internal control over financial reporting that occurred during the Registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Registrant’s internal control over financial reporting; |
5. |
The Registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the Registrant’s auditors and the audit committee of the Registrant’s board of directors (or persons performing the equivalent functions): |
a) |
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Registrant’s ability to record, process, summarize and report financial information; and |
b) |
Any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrant’s internal control over financial reporting. |
Date: August 15, 2016 |
By: |
/s/ TOMMY L. BYRD |
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Tommy L. Byrd |
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Chief Financial Officer, Treasurer and Assistant Secretary |
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(Principal Financial Officer) |
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Date: August 15, 2016 |
By: |
/s/ JONATHAN P. CARROLL |
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Jonathan P. Carroll |
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Chairman of the Board,
Chief Executive Officer, President, Assistant Treasurer and Secretary |
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(Principal Executive Officer) |
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Date: August 15, 2016 |
By: |
/s/ TOMMY L. BYRD |
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Tommy L. Byrd |
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Chief Financial Officer, Treasurer and Assistant Secretary |
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(Principal Financial Officer) |
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Document and Entity Information - shares |
6 Months Ended | |
---|---|---|
Jun. 30, 2016 |
Aug. 15, 2016 |
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Document And Entity Information | ||
Entity Registrant Name | BLUE DOLPHIN ENERGY CO | |
Entity Central Index Key | 0000793306 | |
Document Type | 10-Q | |
Document Period End Date | Jun. 30, 2016 | |
Amendment Flag | false | |
Current Fiscal Year End Date | --12-31 | |
Is Entity a Well-known Seasoned Issuer? | No | |
Is Entity a Voluntary Filer? | No | |
Is Entity's Reporting Status Current? | Yes | |
Entity Filer Category | Smaller Reporting Company | |
Entity Common Stock, Shares Outstanding | 10,464,715 | |
Document Fiscal Period Focus | Q2 | |
Document Fiscal Year Focus | 2016 |
Consolidated Balance Sheets (Unaudited) (Parenthetical) - $ / shares |
Jun. 30, 2016 |
Dec. 31, 2015 |
---|---|---|
STOCKHOLDERS' EQUITY | ||
Common stock, par value | $ 0.01 | $ 0.01 |
Common stock, shares authorized | 20,000,000 | 20,000,000 |
Common stock, shares issued | 10,614,715 | 10,603,802 |
Common stock, shares outstanding | 10,614,715 | 10,603,802 |
Treasury stock, shares | 150,000 | 150,000 |
Consolidated Statements of Operations (Unaudited) - USD ($) |
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2016 |
Jun. 30, 2015 |
Jun. 30, 2016 |
Jun. 30, 2015 |
|
REVENUE FROM OPERATIONS | ||||
Refined petroleum product sales | $ 41,402,286 | $ 58,839,160 | $ 72,595,423 | $ 119,906,222 |
Tank rental revenue | 615,487 | 286,892 | 906,974 | 573,784 |
Pipeline operations | 24,687 | 35,562 | 52,339 | 73,957 |
Total revenue from operations | 42,042,460 | 59,161,614 | 73,554,736 | 120,553,963 |
COST OF OPERATIONS | ||||
Cost of refined products sold | 42,633,298 | 53,801,698 | 73,626,775 | 103,189,147 |
Refinery operating expenses | 2,877,748 | 2,586,151 | 6,314,763 | 5,467,122 |
Joint Marketing Agreement profit share | 97,527 | 938,661 | (573,565) | 3,377,298 |
Pipeline operating expenses | 95,195 | 60,887 | 174,485 | 107,483 |
Lease operating expenses | 8,455 | 14,098 | 23,107 | 21,414 |
General and administrative expenses | 255,319 | 400,018 | 612,323 | 745,902 |
Depletion, depreciation and amortization | 470,347 | 402,937 | 910,800 | 802,168 |
Recovery of bad debt | (139,868) | |||
Accretion expense | 28,186 | 52,720 | 56,372 | 105,935 |
Total cost of operations | 46,466,075 | 58,257,170 | 81,005,192 | 113,816,469 |
Income (loss) from operations | (4,423,615) | 904,444 | (7,450,456) | 6,737,494 |
OTHER INCOME (EXPENSE) | ||||
Easement, interest and other income | 126,097 | 66,460 | 257,860 | 132,467 |
Interest and other expense | (399,559) | (732,296) | (819,466) | (940,371) |
Total other expense | (273,462) | (665,836) | (561,606) | (807,904) |
Income (loss) before income taxes | (4,697,077) | 238,608 | (8,012,062) | 5,929,590 |
Income tax benefit (expense) | 1,534,341 | (100,729) | 2,700,242 | (2,090,347) |
Net income (loss) | $ (3,162,736) | $ 137,879 | $ (5,311,820) | $ 3,839,243 |
Income (loss) per common share: | ||||
Basic | $ (0.30) | $ 0.01 | $ (0.51) | $ 0.37 |
Diluted | $ (0.30) | $ 0.01 | $ (0.51) | $ 0.37 |
Weighted average number of common shares outstanding: | ||||
Basic | 10,459,996 | 10,450,210 | 10,458,895 | 10,449,829 |
Diluted | 10,459,996 | 10,450,210 | 10,458,895 | 10,449,829 |
1. Organization |
6 Months Ended | |||||||||||||||
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Jun. 30, 2016 | ||||||||||||||||
Organization, Consolidation and Presentation of Financial Statements [Abstract] | ||||||||||||||||
Organization | Nature of Operations. Blue Dolphin Energy Company (Blue Dolphin,) isprimarily an independent refiner and marketer of petroleum products. Our primary asset is a 15,000 bpd crude oil and condensate processing facility that is located in Nixon, Texas (the Nixon Facility). As part of our refinery business segment, we conduct petroleum storage and terminaling operations under third-party lease agreements at the Nixon Facility. We also own and operate pipeline assets and have leasehold interests in oil and gas properties. (See Note (4) Business Segment Information for further discussion of our business segments.)
Structure and Management. Blue Dolphin was formed as a Delaware corporation in 1986. We are currently controlled by Lazarus Energy Holdings, LLC (LEH), which owns approximately 81% of our common stock, par value $0.01 per share (the Common Stock). LEH manages and operates all of our properties pursuant to an Operating Agreement (the Operating Agreement). Jonathan Carroll is Chairman of the Board of Directors (the Board), Chief Executive Officer, and President of Blue Dolphin, as well as a majority owner of LEH. (See Note (8) Accounts Payable, Related Party, Note (9) Long-Term Debt, Net, and Note (19) Commitments and Contingencies Financing Agreements for additional disclosures related to LEH, the Operating Agreement, and Jonathan Carroll.)
Our operations are conducted through the following active subsidiaries:
See "Part II, Item 7. Managements Discussion and Analysis of Financial Condition and Results of Operations Owned and Leased Assets in our Form 10-K for the fiscal year ended December 31, 2015 (the Annual Report) as filed with the Securities and Exchange Commission (the SEC) for additional information regarding our operating subsidiaries.
References in this Quarterly Report to we, us, and our are to Blue Dolphin and its subsidiaries unless otherwise indicated or the context otherwise requires.
Operating Risks. We had cash and cash equivalents of $2,183,562 and $1,853,875 as of June 30, 2016 and December 31, 2015, respectively, and restricted cash (current portion) of $4,186,150 and $3,175,299 as of June 30, 2016 and December 31, 2015, respectively. As of June 30, 2016, we had current assets of $26,291,337 and current liabilities (including the current portion of long-term debt) of $67,037,594, resulting in a working capital deficit of $40,746,257. Excluding the current portion of long-term debt, as of June 30, 2016, we had a working capital deficit of $8,195,017. Non-payment of Operations Payments by GEL TEX Marketing, LLC (GEL) under a Joint Marketing Agreement (the Joint Marketing Agreement) also contributed to the working capital deficit as of June 30, 2016. We currently rely on Operations Payments and our profit share under the Joint Marketing Agreement and advances from LEH to fund our working capital requirements. If GEL does not advance Operations Payments and the profit share is insufficient to fund our working capital requirements, LEH may, but is not required to, fund our working capital requirements. There can be no assurances that LEH will continue to fund our working capital requirements.(See Note (8) Accounts Payable, Related Party and Note (19) Commitments and Contingencies Genesis Agreements and Legal Matters for a discussion related to Operations Payments and the Joint Marketing Agreement.)
As of June 30, 2016, we were in violation of certain financial covenants in secured loan agreements with Sovereign Bank(Sovereign). As a result of these covenant defaults, Sovereign could elect to declare the amounts owed under these loan agreements to be immediately due and payable, exercise its rights with respect to collateral securing our obligations under these loan agreements, or exercise any other rights and remedies available. Accordingly, $31,824,613 of debt under these loan agreements was classified within the current portion of long-term debt on our consolidated balance sheet as of June 30, 2016. (See Note (9) Long-Term Debt, Net and Note (20) Subsequent Events for additional disclosures related to our long-term debt and financial covenant violations.)
In addition to the Joint Marketing Agreement, we are party to a variety of contracts and agreements with Genesis and its affiliates that enable the purchase of crude oil and condensate, transportation of crude oil and condensate, and other services. Certain of these agreements with Genesis and its affiliates have successive one-year renewals until August 2019 unless sooner terminated by Genesis or its affiliates with 180 days prior written notice. An adverse change in our relationship with Genesis could have a material adverse effect on our operations, liquidity, and financial condition. We are currently involved in a dispute with Genesis over certain contractual matters. (See Note (19) Commitments and Contingencies Genesis Agreements and Legal Matters for a summary of the Joint Marketing Agreement and Crude Supply Agreement and information regarding the current contractual dispute with Genesis.)
Execution of our business strategy depends on several factors, including adequate crude oil and condensate sourcing, levels of accounts receivable, refined petroleum product inventories, accounts payable, capital expenditures, and adequate access to credit on satisfactory terms. These factors may be impacted by general economic, political, financial, competitive, and other factors that are beyond our control. There can be no assurance that our business and operational strategy will achieve anticipated outcomes. If our strategy is not successful, our working capital requirements are not funded through Operations Payments or our profit share under the Joint Marketing Agreement or certain advances from LEH, or Sovereign exercises remedies available under the loan agreements for covenant violations, we may experience a significant and material adverse effect on our operations, liquidity, and financial condition. |
2. Basis of Presentation |
6 Months Ended |
---|---|
Jun. 30, 2016 | |
Accounting Policies [Abstract] | |
Basis of Presentation | The accompanying unaudited consolidated financial statements, which include Blue Dolphin and subsidiaries, have been prepared in accordance with U.S. generally accepted accounting principles (GAAP) for interim consolidated financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, certain information and footnote disclosures normally included in our audited financial statements have been condensed or omitted pursuant to the SECs rules and regulations. Significant intercompany transactions have been eliminated in the consolidation. In managements opinion, all adjustments considered necessary for a fair presentation have been included, disclosures are adequate, and the presented information is not misleading.
The consolidated balance sheet as of December 31, 2015 has been derived from the audited financial statements at that date. The accompanying consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in our Annual Report. Operating results for the three and six months ended June 30, 2016 are not necessarily indicative of the results that may be expected for the fiscal year ending December 31, 2016, or for any other period. |
3. Significant Accounting Policies |
6 Months Ended | |||||||||||||||
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Jun. 30, 2016 | ||||||||||||||||
Accounting Policies [Abstract] | ||||||||||||||||
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 have made a number of estimates and assumptions related to the reporting of our consolidated assets and liabilities and to the disclosure of contingent assets and liabilities to prepare these consolidated financial statements in conformity with GAAP. While we believe our current estimates are reasonable and appropriate, actual results could differ from those estimated.
Cash and Cash Equivalents. Cash and cash equivalents represent liquid investments with an original maturity of three months or less. Cash balances are maintained in depository and overnight investment accounts with financial institutions that, at times, may exceed insured deposit limits. We monitor the financial condition of the financial institutions and have experienced no losses associated with these accounts. Cash and cash equivalents totaled $2,183,562 and $1,853,875 as of June 30, 2016 and December 31, 2015, respectively.
Restricted Cash. Total restricted cash was $12,139,773 and $18,791,777 as of June 30, 2016 and December 31, 2015, respectively. Total restricted cash was comprised of restricted cash (current portion), which totaled $4,186,150 and $3,175,299 as of June 30, 2016 and December 31, 2015, respectively and restricted cash, noncurrent, which totaled $7,953,623 and $15,616,478 as of June 30, 2016 and December 31, 2015, respectively. Restricted cash (current portion) primarily represents: (i) amounts held in our disbursement account with Sovereign attributable to construction invoices awaiting payment from that account, (ii) a payment reserve account held by Sovereign as security for payments under a loan agreement, and(iii) a construction contingency account under which Sovereign will fund contingencies. Restricted cash, noncurrent represents funds held in the Sovereign disbursement account for payment of future construction related expenses to build new petroleum storage tanks. (See Note (9) Long-Term Debt, Net for additional disclosures related to our loan agreements with Sovereign.)
Accounts Receivable and Allowance for Doubtful Accounts. Accounts receivable are customer obligations due under normal trade terms. The allowance for doubtful accounts represents our estimate of the amount of probable credit losses existing in our accounts receivable. We have a limited number of customers with individually large amounts due on any given date. Any unanticipated change in any one of these customers credit worthiness or other matters affecting the collectability of amounts due from such customers could have a material adverse effect on our results of operations in the period in which such changes or events occur. We regularly review all of our aged accounts receivable for collectability and establish an allowance for individual customer balances as necessary. Allowance for doubtful accounts totaled $0 and $139,868 as of June 30, 2016 and December 31, 2015, respectively.
Inventory. The nature of our business requires us to maintain inventory, which primarily consists of refined petroleum products and chemicals. Our overall inventory is valued at lower of cost or market with costs being determined by the average cost method. If the market value of our refined petroleum product inventories declines to an amount less than our average cost, we record a write-down of inventory and an associated adjustment to cost of refined products sold. (See Note (6) Inventory for additional disclosures related to our inventory.)
Derivatives. We are exposed to commodity prices and other market risks including gains and losses on certain financial assets as a result of our inventory risk management policy. Under our inventory risk management policy, commodity futures contracts may be used to mitigate the change in value for certain of our refined petroleum product inventories subject to market price fluctuations. The physical inventory volumes are not exchanged and these contracts are net settled with cash.
Although these commodity futures contracts are not subject to hedge accounting treatment under Financial Accounting Standards Board (the FASB) Accounting Standards Codification (ASC) guidance, we record the fair value of these hedges in our consolidated balance sheet each financial reporting period because of contractual arrangements under which we are effectively exposed to the potential gains or losses. We recognize all commodity hedge positions as either current assets or current liabilities in our consolidated balance sheets, and those instruments are measured at fair value. Changes in the fair value from financial reporting period to financial reporting period are recognized in our consolidated statements of operations. Net gains or losses associated with these transactions are recognized within cost of refined products sold in our consolidated statements of operations using mark-to-market accounting.
(See Note (17) Fair Value Measurement and Note (18) Inventory Risk Management for additional disclosures related to derivatives.)
Property and Equipment.
Refinery and Facilities. Additions to refinery and facilities assets are capitalized. Expenditures for repairs and maintenance are expensed as incurred and are included as operating expenses under the Operating Agreement. Management expects to continue making improvements to the Nixon Facility based on technological advances.
We record refinery and facilities at cost less any adjustments for depreciation or impairment. Adjustment of the asset and the related accumulated depreciation accounts are made for the refinery and facilities assets retirement and disposal, with the resulting gain or loss included in the consolidated statements of operations. For financial reporting purposes, depreciation of refinery and facilities assets is computed using the straight-line method using an estimated useful life of 25 years beginning when the refinery and facilities assets are placed in service. We did not record any impairment of our refinery and facilities assets for any period presented.
Pipelines and Facilities. We record pipelines and facilities at cost less any adjustments for depreciation or impairment. Depreciation is computed using the straight-line method over estimated useful lives ranging from 10 to 22 years. In accordance with FASB ASC guidance on accounting for the impairment or disposal of long-lived assets, we periodically evaluate our long-lived assets for impairment. Additionally, we evaluate our long-lived assets when events or circumstances indicate that the carrying value of these assets may not be recoverable.
Oil and Gas Properties. We account for our oil and gas properties using the full-cost method of accounting, whereby all costs associated with acquisition, exploration and development of oil and gas properties, including directly related internal costs, are capitalized on a cost center basis. Amortization of such costs and estimated future development costs are determined using the unit-of-production method. Our oil and gas properties had no production during the three and six months ended June 30, 2016 and 2015. All leases associated with our oil and gas properties have expired, and our oil and gas properties were fully impaired as of December 31, 2012.
Construction in Progress. Construction in progress expenditures, which relate to construction and refurbishment activities at the Nixon Facility, are capitalized as incurred. Depreciation begins once the asset is placed in service.
(See Note (7) Property, Plant and Equipment, Net for additional disclosures related to our refinery and facilities assets, oil and gas properties, pipelines and facilities assets, and construction in progress.)
Intangibles Other. We have an intangible asset consisting of the Blue Dolphin Energy Company trade name in the amount of $303,346 on our consolidated balance sheets as of June 30, 2016 and December 31, 2015. We have determined the trade name to have an indefinite useful life. We account for other intangible assets under FASB ASC guidance related to intangibles, goodwill, and other. Under the guidance, we test intangible assets with indefinite lives annually for impairment. Management performed its regular annual impairment testing of trade name in the fourth quarter of 2015. Upon completion of that testing, we determined that no impairment was necessary as of December 31, 2015.
Revenue Recognition.
Refined Petroleum Products Revenue. Jet fuel,our only finished product, is sold in nearby markets to wholesalers. Our intermediate products, including LPG, naphtha, HOBM, and AGO, are primarily sold in nearby markets to wholesalers and refiners for further blending and processing. Revenue from refined petroleum products sales is recognized when sales prices are fixed or determinable, collectability is reasonably assured, and title passes. Title passage occurs when refined petroleum products are delivered in accordance with the terms of the respective sales agreements, and customers assume the risk of loss when title is transferred. Transportation, shipping, and handling costs incurred are included in cost of refined products sold. Excise and other taxes that are collected from customers and remitted to governmental authorities are not included in revenue.
Tank Rental Revenue. Tank rental fees are invoiced monthly in accordance with the terms of the related lease agreement and recognized in revenue as earned.
Easement Revenue. Land easement revenue is recognized monthly as earned and is included in other income.
Pipeline Transportation Revenue. Revenue from our pipeline operations is derived from fee-based contracts and is typically based on transportation fees per unit of volume transported multiplied by the volume delivered. Revenue is recognized when volumes have been physically delivered for the customer through the pipeline.
Deferred Revenue. In 2014, we increased the ownership interest in our pipeline assets from approximately 83% to 100% pursuant to an Asset Sale Agreement (the Purchase Agreement) with a former partner. Pursuant to the Purchase Agreement, the former partner paid us $100,000 in cash, and a surety company $850,000 in cash as collateral for supplemental pipeline bonds for our benefit in exchange for the payment and discharge of any and all payables, claims, and obligations related to the pipeline assets. We recorded the amount received for our benefit related to the supplemental pipeline bonds as deferred revenue. We recognized the deferred revenue on a straight-line basis through December 31, 2018, the expected retirement date of the associated assets. In 2015, a significant portion of the remaining deferred revenue was recognized as a result of abandoning a segment of the pipeline assets. (See Part I, Business Governmental Regulation Offshore Safety and Environmental Oversight Decommissioning Requirements in our Annual Report for a discussion related to supplemental pipeline bonds.)
Income Taxes. We account for income taxes under FASB ASC guidance related to income taxes, which requires recognition of income taxes based on amounts payable with respect to the current three and six month periods and the effects of deferred taxes for the expected future tax consequences of events that have been included in our financial statements or tax returns. Under this method, deferred tax assets and liabilities are determined based on the differences between the financial accounting and tax basis of assets and liabilities, as well as for operating losses and tax credit carryforwards using enacted tax rates in effect for the year in which the differences are expected to reverse.
As of each reporting date, management considers new evidence, both positive and negative, to determine the realizability of deferred tax assets. Management considers whether it is more likely than not that a portion or all of the deferred tax assets will be realized, which is dependent upon the generation of future taxable income prior to the expiration of any net operating loss (NOL) carryforwards. When management determines that it is more likely than not that a tax benefit will not be realized, a valuation allowance is recorded to reduce deferred tax assets.
The guidance also prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return, as well as guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosures, and transition.
(See Note (15) Income Taxes for further information related to income taxes.)
Impairment or Disposal of Long-Lived Assets. In accordance with FASB ASC guidance on accounting for the impairment or disposal of long-lived assets, we periodically evaluate our long-lived assets for impairment. Additionally, we evaluate our long-lived assets when events or circumstances indicate that the carrying value of these assets may not be recoverable. The carrying value is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset or group of assets. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount by which the carrying value exceeds the fair value of the asset or group of assets is recognized. Significant management judgment is required in the forecasting of future operating results that are used in the preparation of projected cash flows and, should different conditions prevail or judgments be made, material impairment charges could be necessary.
Asset Retirement Obligations. FASB ASC guidance related to asset retirement obligations (AROs) requires that a liability for the discounted fair value of an ARO be recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted towards its future value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized.
Management has concluded that there is no legal or contractual obligation to dismantle or remove the refinery and facilities assets. Further, management believes that these 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 the 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.
We recorded an ARO liability related to future asset retirement costs associated with dismantling, relocating, or disposing of our offshore platform, pipeline systems, and related onshore facilities, as well as for plugging and abandoning wells and restoring land and sea beds. We developed these cost estimates for each of our assets based upon regulatory requirements, structural makeup, water depth, reservoir characteristics, reservoir depth, equipment demand, current retirement procedures, and construction and engineering consultations. Because these costs typically extend many years into the future, estimating future costs are difficult and require management to make judgments that are subject to future revisions based upon numerous factors, including changing technology, political, and regulatory environments. We review our assumptions and estimates of future abandonment costs on an annual basis.
(See Note (11) Asset Retirement Obligations for additional information related to our AROs.)
Computation of Earnings Per Share. We apply the provisions of FASB ASC guidance for computing earnings per share (EPS). The guidance requires the presentation of basic EPS, which excludes dilution and is computed by dividing net income available to common stockholders by the weighted-average number of shares of common stock outstanding for the period. The guidance requires dual presentation of basic EPS and diluted EPS on the face of our consolidated statements of operations and requires a reconciliation of the numerators and denominators of basic EPS and diluted EPS. Diluted EPS is computed by dividing net income available to common stockholders by the diluted weighted average number of common shares outstanding, which includes the potential dilution that could occur if securities or other contracts to issue shares of common stock were converted to common stock that then shared in the earnings of the entity.
The number of shares related to options, warrants, restricted stock, and similar instruments included in diluted EPS is based on the Treasury Stock Method prescribed in FASB ASC guidance for computation of EPS. This method assumes theoretical repurchase of shares using proceeds of the respective stock option or warrant exercised, and, for restricted stock, the amount of compensation cost attributed to future services that has not yet been recognized and the amount of any current and deferred tax benefit that would be credited to additional paid-in-capital upon the vesting of the restricted stock, at a price equal to the issuers average stock price during the related earnings period. Accordingly, the number of shares includable in the calculation of EPS in respect of the stock options, warrants, restricted stock, and similar instruments is dependent on this average stock price and will increase as the average stock price increases. (See Note (16) Earnings Per Share for additional information related to EPS.)
Stock-Based Compensation. In accordance with FASB ASC guidance for stock-based compensation, share-based payments to directors, including the issuance of restricted common stock, are measured at fair value as of the date of grant and are expensed in our consolidated statements of operations over the service period (generally the vesting period).
Treasury Stock. We account for treasury stock under the cost method. When treasury stock is re-issued, the net change in share price subsequent to acquisition of the treasury stock is recognized as a component of additional paid-in-capital in our consolidated balance sheets. (See Note (12) Treasury Stock for additional disclosures related to treasury stock.)
New Pronouncements Adopted. The FASB issues an Accounting Standards Update (ASU) to communicate changes to the FASB ASC, including changes to non-authoritative SEC content. For the three and six months ended June 30, 2016, we adopted the following recently issued ASUs:
ASU 2015-17,Income Taxes (Topic 740). In November 2015, FASB issued ASU 2015-17. This guidance simplifies the presentation of deferred income taxes by requiring that deferred tax liabilities and assets be classified as noncurrent instead of separated into current and noncurrent. We adopted this accounting pronouncement effective April 1, 2016. Accordingly, our consolidated balance sheet as of December 31, 2015 has been changed to reclassify approximately $3.5 million previously reported as deferred tax assets, current portion, net to deferred tax assets, net. The adoption of ASU 2015-17 had no impact on our results of operations or cash flows.
ASU 2015-03, Imputation of Interest (Topic 835): Simplifying the Presentation of Debt Issuance Costs. In April 2015, FASB issued ASU 2015-03. This guidance requires debt issue costs to be presented as an offset to their related debt. We adopted this accounting pronouncement effective January 1, 2016. Accordingly, our consolidated balance sheet as of December 31, 2015 has been changed to reclassify approximately $2.4 million previously reported as debt issue costs as a direct deduction of long-term debt. The adoption of ASU 2015-03 had no impact on our results of operations or cash flows.
New Pronouncements Issued But Not Yet Effective. The following are recently issued, but not yet effective, ASUs that may have an effect on our consolidated financial position, results of operations, or cash flows:
ASU 2016-13,Financial Instruments Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments). In June 2016, FASB issued ASU 2016-13. This guidance updates the current impairment model to incorporate both expected and incurred credit losses, eliminating potential overstatements of assets and resulting in more timely recognition of losses. For a public business entity, the amendments in ASU 2016-13 are effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. Early application as of the fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, is permitted. We are evaluating the impact that adoption of this guidance will have on our consolidated financial statements.
ASU 2016-02,Leases (Topic 842). In February 2016, FASB issued ASU 2016-02. This guidance increases transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. For a public business entity, the amendments in ASU 2016-02 are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early application is permitted. We are evaluating the impact that adoption of this guidance will have on our consolidated balance sheets.
ASU 2015-11,Inventory(Topic 330):Simplifying the Measurement of Inventory. In July 2015, FASB issued ASU 2015-11. Current guidance requires an entity to measure inventory at the lower of cost or market. Market could be replacement cost, net realizable value, or net realizable value less an approximately normal profit margin. Under ASU 2015-11, an entity should measure inventory at the lower of cost or net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. Amendments under ASU 2015-11 more closely align the measurement of inventory in GAAP with the measurement of inventory in International Financial Reporting Standards. For public business entities, ASU 2015-11 is effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. ASU 2015-11 should be applied prospectively with earlier application permitted as of the beginning of an interim or annual reporting period. We do not anticipate adoption of this guidance to have a material effect on our consolidated financial statements.
ASU 2014-15, Disclosure of Uncertainties about an Entitys Ability to Continue as a Going Concern (Subtopic 205-40). In August 2014, FASB issued ASU 2014-15, which requires management to perform interim and annual assessments of an entitys ability to continue as a going concern for a one-year period subsequent to the date of the financial statements. An entity must provide certain disclosures if conditions or events raise substantial doubt about the entitys ability to continue as a going concern. The guidance is effective for all entities for the first annual period ending after December 15, 2016 and interim periods thereafter, with early adoption permitted. We do not anticipate adoption of this guidance to have a material effect on our consolidated financial statements.
ASU 2014-09,Revenue from Contracts with Customers (Topic 606). In May 2014, FASB and the International Accounting Standards Board (the IASB) issued ASU 2014-09, a converged standard on recognition of revenue from contracts with customers. In June 2014, the FASB and the IASB (collectively, the Accounting Boards) formed the FASB-IASB Joint Transition Resource Group for Revenue Recognition (the TRG). The primary objective of the TRG is to inform the Accounting Boards about potential implementation issues that could arise when organizations implement the new revenue guidance. Resultant ASUs as part of the TRG process include:
We are evaluating the impact that adoption of ASU 2014-09, ASU 2015-14, ASU 2016-08, ASU 2016-10, ASU 2016-11, and 2016-12, all of which relate to Revenue from Contracts with Customers (Topic 606), will have on our consolidated financial statements.
Other new pronouncements issued but not effective until after June 30, 2016 are not expected to have a material impact on our financial position, results of operations, or liquidity.
Reclassification. We have reclassified certain prior year amounts to conform to our 2016 presentation. |
4. Business Segment Information |
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Segment Reporting [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Business Segment Information | We have two reportable business segments: (i) Refinery Operations and (ii) Pipeline Transportation. Business activities related to our Refinery Operations business segment are conducted at the Nixon Facility. Business activities related to our Pipeline Transportation business segment are primarily conducted in the Gulf of Mexico through our Pipeline Assets and leasehold interests in oil and gas properties.
Business segment information for the periods indicated (and as of the dates indicated), was as follows:
Business segment information for the periods indicated (and as of the dates indicated), was as follows:
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5. Prepaid Expenses and Other Current Assets |
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Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Prepaid Expenses and Other Current Assets | Prepaid expenses and other current assets as of the dates indicated consisted of the following:
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6. Inventory |
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Inventory | Inventory as of the dates indicated consisted of the following:
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7. Property, Plant and Equipment, Net |
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Property, Plant and Equipment, Net | Property, plant and equipment, net, as of the dates indicated consisted of the following:
We capitalize interest cost incurred on funds used to construct property, plant, and equipment. The capitalized interest is recorded as part of the asset to which it relates and is depreciated over the assets useful life. Interest cost capitalized was $1,363,536 and $556,032 as of June 30, 2016 and December 31, 2015, respectively. |
8. Accounts Payable, Related Party |
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Payables and Accruals [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Accounts Payable, Related Party | Accounts payable, related party as of the dates indicated consisted of the following:
Accounts payable, related party correspond to the following:
Ingleside Crude, LLC (Ingleside). Pursuant to a Tank Lease Agreement with Ingleside, we lease petroleum storage tanks to meet periodic, additional storage needs. The Tank Lease Agreement had an initial term of 30 days and automatically renews for 30 day periods. The parties may terminate the tank lease agreement upon 30 days written notice. Amounts owed to Ingleside under the tank lease agreement are reflected within accounts payable, related party in our consolidated balance sheets. Amounts expensed as fees to Ingleside are reflected within refinery operating expenses in our consolidated statements of operations. Ingleside is a related party of LEH and Jonathan Carroll.
For the three months ended June 30, 2016 and 2015, fees to Ingleside totaled $450,000(approximately $0.63 per bbl of throughput) and $0, respectively. For the six months ended June 30, 2016 and 2015, fees to Ingleside totaled $725,000(approximately $0.38 per bbl of throughput) and $0, respectively.
LEH. We are party to an Operating Agreement, a Product Sales Agreement, and a Terminal Services Agreement with LEH. LEH, our controlling shareholder, owns approximately 81% of our Common Stock. Jonathan Carroll, Chairman of the Board, Chief Executive Officer, and President of Blue Dolphin, is the majority owner of LEH.
Operating Agreement. LEH manages and operates all of our properties pursuant to the Operating Agreement. The Operating Agreement expires upon the earliest to occur of: (a) the date of the termination of the Joint Marketing Agreement pursuant to its terms, (b) August 2018, or (c) upon written notice of either party to the Operating Agreement of a material breach of the Operating Agreement by the other party. For services rendered under the Operating Agreement, LEH receives reimbursements and fees as follows:
Product Sales Agreement. Under a Product Sales Agreement, LEH purchases jet fuel from the Nixon Facility for resale to third parties. Sales to LEH are reflected within refined petroleum product sales in our consolidated statements of operations. For the three months ended June 30, 2016 and 2015, sales to LEH totaled $8,912,074 and $0, respectively. For the six months ended June 30, 2016 and 2015, sales to LEH totaled $8,912,074 and $0, respectively.
Terminal Services Agreement. Pursuant to a Terminal Services Agreement, LEH leases a petroleum storage tank at the Nixon Facility. The Terminal Services Agreement has an initial term of 12 months and automatically renews for additional terms of 6 months. The parties may terminate the Terminal Services Agreement upon 45 days written notice. Fees from LEH are reflected within tank rental revenue in our consolidated statements of operations. For the three months ended June 30, 2016 and 2015, fees from LEH totaled $324,000 and $0, respectively. For the six months ended June 30, 2016 and 2016, fees from LEH totaled $324,000 and $0, respectively.
Jonathan Carroll. Pursuant to Guaranty Fee Agreements, Jonathan Carroll receives fees for providing his personal guarantee on certain of our long-term debt. Jonathan Carroll was required to guarantee repayment of funds borrowed and interest accrued under the loan agreements. Amounts owed to Jonathan Carroll under Guaranty Fee Agreements are reflected within accounts payable, related party in our consolidated balance sheets. Jonathan Carroll is Chairman of the Board, Chief Executive Officer, and President of Blue Dolphin. (See Note (9) Long-Term Debt, Net for further discussion related to the Guaranty Fee Agreements.)
We believe these related party transactions were consummated on terms equivalent to those that prevail in arm's-length transactions. |
9. Long-Term Debt, Net |
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Debt Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Long-Term Debt, Net | Effective January 1, 2016, we adopted the provisions of the FASB ASC guidance that requires debt issue costs to be presented as an offset to their related debt. Accordingly, our consolidated balance sheet as of December 31, 2015 has been changed to reclassify approximately $2.4 million previously reported debt issue costs as a direct deduction of long-term debt.
Long-term debt, net, which represents the outstanding principal and interest of long-term debt less associated debt issue costs, as of the dates indicated consisted of the following:
Accrued interest related to our long-term debt, net (reflected as interest payable, current portion and long-term interest payable, net of current portion in our consolidated balance sheets) as of the dates indicated consisted of the following:
First Term Loan Due 2034. In June 2015, LE entered into a loan agreement and related security agreement with Sovereign as administrative agent and lender,providing for a term loan in the principal amount of $25.0 million (the First Term Loan Due 2034). The First Term Loan Due 2034 matures in June 2034, has a current monthly payment of principal and interest of $188,416, and accrues interest at a rate based on the Wall Street Journal Prime Rate plus 2.75%. Pursuant to a construction rider in the First Term Loan Due 2034, proceeds available for use were placed in a disbursement account whereby Sovereign makes payments for construction related expenses. Amounts held in the disbursement account are reflected as restricted cash (current portion) and restricted cash, noncurrent in our consolidated balance sheets.
As of June 30, 2016, LE was in violation of the debt service coverage ratio, the current ratio, and debt to net worth ratio financial covenants under the First Term Loan Due 2034. Accordingly, the First Term Loan Due 2034 was classified within the current portion of long-term debt on our consolidated balance sheet as of June 30, 2016. (See Note (1) Organization Operating Risks and Note (20) Subsequent Events for additional disclosures related to the First Term Loan Due 2034 and financial covenant violations.)
As a condition of the First Term Loan Due 2034, Jonathan Carroll was required to guarantee repayment of funds borrowed and interest accrued under the loan. For his personal guarantee, LE entered into a Guaranty Fee Agreement with Jonathan Carroll whereby he receives a fee equal to 2.00% per annum, paid monthly, of the outstanding principal balance owed under the First Term Loan Due 2034. For the three months ended June 30, 2016 and 2015, guaranty fees related to the First Term Loan Due 2034 totaled $121,739 and $0, respectively. For the six months ended June 30, 2016 and 2015, guaranty fees related to the First Term Loan Due 2034 totaled $244,372 and $0, respectively. Guaranty fees are recognized monthly as incurred and are included in interest and other expense in our consolidated statements of operations. LEH, LRM and Blue Dolphin also guaranteed the First Term Loan Due 2034. (See Note (8) Accounts Payable, Related Party for additional disclosures related to LEH and Jonathan Carroll.)
A portion of the proceeds of the First Term Loan Due 2034 were used to refinance approximately $8.5 million of debt owed under a previous debt facility with American First National Bank. Remaining proceeds are being used primarily to construct new petroleum storage tanks at the Nixon Facility. The First Term Loan Due 2034 is secured by: (i) a first lien on all Nixon Facility business assets (excluding accounts receivable and inventory), (ii) assignment of all Nixon Facility contracts, permits, and licenses, (iii) absolute assignment of Nixon Facility rents and leases, including tank rental income, (iv) a $1.0 million payment reserve account held by Sovereign, and (v) a pledge of $5.0 million of a life insurance policy on Jonathan Carroll. The First Term Loan Due 2034 contains representations and warranties, affirmative, restrictive, and financial covenants, as well as events of default which are customary for credit facilities of this type.
Second Term Loan Due 2034. In December 2015, LRM entered into a loan agreement and related security agreement with Sovereign as administrative agent and lender, providing for a term loan in the principal amount of $10.0 million (the Second Term Loan Due 2034). The Second Term Loan Due 2034 matures in December 2034, has a current monthly payment of principal and interest of $74,111, and accrues interest at a rate based on the Wall Street Journal Prime Rate plus 2.75%. Pursuant to a construction rider in the Second Term Loan Due 2034, proceeds available for use were placed in a disbursement account whereby Sovereign makes payments for construction related expenses. Amounts held in the disbursement account are reflected as restricted cash (current portion) and restricted cash, noncurrent in our consolidated balance sheets.
As of June 30, 2016, LRM was in violation of the debt service coverage ratio, the current ratio, and the debt to net worth ratio financial covenants under the Second Term Loan Due 2034. Accordingly, the Second Term Loan Due 2034 was classified within the current portion of long-term debt on our consolidated balance sheets. (See Note (1) Organization Operating Risks and Note (20) Subsequent Events for additional disclosures related to the Second Term Loan Due 2034 and financial covenant violations.)
As a condition of the Second Term Loan Due 2034, Jonathan Carroll was required to guarantee repayment of funds borrowed and interest accrued under the loan. For his personal guarantee, LRM entered into a Guaranty Fee Agreement with Jonathan Carroll whereby he receives a fee equal to 2.00% per annum, paid monthly, of the outstanding principal balance owed under the Second Term Loan Due 2034. For the three months ended June 30, 2016 and 2015, guaranty fees related to the Second Term Loan Due 2034 totaled $49,420 and $0, respectively. For the six months ended June 30, 2016 and 2015, guaranty fees related to the Second Term Loan Due 2034 totaled $99,168 and $0, respectively. Guaranty fees are recognized monthly as incurred and are included in interest and other expense in our consolidated statements of operations. LEH, LE and Blue Dolphin also guaranteed the Second Term Loan Due 2034. (See Note (8) Accounts Payable, Related Party for additional disclosures related to LEH and Jonathan Carroll.)
A portion of the proceeds of the Second Term Loan Due 2034 were used to refinance a previous bridge loan from Sovereign in the amount of $3.0 million. Remaining proceeds are being used primarily to construct additional new petroleum storage tanks at the Nixon Facility. The Second Term Loan Due 2034 is secured by: (i) a second priority lien on the rights of LE in the Nixon Facility and the other collateral of LE pursuant to a security agreement; (ii) a first priority lien on the real property interests of LRM; (iii) a first priority lien on all of LRMs fixtures, furniture, machinery and equipment; (iv) a first priority lien on all of LRMs contractual rights, general intangibles and instruments, except with respect to LRMs rights in its leases of certain specified tanks, with respect to which Sovereign has a second priority lien in such leases subordinate to a prior lien granted by LRM to Sovereign to secure obligations of LRM under the Term Loan Due 2017; and (v) all other collateral as described in the security documents. The Second Term Loan Due 2034 contains representations and warranties, affirmative, restrictive, and financial covenants, as well as events of default which are customary for credit facilities of this type.
Notre Dame Debt. LE entered into a loan with Notre Dame Investors, Inc. as evidenced by a Promissory Note in the original principal amount of $8.0 million, which is currently held by John Kissick (the Notre Dame Debt). The Notre Dame Debt matures in January 2018, and accrues interest at a rate of 16.00%.
The Notre Dame Debt is secured by a Deed of Trust, Security Agreement and Financing Statements (the Subordinated Deed of Trust), which encumbers the Nixon Facility and general assets of LE. There are no financial maintenance covenants associated with the Notre Dame Debt. Pursuant to a Subordination Agreement dated June 2015, the holder of the Notre Dame Debt agreed to subordinate any security interest and liens on the Nixon Facility, as well as its right to payments, in favor of Sovereign as holder of the First Term Loan Due 2034.
Term Loan Due 2017. LRM entered into a Loan and Security Agreement with Sovereign in May 2014, for a term loan facility in the principal amount of $2.0 million (the Term Loan Due 2017). The Term Loan Due 2017 was amended in March 2015, pursuant to a Loan Modification Agreement (the March Loan Modification Agreement). Under the March Loan Modification Agreement, the interest rate was modified to be the greater of the Wall Street Journal Prime Rate plus 2.75% or 6.00%, and the due date was extended to March 2017. Pursuant to the March Loan Modification Agreement, the Term Loan Due 2017 has a current monthly principal payment of $61,665 plus interest. Due to its maturity date, the Term Loan Due 2017 was classified within the current portion of long-term debt on our consolidated balance sheet as of June 30, 2016.
As a condition of the Term Loan Due 2017, Jonathan Carroll was required to guarantee repayment of funds borrowed and interest accrued under the loan. For his personal guarantee, LRM entered into a Guaranty Fee Agreement with Jonathan Carroll whereby he receives a fee equal to 2.00% per annum, paid monthly, of the outstanding principal balance owed under the Term Loan Due 2017. For the three months ended June 30, 2016 and 2015, guaranty fees related to the Term Loan Due 2017 totaled $3,083 and $0, respectively. For the six months ended June 30, 2016 and 2015, guaranty fees related to the Term Loan Due 2017 totaled $7,091 and $0, respectively. Guaranty fees are recognized monthly as incurred and are included in interest and other expense in our consolidated statements of operations.
The proceeds of the Term Loan Due 2017 were used primarily to finance costs associated with refurbishment of the Nixon Facilitys naphtha stabilizer and depropanizer units. The Term Loan Due 2017 is: (i) subject to a financial maintenance covenant pertaining to debt service coverage ratio and (ii) secured by the assignment of certain leases of LRM and certain assets of LEH. (See Note (8) Accounts Payable, Related Party for additional disclosures related to LEH and Jonathan Carroll.)
Capital Leases. LRM entered into a 36-month build-to-suit capital lease in August 2014 for the purchase of new boiler equipment for the Nixon Facility. The equipment, which was delivered in December 2014, was added to construction in progress. Once placed in service, the equipment will be reclassified to refinery and facilities and depreciation will begin. The capital lease, which requires a quarterly payment in the amount of $44,258, is guaranteed by Blue Dolphin.
A summary of equipment held under long-term capital leases as of the dates indicated follows:
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10. Accrued Expenses and Other Current Liabilities |
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Disclosure Text Block Supplement [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Accrued Expenses and Other Current Liabilities | Accrued expenses and other current liabilities as of the dates indicated consisted of the following:
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11. Asset Retirement Obligations |
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Asset Retirement Obligation Disclosure [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Asset Retirement Obligations | Refinery and Facilities. Management has concluded that there is no legal or contractual obligation to dismantle or remove the refinery and facilities assets. Management believes that the 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 the 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 the dismantlement and abandonment in place of our pipelines and facilities assets, as well as the plugging and abandonment of 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. We depreciate the amount added to property and equipment and recognize accretion expense in connection with the discounted liability over the remaining life of the asset. Plugging and abandonment costs are recorded during the period incurred or as information becomes available to substantiate actual and/or probable costs.
Changes to our ARO liability for the periods indicated were as follows:
Liabilities settled represents amounts paid for plugging and abandonment costs against the assets ARO liability and are reflected in our consolidated balance sheets. As of June 30, 2016 and December 31, 2015, we recognized $59,247 and $92,330, respectively, in liabilities settled. Abandonment expense represents amounts paid for plugging and abandonment costs that exceed the assets ARO liability and are reflected in our consolidated statements of operations. For the three months ended June 30, 2016 and 2015, we recognized $0 in abandonment expense. For the six months ended June 30, 2016 and 2015, we recognized $0 in abandonment expense. |
12. Treasury Stock |
6 Months Ended |
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Jun. 30, 2016 | |
Equity [Abstract] | |
Treasury Stock | As of June 30, 2016 and December 31, 2015, we had 150,000 shares of treasury stock. |
13. Concentration of Risk |
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Risks and Uncertainties [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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 our cash balances at financial institutions located in Houston, Texas. In the U.S., the Federal Deposit Insurance Corporation (the FDIC) insures certain financial products up to a maximum of $250,000 per depositor. We had cash balances in excess of the FDIC insurance limit per depositor in the amount of $13,716,774 and $19,594,883 as of June 30, 2016 and December 31, 2015, respectively.
Key Supplier. Under a Crude Oil and Supply Throughput Services Agreement dated in August 2011 (the Crude Supply Agreement), GEL supplies crude oil and condensate to the Nixon Facility. The initial term of the Crude Supply Agreement was to expire in August 2014. However, in October 2013, we entered into a Letter Agreement Regarding Certain Advances and Related Agreements with GEL and Milam Services, Inc., another Genesis affiliate (Milam), (the October 2013 Letter Agreement), effective in October 2013. In accordance with the terms of the October 2013 Letter Agreement, we agreed not to terminate the Crude Supply Agreement and GEL agreed to automatically renew the Crude Supply Agreement at the end of the initial term for successive one year periods until August 2019, unless sooner terminated by GEL with 180 days prior written notice.
(See Note (19) Commitments and Contingencies Genesis Agreements and Legal Matters for a summary of the Crude Supply Agreement and a discussion of the current contractual dispute with Genesis.)
Significant Customers. We routinely assess the financial strength of our customers and have not experienced significant write-downs in our accounts receivable balances. As a result, we believe that our accounts receivable credit risk exposure is limited. For the three months ended June 30, 2016, we had 4 customers that accounted for approximately 71% of our refined petroleum products sales. These 4 customers represented approximately $6.2 million in accounts receivable as of June 30, 2016. For the three months ended June 30, 2015, we had 5 customers that accounted for approximately 82% of our refined petroleum products sales. These 5 customers represented approximately $5.2 million in accounts receivable as of June 30, 2015.
For the six months ended June 30, 2016, we had 4 customers that accounted for approximately 64% of our refined petroleum products sales. These 4 customers represented approximately $6.2 million in accounts receivable as of June 30, 2016. For the six months ended June 30, 2015, we had 3 customers that accounted for approximately 58% of our refined petroleum products sales. These 3 customers represented approximately $3.2 million in accounts receivable as of June 30, 2015.
Refined Petroleum Product Sales. Our refined petroleum products are primarily sold in the U.S. However, with the opening of the Mexican diesel market to private companies, we began exporting low sulfur diesel to Mexico during the second quarter of 2016. Total refined petroleum product sales by distillation (from light to heavy) for the periods indicated consisted of the following:
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14. Leases |
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Jun. 30, 2016 | |
Leases, Operating [Abstract] | |
Leases | Our company headquarters is located in downtown Houston, Texas. We lease 13,878 square feet of office space, 7,389 square feet of which is used and paid for by LEH. The office lease has a 10-year term that expires in September 2017. The lease included a free rent period, has escalating rent payment provisions, and requires payment of a portion of operating expenses. Rent expense is recognized on a straight-line basis. For the three months ended June 30, 2016 and 2015, rent expense totaled $29,857 and $57,060, respectively. For the six months ended June 30, 2016 and 2015, rent expense totaled $59,715 and $82,889, respectively. |
15. Income Taxes |
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Income Tax Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Income Taxes | Income Tax Benefit (Expense). Income tax benefit (expense) for the periods indicated consisted of the following:
The state of Texas has a Texas margins tax (TMT), which is a form of business tax imposed on gross margin. Although TMT is imposed on an entitys gross margin rather than on its net income, certain aspects of TMT make it similar to an income tax. Accordingly, TMT is treated as an income tax for financial reporting purposes.
Deferred Income Taxes. Deferred income tax balances reflect the effects of temporary differences between the carrying amounts of assets and liabilities and their tax basis, as well as from NOL carryforwards. We state those balances at the enacted tax rates we expect will be in effect when taxes are actually paid. NOL carryforwards and deferred tax assets represent amounts available to reduce future taxable income.
NOL Carryforwards. Under Section 382 of the Internal Revenue Code of 1986, as amended (IRC Section 382), a corporation that undergoes an ownership change is subject to limitations on its use of pre-change NOL carryforwards to offset future taxable income. Within the meaning of IRC Section 382, an ownership change occurs when the aggregate stock ownership of certain stockholders (generally 5% shareholders, applying certain look-through rules) increases by more than 50 percentage points over such stockholders' lowest percentage ownership during the testing period (generally three years). For income tax purposes, we experienced ownership changes in 2005, in connection with a series of private placements, and in 2012, as a result of a reverse acquisition, that limit the use of pre-change NOL carryforwards to offset future taxable income. In general, the annual use limitation equals the aggregate value of common stock at the time of the ownership change multiplied by a specified tax-exempt interest rate. The 2012 ownership change will subject approximately $18.8 million in NOL carryforwards that were generated prior to the ownership change to an annual use limitation of $638,196 per year. Unused portions of the annual use limitation amount may be used in subsequent years. As a result of the annual use limitation, approximately $6.7 million in NOL carryforwards that were generated prior to the 2012 ownership change will expire unused. NOL carryforwards that were generated after the 2012 ownership change are not subject to an annual use limitation under IRC Section 382 and may be used in addition to available amounts of NOL carryforwards generated prior to the ownership change.
NOL carryforwards that remained available for future use for the periods indicated were as follow (amounts shown are net of NOLs that will expire unused as a result of the IRC Section 382 limitation):
Deferred Tax Assets and Liabilities. As of June 30, 2016 and December 31, 2015, approximately $6.3 million and $3.6 million, respectively, of net deferred tax assets remained available for future use. Significant components of deferred tax assets and liabilities as of the dates indicated were as follow:
Valuation Allowance. As of each reporting date, management considers new evidence, both positive and negative, that could impact managements view with regard to future realization of deferred tax assets. As of June 30, 2016 and December 31, 2015, management determined that sufficient positive evidence existed to conclude that it was more likely than not that net deferred tax assets of approximately $6.3 million and $3.6 million, respectively, were realizable, and as a result, reflected a valuation allowance of $2.3 million at each date.
Current Versus Long-Term. Effective April 1, 2016, we adopted the provisions of the FASB ASC guidance that simplifies the presentation of deferred income taxes by requiring that deferred tax liabilities and assets be classified as noncurrent instead of separated into current and noncurrent. Accordingly, our consolidated balance sheet as of December 31, 2015 has been changed to reclassify approximately $3.5 million previously reported as deferred tax assets, current portion, net to deferred tax assets, net.
Uncertain Tax Positions. We adopted the provisions of the FASB ASC guidance on accounting for uncertainty in income taxes. The guidance clarifies the accounting for uncertainty in income taxes recognized in an enterprises financial statements. The guidance also prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The standard also provides guidance on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure and transition.
As part of this guidance, we record income tax related interest and penalties, if applicable, as a component of the provision for income tax benefit (expense). However, there were no amounts recognized relating to interest and penalties in the consolidated statements of operations for the three and six months ended June 30, 2016 and 2015. Our federal income tax returns are subject to examination by the Internal Revenue Service for tax years ending December 31, 2012, or after and by the state of Texas for tax years ending December 31, 2011, or after. We believe there are no uncertain tax positions for both federal and state income taxes. |
16. Earnings Per Share |
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Earnings Per Share [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Earnings Per Share | A reconciliation between basic and diluted income per share for the periods indicated was as follows:
Diluted EPS is computed by dividing net income available to common stockholders by the weighted average number of shares of common stock outstanding. Diluted EPS for the three and six months ended June 30, 2016 and 2015 was the same as basic EPS as there were no stock options or other dilutive instruments outstanding. |
17. Fair Value Measurement |
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Fair Value Disclosures [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair Value Measurement | The purchase and sale of financial instruments may be executed for the purpose of economically hedging commodity price risks associated with our refined petroleum products and the purchase of crude oil and condensate. When executed these financial instruments are direct contractual obligations of our crude supplier and not us. However, we financially benefit from any gains and financially bear any losses associated with the purchase and/or sale of such financial instruments. Because such instruments represent embedded derivatives for the purpose of financial reporting, we account for such embedded derivatives in our financial records by utilizing the market approach when measuring fair value of our financial instruments (typically in current assets and/or liabilities, as discussed below). The market approach uses prices and other relevant information generated by such market transactions executed on our behalf involving identical or comparable assets or liabilities.
Generally accepted accounting principles establish a framework for measuring fair value. That framework provides a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The fair value hierarchy consists of the following three levels:
The carrying amounts of accounts receivable, accounts payable, and accrued liabilities approximated their fair values as of June 30, 2016 and December 31, 2015 due to their short-term maturities. The fair value of our long-term debt, net including the current portion as of June 30, 2016 and December 31, 2015 was $36,227,804 and $37,172,668, respectively. The fair value of our debt was determined using a Level 3 hierarchy.
The following table represents our assets and liabilities measured at fair value on a recurring basis as of June 30, 2016 and December 31, 2015 and the basis for the measurement:
Carrying amounts of commodity contracts are reflected as other current assets or other current liabilities in our consolidated balance sheets. |
18. Inventory Risk Management |
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Derivative Instruments and Hedging Activities Disclosure [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Inventory Risk Management | Management periodically determines whether to maintain, increase, or decrease inventory levels based on various factors, including the crude pricing market in the U.S. Gulf Coast region, the refined petroleum products market in the same region, the relationship between these two markets, fulfilling contract demands, and other factors that may impact our operations, financial condition, and cash flows. Under our inventory risk management policy, commodity futures contracts may be used to mitigate the change in value for certain of our refined petroleum product inventories subject to market price fluctuations in our inventory. The physical inventory volumes are not exchanged, and these contracts are net settled with cash.
The fair value of commodity futures contracts is reflected in our consolidated balance sheets and the related net gain or loss is recorded within cost of refined products sold in our consolidated statements of operations. Quoted prices for identical assets or liabilities in active markets (Level 1) are considered to determine the fair values for the purpose of marking to market the financial instruments at each period end.
Commodity transactions are executed to minimize transaction costs, monitor consolidated net exposures, and allow for increased responsiveness to changes in market factors. Due to mark-to-market accounting during the term of the commodity futures contracts, significant unrealized non-cash net gains and losses could be recorded in our results of operations.
As of June 30, 2016, we had the following obligations based on futures contracts of refined petroleum products and crude oil and condensate that were entered into as economic hedges. The information presents the notional volume of open commodity instruments by type and year of maturity (volumes in bbls):
The following table provides the location and fair value amounts of derivative instruments that are reported in our consolidated balance sheets as of June 30, 2016 and December 31, 2015:
The following table provides the effect of derivative instruments in our consolidated statements of operations for the three and six months ended June 30, 2016 and 2015:
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19. Commitments and Contingencies |
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Commitments and Contingencies Disclosure [Abstract] | |||||||||||||
Commitments and Contingencies | Operating Agreement. (See Note (8) Accounts Payable, Related Party for additional disclosures related to the Operating Agreement.)
Genesis Agreements. Our relationship with Genesis and its affiliates is currently governed by two agreements, as follows:
Crude Supply Agreement. Under the Crude Supply Agreement, GEL supplies crude oil and condensate to the Nixon Facility. GEL supplies crude oil and condensate to us at cost plus freight expense and any costs associated with hedging. All crude oil and condensate supplied to us pursuant to the Crude Supply Agreement is paid for pursuant to the terms of the Joint Marketing Agreement as described within this section. In addition, GEL has a first right of refusal to use three petroleum storage tanks at the Nixon Facility during the term of the Crude Supply Agreement. Subject to certain termination rights, the Crude Supply Agreement had an initial term of three years expiring in August 2014. In accordance with the terms of the October 2013 Letter Agreement, we agreed not to terminate the Crude Supply Agreement and GEL agreed to automatically renew the Crude Supply Agreement at the end of the initial term for successive one year periods until August 2019, unless sooner terminated by GEL with 180 days prior written notice; and
Joint Marketing Agreement. Under the Joint Marketing Agreement, we, together with GEL, jointly market and sell certain output produced at the Nixon Facility and share the associated Gross Profits (as defined below) from such sales. Payments for the sale of certain output produced at the Nixon Facility are made directly to GEL as collection agent, and associated customers must satisfy GELs customer credit approval process. The Joint Marketing Agreement also provides for the sharing of Gross Profits (defined as the total revenue from the sale of certain output from the Nixon Facility minus the cost of crude oil and condensate pursuant to the Crude Supply Agreement). Key provisions of the Joint Marketing Agreement are as follows:
The Joint Marketing Agreement contains negative covenants that restrict our actions under certain circumstances. The Joint Marketing Agreement had an initial term of three years expiring in August 2014. In accordance with the terms of the October 2013 Letter Agreement, we agreed not to terminate the Joint Marketing Agreement and GEL agreed to automatically renew the Joint Marketing Agreement at the end of the initial term for successive one year periods until August 2019, unless sooner terminated by GEL with 180 days prior written notice.
Pursuant to a Letter Agreement Regarding Subordination of GEL Transaction Documents dated in June 2015, we, among other things, assigned our rights to payments under the Crude Supply Agreement and Joint Marketing Agreement as collateral in favor of Sovereign Bank, as lender and lienholder pursuant to the First Term Loan Due 2034. (See Note (9) Long-Term Debt, Net for further discussion related to the First Term Loan Due 2034.)
Genesis Contractual Dispute. LE currently has a contractual dispute with GEL related to the Joint Marketing Agreement and Crude Supply Agreement. (See Legal Matters below for a discussion of the current contractual dispute with Genesis.)
FLNG Master Easement Agreement. Pursuant to a Master Easement Agreement dated in December 2013, we provide FLNG Land II, Inc., a Delaware corporation (FLNG) with: (i) uninterrupted pedestrian and vehicular ingress and egress to and from State Highway 332, across certain of our property to certain property of FLNG (the Access Easement) and (ii) a pipeline easement and right of way across certain of our property to certain property owned by FLNG (the Pipeline Easement and together with the Access Easement, the Easements). Under the agreement, FLNG will make payments to us in the amount of $500,000 in October of each year through 2019. Thereafter, FLNG will make payments to us in the amount of $10,000 in October of each year for so long as FLNG desires to use the Access Easement.
Supplemental Pipeline Bonds. In July 2016, the Bureau of Ocean Energy Management (the BOEM) issued Notice to Lessees (NTL) No. 2016-N01 (Requiring Additional Security), which changes the way that lessees and rights-of-way holders demonstrate financial strength and reliability to plug and abandon wells, as well as decommission and remove platforms and pipelines at the end of production or service activities. The NTL, which changes an earlier supplemental waiver process to a self-insurance model, becomes effective in September 2016. Pursuant to the NTL, the BOEM has requested that lessees submit any relevant information needed for an overall financial review of the lessees account. The BOEM will use this information to evaluate a lessees ability to carry out its obligations and determine whether, and/or how much self-insurance a lessee can use.
In August 2015, we received a letter from the BOEM requiring additional supplemental bonds or acceptable financial assurance of approximately $4.2 million for existing pipeline rights-of-way. In light of the NTL, we are awaiting further direction from the BOEM to address financial assurance requirements. As of June 30, 2016 and December 31, 2015, we maintained approximately $0.9 million in credit and cash-backed rights-of-way bonds issued to the BOEM. There can be no assurance that the BOEM will accept a reduced amount of supplemental financial assurance or not require additional supplemental pipeline bonds related to our existing pipeline rights-of-way. If we are required by the BOEM to provide significant additional supplemental bonds or acceptable financial assurance, we may experience a significant and material adverse effect on our operations, liquidity, and financial condition.
Financing Agreements. (See Note (9) Long-Term Debt, Net for additional disclosures related to financing agreements.)
Nixon Facility Expansion. We have made and continue to make capital and efficiency improvements to the Nixon Facility. As a result, we have incurred and will continue to incur capital expenditures related to these improvements, which include, among other things, facility and land improvements and construction of additional petroleum storage tanks.
Legal Matters.
Genesis Contractual Dispute. As described above under Genesis Agreements, we are party to a variety of contracts and agreements with Genesis and its affiliates, including GEL that enable the purchase of crude oil and condensate, transportation of crude oil and condensate, and other services.
In May 2016, GEL filed, in state district court in Harris County, Texas, a petition and application for a temporary restraining order, temporary injunction, and permanent injunction (the Petition) against LE and LEH. The Petition alleges that LE breached the Joint Marketing Agreement, and that LEH tortiously interfered with the Joint Marketing Agreement, in connection with an agreement by LEH to supply jet fuel acquired from LE to a customer. The Petition primarily sought temporary and permanent injunctions related to sales of product from the Nixon Facility to this customer. In June 2016, the court issued a temporary injunction against LE and LEH as requested by GEL. LE believes that GELs claims in the Petition are without merit and intends to defend the matter vigorously.
In a matter separate from the above referenced Petition, LE filed a demand for arbitration in June 2016, pursuant to the terms of a Dispute Resolution Agreement between the parties (the Arbitration). The Arbitration alleges that GEL breached the Crude Supply Agreement related to:
With regard to the Petition, the next hearing date and a trial date have been set for August 22, 2016 and December 5, 2016, respectively, although the parties may elect arbitration. With respect to the Arbitration, a hearing date has not yet been set. We do not expect the temporary injunction issued by the court to have a material effect on our results of operations or financial condition. However, we are unable to predict the outcome of these proceedings or their ultimate impact, if any, on our business, financial condition or results of operations and, accordingly, have not recorded a liability on our consolidated balance sheet as of June 30, 2016.
Other Legal Matters. From time to time we are involved in routine lawsuits, claims, and proceedings incidental to the conduct of our business, including mechanics liens and administrative proceedings. Management does not believe that such matters will have a material adverse effect on our financial position, earnings, or cash flows.
Health, Safety and Environmental Matters. All of our operations and properties 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 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 greenhouse gas emissions. Our operations also require numerous permits and authorizations under various environmental, health, and safety laws and regulations. Failure to obtain and comply with these permits or environmental, health, or safety laws generally could result in fines, penalties or other sanctions, or a revocation of our permits. |
20. Subsequent Events |
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Subsequent Events [Abstract] | |
Subsequent Events | BDPL Credit Facility. On August 15, 2016, BDPL entered into a loan and security agreement as evidenced by a promissory note with LEH as lender, providing for a term loan to BDPL in the principal amount of $4.0 million (the BDPL Credit Facility). The BDPL Credit Facility matures in August 2018 and has an interest rate of 16%. Under the BDPL Credit Facility, BDPL will make payments of $500,000 per year from the annual payment received from FLNG under the FLNG Master Easement Agreement, with a final balloon payment due at the maturity date. Proceeds of the BDPL Credit Facility will primarily be used for working capital. The BDPL Credit Facility is secured by: (i) the remaining payments due from FLNG under the FLNG Master Easement Agreement and (ii) approximately 193 acres of land owned by BDPL in Freeport, Texas.
Financial Covenant Defaults. As of June 30, 2016, LE and LRM were in violation of the debt service coverage ratio, the current ratio, and debt to net worth ratio financial covenants under the First Term Loan Due 2034 and Second Term Loan Due 2034, respectively. Accordingly, the First Term Loan Due 2034 and Second Term Loan Due 2034 were classified within the current portion of long-term debt on our consolidated balance sheet as of June 30, 2016. On August 12, 2016, LE and LRM received a waiver from Sovereign of the financial covenant defaults related to the First Term Loan Due 2034 and Second Term Loan Due 2034, respectively, as of June 30, 2016. |
3. Significant Accounting Policies (Policies) |
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Use of Estimates | Use of Estimates. We have made a number of estimates and assumptions related to the reporting of our consolidated assets and liabilities and to the disclosure of contingent assets and liabilities to prepare these consolidated financial statements in conformity with GAAP. While we believe our current estimates are reasonable and appropriate, actual results could differ from those estimated. |
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Cash and Cash Equivalents | Cash and Cash Equivalents. Cash and cash equivalents represent liquid investments with an original maturity of three months or less. Cash balances are maintained in depository and overnight investment accounts with financial institutions that, at times, may exceed insured deposit limits. We monitor the financial condition of the financial institutions and have experienced no losses associated with these accounts. Cash and cash equivalents totaled $2,183,562 and $1,853,875 as of June 30, 2016 and December 31, 2015, respectively. |
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Restricted Cash | Restricted Cash. Total restricted cash was $12,139,773 and $18,791,777 as of June 30, 2016 and December 31, 2015, respectively. Total restricted cash was comprised of restricted cash (current portion), which totaled $4,186,150 and $3,175,299 as of June 30, 2016 and December 31, 2015, respectively and restricted cash, noncurrent, which totaled $7,953,623 and $15,616,478 as of June 30, 2016 and December 31, 2015, respectively. Restricted cash (current portion) primarily represents: (i) amounts held in our disbursement account with Sovereign attributable to construction invoices awaiting payment from that account, (ii) a payment reserve account held by Sovereign as security for payments under a loan agreement, and(iii) a construction contingency account under which Sovereign will fund contingencies. Restricted cash, noncurrent represents funds held in the Sovereign disbursement account for payment of future construction related expenses to build new petroleum storage tanks. (See Note (9) Long-Term Debt, Net for additional disclosures related to our loan agreements with Sovereign.) |
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Accounts Receivable and Allowance for Doubtful Accounts | Accounts Receivable and Allowance for Doubtful Accounts. Accounts receivable are customer obligations due under normal trade terms. The allowance for doubtful accounts represents our estimate of the amount of probable credit losses existing in our accounts receivable. We have a limited number of customers with individually large amounts due on any given date. Any unanticipated change in any one of these customers credit worthiness or other matters affecting the collectability of amounts due from such customers could have a material adverse effect on our results of operations in the period in which such changes or events occur. We regularly review all of our aged accounts receivable for collectability and establish an allowance for individual customer balances as necessary. Allowance for doubtful accounts totaled $0 and $139,868 as of June 30, 2016 and December 31, 2015, respectively. |
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Inventory | Inventory. The nature of our business requires us to maintain inventory, which primarily consists of refined petroleum products and chemicals. Our overall inventory is valued at lower of cost or market with costs being determined by the average cost method. If the market value of our refined petroleum product inventories declines to an amount less than our average cost, we record a write-down of inventory and an associated adjustment to cost of refined products sold. (See Note (6) Inventory for additional disclosures related to our inventory.) |
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Derivatives | Derivatives. We are exposed to commodity prices and other market risks including gains and losses on certain financial assets as a result of our inventory risk management policy. Under our inventory risk management policy, commodity futures contracts may be used to mitigate the change in value for certain of our refined petroleum product inventories subject to market price fluctuations. The physical inventory volumes are not exchanged and these contracts are net settled with cash.
Although these commodity futures contracts are not subject to hedge accounting treatment under Financial Accounting Standards Board (the FASB) Accounting Standards Codification (ASC) guidance, we record the fair value of these hedges in our consolidated balance sheet each financial reporting period because of contractual arrangements under which we are effectively exposed to the potential gains or losses. We recognize all commodity hedge positions as either current assets or current liabilities in our consolidated balance sheets, and those instruments are measured at fair value. Changes in the fair value from financial reporting period to financial reporting period are recognized in our consolidated statements of operations. Net gains or losses associated with these transactions are recognized within cost of refined products sold in our consolidated statements of operations using mark-to-market accounting.
(See Note (17) Fair Value Measurement and Note (18) Inventory Risk Management for additional disclosures related to derivatives.) |
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Property and Equipment | Property and Equipment.
Refinery and Facilities. Additions to refinery and facilities assets are capitalized. Expenditures for repairs and maintenance are expensed as incurred and are included as operating expenses under the Operating Agreement. Management expects to continue making improvements to the Nixon Facility based on technological advances.
We record refinery and facilities at cost less any adjustments for depreciation or impairment. Adjustment of the asset and the related accumulated depreciation accounts are made for the refinery and facilities assets retirement and disposal, with the resulting gain or loss included in the consolidated statements of operations. For financial reporting purposes, depreciation of refinery and facilities assets is computed using the straight-line method using an estimated useful life of 25 years beginning when the refinery and facilities assets are placed in service. We did not record any impairment of our refinery and facilities assets for any period presented.
Pipelines and Facilities. We record pipelines and facilities at cost less any adjustments for depreciation or impairment. Depreciation is computed using the straight-line method over estimated useful lives ranging from 10 to 22 years. In accordance with FASB ASC guidance on accounting for the impairment or disposal of long-lived assets, we periodically evaluate our long-lived assets for impairment. Additionally, we evaluate our long-lived assets when events or circumstances indicate that the carrying value of these assets may not be recoverable.
Oil and Gas Properties. We account for our oil and gas properties using the full-cost method of accounting, whereby all costs associated with acquisition, exploration and development of oil and gas properties, including directly related internal costs, are capitalized on a cost center basis. Amortization of such costs and estimated future development costs are determined using the unit-of-production method. Our oil and gas properties had no production during the three and six months ended June 30, 2016 and 2015. All leases associated with our oil and gas properties have expired, and our oil and gas properties were fully impaired as of December 31, 2012.
Construction in Progress. Construction in progress expenditures, which relate to construction and refurbishment activities at the Nixon Facility, are capitalized as incurred. Depreciation begins once the asset is placed in service.
(See Note (7) Property, Plant and Equipment, Net for additional disclosures related to our refinery and facilities assets, oil and gas properties, pipelines and facilities assets, and construction in progress.) |
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Intangibles - Other | Intangibles Other. We have an intangible asset consisting of the Blue Dolphin Energy Company trade name in the amount of $303,346 on our consolidated balance sheets as of June 30, 2016 and December 31, 2015. We have determined the trade name to have an indefinite useful life. We account for other intangible assets under FASB ASC guidance related to intangibles, goodwill, and other. Under the guidance, we test intangible assets with indefinite lives annually for impairment. Management performed its regular annual impairment testing of trade name in the fourth quarter of 2015. Upon completion of that testing, we determined that no impairment was necessary as of December 31, 2015. |
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Revenue Recognition | Revenue Recognition.
Refined Petroleum Products Revenue. Jet fuel,our only finished product, is sold in nearby markets to wholesalers. Our intermediate products, including LPG, naphtha, HOBM, and AGO, are primarily sold in nearby markets to wholesalers and refiners for further blending and processing. Revenue from refined petroleum products sales is recognized when sales prices are fixed or determinable, collectability is reasonably assured, and title passes. Title passage occurs when refined petroleum products are delivered in accordance with the terms of the respective sales agreements, and customers assume the risk of loss when title is transferred. Transportation, shipping, and handling costs incurred are included in cost of refined products sold. Excise and other taxes that are collected from customers and remitted to governmental authorities are not included in revenue.
Tank Rental Revenue. Tank rental fees are invoiced monthly in accordance with the terms of the related lease agreement and recognized in revenue as earned.
Easement Revenue. Land easement revenue is recognized monthly as earned and is included in other income.
Pipeline Transportation Revenue. Revenue from our pipeline operations is derived from fee-based contracts and is typically based on transportation fees per unit of volume transported multiplied by the volume delivered. Revenue is recognized when volumes have been physically delivered for the customer through the pipeline.
Deferred Revenue. In 2014, we increased the ownership interest in our pipeline assets from approximately 83% to 100% pursuant to an Asset Sale Agreement (the Purchase Agreement) with a former partner. Pursuant to the Purchase Agreement, the former partner paid us $100,000 in cash, and a surety company $850,000 in cash as collateral for supplemental pipeline bonds for our benefit in exchange for the payment and discharge of any and all payables, claims, and obligations related to the pipeline assets. We recorded the amount received for our benefit related to the supplemental pipeline bonds as deferred revenue. We recognized the deferred revenue on a straight-line basis through December 31, 2018, the expected retirement date of the associated assets. In 2015, a significant portion of the remaining deferred revenue was recognized as a result of abandoning a segment of the pipeline assets. (See Part I, Business Governmental Regulation Offshore Safety and Environmental Oversight Decommissioning Requirements in our Annual Report for a discussion related to supplemental pipeline bonds.) |
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Income Taxes | Income Taxes. We account for income taxes under FASB ASC guidance related to income taxes, which requires recognition of income taxes based on amounts payable with respect to the current three and six month periods and the effects of deferred taxes for the expected future tax consequences of events that have been included in our financial statements or tax returns. Under this method, deferred tax assets and liabilities are determined based on the differences between the financial accounting and tax basis of assets and liabilities, as well as for operating losses and tax credit carryforwards using enacted tax rates in effect for the year in which the differences are expected to reverse.
As of each reporting date, management considers new evidence, both positive and negative, to determine the realizability of deferred tax assets. Management considers whether it is more likely than not that a portion or all of the deferred tax assets will be realized, which is dependent upon the generation of future taxable income prior to the expiration of any net operating loss (NOL) carryforwards. When management determines that it is more likely than not that a tax benefit will not be realized, a valuation allowance is recorded to reduce deferred tax assets.
The guidance also prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return, as well as guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosures, and transition.
(See Note (15) Income Taxes for further information related to income taxes.) |
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Impairment or Disposal of Long-Lived Assets | Impairment or Disposal of Long-Lived Assets. In accordance with FASB ASC guidance on accounting for the impairment or disposal of long-lived assets, we periodically evaluate our long-lived assets for impairment. Additionally, we evaluate our long-lived assets when events or circumstances indicate that the carrying value of these assets may not be recoverable. The carrying value is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset or group of assets. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount by which the carrying value exceeds the fair value of the asset or group of assets is recognized. Significant management judgment is required in the forecasting of future operating results that are used in the preparation of projected cash flows and, should different conditions prevail or judgments be made, material impairment charges could be necessary. |
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Asset Retirement Obligations | Asset Retirement Obligations. FASB ASC guidance related to asset retirement obligations (AROs) requires that a liability for the discounted fair value of an ARO be recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted towards its future value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized.
Management has concluded that there is no legal or contractual obligation to dismantle or remove the refinery and facilities assets. Further, management believes that these 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 the 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.
We recorded an ARO liability related to future asset retirement costs associated with dismantling, relocating, or disposing of our offshore platform, pipeline systems, and related onshore facilities, as well as for plugging and abandoning wells and restoring land and sea beds. We developed these cost estimates for each of our assets based upon regulatory requirements, structural makeup, water depth, reservoir characteristics, reservoir depth, equipment demand, current retirement procedures, and construction and engineering consultations. Because these costs typically extend many years into the future, estimating future costs are difficult and require management to make judgments that are subject to future revisions based upon numerous factors, including changing technology, political, and regulatory environments. We review our assumptions and estimates of future abandonment costs on an annual basis.
(See Note (11) Asset Retirement Obligations for additional information related to our AROs.) |
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Computation of Earnings Per Share | Computation of Earnings Per Share. We apply the provisions of FASB ASC guidance for computing earnings per share (EPS). The guidance requires the presentation of basic EPS, which excludes dilution and is computed by dividing net income available to common stockholders by the weighted-average number of shares of common stock outstanding for the period. The guidance requires dual presentation of basic EPS and diluted EPS on the face of our consolidated statements of operations and requires a reconciliation of the numerators and denominators of basic EPS and diluted EPS. Diluted EPS is computed by dividing net income available to common stockholders by the diluted weighted average number of common shares outstanding, which includes the potential dilution that could occur if securities or other contracts to issue shares of common stock were converted to common stock that then shared in the earnings of the entity.
The number of shares related to options, warrants, restricted stock, and similar instruments included in diluted EPS is based on the Treasury Stock Method prescribed in FASB ASC guidance for computation of EPS. This method assumes theoretical repurchase of shares using proceeds of the respective stock option or warrant exercised, and, for restricted stock, the amount of compensation cost attributed to future services that has not yet been recognized and the amount of any current and deferred tax benefit that would be credited to additional paid-in-capital upon the vesting of the restricted stock, at a price equal to the issuers average stock price during the related earnings period. Accordingly, the number of shares includable in the calculation of EPS in respect of the stock options, warrants, restricted stock, and similar instruments is dependent on this average stock price and will increase as the average stock price increases. (See Note (16) Earnings Per Share for additional information related to EPS.) |
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Stock-Based Compensation | Stock-Based Compensation. In accordance with FASB ASC guidance for stock-based compensation, share-based payments to directors, including the issuance of restricted common stock, are measured at fair value as of the date of grant and are expensed in our consolidated statements of operations over the service period (generally the vesting period). |
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Treasury Stock | Treasury Stock. We account for treasury stock under the cost method. When treasury stock is re-issued, the net change in share price subsequent to acquisition of the treasury stock is recognized as a component of additional paid-in-capital in our consolidated balance sheets. (See Note (12) Treasury Stock for additional disclosures related to treasury stock.) |
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New Pronouncements Adopted | New Pronouncements Adopted. The FASB issues an Accounting Standards Update (ASU) to communicate changes to the FASB ASC, including changes to non-authoritative SEC content. For the three and six months ended June 30, 2016, we adopted the following recently issued ASUs:
ASU 2015-17,Income Taxes (Topic 740). In November 2015, FASB issued ASU 2015-17. This guidance simplifies the presentation of deferred income taxes by requiring that deferred tax liabilities and assets be classified as noncurrent instead of separated into current and noncurrent. We adopted this accounting pronouncement effective April 1, 2016. Accordingly, our consolidated balance sheet as of December 31, 2015 has been changed to reclassify approximately $3.5 million previously reported as deferred tax assets, current portion, net to deferred tax assets, net. The adoption of ASU 2015-17 had no impact on our results of operations or cash flows.
ASU 2015-03, Imputation of Interest (Topic 835): Simplifying the Presentation of Debt Issuance Costs. In April 2015, FASB issued ASU 2015-03. This guidance requires debt issue costs to be presented as an offset to their related debt. We adopted this accounting pronouncement effective January 1, 2016. Accordingly, our consolidated balance sheet as of December 31, 2015 has been changed to reclassify approximately $2.4 million previously reported as debt issue costs as a direct deduction of long-term debt. The adoption of ASU 2015-03 had no impact on our results of operations or cash flows. |
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New Pronouncements Issued but Not Yet Effective | New Pronouncements Issued But Not Yet Effective. The following are recently issued, but not yet effective, ASUs that may have an effect on our consolidated financial position, results of operations, or cash flows:
ASU 2016-13,Financial Instruments Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments). In June 2016, FASB issued ASU 2016-13. This guidance updates the current impairment model to incorporate both expected and incurred credit losses, eliminating potential overstatements of assets and resulting in more timely recognition of losses. For a public business entity, the amendments in ASU 2016-13 are effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. Early application as of the fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, is permitted. We are evaluating the impact that adoption of this guidance will have on our consolidated financial statements.
ASU 2016-02,Leases (Topic 842). In February 2016, FASB issued ASU 2016-02. This guidance increases transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. For a public business entity, the amendments in ASU 2016-02 are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early application is permitted. We are evaluating the impact that adoption of this guidance will have on our consolidated balance sheets.
ASU 2015-11,Inventory(Topic 330):Simplifying the Measurement of Inventory. In July 2015, FASB issued ASU 2015-11. Current guidance requires an entity to measure inventory at the lower of cost or market. Market could be replacement cost, net realizable value, or net realizable value less an approximately normal profit margin. Under ASU 2015-11, an entity should measure inventory at the lower of cost or net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. Amendments under ASU 2015-11 more closely align the measurement of inventory in GAAP with the measurement of inventory in International Financial Reporting Standards. For public business entities, ASU 2015-11 is effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. ASU 2015-11 should be applied prospectively with earlier application permitted as of the beginning of an interim or annual reporting period. We do not anticipate adoption of this guidance to have a material effect on our consolidated financial statements.
ASU 2014-15, Disclosure of Uncertainties about an Entitys Ability to Continue as a Going Concern (Subtopic 205-40). In August 2014, FASB issued ASU 2014-15, which requires management to perform interim and annual assessments of an entitys ability to continue as a going concern for a one-year period subsequent to the date of the financial statements. An entity must provide certain disclosures if conditions or events raise substantial doubt about the entitys ability to continue as a going concern. The guidance is effective for all entities for the first annual period ending after December 15, 2016 and interim periods thereafter, with early adoption permitted. We do not anticipate adoption of this guidance to have a material effect on our consolidated financial statements.
ASU 2014-09,Revenue from Contracts with Customers (Topic 606). In May 2014, FASB and the International Accounting Standards Board (the IASB) issued ASU 2014-09, a converged standard on recognition of revenue from contracts with customers. In June 2014, the FASB and the IASB (collectively, the Accounting Boards) formed the FASB-IASB Joint Transition Resource Group for Revenue Recognition (the TRG). The primary objective of the TRG is to inform the Accounting Boards about potential implementation issues that could arise when organizations implement the new revenue guidance. Resultant ASUs as part of the TRG process include:
We are evaluating the impact that adoption of ASU 2014-09, ASU 2015-14, ASU 2016-08, ASU 2016-10, ASU 2016-11, and 2016-12, all of which relate to Revenue from Contracts with Customers (Topic 606), will have on our consolidated financial statements.
Other new pronouncements issued but not effective until after June 30, 2016 are not expected to have a material impact on our financial position, results of operations, or liquidity. |
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Reclassification | Reclassification. We have reclassified certain prior year amounts to conform to our 2016 presentation. |
4. Business Segment Information (Tables) |
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Segment Reporting [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Business segment reporting | Business segment information for the periods indicated (and as of the dates indicated), was as follows:
Business segment information for the periods indicated (and as of the dates indicated), was as follows:
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5. Prepaid Expenses and Other Current Assets (Tables) |
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Prepaid balances | Prepaid expenses and other current assets as of the dates indicated consisted of the following:
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6. Inventory (Tables) |
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Inventory | Inventory as of the dates indicated consisted of the following:
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7. Property, Plant and Equipment, Net (Tables) |
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Property and equipment | Property, plant and equipment, net, as of the dates indicated consisted of the following:
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8. Accounts Payable, Related Party (Tables) |
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Accounts Payable, Related Party | Accounts payable, related party as of the dates indicated consisted of the following:
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9. Long-Term Debt, Net (Tables) |
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Long Term Debt | Long-term debt, net, which represents the outstanding principal and interest of long-term debt less associated debt issue costs, as of the dates indicated consisted of the following:
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Accrued interest related to our long-term debt, net | Accrued interest related to our long-term debt, net (reflected as interest payable, current portion and long-term interest payable, net of current portion in our consolidated balance sheets) as of the dates indicated consisted of the following:
|
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Schedule of summary of equipment held under long-term capital leases | A summary of equipment held under long-term capital leases as of the dates indicated follows:
|
10. Accrued Expenses and Other Current Liabilities (Tables) |
6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2016 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Disclosure Text Block Supplement [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Accrued expenses and other current liabilities | Accrued expenses and other current liabilities as of the dates indicated consisted of the following:
|
11. Asset Retirement Obligations (Tables) |
6 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Jun. 30, 2016 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Asset Retirement Obligation Disclosure [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Asset retirement obligations | Changes to our ARO liability for the periods indicated were as follows:
|
13. Concentration of Risk (Tables) |
6 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2016 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Risks and Uncertainties [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Percentages of all refined petroleum products sales to total sales | Total refined petroleum product sales by distillation (from light to heavy) for the periods indicated consisted of the following:
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15. Income Taxes (Tables) |
6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2016 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Income Tax Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Income tax benefit (expense) | Income Tax Benefit (Expense). Income tax benefit (expense) for the periods indicated consisted of the following:
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NOL carryforwards | NOL carryforwards that remained available for future use for the periods indicated were as follow (amounts shown are net of NOLs that will expire unused as a result of the IRC Section 382 limitation):
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Deferred tax assets and deferred tax liabilities | Significant components of deferred tax assets and liabilities as of the dates indicated were as follow:
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16. Earnings Per Share (Tables) |
6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2016 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Earnings Per Share [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Earnings per share | A reconciliation between basic and diluted income per share for the periods indicated was as follows:
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17. Fair Value Measurement (Tables) |
6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2016 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair Value Disclosures [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair Value Measurement | The following table represents our assets and liabilities measured at fair value on a recurring basis as of June 30, 2016 and December 31, 2015 and the basis for the measurement:
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18. Inventory Risk Management (Tables) |
6 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2016 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Derivative Instruments and Hedging Activities Disclosure [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Notional volume of outstanding contracts by type of instrument | The information presents the notional volume of open commodity instruments by type and year of maturity (volumes in bbls):
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Fair value amounts of derivative instruments | The following table provides the location and fair value amounts of derivative instruments that are reported in our consolidated balance sheets as of June 30, 2016 and December 31, 2015:
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Effect of derivative instruments | The following table provides the effect of derivative instruments in our consolidated statements of operations for the three and six months ended June 30, 2016 and 2015:
|
1. Organization (Details Narrative) - USD ($) |
Jun. 30, 2016 |
Dec. 31, 2015 |
Jun. 30, 2015 |
Dec. 31, 2014 |
---|---|---|---|---|
Organization, Consolidation and Presentation of Financial Statements [Abstract] | ||||
Cash and cash equivalents | $ 2,183,562 | $ 1,853,875 | $ 2,508,514 | $ 1,293,233 |
Restricted cash (current portion) | 4,186,150 | 3,175,299 | ||
Current assets | 26,291,337 | 19,629,841 | ||
Current liabilities | 67,037,594 | $ 20,228,648 | ||
Working capital deficit current portion | 40,746,257 | |||
Working capital deficit payment of Operations | $ 8,195,017 |
3. Significant Accounting Policies (Details Narrative) - USD ($) |
Jun. 30, 2016 |
Dec. 31, 2015 |
Jun. 30, 2015 |
Dec. 31, 2014 |
---|---|---|---|---|
Accounting Policies [Abstract] | ||||
Cash and cash equivalents | $ 2,183,562 | $ 1,853,875 | $ 2,508,514 | $ 1,293,233 |
Restricted cash | 12,139,773 | 18,791,777 | ||
Restricted cash (current portion) | 4,186,150 | 3,175,299 | ||
Restricted cash, noncurrent | 7,953,623 | 15,616,478 | ||
Allowance for doubtful accounts | 0 | 139,868 | ||
Trade name | $ 303,346 | 303,346 | ||
Deferred tax assets | 3,500,000 | |||
Debt issue costs | $ 2,400,000 |
4. Business Segment Information (Details) - USD ($) |
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2016 |
Jun. 30, 2015 |
Jun. 30, 2016 |
Jun. 30, 2015 |
|
Revenue from operations | $ 42,042,460 | $ 59,161,614 | $ 73,554,736 | $ 120,553,963 |
Income tax benefit (expense) | (1,534,341) | 100,729 | (2,700,242) | 2,090,347 |
Net income (loss) | (3,162,736) | 137,879 | (5,311,820) | 3,839,243 |
Refinery Operations [Member] | ||||
Revenue from operations | 42,017,773 | 59,126,052 | 73,502,397 | 120,480,006 |
Less: cost of operations | (45,534,109) | (56,504,401) | (79,956,962) | (108,763,871) |
Other non-interest income | ||||
Adjusted EBITDA | (3,516,336) | 2,621,651 | (6,454,565) | 11,716,135 |
Less: JMA Profit Share | (97,527) | (938,661) | 573,565 | (3,377,298) |
EBITDA | (3,613,863) | 1,682,990 | (5,881,000) | 8,338,837 |
Capital expenditures | 3,433,333 | 4,967,579 | 7,072,978 | 6,259,494 |
Identifiable assets | 93,402,963 | 73,643,964 | 93,402,963 | 73,643,964 |
Pipeline Transportation [Member] | ||||
Revenue from operations | 24,687 | 35,562 | 52,339 | 73,957 |
Less: cost of operations | (131,836) | (127,704) | (253,964) | (181,616) |
Other non-interest income | 125,000 | 62,500 | 255,665 | 125,000 |
Adjusted EBITDA | 17,851 | (29,642) | 54,040 | 17,341 |
Less: JMA Profit Share | ||||
EBITDA | 17,851 | (29,642) | 54,040 | 17,341 |
Capital expenditures | ||||
Identifiable assets | 1,867,687 | 2,788,381 | 1,867,687 | 2,788,381 |
Corporate and Other [Member] | ||||
Revenue from operations | ||||
Less: cost of operations | (232,256) | (283,467) | (457,031) | (691,515) |
Other non-interest income | ||||
Adjusted EBITDA | (232,256) | (283,467) | (457,031) | (691,515) |
Less: JMA Profit Share | ||||
EBITDA | (232,256) | (283,467) | (457,031) | (691,515) |
Capital expenditures | ||||
Identifiable assets | 3,892,504 | 4,046,157 | 3,892,504 | 4,046,157 |
Total | ||||
Revenue from operations | 42,042,460 | 59,161,614 | 73,554,736 | 120,553,963 |
Less: cost of operations | (45,898,201) | (56,915,572) | (80,667,957) | (109,637,002) |
Other non-interest income | 125,000 | 62,500 | 255,665 | 125,000 |
Adjusted EBITDA | (3,730,741) | 2,308,542 | (6,857,556) | 11,041,961 |
Less: JMA Profit Share | (97,527) | (938,661) | 573,565 | (3,377,298) |
Depletion, depreciation and amortization | (470,347) | (402,937) | (910,800) | (802,168) |
Interest expense, net | (398,462) | (728,336) | (817,271) | (932,905) |
Income (loss) before income taxes | (4,697,077) | 238,608 | (8,012,062) | 5,929,590 |
Income tax benefit (expense) | 1,534,341 | (100,729) | 2,700,242 | (2,090,347) |
Net income (loss) | (3,162,736) | 137,879 | (5,311,820) | 3,839,243 |
Capital expenditures | 3,433,333 | 4,967,579 | 7,072,978 | 6,259,494 |
Identifiable assets | $ 99,163,154 | $ 80,478,502 | $ 99,163,154 | $ 80,478,502 |
5. Prepaid Expenses and Other Current Assets (Details) - USD ($) |
Jun. 30, 2016 |
Dec. 31, 2015 |
---|---|---|
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract] | ||
Prepaid related party operating expenses | $ 402,671 | $ 624,570 |
Prepaid insurance | 231,518 | 315,120 |
Unrealized hedging gains | 201,950 | |
Prepaid listing fees | 7,500 | |
Prepaid expenses, net | $ 843,639 | $ 939,690 |
6. Inventory (Details) - USD ($) |
Jun. 30, 2016 |
Dec. 31, 2015 |
---|---|---|
Inventory Disclosure [Abstract] | ||
HOBM | $ 6,382,469 | $ 5,007,576 |
Jet fuel | 1,438,134 | 2,045,784 |
Crude oil and condensate | 936,301 | 19,041 |
Naphtha | 333,627 | 309,850 |
AGO | 288,707 | 278,278 |
Chemicals | 282,562 | 122,777 |
Propane | 17,299 | 17,860 |
LPG mix | 5,022 | 7,152 |
Inventories, net | $ 9,684,121 | $ 7,808,318 |
7. Property, Plant and Equipment, Net (Details) - USD ($) |
Jun. 30, 2016 |
Dec. 31, 2015 |
---|---|---|
Property, Plant and Equipment [Abstract] | ||
Refinery and facilities | $ 47,660,502 | $ 40,195,928 |
Pipelines and facilities | 2,127,207 | 2,127,207 |
Onshore separation and handling facilities | 325,435 | 325,435 |
Land | 602,938 | 602,938 |
Other property and equipment | 652,795 | 644,795 |
Property, Plant and Equipment, Gross | 51,368,877 | 43,896,303 |
Less: Accumulated depletion, depreciation and amortization | 7,144,961 | (6,234,161) |
Property, plant and equipment, gross | 44,223,916 | 37,662,142 |
Construction in progress | 13,373,453 | 11,179,670 |
Property, plant and equipment, net | $ 57,597,369 | $ 48,841,812 |
8. Property, Plant and Equipment, Net (Details Narrative) - USD ($) |
6 Months Ended | 12 Months Ended |
---|---|---|
Jun. 30, 2016 |
Dec. 31, 2015 |
|
Property, Plant and Equipment [Abstract] | ||
Interest cost capitalized | $ 1,363,536 | $ 556,032 |
8. Accounts Payable, Related Party (Details) - USD ($) |
Jun. 30, 2016 |
Dec. 31, 2015 |
---|---|---|
Accounts payable, related party | $ 861,963 | $ 300,000 |
Ingleside [Member] | ||
Accounts payable, related party | 554,389 | 300,000 |
Jonathan Carroll [Member] | ||
Accounts payable, related party | $ 307,574 |
8. Accounts Payable, Related Party (Details Narrative) - USD ($) |
3 Months Ended | 6 Months Ended | |||
---|---|---|---|---|---|
Jun. 30, 2016 |
Jun. 30, 2015 |
Jun. 30, 2016 |
Jun. 30, 2015 |
Dec. 31, 2015 |
|
Expense for service | $ 450,000 | $ 0 | $ 725,000 | $ 0 | |
Prepaid related party operating expenses | 402,671 | 402,671 | $ 624,570 | ||
Accounts payable, related party | 861,963 | 861,963 | $ 300,000 | ||
LEH [Member] | |||||
Expense for service | 2,427,748 | 2,586,151 | 5,589,763 | 5,467,122 | |
Sales to LEH totaled | 8,912,074 | 0 | 8,912,074 | 0 | |
Services Agreement Fees | $ 324,000 | $ 0 | $ 324,000 | $ 0 |
9. Long-Term Debt, Net (Details 1) - USD ($) |
Jun. 30, 2016 |
Dec. 31, 2015 |
---|---|---|
Debt Disclosure [Abstract] | ||
Notre Dame Debt | $ 1,586,522 | $ 1,482,801 |
Second Term Loan Due 2034 | 42,610 | 39,193 |
First Term Loan Due 2034 | 32,226 | 34,883 |
Capital leases | 1,894 | 2,612 |
Term Loan Due 2017 | 463 | 4,779 |
Total | 1,663,715 | 1,564,268 |
Less: Interest payable, current portion | (77,193) | (81,467) |
Long term debt | $ 1,586,522 | $ 1,482,801 |
9. Long-Term Debt, Net (Details 2) - USD ($) |
Jun. 30, 2016 |
Dec. 31, 2015 |
---|---|---|
Debt Disclosure [Abstract] | ||
Boiler equipment | $ 538,598 | $ 538,598 |
Less: accumulated depreciation | ||
Capital lease obligation | $ 538,598 | $ 538,598 |
9. Long-Term Debt, Net (Details Narrative) - USD ($) |
3 Months Ended | 6 Months Ended | |||
---|---|---|---|---|---|
Jun. 30, 2016 |
Jun. 30, 2015 |
Jun. 30, 2016 |
Jun. 30, 2015 |
Dec. 31, 2015 |
|
Principal balance outstanding | $ 1,349,324 | $ 1,349,324 | $ 32,846,254 | ||
Term Loan Due 2017 [Member] | |||||
Guaranty fees | 3,083 | $ 0 | 7,091 | $ 0 | |
Second Term Loan Due 2034 [Member] | |||||
Interest accrued | 74,111 | 74,111 | |||
Principal balance outstanding | 1,000,000 | 1,000,000 | |||
Guaranty fees | 49,420 | 0 | 99,168 | 0 | |
First Term Loan Due 2034 [Member] | |||||
Guaranty fees | $ 121,739 | $ 0 | $ 0 | $ 244,372 |
10. Accrued Expenses and Other Current Liabilities (Details) - USD ($) |
Jun. 30, 2016 |
Dec. 31, 2015 |
---|---|---|
Disclosure Text Block Supplement [Abstract] | ||
Unearned revenue | $ 332,055 | $ 781,859 |
Excise and income taxes payable | 273,735 | 1,290,101 |
Other payable | 152,914 | 157,714 |
Transportation and inspection | 123,337 | |
Board of director fees payable | 101,429 | 86,429 |
Property taxes | 61,178 | |
Insurance | 25,756 | 103,024 |
Inspection fees | 17,250 | |
Genesis JMA Profit Share payable | 388,364 | |
Unrealized hedging loss | 183,400 | |
Accrued Expenses and Other Current Liabilities, Net | $ 1,087,654 | $ 2,990,891 |
11. Asset Retirement Obligations (Details) - USD ($) |
3 Months Ended | 6 Months Ended | 12 Months Ended | ||
---|---|---|---|---|---|
Jun. 30, 2016 |
Jun. 30, 2015 |
Jun. 30, 2016 |
Jun. 30, 2015 |
Dec. 31, 2015 |
|
Asset Retirement Obligation Disclosure [Abstract] | |||||
Asset retirement obligations, at the beginning of the period | $ 1,985,864 | $ 1,866,770 | $ 1,866,770 | ||
New asset retirement obligations and adjustments | 49 | ||||
Liabilities settled | (59,247) | (92,330) | |||
Accretion expense | $ 28,186 | $ 52,720 | 56,372 | $ 105,935 | 211,375 |
Asset retirement obligations | 1,982,989 | 1,982,989 | 1,985,864 | ||
Less: asset retirement obligations, current portion | (26,399) | (26,399) | (38,644) | ||
Long-term asset retirement obligations, at the end of the period | $ 1,956,590 | $ 1,956,590 | $ 1,947,220 |
11. Asset Retirement Obligations (Details Narrative) - USD ($) |
3 Months Ended | 6 Months Ended | 12 Months Ended | ||
---|---|---|---|---|---|
Jun. 30, 2016 |
Jun. 30, 2015 |
Jun. 30, 2016 |
Jun. 30, 2015 |
Dec. 31, 2015 |
|
Asset Retirement Obligation Disclosure [Abstract] | |||||
Liabilities settled recognized | $ 59,247 | $ 92,330 | |||
Abandonment expense | $ 0 | $ 0 | $ 0 | $ 0 |
12. Treasury Stock (Details Narrative) - shares |
Jun. 30, 2016 |
Dec. 31, 2015 |
---|---|---|
Equity [Abstract] | ||
Treasury stock | 150,000 | 150,000 |
13. Concentration of Risk (Details) - USD ($) |
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2016 |
Jun. 30, 2015 |
Jun. 30, 2016 |
Jun. 30, 2015 |
|
Total refined petroleum product sales | $ 41,402,286 | $ 58,839,160 | $ 72,595,423 | $ 119,906,222 |
Concentration Risk | 100.00% | 100.00% | 100.00% | 100.00% |
LPG mix | ||||
Total refined petroleum product sales | $ 133,757 | $ 234,184 | $ 384,304 | $ 291,492 |
Concentration Risk | 0.30% | 0.40% | 0.80% | 0.20% |
Naphtha | ||||
Total refined petroleum product sales | $ 7,287,804 | $ 13,413,484 | $ 16,313,325 | $ 26,829,683 |
Concentration Risk | 17.60% | 22.70% | 28.90% | 22.40% |
Jet Fuel | ||||
Total refined petroleum product sales | $ 17,539,473 | $ 17,411,470 | $ 26,045,786 | $ 33,930,973 |
Concentration Risk | 42.40% | 29.60% | 27.30% | 28.30% |
HOBM | ||||
Total refined petroleum product sales | $ 7,889,499 | $ 13,622,360 | $ 11,052,994 | $ 31,031,439 |
Concentration Risk | 19.10% | 23.20% | 10.10% | 25.90% |
Reduced crude | ||||
Total refined petroleum product sales | $ 546,112 | $ 3,791,919 | ||
Concentration Risk | 1.30% | 0.00% | 10.40% | 0.00% |
AGO | ||||
Total refined petroleum product sales | $ 8,005,641 | $ 14,157,662 | $ 15,007,095 | $ 27,822,635 |
Concentration Risk | 19.30% | 24.10% | 22.50% | 23.20% |
13. Concentration of Risk (Details Narrative) - USD ($) |
3 Months Ended | 6 Months Ended | |||
---|---|---|---|---|---|
Jun. 30, 2016 |
Jun. 30, 2015 |
Jun. 30, 2016 |
Jun. 30, 2015 |
Dec. 31, 2015 |
|
Concentration Risk | 100.00% | 100.00% | 100.00% | 100.00% | |
FDIC insurance limit | $ 250,000 | ||||
Excess of the FDIC insurance limit | $ 13,716,774 | $ 13,716,774 | $ 19,594,883 | ||
Account receivable [Member] | Five customers [Member] | |||||
Concentration Risk | 82.00% | ||||
Concentration risk accounts receivable | $ 5,200,000 | $ 5,200,000 | |||
Account receivable [Member] | Three customers [Member] | |||||
Concentration Risk | 58.00% | ||||
Sales Revenue [Member] | Five customers [Member] | |||||
Concentration Risk | 75.40% | ||||
Sales Revenue [Member] | Four customers [Member] | |||||
Concentration Risk | 71.00% | 64.00% | |||
Concentration risk accounts receivable | $ 6,200,000 | $ 6,200,000 | |||
Sales Revenue [Member] | Three customers [Member] | |||||
Concentration risk accounts receivable | $ 3,200,000 | $ 3,200,000 |
14. Leases (Details Narrative) - USD ($) |
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2016 |
Jun. 30, 2015 |
Jun. 30, 2016 |
Jun. 30, 2015 |
|
Leases, Operating [Abstract] | ||||
Rent expense | $ 29,857 | $ 57,060 | $ 59,715 | $ 82,889 |
15. Income Taxes (Details) - USD ($) |
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2016 |
Jun. 30, 2015 |
Jun. 30, 2016 |
Jun. 30, 2015 |
|
Current: | ||||
Federal | $ 14,038 | $ (85,242) | ||
State | (29,701) | (112,554) | ||
Deferred: | ||||
Federal | 1,534,341 | (85,066) | 2,653,721 | (1,892,551) |
Income tax benefit (expense) | $ 1,534,341 | $ (100,729) | $ 2,653,721 | $ (2,090,347) |
15. Income Taxes (Details 2) - USD ($) |
3 Months Ended | 12 Months Ended | |
---|---|---|---|
Jun. 30, 2016 |
Mar. 31, 2016 |
Dec. 31, 2015 |
|
Balance | $ 25,102,740 | $ 19,231,390 | $ 22,912,701 |
Net operating loss carryforwards utilized | (3,681,311) | ||
Net operating losses | 4,230,763 | 5,871,350 | |
Balance | 29,333,503 | 25,102,740 | 19,231,390 |
Pre-Ownership Change [Member] | |||
Balance | 9,614,449 | 9,614,449 | 10,766,912 |
Net operating loss carryforwards utilized | (1,152,463) | ||
Net operating losses | |||
Balance | 9,614,449 | 9,614,449 | 9,614,449 |
Post-Ownership Change [Member] | |||
Balance | 15,488,291 | 9,616,941 | 12,145,789 |
Net operating loss carryforwards utilized | (2,528,848) | ||
Net operating losses | 4,230,763 | 5,871,350 | |
Balance | $ 19,719,054 | $ 15,488,291 | $ 9,616,941 |
15. Income Taxes (Details 3) - USD ($) |
Jun. 30, 2016 |
Dec. 31, 2015 |
---|---|---|
Deferred tax assets: | ||
Net operating loss and capital loss carryforwards | $ 12,243,743 | $ 8,815,794 |
Start-up costs (Nixon Facility) | 1,442,032 | 1,510,699 |
Asset retirement obligations liability/deferred revenue | 709,657 | 717,723 |
Unrealized hedges | 62,356 | |
AMT credit and other | 275,857 | 302,086 |
Total deferred tax assets | 14,671,289 | 11,408,658 |
Deferred tax liabilities: | ||
Fair market value adjustments | (46,116) | (46,116) |
Unrealized hedges | (68,663) | |
Basis differences in property and equipment | (5,978,709) | (5,484,983) |
Total deferred tax liabilities | (6,093,488) | (5,531,099) |
Deferred tax assets, net | 8,577,801 | 5,877,559 |
Valuation allowance | (2,270,322) | (2,270,322) |
Deferred tax assets, net | $ 6,307,479 | $ 3,607,237 |
15. Income Taxes (Details Narrative) - USD ($) |
6 Months Ended | ||
---|---|---|---|
Jun. 30, 2016 |
Jun. 30, 2015 |
Dec. 31, 2015 |
|
Income Tax Disclosure [Abstract] | |||
Deferred Tax Assets | $ 6,300,000 | $ 3,600,000 | |
Valuation allowance | $ 2,300,000 | $ 2,300,000 |
16. Earnings per share (Details) - USD ($) |
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2016 |
Jun. 30, 2015 |
Jun. 30, 2016 |
Jun. 30, 2015 |
|
Earnings Per Share [Abstract] | ||||
Net income (loss) | $ (3,162,736) | $ 137,879 | $ (5,311,820) | $ 3,839,243 |
Basic and diluted income per share | $ (0.30) | $ 0.01 | $ (0.51) | $ 0.37 |
Basic and diluted | ||||
Weighted average number of shares of common stock outstanding and potential dilutive shares of common stock | 10,459,996 | 10,450,210 | 10,458,895 | 10,444,829 |
17. Fair Value Measurement (Details) - USD ($) |
Jun. 30, 2016 |
Dec. 31, 2015 |
---|---|---|
Financial assets (liabilties): | ||
Commodity contracts | $ 201,950 | $ (183,400) |
Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) [Member] | ||
Financial assets (liabilties): | ||
Commodity contracts | 201,950 | (183,400) |
Significant Other Observable Inputs (Level 2) [Member] | ||
Financial assets (liabilties): | ||
Commodity contracts | ||
Significant Unobservable Inputs (Level 3) [Member] | ||
Financial assets (liabilties): | ||
Commodity contracts |
17. Fair Value Measurement (Details Narrative) - USD ($) |
Jun. 30, 2016 |
Dec. 31, 2015 |
---|---|---|
Fair Value Disclosures [Abstract] | ||
Fair value of long term debt and short-term notes payable | $ 36,227,804 | $ 34,781,186 |
18. Inventory Risk Management (Details) - Refined products - net short (long) positions |
Jun. 30, 2016
shares
|
---|---|
Volume in Thousands of barrels | |
Notional Contract Volumes 2016 | 330,000 |
Notional Contract Volumes 2017 | |
Notional Contract Volumes 2018 |
18. Inventory Risk Management (Details 1) - Commodity Contracts [Member] - USD ($) |
3 Months Ended | 6 Months Ended | |||
---|---|---|---|---|---|
Jun. 30, 2016 |
Jun. 30, 2015 |
Jun. 30, 2016 |
Jun. 30, 2015 |
Dec. 31, 2015 |
|
Prepaid expenses and other current assets (accrued expenses and other current liabilities) | $ 201,950 | $ 201,950 | $ (183,400) | ||
Cost of refined products sold | $ (3,852,100) | $ (1,370,293) | $ (3,359,572) | $ (442,709) |
19. Commitments and Contingencies (Details Narrative) - USD ($) |
Jun. 30, 2016 |
Dec. 31, 2015 |
---|---|---|
Commitments and Contingencies Disclosure [Abstract] | ||
Credit and cash backed rights of way bonds issued to the BOEM | $ 900,000 | $ 900,000 |
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