SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
☒ | |
Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
For the quarterly period ended
September 30,OR
☐ | |
TRANSITION REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from __________ to _________
Commission File Number 001-33503
BLUEKNIGHT ENERGY PARTNERS, L.P.
(Exact name of registrant as specified in its charter)
Delaware (State or other jurisdiction of incorporation or organization) | 20-8536826 (IRS Employer Identification No.) | ||
6060 American Plaza, Suite 600 Tulsa, Oklahoma 74135 (Address of principal executive offices, zip code) Registrant’s telephone number, including area code: |
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer | Accelerated filer | |
Non-accelerated filer | Smaller reporting company | |
Emerging growth company |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes
Securities registered pursuant to Section 12(b) of the Exchange Act:
Title of each class | Trading Symbol(s) | Name of each exchange on which registered |
Common Units | BKEP | The Nasdaq Global Market |
Series A Preferred Units | BKEPP | The Nasdaq Global Market |
As of
Table of Contents Page FINANCIAL INFORMATION Unaudited Condensed Consolidated Financial Statements Condensed Consolidated Balance Sheets as of December 31, 2017,2018, and September 30, 20182019 Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 20172018 and 20182019 Condensed Consolidated StatementStatements of Changes in Partners’ Capital (Deficit) for the Three and Nine Months Ended September 30, 2018 and 2019 Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 20172018 and 20182019 Notes to the Unaudited Condensed Consolidated Financial Statements Management’s Discussion and Analysis of Financial Condition and Results of Operations Quantitative and Qualitative Disclosures about Market Risk Controls and Procedures OTHER INFORMATION Legal Proceedings Risk Factors Exhibits
Item 1. Unaudited Condensed Consolidated Financial Statements
BLUEKNIGHT ENERGY PARTNERS, L.P. CONDENSED CONSOLIDATED BALANCE SHEETS (in thousands, except unit data) |
As of | As of | |||||||
December 31, 2018 | September 30, 2019 | |||||||
(unaudited) | ||||||||
ASSETS | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 1,455 | $ | 2,777 | ||||
Accounts receivable, net | 35,683 | 25,913 | ||||||
Receivables from related parties, net | 1,043 | 1,873 | ||||||
Other current assets | 9,345 | 7,774 | ||||||
Total current assets | 47,526 | 38,337 | ||||||
Property, plant and equipment, net of accumulated depreciation of $263,554 and $278,768 at December 31, 2018, and September 30, 2019, respectively | 248,261 | 238,818 | ||||||
Goodwill | 6,728 | 6,728 | ||||||
Debt issuance costs, net | 3,349 | 2,595 | ||||||
Operating lease assets | - | 11,374 | ||||||
Intangible assets, net | 16,834 | 14,775 | ||||||
Other noncurrent assets | 606 | 1,348 | ||||||
Total assets | $ | 323,304 | $ | 313,975 | ||||
LIABILITIES AND PARTNERS’ CAPITAL | ||||||||
Current liabilities: | ||||||||
Accounts payable | $ | 3,707 | $ | 4,036 | ||||
Accounts payable to related parties | 2,263 | 3,306 | ||||||
Accrued crude oil purchases | 13,949 | 6,465 | ||||||
Accrued crude oil purchases to related parties | 10,219 | 11,438 | ||||||
Accrued interest payable | 465 | 289 | ||||||
Accrued property taxes payable | 3,089 | 3,701 | ||||||
Unearned revenue | 3,206 | 5,476 | ||||||
Unearned revenue with related parties | 4,835 | 2,624 | ||||||
Accrued payroll | 3,667 | 3,836 | ||||||
Current operating lease liability | - | 2,479 | ||||||
Other current liabilities | 3,465 | 3,352 | ||||||
Total current liabilities | 48,865 | 47,002 | ||||||
Long-term unearned revenue with related parties | 1,714 | 1,545 | ||||||
Other long-term liabilities | 4,010 | 3,708 | ||||||
Noncurrent operating lease liability | - | 8,968 | ||||||
Contingent liability with related party (Note 9) | 10,019 | 12,061 | ||||||
Long-term debt | 265,592 | 258,592 | ||||||
Commitments and contingencies (Note 15) | ||||||||
Partners’ capital: | ||||||||
Common unitholders (40,424,372 and 40,813,488 units issued and outstanding at December 31, 2018, and September 30, 2019, respectively) | 370,972 | 360,144 | ||||||
Preferred Units (35,125,202 units issued and outstanding at both dates) | 253,923 | 253,923 | ||||||
General partner interest (1.6% interest with 1,225,409 general partner units outstanding at both dates) | (631,791 | ) | (631,968 | ) | ||||
Total partners’ deficit | (6,896 | ) | (17,901 | ) | ||||
Total liabilities and partners’ deficit | $ | 323,304 | $ | 313,975 |
BLUEKNIGHT ENERGY PARTNERS, L.P. CONDENSED CONSOLIDATED BALANCE SHEETS (in thousands, except unit data) | |||||||
As of | As of | ||||||
December 31, 2017 | September 30, 2018 | ||||||
(unaudited) | |||||||
ASSETS | |||||||
Current assets: | |||||||
Cash and cash equivalents | $ | 2,469 | $ | 1,926 | |||
Accounts receivable, net of allowance for doubtful accounts of $28 at both dates | 7,589 | 46,917 | |||||
Receivables from related parties, net of allowance for doubtful accounts of $0 at both dates | 3,070 | 1,647 | |||||
Prepaid insurance | 2,009 | 2,146 | |||||
Other current assets | 8,438 | 9,834 | |||||
Total current assets | 23,575 | 62,470 | |||||
Property, plant and equipment, net of accumulated depreciation of $316,591 and $276,290 at December 31, 2017, and September 30, 2018, respectively | 296,069 | 295,272 | |||||
Goodwill | 3,870 | 6,728 | |||||
Debt issuance costs, net | 4,442 | 3,600 | |||||
Intangibles and other assets, net | 12,913 | 18,169 | |||||
Total assets | $ | 340,869 | $ | 386,239 | |||
LIABILITIES AND PARTNERS’ CAPITAL | |||||||
Current liabilities: | |||||||
Accounts payable | $ | 4,439 | $ | 4,311 | |||
Accounts payable to related parties | 2,268 | 3,093 | |||||
Accrued crude oil purchases | 1,115 | 15,142 | |||||
Accrued crude oil purchases to related parties | — | 16,681 | |||||
Accrued interest payable | 694 | 462 | |||||
Accrued property taxes payable | 2,432 | 3,776 | |||||
Unearned revenue | 2,393 | 3,207 | |||||
Unearned revenue with related parties | 551 | 2,809 | |||||
Accrued payroll | 6,119 | 3,838 | |||||
Other current liabilities | 3,632 | 3,820 | |||||
Total current liabilities | 23,643 | 57,139 | |||||
Long-term unearned revenue with related parties | 1,052 | 745 | |||||
Other long-term liabilities | 3,673 | 3,726 | |||||
Long-term interest rate swap liabilities | 225 | — | |||||
Long-term debt | 307,592 | 271,592 | |||||
Commitments and contingencies (Note 15) | |||||||
Partners’ capital: | |||||||
Common unitholders (40,158,342 and 40,387,006 units issued and outstanding at December 31, 2017, and September 30, 2018, respectively) | 454,358 | 429,959 | |||||
Preferred Units (35,125,202 units issued and outstanding at both dates) | 253,923 | 253,923 | |||||
General partner interest (1.6% interest with 1,225,409 general partner units outstanding at both dates) | (703,597 | ) | (630,845 | ) | |||
Total partners’ capital | 4,684 | 53,037 | |||||
Total liabilities and partners’ capital | $ | 340,869 | $ | 386,239 |
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
BLUEKNIGHT ENERGY PARTNERS, L.P. CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (in thousands, except per unit data) | ||||||||||||||||
Three Months ended September 30, | Nine Months ended September 30, | |||||||||||||||
2017 | 2018 | 2017 | 2018 | |||||||||||||
(unaudited) | ||||||||||||||||
Service revenue: | ||||||||||||||||
Third-party revenue | $ | 30,635 | $ | 12,743 | $ | 87,443 | $ | 44,164 | ||||||||
Related-party revenue | 14,464 | 5,396 | 41,611 | 17,780 | ||||||||||||
Lease revenue: | ||||||||||||||||
Third-party revenue | — | 11,368 | — | 31,409 | ||||||||||||
Related-party revenue | — | 5,406 | — | 20,584 | ||||||||||||
Product sales revenue: | ||||||||||||||||
Third-party revenue | 2,375 | 97,763 | 8,637 | 146,892 | ||||||||||||
Related-party revenue | — | 482 | — | 482 | ||||||||||||
Total revenue | 47,474 | 133,158 | 137,691 | 261,311 | ||||||||||||
Costs and expenses: | ||||||||||||||||
Operating expense | 29,380 | 27,174 | 91,896 | 87,297 | ||||||||||||
Cost of product sales | 1,675 | 50,815 | 6,483 | 73,493 | ||||||||||||
Cost of product sales from related party | — | 44,106 | — | 67,853 | ||||||||||||
General and administrative expense | 4,093 | 4,322 | 13,000 | 13,029 | ||||||||||||
Asset impairment expense | — | 15 | 45 | 631 | ||||||||||||
Total costs and expenses | 35,148 | 126,432 | 111,424 | 242,303 | ||||||||||||
Gain (loss) on sale of assets | (107 | ) | (63 | ) | (986 | ) | 300 | |||||||||
Operating income | 12,219 | 6,663 | 25,281 | 19,308 | ||||||||||||
Other income (expenses): | ||||||||||||||||
Equity earnings in unconsolidated affiliate | — | — | 61 | — | ||||||||||||
Gain on sale of unconsolidated affiliate | 1,112 | — | 5,284 | 2,225 | ||||||||||||
Interest expense | (3,500 | ) | (4,090 | ) | (10,795 | ) | (12,683 | ) | ||||||||
Income before income taxes | 9,831 | 2,573 | 19,831 | 8,850 | ||||||||||||
Provision for income taxes | 60 | 165 | 147 | 215 | ||||||||||||
Net income | $ | 9,771 | $ | 2,408 | $ | 19,684 | $ | 8,635 | ||||||||
Allocation of net income for calculation of earnings per unit: | ||||||||||||||||
General partner interest in net income | $ | 312 | $ | 39 | $ | 777 | $ | 298 | ||||||||
Preferred interest in net income | $ | 6,279 | $ | 6,279 | $ | 18,837 | $ | 18,836 | ||||||||
Net income (loss) available to limited partners | $ | 3,180 | $ | (3,910 | ) | $ | 70 | $ | (10,499 | ) | ||||||
Basic and diluted net income (loss) per common unit | $ | 0.08 | $ | (0.09 | ) | $ | — | $ | (0.25 | ) | ||||||
Weighted average common units outstanding - basic and diluted | 38,189 | 40,380 | 38,164 | 40,331 |
BLUEKNIGHT ENERGY PARTNERS, L.P. CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (in thousands, except per unit data) |
Three Months ended September 30, | Nine Months ended September 30, | |||||||||||||||
2018 | 2019 | 2018 | 2019 | |||||||||||||
(unaudited) | ||||||||||||||||
Service revenue: | ||||||||||||||||
Third-party revenue | $ | 12,743 | $ | 15,716 | $ | 44,164 | $ | 47,329 | ||||||||
Related-party revenue | 5,396 | 3,956 | 17,780 | 12,257 | ||||||||||||
Lease revenue: | ||||||||||||||||
Third-party revenue | 11,368 | 11,444 | 31,409 | 31,026 | ||||||||||||
Related-party revenue | 5,406 | 5,427 | 20,584 | 15,179 | ||||||||||||
Product sales revenue: | ||||||||||||||||
Third-party revenue | 97,763 | 55,213 | 146,892 | 173,773 | ||||||||||||
Related-party revenue | 482 | - | 482 | - | ||||||||||||
Total revenue | 133,158 | 91,756 | 261,311 | 279,564 | ||||||||||||
Costs and expenses: | ||||||||||||||||
Operating expense | 27,174 | 25,168 | 87,297 | 78,326 | ||||||||||||
Cost of product sales | 50,815 | 18,972 | 73,493 | 64,069 | ||||||||||||
Cost of product sales from related party | 44,106 | 32,691 | 67,853 | 99,886 | ||||||||||||
General and administrative expense | 4,322 | 3,840 | 13,029 | 10,495 | ||||||||||||
Asset impairment expense | 15 | 83 | 631 | 2,316 | ||||||||||||
Total costs and expenses | 126,432 | 80,754 | 242,303 | 255,092 | ||||||||||||
Gain (loss) on sale of assets | (63 | ) | (40 | ) | 300 | 1,765 | ||||||||||
Operating income | 6,663 | 10,962 | 19,308 | 26,237 | ||||||||||||
Other income (expenses): | ||||||||||||||||
Other income | - | - | - | 268 | ||||||||||||
Gain on sale of unconsolidated affiliate | - | - | 2,225 | - | ||||||||||||
Interest expense | (4,090 | ) | (3,989 | ) | (12,683 | ) | (12,394 | ) | ||||||||
Income before income taxes | 2,573 | 6,973 | 8,850 | 14,111 | ||||||||||||
Provision for income taxes | 165 | 14 | 215 | 39 | ||||||||||||
Net income | $ | 2,408 | $ | 6,959 | $ | 8,635 | $ | 14,072 | ||||||||
Allocation of net income for calculation of earnings per unit: | ||||||||||||||||
General partner interest in net income | $ | 39 | $ | 110 | $ | 298 | $ | 268 | ||||||||
Preferred interest in net income | $ | 6,279 | $ | 6,278 | $ | 18,836 | $ | 18,836 | ||||||||
Net income (loss) available to limited partners | $ | (3,910 | ) | $ | 571 | $ | (10,499 | ) | $ | (5,032 | ) | |||||
Basic and diluted net income (loss) per common unit | $ | (0.09 | ) | $ | 0.01 | $ | (0.25 | ) | $ | (0.12 | ) | |||||
Weighted average common units outstanding - basic and diluted | 40,380 | 40,811 | 40,331 | 40,735 |
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
BLUEKNIGHT ENERGY PARTNERS, L.P. CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS’ CAPITAL (DEFICIT) (in thousands) | |||||||||||||||
Common Unitholders | Series A Preferred Unitholders | General Partner Interest | Total Partners’ Capital (Deficit) | ||||||||||||
(unaudited) | |||||||||||||||
Balance, December 31, 2017 | $ | 454,358 | $ | 253,923 | $ | (703,597 | ) | $ | 4,684 | ||||||
Net income (loss) | (10,655 | ) | 18,836 | 454 | 8,635 | ||||||||||
Equity-based incentive compensation | 1,325 | — | 27 | 1,352 | |||||||||||
Distributions | (15,277 | ) | (18,836 | ) | (879 | ) | (34,992 | ) | |||||||
Capital contributions | — | — | 183 | 183 | |||||||||||
Capital contributions related to sale of terminal assets to Ergon | — | — | 72,967 | 72,967 | |||||||||||
Proceeds from sale of 61,327 common units pursuant to the Employee Unit Purchase Plan | 208 | — | — | 208 | |||||||||||
Balance, September 30, 2018 | $ | 429,959 | $ | 253,923 | $ | (630,845 | ) | $ | 53,037 |
BLUEKNIGHT ENERGY PARTNERS, L.P. CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL (DEFICIT) (in thousands) |
Common Unitholders | Series A Preferred Unitholders | General Partner Interest | Total Partners’ Capital (Deficit) | |||||||||||||
(unaudited) | ||||||||||||||||
Balance, June 30, 2018 | $ | 436,416 | $ | 253,923 | $ | (703,704 | ) | $ | (13,365 | ) | ||||||
Net income (loss) | (3,910 | ) | 6,279 | 39 | 2,408 | |||||||||||
Equity-based incentive compensation | 656 | - | 9 | 665 | ||||||||||||
Distributions | (3,319 | ) | (6,279 | ) | (156 | ) | (9,754 | ) | ||||||||
Capital contributions related to sale of terminal assets to Ergon | - | - | 72,967 | 72,967 | ||||||||||||
Proceeds from sale of 40,081 common units pursuant to the Employee Unit Purchase Plan | 116 | - | - | 116 | ||||||||||||
Balance, September 30, 2018 | $ | 429,959 | $ | 253,923 | $ | (630,845 | ) | $ | 53,037 | |||||||
Balance, December 31, 2017 | $ | 454,358 | $ | 253,923 | $ | (703,597 | ) | $ | 4,684 | |||||||
Net income (loss) | (10,655 | ) | 18,836 | 454 | 8,635 | |||||||||||
Equity-based incentive compensation | 1,325 | - | 27 | 1,352 | ||||||||||||
Distributions | (15,277 | ) | (18,836 | ) | (879 | ) | (34,992 | ) | ||||||||
Capital contributions | - | - | 183 | 183 | ||||||||||||
Capital contributions related to sale of terminal assets to Ergon | - | - | 72,967 | 72,967 | ||||||||||||
Proceeds from sale of 61,327 common units pursuant to the Employee Unit Purchase Plan | 208 | - | - | 208 | ||||||||||||
Balance, September 30, 2018 | $ | 429,959 | $ | 253,923 | $ | (630,845 | ) | $ | 53,037 | |||||||
Balance, June 30, 2019 | $ | 360,861 | $ | 253,923 | $ | (631,952 | ) | $ | (17,168 | ) | ||||||
Net income (loss) | 574 | 6,278 | 107 | 6,959 | ||||||||||||
Equity-based incentive compensation | 284 | - | 5 | 289 | ||||||||||||
Distributions | (1,678 | ) | (6,278 | ) | (128 | ) | (8,084 | ) | ||||||||
Proceeds from sale of 98,631 common units pursuant to the Employee Unit Purchase Plan | 103 | - | - | 103 | ||||||||||||
Balance, September 30, 2019 | $ | 360,144 | $ | 253,923 | $ | (631,968 | ) | $ | (17,901 | ) | ||||||
Balance, December 31, 2018 | $ | 370,972 | $ | 253,923 | $ | (631,791 | ) | $ | (6,896 | ) | ||||||
Net income (loss) | (4,983 | ) | 18,836 | 219 | 14,072 | |||||||||||
Equity-based incentive compensation | 637 | - | 15 | 652 | ||||||||||||
Distributions | (6,658 | ) | (18,836 | ) | (411 | ) | (25,905 | ) | ||||||||
Proceeds from sale of 161,971 common units pursuant to the Employee Unit Purchase Plan | 176 | - | - | 176 | ||||||||||||
Balance, September 30, 2019 | $ | 360,144 | $ | 253,923 | $ | (631,968 | ) | $ | (17,901 | ) |
The accompanying notes are an integral part of thisthese unaudited condensed consolidated financial statement.
BLUEKNIGHT ENERGY PARTNERS, L.P. CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (in thousands) | |||||||
Nine Months ended September 30, | |||||||
2017 | 2018 | ||||||
(unaudited) | |||||||
Cash flows from operating activities: | |||||||
Net income | $ | 19,684 | $ | 8,635 | |||
Adjustments to reconcile net income to net cash provided by operating activities: | |||||||
Provision for uncollectible receivables from third parties | (19 | ) | — | ||||
Depreciation and amortization | 23,586 | 21,945 | |||||
Amortization and write-off of debt issuance costs | 1,560 | 1,200 | |||||
Unrealized gain related to interest rate swaps | (1,253 | ) | (277 | ) | |||
Intangible asset impairment charge | — | 189 | |||||
Fixed asset impairment charge | 45 | 442 | |||||
Loss (gain) on sale of assets | 986 | (300 | ) | ||||
Gain on sale of unconsolidated affiliate | (5,284 | ) | (2,225 | ) | |||
Equity-based incentive compensation | 913 | 1,352 | |||||
Equity earnings in unconsolidated affiliate | (61 | ) | — | ||||
Changes in assets and liabilities: | |||||||
Increase in accounts receivable | (352 | ) | (39,328 | ) | |||
Decrease (increase) in receivables from related parties | (110 | ) | 1,423 | ||||
Decrease in prepaid insurance | 1,964 | 1,817 | |||||
Decrease (increase) in other current assets | 53 | (949 | ) | ||||
Decrease in other non-current assets | 56 | 424 | |||||
Decrease in accounts payable | (142 | ) | (435 | ) | |||
Increase in payables to related parties | 159 | 1,068 | |||||
Increase in accrued crude oil purchases | 785 | 15,142 | |||||
Increase in accrued crude oil purchases to related parties | — | 16,681 | |||||
Increase (decrease) in accrued interest payable | 338 | (232 | ) | ||||
Increase in accrued property taxes | 1,187 | 1,718 | |||||
Increase in unearned revenue | 775 | 853 | |||||
Increase in unearned revenue from related parties | 3,835 | 2,829 | |||||
Decrease in accrued payroll | (804 | ) | (2,281 | ) | |||
Decrease in other accrued liabilities | (1,720 | ) | (1,504 | ) | |||
Net cash provided by operating activities | 46,181 | 28,187 | |||||
Cash flows from investing activities: | |||||||
Acquisitions | — | (21,959 | ) | ||||
Capital expenditures | (13,312 | ) | (29,560 | ) | |||
Proceeds from sale of assets | 9,202 | 4,707 | |||||
Proceeds from sale of terminal assets to Ergon | — | 88,538 | |||||
Proceeds from sale of unconsolidated affiliate | 26,436 | 2,225 | |||||
Net cash provided by investing activities | 22,326 | 43,951 | |||||
Cash flows from financing activities: | |||||||
Payment on insurance premium financing agreement | (2,074 | ) | (1,722 | ) | |||
Debt issuance costs | (4,172 | ) | (358 | ) | |||
Borrowings under credit agreement | 344,592 | 216,000 | |||||
Payments under credit agreement | (371,000 | ) | (252,000 | ) | |||
Proceeds from equity issuance | 240 | 208 | |||||
Capital contributions | 104 | 183 | |||||
Distributions | (36,853 | ) | (34,992 | ) | |||
Net cash used in financing activities | (69,163 | ) | (72,681 | ) | |||
Net decrease in cash and cash equivalents | (656 | ) | (543 | ) | |||
Cash and cash equivalents at beginning of period | 3,304 | 2,469 | |||||
Cash and cash equivalents at end of period | $ | 2,648 | $ | 1,926 | |||
BLUEKNIGHT ENERGY PARTNERS, L.P. CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (in thousands) |
Nine Months ended September 30, | ||||||||
2018 | 2019 | |||||||
(unaudited) | ||||||||
Cash flows from operating activities: | ||||||||
Net income | $ | 8,635 | $ | 14,072 | ||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||
Depreciation and amortization | 21,945 | 19,211 | ||||||
Amortization of debt issuance costs | 1,200 | 754 | ||||||
Unrealized (gain) loss related to interest rate swaps | (277 | ) | 44 | |||||
Intangible asset impairment charge | 189 | - | ||||||
Fixed asset impairment charge | 442 | 2,316 | ||||||
Gain on sale of assets | (300 | ) | (1,765 | ) | ||||
Gain on sale of unconsolidated affiliate | (2,225 | ) | - | |||||
Equity-based incentive compensation | 1,352 | 652 | ||||||
Changes in assets and liabilities: | ||||||||
Decrease (increase) in accounts receivable | (39,328 | ) | 7,128 | |||||
Decrease (increase) in receivables from related parties | 1,423 | (830 | ) | |||||
Decrease in other current assets | 868 | 3,571 | ||||||
Decrease in other non-current assets | 424 | 2,255 | ||||||
Decrease in accounts payable | (435 | ) | (250 | ) | ||||
Increase in payables to related parties | 1,068 | 535 | ||||||
Increase (decrease) in accrued crude oil purchases | 15,142 | (7,484 | ) | |||||
Increase in accrued crude oil purchases to related parties | 16,681 | 1,219 | ||||||
Decrease in accrued interest payable | (232 | ) | (176 | ) | ||||
Increase in accrued property taxes | 1,718 | 612 | ||||||
Increase in unearned revenue | 853 | 1,557 | ||||||
Increase (decrease) in unearned revenue from related parties | 2,829 | (2,380 | ) | |||||
Increase (decrease) in accrued payroll | (2,281 | ) | 169 | |||||
Decrease in other accrued liabilities | (1,504 | ) | (2,926 | ) | ||||
Net cash provided by operating activities | 28,187 | 38,284 | ||||||
Cash flows from investing activities: | ||||||||
Acquisitions | (21,959 | ) | - | |||||
Capital expenditures | (29,560 | ) | (9,428 | ) | ||||
Proceeds from sale of assets | 4,707 | 7,089 | ||||||
Proceeds from sale of terminal assets to Ergon | 88,538 | - | ||||||
Proceeds from sale of unconsolidated affiliate | 2,225 | - | ||||||
Net cash provided by (used in) investing activities | 43,951 | (2,339 | ) | |||||
Cash flows from financing activities: | ||||||||
Payments on other financing activities | (1,722 | ) | (1,894 | ) | ||||
Debt issuance costs | (358 | ) | - | |||||
Borrowings under credit agreement | 216,000 | 218,000 | ||||||
Payments under credit agreement | (252,000 | ) | (225,000 | ) | ||||
Proceeds from equity issuance | 208 | 176 | ||||||
Capital contributions | 183 | - | ||||||
Distributions | (34,992 | ) | (25,905 | ) | ||||
Net cash used in financing activities | (72,681 | ) | (34,623 | ) | ||||
Net increase (decrease) in cash and cash equivalents | (543 | ) | 1,322 | |||||
Cash and cash equivalents at beginning of period | 2,469 | 1,455 | ||||||
Cash and cash equivalents at end of period | $ | 1,926 | $ | 2,777 | ||||
Supplemental disclosure of non-cash financing and investing cash flow information: | ||||||||
Non-cash changes in property, plant and equipment | $ | (908 | ) | $ | 1,528 | |||
Non-cash change in assets and liabilities due to settlement items related to the sale of terminal assets to Ergon | $ | (1,308 | ) | $ | - | |||
Increase in accrued liabilities related to insurance premium financing agreement | $ | 2,225 | $ | 2,356 |
BLUEKNIGHT ENERGY PARTNERS, L.P. CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (in thousands) | |||||||
Supplemental disclosure of non-cash financing and investing cash flow information: | |||||||
Non-cash changes in property, plant and equipment | $ | 717 | $ | (908 | ) | ||
Non-cash change in assets and liabilities due to settlement items related to the sale of terminal assets to Ergon | $ | — | $ | (1,308 | ) | ||
Increase in accrued liabilities related to insurance premium financing agreement | $ | 2,938 | $ | 2,225 |
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
1. | ORGANIZATION AND NATURE OF BUSINESS |
Blueknight Energy Partners, L.P. and subsidiaries (collectively, the “Partnership”) is a publicly traded master limited partnership with operations in
27 states. The Partnership provides integrated terminalling, gathering, transportation and marketing services for companies engaged in the production, distribution and marketing of crude oil and asphalt products. The Partnership manages its operations through four operating segments: (i) asphalt terminalling services, (ii) crude oil terminalling services, (iii) crude oil pipeline services and (iv) crude oil trucking services.2. | BASIS OF CONSOLIDATION AND PRESENTATION |
The financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The condensed consolidated balance sheet as of September 30, 2018,2019, the condensed consolidated statements of operations for the three and nine months ended September 30,
Certain reclassifications have been made in the consolidated balance sheet as of December 31, 2017,2018, and the consolidated statement of cash flows for the nine months ended September 30, 2018, to conform to the 20182019 financial statement presentation. This was a reclassificationThese reclassifications relate to items included in “Other current assets” and “Other noncurrent assets.” Reclassifications on the consolidated statement of “Accrued crude oil purchases”cash flows were limited to the “Cash flows from “Accrued liabilities.”operating activities” section. The reclassification hasreclassifications have no impact on net income.
3. | REVENUE |
On January 1, 2018,2019, the Partnership adopted ASU 2016-02, which created the new accounting standard
There are two types of contracts in the asphalt terminalling segment: (i) operating lease contracts, under which customers operate the facilities, and (ii) storage, throughput and handling contracts, under which the Partnership operates the facilities. The operating lease contracts are accounted for in accordance with
ASCAsphalt storage, throughput and handling contracts also contain variable consideration in the form of reimbursements of utility, fuel and power expenses and throughput fees. Utility, fuel and power reimbursements are allocated entirely to the service component of the contracts. Utility, fuel and power reimbursements relate directly to the distinct monthly service that makes up the overall performance obligation and revenue is recognized in the period in which the service takes place. Variable consideration related to reimbursements of utility, fuel and power expenses is billed in the month subsequent to the period of service, and payment is due within 30 days of billing. Throughput fees are allocated to both the lease and service component of the contracts using the allocation percentages from contract inception. Total throughput fees are estimated at contract inception and updated at the beginning of each reporting period based on historical trends, current year throughput activities at the facilities, and analysis with customers regarding expectations for the current year. This consideration can be constrained when there is a lack of historical data or other uncertainties exist regarding expected throughput volumes. The service component of throughput fees is recognized on a straight-line basis over time as the customer receives and consumes benefits. In accordance with ASC 840,842, the lease component of variable throughput fees is recognized in the period when the changes in facts and circumstances on which the variable payment is based occur. Fees related to actualAdditionally, under ASC 842, when variable consideration contains both a lease and non-lease service component, the service component cannot be recognized until the period in which the changes in facts and circumstances on which the variable payment is based occur. At that time, it can be recognized in accordance with ASC 606. The service component of variable throughput are billedfees is treated as a change in estimate in the month subsequent toperiod in when the period of movement,changes in facts and circumstances on which can result in the recognition of un-billed accounts receivable (contract assets) when therevariable payment is based occur and is then recognized on a variance instraight-line basis over time as the straight-line revenue recognitioncustomer receives and actual throughput fees billed.consumes benefits. Payment on variable throughput consideration is due within 30 days of billing. Changes in estimated throughput fees affect the total transaction price and will be recorded as an adjustment to revenue in the period in which the change is identified. The Partnership recorded a decrease to revenue of $0.1 million related to changes in estimated throughput fees for the three months ended September 30, 2018.
Certain asphalt storage, throughput and handling contracts contain provisions for reimbursement of specified major maintenance costs above a specified threshold over the life of the contract. Reimbursements of specified major maintenance costs are allocated to both the lease and service component of the contracts using the allocation percentages from contract inception. Reimbursements of specified major maintenance costs are reviewed and paid quarterly, which may result in overpayments that must be paid back to the customer in future years. As such, the service component of this consideration is constrained and recorded in unearned revenue (contract liability) until facts and circumstances indicate it is probable that the minimum threshold will be met. In the event the minimum threshold is not met, the Partnership will return the reimbursement to the customer.
The following table includes revenue associated with contractual commitments in place related to future performance obligations satisfied over time under asphalt storage, throughput and handling contracts thatas of the end of the reporting period, which are wholly or partially unsatisfied. The revenue relatedexpected to these performance obligations will be recognized as followsin revenue in the specified periods (in thousands):
Revenue from Contracts with Customers(1) | Revenue from Leases | |||||||
Remainder of 2019 | $ | 7,756 | $ | 14,012 | ||||
2020 | 30,602 | 53,487 | ||||||
2021 | 27,253 | 49,244 | ||||||
2022 | 19,937 | 38,545 | ||||||
2023 | 14,533 | 29,609 | ||||||
Thereafter | 9,142 | 22,342 | ||||||
Total revenue related to future performance obligations | $ | 109,223 | $ | 207,239 |
Revenue Related to Future Performance Obligations Due by Period(1) | ||||
Less than 1 year | $ | 28,299 | ||
1-3 years | 51,848 | |||
4-5 years | 32,536 | |||
More than 5 years | 10,320 | |||
Total revenue related to future performance obligations | $ | 123,003 |
____________________
(1) | |
Excluded from the table is revenue that is either constrained or related to performance obligations that are wholly unsatisfied as of September 30, |
Crude oil terminalling services contracts can be either short- or long-term written contracts. The contracts contain a single performance obligation that consists of a series of distinct services provided over time. Customers are billed a month prior to the performance of terminalling services and payment is due by the first day of the month of service. Payments received in advance of the month of service are recorded as unearned revenue (contract liability) until the service is performed. These contracts also contain provisions under which customers are invoiced for product throughput in the month following the month in which the service is provided. Payment on product throughput is due within 30 days. The Partnership has elected to use the right-to-invoice expedient on crude oil terminalling services contracts as the right to consideration corresponds directly with the value to the customer of performance completed to date.
There are primarily two types of contracts in the crude oil pipeline segment: (i) monthly transportation contracts and (ii) product sales contracts.
Under crude oil pipeline services monthly transportation contracts, customers submit nominations for transportation monthly and a contract is created upon the Partnership’s acceptance of the nomination under its published tariffs. Crude oil pipeline services contracts have a single performance obligation to perform the transportation service. The transportation service is provided to the customer in the same month in which the customer makes the related nomination. Revenue is recorded in the month of service and invoiced in the following month. Payment is due within 30 days. The Partnership has elected to use the right-to-invoice expedient on crude oil pipeline services contracts as the right to consideration corresponds directly with the value to the customer of performance completed to date.
The Partnership also purchases crude oil and resells to third parties under written product sales contracts. Product sales contracts have a single performance obligation, and revenue is recognized at the point in time that control is transferred to the customer. Control is considered transferred to the customer on the day of the sale. Revenue is recorded in the month of service andCustomers are invoiced in the following month. Payment is due within 30 days. The Partnership has elected to use the right-to-invoice expedient on product sales contracts as the right to consideration corresponds directly with the value to the customer of performance completed to date.
Services in the crude oil trucking segment are provided under master service agreements with customers that include rate sheets. Contracts are initiated when a customer requests service and both parties are committed upon the Partnership’s acceptance of the customer’s request. Crude oil trucking contracts have a single performance obligation to perform the service, which is completed in a day. Revenue is recorded in the month of service and invoiced in the following month. Payment is due within 30 days. The Partnership has elected to use the right-to-invoice expedient on crude oil trucking revenues as the right to consideration corresponds directly with the value to the customer of performance completed to date.
Disaggregation of revenue from contracts with customers for each operating segment by revenue type is presented as follows (in thousands):
Asphalt Terminalling Services | Crude Oil Terminalling Services | Crude Oil Pipeline Services | Crude Oil Trucking Services | Total | ||||||||||||||||
Three Months ended September 30, 2018 | ||||||||||||||||||||
Third-party revenue: | ||||||||||||||||||||
Fixed storage, throughput and other revenue | $ | 4,865 | $ | 1,830 | $ | - | $ | - | $ | 6,695 | ||||||||||
Variable throughput revenue | 112 | 93 | - | - | 205 | |||||||||||||||
Variable reimbursement revenue | 1,943 | - | - | - | 1,943 | |||||||||||||||
Crude oil transportation revenue | - | - | 1,166 | 2,734 | 3,900 | |||||||||||||||
Crude oil product sales revenue | - | - | 97,763 | - | 97,763 | |||||||||||||||
Related-party revenue: | ||||||||||||||||||||
Fixed storage, throughput and other revenue | 3,011 | - | 83 | - | 3,094 | |||||||||||||||
Variable throughput revenue | 762 | - | - | - | 762 | |||||||||||||||
Variable reimbursement revenue | 1,439 | - | 101 | - | 1,540 | |||||||||||||||
Total revenue from contracts with customers | $ | 12,132 | $ | 1,923 | $ | 99,113 | $ | 2,734 | $ | 115,902 |
Nine Months ended September 30, 2018 | ||||||||||||||||||||
Third-party revenue: | ||||||||||||||||||||
Fixed storage, throughput and other revenue | $ | 13,038 | $ | 8,679 | $ | - | $ | - | $ | 21,717 | ||||||||||
Variable throughput revenue | 471 | 739 | - | - | 1,210 | |||||||||||||||
Variable reimbursement revenue | 5,184 | - | - | - | 5,184 | |||||||||||||||
Crude oil transportation revenue | - | - | 4,270 | 11,783 | 16,053 | |||||||||||||||
Crude oil product sales revenue | - | - | 146,882 | 10 | 146,892 | |||||||||||||||
Related-party revenue: | ||||||||||||||||||||
Fixed storage, throughput and other revenue | 12,272 | - | 132 | - | 12,404 | |||||||||||||||
Variable throughput revenue | 762 | - | - | 762 | ||||||||||||||||
Variable reimbursement revenue | 4,478 | - | 136 | - | 4,614 | |||||||||||||||
Total revenue from contracts with customers | $ | 36,205 | $ | 9,418 | $ | 151,420 | $ | 11,793 | $ | 208,836 |
Three Months ended September 30, 2019 | ||||||||||||||||||||
Third-party revenue: | ||||||||||||||||||||
Fixed storage, throughput and other revenue | $ | 5,138 | $ | 3,509 | $ | - | $ | - | $ | 8,647 | ||||||||||
Variable throughput revenue | 518 | 716 | - | - | 1,234 | |||||||||||||||
Variable reimbursement revenue | 1,729 | - | - | - | 1,729 | |||||||||||||||
Crude oil transportation revenue | - | - | 1,284 | 2,822 | 4,106 | |||||||||||||||
Crude oil product sales revenue | - | - | 55,213 | - | 55,213 | |||||||||||||||
Related-party revenue: | ||||||||||||||||||||
Fixed storage, throughput and other revenue | 2,794 | - | 63 | - | 2,857 | |||||||||||||||
Variable reimbursement revenue | 1,098 | - | 1 | - | 1,099 | |||||||||||||||
Total revenue from contracts with customers | $ | 11,277 | $ | 4,225 | $ | 56,561 | $ | 2,822 | $ | 74,885 |
Nine Months ended September 30, 2019 | ||||||||||||||||||||
Third-party revenue: | ||||||||||||||||||||
Fixed storage, throughput and other revenue | $ | 15,174 | $ | 9,956 | $ | - | $ | - | $ | 25,130 | ||||||||||
Variable throughput revenue | 554 | 1,863 | - | - | 2,417 | |||||||||||||||
Variable reimbursement revenue | 5,489 | - | - | - | 5,489 | |||||||||||||||
Crude oil transportation revenue | - | - | 5,753 | 8,540 | 14,293 | |||||||||||||||
Crude oil product sales revenue | - | - | 173,773 | - | 173,773 | |||||||||||||||
Related-party revenue: | ||||||||||||||||||||
Fixed storage, throughput and other revenue | 8,500 | - | 229 | - | 8,729 | |||||||||||||||
Variable reimbursement revenue | 3,491 | - | 37 | - | 3,528 | |||||||||||||||
Total revenue from contracts with customers | $ | 33,208 | $ | 11,819 | $ | 179,792 | $ | 8,540 | $ | 233,359 |
Three Months ended September 30, 2018 | ||||||||||||||||||||
Asphalt Terminalling Services | Crude Oil Terminalling Services | Crude Oil Pipeline Services | Crude Oil Trucking Services | Total | ||||||||||||||||
Third-party revenue: | ||||||||||||||||||||
Fixed storage, throughput and other revenue | $ | 4,865 | $ | 1,830 | $ | — | $ | — | $ | 6,695 | ||||||||||
Variable throughput revenue | 112 | 93 | — | — | 205 | |||||||||||||||
Variable reimbursement revenue | 1,943 | — | — | — | 1,943 | |||||||||||||||
Crude oil transportation revenue | — | — | 1,166 | 2,734 | 3,900 | |||||||||||||||
Crude oil product sales revenue | — | — | 97,763 | — | 97,763 | |||||||||||||||
Related-party revenue: | ||||||||||||||||||||
Fixed storage, throughput and other revenue | 3,011 | — | 83 | — | 3,094 | |||||||||||||||
Variable throughput revenue | 762 | — | — | — | 762 | |||||||||||||||
Variable reimbursement revenue | 1,439 | — | 101 | — | 1,540 | |||||||||||||||
Total revenue from contracts with customers | $ | 12,132 | $ | 1,923 | $ | 99,113 | $ | 2,734 | $ | 115,902 |
Nine Months ended September 30, 2018 | ||||||||||||||||||||
Asphalt Terminalling Services | Crude Oil Terminalling Services | Crude Oil Pipeline Services | Crude Oil Trucking Services | Total | ||||||||||||||||
Third-party revenue: | ||||||||||||||||||||
Fixed storage, throughput and other revenue | $ | 13,038 | $ | 8,679 | $ | — | $ | — | $ | 21,717 | ||||||||||
Variable throughput revenue | 471 | 739 | — | — | 1,210 | |||||||||||||||
Variable reimbursement revenue | 5,184 | — | — | — | 5,184 | |||||||||||||||
Crude oil transportation revenue | — | — | 4,270 | 11,783 | 16,053 | |||||||||||||||
Crude oil product sales revenue | — | — | 146,882 | 10 | 146,892 | |||||||||||||||
Related-party revenue: | ||||||||||||||||||||
Fixed storage, throughput and other revenue | 12,272 | — | 132 | — | 12,404 | |||||||||||||||
Variable throughput revenue | 762 | — | — | — | 762 | |||||||||||||||
Variable reimbursement revenue | 4,478 | — | 136 | — | 4,614 | |||||||||||||||
Total revenue from contracts with customers | $ | 36,205 | $ | 9,418 | $ | 151,420 | $ | 11,793 | $ | 208,836 |
Contract Balances
The timing of revenue recognition, billings and cash collections result in billed accounts receivable un-billed accounts receivable (contract assets) and unearned revenue (contract liabilities) on the unaudited condensed consolidated balance sheetsheets as noted in the contract discussions above. Accounts receivable and un-billed accounts receivable are both reflected in the line items “Accounts receivable” and “Receivables from related parties” on the unaudited condensed consolidated balance sheet.sheets. Unearned revenue is included in the line items “Unearned revenue,” “Unearned revenue with related parties,” “Long-term unearned revenue with related parties” and “Other long-term liabilities” on the unaudited condensed consolidated balance sheet.
Billed accounts receivable from contracts with customers were $8.5$34.6 million and $44.9$24.6 million at December 31, 2017,2018, and September 30, 2018,2019, respectively.
The Partnership records unearned revenues when cash payments are received in advance of performance. Unearned revenue related to contracts with customers was $3.7$5.9 million and $4.8$5.7 million at December 31, 2017,2018, and September 30, 2018,2019, respectively. The change in the unearned revenue balance for the nine months ended September 30, 2018,2019, is driven by $2.8$3.2 million in cash payments received in advance of satisfying performance obligations, partially offset by $1.7$3.4 million of revenues recognized that were included in the unearned revenue balance at the beginning of the period.
Practical Expedients and Exemptions
The Partnership does not disclose the value of unsatisfied performance obligations for (i) contracts with an original expected length of one year or less and (ii) contracts for which revenue is recognized at the amount to which the Partnership has the right to invoice for services performed. The Partnership is using the right-to-invoice practical expedient on all contracts with customers in its crude oil terminalling services, crude oil pipeline services and crude oil trucking services segments.
4. | EQUITY METHOD INVESTMENT |
The Partnership’s investment in Advantage Pipeline, L.L.C. (“Advantage Pipeline”), over which the Partnership recognized certain restructuring charges in its crude oil trucking services segment pursuant to an approved plan to exithad significant influence but not control, was accounted for by the trucking market in West Texas.equity method. The restructuring charges included an accrual related to leased vehicles that were idled asPartnership did not consolidate any part of the restructuring plan. This accrual was being amortized over the remaining lease termassets or liabilities of the vehicles. In June 2018, the Partnership purchased the vehicles off lease and resold them to a third party, paying off the remaining liability.
Three Months ended September 30, | Nine Months ended September 30, | ||||||||||
2017 | 2017 | 2018 | |||||||||
Beginning balance | $ | 382 | $ | 474 | $ | 286 | |||||
Cash payments | 48 | 140 | 286 | ||||||||
Ending balance | $ | 334 | $ | 334 | $ | — |
5. | PROPERTY, PLANT AND EQUIPMENT |
Estimated Useful | December 31, | September 30, | |||||||||
Lives (Years) | 2018 | 2019 | |||||||||
(dollars in thousands) | |||||||||||
Land | N/A | $ | 24,705 | $ | 24,705 | ||||||
Land improvements | 10-20 | 5,758 | 5,804 | ||||||||
Pipelines and facilities | 5-30 | 116,155 | 118,449 | ||||||||
Storage and terminal facilities | 10-35 | 321,096 | 326,738 | ||||||||
Transportation equipment | 3-10 | 2,798 | 3,140 | ||||||||
Office property and equipment and other | 3-20 | 26,980 | 27,415 | ||||||||
Pipeline linefill and tank bottoms | N/A | 10,297 | 8,258 | ||||||||
Construction-in-progress | N/A | 4,026 | 3,077 | ||||||||
Property, plant and equipment, gross | 511,815 | 517,586 | |||||||||
Accumulated depreciation | (263,554 | ) | (278,768 | ) | |||||||
Property, plant and equipment, net | $ | 248,261 | $ | 238,818 |
Property, plant and Advantage Pipeline were parties andequipment under which the Partnership operated the 70-mile, 16-inch Advantage crude oil pipeline, located in the southern Delaware Basin in Texas, was terminatedoperating leases at closing. The Partnership and the Plains/Noble joint venture entered into a short-term transition services agreement under which the Partnership provided certain services through August 1, 2017.
Period ended April 3, 2017 | |||
Income Statement | |||
Operating revenues | $ | 3,150 | |
Operating expenses | $ | 465 | |
Net income | $ | 187 |
Estimated Useful Lives (Years) | December 31, 2017 | September 30, 2018 | |||||||
(dollars in thousands) | |||||||||
Land | N/A | $ | 24,776 | $ | 25,030 | ||||
Land improvements | 10-20 | 6,787 | 5,815 | ||||||
Pipelines and facilities | 5-30 | 166,004 | 173,139 | ||||||
Storage and terminal facilities | 10-35 | 370,056 | 320,635 | ||||||
Transportation equipment | 3-10 | 3,293 | 1,314 | ||||||
Office property and equipment and other | 3-20 | 32,011 | 26,971 | ||||||
Pipeline linefill and tank bottoms | N/A | 3,233 | 14,946 | ||||||
Construction-in-progress | N/A | 6,500 | 3,712 | ||||||
Property, plant and equipment, gross | 612,660 | 571,562 | |||||||
Accumulated depreciation | (316,591 | ) | (276,290 | ) | |||||
Property, plant and equipment, net | $ | 296,069 | $ | 295,272 |
Depreciation expense for the three months ended September 30, 20172018 and 2018,2019, was $7.4$6.5 million and $6.5$5.5 million, respectively. Depreciation expense for the nine months ended September 30, 20172018 and 2018,2019, was $22.6$20.2 million and $20.2$16.9 million, respectively.
During the nine months ended September 30, 2019, the Partnership recognized asset impairment expense of $2.3 million. A change in estimate of the push-down impairment related to Cimarron Express Pipeline, LLC (“Cimarron Express”) resulted in additional impairment expense of $2.0 million. This impairment is recorded at the corporate level and the estimate is based on the expected amount due to Ergon, Inc. (“Ergon”) if the Put (as defined in Note 9) is exercised (see Note 9 for more information). In addition, flooding at several asphalt plants in the Midwest led to an impairment of $0.3 million.
During the nine months ended September 30, 2019, the Partnership sold various surplus assets, including the sale of three truck stations for $1.6 million, which resulted in a gain of $1.5 million, and the sale of pipeline linefill for $1.6 million, which resulted in a gain of $0.3 million. In addition, proceeds received during the nine months ended September 30, 2019, included $2.6 million related to a sale of pipeline linefill in December 2018 for which the proceeds were received in January 2019.
On July 12, 2018, the Partnership sold certain asphalt terminals, storage tanks and related real property, contracts, permits, assets and other interests located in Lubbock and Saginaw, Texas and Memphis, Tennessee (the “Divestiture”) to Ergon Asphalt & Emulsion, Inc. for a purchase price of $90.0$90.0 million, subject to customary adjustments. The Divestiture does not qualify as discontinued operations as it does not represent a strategic shift that will have a major effect on the Partnership’s operations or financial results. The Partnership used the proceeds received at closingfrom the sale to prepay revolving debt under its credit agreement.
In April 2018, the Partnership sold its producer field services business. The Partnership received cash proceeds at closing of approximately $3.0$3.0 million and recorded a gain of $0.4$0.4 million. The sale of the producer field services business does not qualify as discontinued operations as it does not represent a strategic shift that will have a major effect on the Partnership’s operations or financial results.
In March 2018, the Partnership acquired an asphalt terminalling facility in Oklahoma from a third party for approximately $22.0$22.0 million, consisting of property, plant and equipment of $11.5$11.5 million, intangible assets of $7.6$7.6 million and goodwill of $2.9$2.9 million.
6. | DEBT |
On May 11, 2017, the Partnership entered into an amended and restated credit agreement. On June 28, 2018, the credit agreement was amended to, among other things, reduce the revolving loan facility from $450.0 million to
As of October 25, 2018,November 1, 2019, approximately $257.6$250.6 million of revolver borrowings and $4.2$1.0 million of letters of credit were outstanding under the credit agreement, leaving the Partnership with approximately $138.2$148.4 million available capacity for additional revolver borrowings and letters of credit under the credit agreement, although the Partnership’s ability to borrow such funds may be limited by the financial covenants in the credit agreement. The proceeds of loans made under the credit agreement may be used for working capital and other general corporate purposes of the Partnership.
The credit agreement is guaranteed by all of the Partnership’s existing subsidiaries. Obligations under the credit agreement are secured by first priority liens on substantially all of the Partnership’s assets and those of the guarantors.
The credit agreement includes procedures for additional financial institutions to become revolving lenders, or for any existing lender to increase its revolving commitment thereunder, subject to an aggregate maximum of
The credit agreement will mature on May 11, 2022, and all amounts outstanding under the credit agreement will become due and payable on such date. The credit agreement requires mandatory prepayments of amounts outstanding thereunder with the net proceeds of certain asset sales, property or casualty insurance claims and condemnation proceedings, unless the Partnership reinvests such proceeds in accordance with the credit agreement, but these mandatory prepayments will not require any reduction of the lenders’ commitments under the credit agreement.
Borrowings under the credit agreement bear interest, at the Partnership’s option, at either the reserve-adjusted eurodollar rate (as defined in the credit agreement) plus an applicable margin that ranges from
2.0% toThe credit agreement includes financial covenants that are tested on a quarterly basis, based on the rolling four-quarter period that ends on the last day of each fiscal quarter.
Prior to the date on which the Partnership issues qualified senior notes in an aggregate principal amount (when combined with all other qualified senior notes previously or concurrently issued) that equals or exceeds $200.0 million, the maximum permitted consolidated total leverage ratio is 4.75 to 1.00; provided that:
From and after the date on which the Partnership issues qualified senior notes in an aggregate principal amount (when combined with all other qualified senior notes previously or concurrently issued) that equals or exceeds $200.0 million, the maximum permitted consolidated total leverage ratio is 5.00 to 1.00; provided that from and after the fiscal quarter ending immediately preceding the fiscal quarter in which a specified acquisition occurs to and including the last day of the second full fiscal quarter following the fiscal quarter in which such acquisition occurred, the maximum permitted consolidated total leverage ratio will be 5.50 to 1.00.
The maximum permitted consolidated senior secured leverage ratio (as defined in the credit agreement, but generally computed as the ratio of consolidated total secured debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges) is 3.50 to 1.00, but this covenant is only tested from and after the date on which the Partnership issues qualified senior notes in an aggregate principal amount (when combined with all other qualified senior notes previously or concurrently issued) that equals or exceeds $200.0 million.
The minimum permitted consolidated interest coverage ratio (as defined in the credit agreement, but generally computed as the ratio of consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges (“credit agreement EBITDA”) to consolidated interest expense) is
2.50 to 1.00.In addition, the credit agreement contains various covenants that, among other restrictions, limit the Partnership’s ability to:
create, issue, incur or assume indebtedness;
create, incur or assume liens;
engage in mergers or acquisitions;
sell, transfer, assign or convey assets;
repurchase the Partnership’s equity, make distributions to unitholders and make certain other restricted payments;
make investments;
modify the terms of certain indebtedness, or prepay certain indebtedness;
engage in transactions with affiliates;
enter into certain hedging contracts;
enter into certain burdensome agreements;
change the nature of the Partnership’s business; and
make certain amendments to the Partnership’sFourth Amended and Restated Agreement of Limited Partnership of the Partnership (the “Partnership’s partnership agreement.agreement”).
At
September 30,Management evaluates whether conditions and/or events raise substantial doubt about the Partnership’s ability to continue as a going concern within one year after the date that the consolidated financial statements are issued (the “assessment period”). In performing this assessment, management considered the risk associated with its ongoing ability to meet the financial covenants.
Based on current operating plansthe Partnership’s forecasted credit agreement EBITDA during the assessment period, management believes that it will remain in compliance with these financial covenants (as described below). However, there are certain inherent risks associated with our continued ability to comply with our consolidated total leverage ratio covenant. These risks relate, among other things, to potential future (a) decreases in storage volumes and forecasts,rates as well as throughput and transportation rates realized; (b) weather phenomenon that may potentially hinder the Partnership’s asphalt business activity; and (c) other items affecting forecasted levels of expenditures and uses of cash resources. Violation of the consolidated total leverage ratio covenant would be an event of default under the credit agreement, which would cause our $258.6 million in outstanding debt, as of September 30, 2019, to become immediately due and payable. If this were to occur, the Partnership expectswould not expect to have sufficient liquidity to repay these outstanding amounts then due, which could cause the lenders under the credit facility to pursue other remedies. Such remedies could include exercising their collateral rights to the Partnership’s assets.
Based on management’s current forecasts, management believes the Partnership will be able to comply with the consolidated total leverage ratio during the assessment period. However, the Partnership cannot make any assurances that it will be able to achieve management’s forecasts. If the Partnership is unable to achieve management’s forecasts, further actions may be necessary to remain in compliance with all covenants of its credit agreement for the next 12 months, however with less clearance, given the impact of the third quarter of 2018 results on the trailing twelve-monthPartnership’s consolidated total leverage ratio covenant calculations. There areincluding, but not limited to, cost reductions, common and preferred unitholder distribution curtailments, and/or asset sales. The Partnership can make no assurances that it would be successful in undertaking these actions or that the Partnership can achieve this plan.
The credit agreement permits the Partnership to make quarterly distributions of available cash (as defined in the Partnership’s partnership agreement) to unitholders so long as no default or event of default exists under the credit agreement on a pro forma basis after giving effect to such distribution, provided, however, commencing with the fiscal quarter ending September 30, 2018, in no event shall aggregate quarterly distributions in any individual fiscal quarter exceed $10.7 million through, and including, the fiscal quarter ending December 31, 2019. The Partnership is currently allowed to make distributions to its unitholders in accordance with this covenant; however, the Partnership will only make distributions to the extent it has sufficient cash from operations after establishment of cash reserves as determined by the Board of Directors (the “Board”) of Blueknight Energy Partners G.P., L.L.CL.L.C. (the “general partner”) in accordance with the Partnership’s cash distribution policy, including the establishment of any reserves for the proper conduct of the Partnership’s business. See Note 98 for additional information regarding distributions.
In addition to other customary events of default, the credit agreement includes an event of default if:
(i) | the general partner ceases to own 100% of the Partnership’s general partner interest or ceases to control the Partnership; |
(ii) | Ergon ceases to own and control 50% or more of the membership interests of the general partner; or |
(iii) | during any period of 12 consecutive months, a majority of the members of the Board of the general partner ceases to be composed of individuals: |
(A) | who were members of the Board on the first day of such period; |
(B) | whose election or nomination to the Board was approved by individuals referred to in clause (A) above constituting at the time of such election or nomination at least a majority of the Board; or |
(C) | whose election or nomination to the Board was approved by individuals referred to in clauses (A) and (B) above constituting at the time of such election or nomination at least a majority of the Board, provided that any changes to the composition of individuals serving as members of the Board approved by Ergon will not cause an event of default. |
If an event of default relating to bankruptcy or other insolvency events occurs with respect to the general partner or the Partnership, all indebtedness under the credit agreement will immediately become due and payable. If any other event of default exists under the credit agreement, the lenders may accelerate the maturity of the obligations outstanding under the credit agreement and exercise other rights and remedies. In addition, if any event of default exists under the credit agreement, the lenders may commence foreclosure or other actions against the collateral.
If any default occurs under the credit agreement, or if the Partnership is unable to make any of the representations and warranties in the credit agreement, the Partnership will be unable to borrow funds or to have letters of credit issued under the credit agreement.
Upon the execution of the first amendment to its credit agreement in June 2018.2018, the Partnership expensed $0.4 million of debt issuance costs due to the reduction in available borrowing capacity. The Partnership capitalized $0.2less than $0.1 million and less than $0.1$0.4 million of debt issuance costs during each of the three months ended September 30, 2017 and 2018, respectively. The Partnership capitalized $4.2 million and $0.4 million of debt issuance costs during the nine months ended September 30, 2017 and 2018, respectively. Debt issuance costs are being amortized over the term of the credit agreement. Interest expense related to debt issuance cost amortization for each ofboth the three months ended September 30, 20172019 and 2018, was $0.3$0.3 million. Interest expense related to debt issuance cost amortization for both the nine months ended September 30, 20172018 and 2018,2019, was $0.9 million and $0.8 million, respectively.
During the three months ended September 30, 20172018 and 2018,2019, the weighted average interest rate under the Partnership’s credit agreement was 4.54%5.65% and 5.65%5.90%, respectively, resulting in interest expense of approximately $3.5$4.1 million and $4.1$4.0 million, respectively. During the nine months ended September 30, 20172018 and 2018,2019, the weighted average interest rate under the Partnership’s credit agreement, excluding the $0.7 million and $0.4 million respectively, of debt issuance costs in 2018 that were expensed as described above, was 4.36%5.33% and 5.33%6.20%, respectively, resulting in interest expense of approximately $10.2$12.6 million and $12.6$12.3 million, respectively.
The Partnership is exposed to market risk for changes in interest rates related to its credit agreement. Interest rate swap agreements are sometimes used to manage a portion of the exposure related to changing interest rates by converting floating-rate debt to fixed-rate debt. As of December 31, 2017, and September 30, 2018,2019, the Partnership had no interest rate swap agreements with notional amounts totaling $200.0 million and $100.0 million, respectively, to hedge the variability of its LIBOR-basedagreements; interest payments. An interest rate swap agreement with a notional amount of $100.0 million expired on June 28, 2018. Interest rate swap agreements with notional amounts totaling $100.0 million will maturematured on January 28, 2019. During the three months ended September 30, 2017 and 2018, the Partnership recorded swap interest expenseincome of $0.3 millionless than $0.1 million. During the nine months ended September 30, 2018 and 2019, the Partnership recorded swap interest income of less than $0.1 million respectively. During the nine months ended September 30, 2017 and 2018, the Partnership recorded swap interest expense of $1.1 million and swap interest income of less than $0.1 million, respectively.for both periods. The interest rate swaps dodid not receive hedge accounting treatment under
The following provides information regarding the Partnership’s assets and liabilities related to its interest rate swap agreements as of the periods indicated (in thousands):
Fair Value of Derivatives | ||||||
Derivatives Not Designated as Hedging Instruments | Balance Sheet Location | December 31, 2018 | ||||
Interest rate swap assets - current | Other current assets | $ | 44 |
Derivatives Not Designated as Hedging Instruments | Balance Sheet Location | Fair Value of Derivatives | ||||||||
December 31, 2017 | September 30, 2018 | |||||||||
Interest rate swap assets - current | Other current assets | $ | 68 | $ | 120 | |||||
Interest rate swap liabilities - noncurrent | Long-term interest rate swap liabilities | $ | 225 | $ | — |
Changes in the fair value of the interest rate swaps are reflected in the unaudited condensed consolidated statements of operations as follows (in thousands):
Derivatives Not Designated as Hedging Instruments | Location of Gain (Loss) Recognized in Net Income on Derivatives | Amount of Gain (Loss) Recognized in Net Income on Derivatives | |||||||||||
Three Months ended September 30, | Nine Months ended September 30, | ||||||||||||
2018 | 2018 | 2019 | |||||||||||
Interest rate swaps | Interest expense | $ | (37 | ) | $ | 277 | $ | (44 | ) |
Derivatives Not Designated as Hedging Instruments | Location of Gain (Loss) Recognized in Net Income on Derivatives | Amount of Gain (Loss) Recognized in Net Income on Derivatives | ||||||||||||||||
Three Months ended September 30, | Nine Months ended September 30, | |||||||||||||||||
2017 | 2018 | 2017 | 2018 | |||||||||||||||
Interest rate swaps | Interest expense, net of capitalized interest | $ | 278 | $ | (37 | ) | $ | 1,253 | $ | 277 |
7. | NET INCOME PER LIMITED PARTNER UNIT |
For purposes of calculating earnings per unit, the excess of distributions over earnings or excess of earnings over distributions for each period are allocated to the Partnership’s general partner based on the general partner’s ownership interest at the time. The following sets forth the computation of basic and diluted net income per common unit (in thousands, except per unit data):
Three Months ended September 30, | Nine Months ended September 30, | |||||||||||||||
2018 | 2019 | 2018 | 2019 | |||||||||||||
Net income | $ | 2,408 | $ | 6,959 | $ | 8,635 | $ | 14,072 | ||||||||
General partner interest in net income | 39 | 110 | 298 | 268 | ||||||||||||
Preferred interest in net income | 6,279 | 6,278 | 18,836 | 18,836 | ||||||||||||
Net income (loss) available to limited partners | $ | (3,910 | ) | $ | 571 | $ | (10,499 | ) | $ | (5,032 | ) | |||||
Basic and diluted weighted average number of units: | ||||||||||||||||
Common units | 40,380 | 40,811 | 40,331 | 40,735 | ||||||||||||
Restricted and phantom units | 1,090 | 1,130 | 1,019 | 1,004 | ||||||||||||
Total units | 41,470 | 41,941 | 41,350 | 41,739 | ||||||||||||
Basic and diluted net income (loss) per common unit | $ | (0.09 | ) | $ | 0.01 | $ | (0.25 | ) | $ | (0.12 | ) |
Three Months ended September 30, | Nine Months ended September 30, | ||||||||||||||
2017 | 2018 | 2017 | 2018 | ||||||||||||
Net income | $ | 9,771 | $ | 2,408 | $ | 19,684 | $ | 8,635 | |||||||
General partner interest in net income | 312 | 39 | 777 | 298 | |||||||||||
Preferred interest in net income | 6,279 | 6,279 | 18,837 | 18,836 | |||||||||||
Net income (loss) available to limited partners | $ | 3,180 | $ | (3,910 | ) | $ | 70 | $ | (10,499 | ) | |||||
Basic and diluted weighted average number of units: | |||||||||||||||
Common units | 38,189 | 40,380 | 38,164 | 40,331 | |||||||||||
Restricted and phantom units | 922 | 1,090 | 845 | 1,019 | |||||||||||
Total units | 39,111 | 41,470 | 39,009 | 41,350 | |||||||||||
Basic and diluted net income (loss) per common unit | $ | 0.08 | $ | (0.09 | ) | $ | — | $ | (0.25 | ) |
8. | PARTNERS’ CAPITAL AND DISTRIBUTIONS |
On December 1, 2017, the Partnership issued 1.9 million common units to Ergon in a private placement valued at $10.2 million in exchange for an asphalt terminalling facility in Bainbridge, Georgia.
In addition, on October 23, 2018, the Board approved a cash distribution of
9. | RELATED-PARTY TRANSACTIONS |
The Partnership leases asphalt facilities and provides asphalt terminalling services to Ergon. For the three months ended September 30, 20172018 and 2018,2019, the Partnership recognized related-party revenues of $14.5$11.1 million and $11.1$9.3 million, respectively, for services provided to Ergon. For the nine months ended September 30, 20172018 and 2018,2019, the Partnership recognized related-party revenues of $41.3$38.6 million and $38.6$27.2 million, respectively, for services provided to Ergon. As of December 31, 2017,2018, and September 30, 2018,2019, the Partnership had receivables from Ergon of $3.1$1.0 million and $1.6$1.8 million, respectively, net of allowance for doubtful accounts.respectively. As of December 31, 2017,2018, and September 30, 2018,2019, the Partnership had unearned revenues from Ergon of $1.6$6.5 million and $3.6$4.2 million, respectively.
Effective April 1, 2018, the Partnership entered into an agreement with Ergon under which the Partnership purchases crude oil in connection with its crude oil marketing operations. For the three and nine months ended September 30, 2018 and 2019, the Partnership made purchases of crude oil under this agreement totaling $44.4$44.4 million and $74.9$32.8 million, respectively. For the nine months ended September 30, 2018 and 2019, the Partnership made purchases of crude oil under this agreement totaling $74.9 million and $98.6 million, respectively. As of September 30, 2018,2019, the Partnership had payables to Ergon related to this agreement of $16.7$11.4 million related to the September crude oil settlement cycle, and this balance was paid in full on October 19, 2018.
The Partnership and Ergon have an agreement (the “Agreement”) that gives each party rights concerning the purchase or sale of Ergon’s interest in Cimarron Express, Pipeline, LLC (“Cimarron Express”), subject to certain terms and conditions. The Agreement was filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, filed May 14, 2018. The Cimarron Express willwas planned to be a new 16-inch diameter, 65-mile crude oil pipeline running from northeastern Kingfisher County, Oklahoma to the Partnership’s Cushing, Oklahoma crude oil terminal.terminal, with an originally anticipated in-service date in the second half of 2019. Ergon has formed a Delaware limited liability company, Ergon - Oklahoma Pipeline, LLC (“DEVCO”), which will holdholds Ergon’s 50% membership interest in Cimarron Express. Under the Agreement, the Partnership has the right, at any time, to purchase 100% of the authorized and outstanding member interests in DEVCO from Ergon for the Purchase Price (as defined in the Agreement), which shall be computed by taking Ergon’s total
In December 2018, the Partnership soldand Ergon were informed that Kingfisher Midstream, LLC (“Kingfisher Midstream”) made the decision to suspend future investments in Cimarron Express as Kingfisher Midstream determined that the anticipated volumes from the currently dedicated acreage and the resultant project economics did not support additional investment from Kingfisher Midstream. As of December 31, 2018, Cimarron Express had spent approximately $30.6 million on the pipeline project, primarily related to the purchase of steel pipe and equipment, rights of way and engineering and design services. Cimarron Express recorded a $20.9 million impairment charge in the fourth quarter of 2018 to reduce the carrying amount of its assets to their estimated fair value. Ergon recorded a $10.0 million other-than-temporary impairment on its investment in Advantage Pipeline. See Note 5Cimarron Express as of December 31, 2018, to reduce its investment to its estimated fair value. As a result, the Partnership considered the SEC staff’s opinions outlined in SAB 107 Topic 5.T Accounting for additional information. ForExpenses or Liabilities Paid by Principal Stockholders. The Agreement was designed to have the Partnership, ultimately and from the onset, bear any risk of loss on the construction of the pipeline project and eventually own a 50% interest in the pipeline. As a result, the Partnership recorded on a push-down basis a $10.0 million impairment of Ergon’s investment in Cimarron Express in its consolidated results of operations during the year ended December 31, 2018, and a contingent liability payable to Ergon as of December 31, 2018. In April 2019, certain assets from the project were sold to a third party for approximately $1.4 million over the fair market value that was estimated at December 31, 2018, and the Partnership recorded its share, on a push-down basis, based on Ergon’s 50% interest in the assets. Ergon’s interest in DEVCO includes its capital contributions, its share of the cash received for the assets sale discussed above and internal Ergon labor costs, which brings its investment in DEVCO to approximately $10.4 million through September 30, 2019. During the nine months ended September 30, 2017,2019, a change in estimate and accrued interest resulted in the Partnership earned revenuesrecording additional impairment expense of $0.3$2.0 million. The Partnership’s contingent liability as of September 30, 2019, consists of Ergon’s $10.4 million for services providedinvestment plus accrued interest of $1.7 million, of which $0.4 million relates to Advantage Pipeline.the three months ended September 30, 2019.
On September 5, 2019, the management committee of Cimarron Express met and voted to terminate the project pipeline, wind up the business of Cimarron Express, distribute to its members the cash and assets of Cimarron Express, and thereafter dissolve the company. Ergon and Kingfisher Midstream are in the process of negotiating final agreements to windup the business, distribute the assets, and dissolve Cimarron Express.
10. | LONG-TERM INCENTIVE PLAN |
In July 2007, the general partner adopted the Long-Term Incentive Plan (the “LTIP”), which is administered by the compensation committee of the Board. Effective April 29, 2014, the Partnership’s unitholders approved an amendment to the LTIP to increase the number of common units reserved for issuance under the incentive plan to 4,100,000 common units, subject to adjustments for certain events. Although other types of awards are contemplated under the LTIP, currently outstanding awards include “phantom” units, which convey the right to receive common units upon vesting, and “restricted” units, which are grants of common units restricted until the time of vesting. The phantom unit awards also include distribution equivalent rights (“DERs”).
Subject to applicable earning criteria, a DER entitles the grantee to a cash payment equal to the cash distribution paid on an outstanding common unit prior to the vesting date of the underlying award. Recipients of restricted and phantom units are entitled to receive cash distributions paid on common units during the vesting period which are reflected initially as a reduction of partners’ capital. Distributions paid on units which ultimately do not vest are reclassified as compensation expense. Awards granted to date are equity awards and, accordingly, the fair value of the awards as of the grant date is expensed over the vesting period.
Restricted common units are granted to the independent directors.directors on each anniversary of joining the Board. The units vest in one-third increments over three years. The following table includes information on outstanding grants made to the directors under the LTIP:
Grant Date | Number of Units | Weighted Average Grant Date Fair Value(1) | Grant Date Total Fair Value (in thousands) | |||||||||
December 2016 | 10,950 | $ | 6.85 | $ | 75 | |||||||
December 2017 | 15,306 | $ | 4.85 | $ | 74 | |||||||
December 2018 | 23,436 | $ | 1.20 | $ | 28 |
Grant Date | Number of Units | Weighted Average Grant Date Fair Value(1) | Grant Date Total Fair Value | |||||||
(in thousands) | ||||||||||
December 2016 | 10,950 | $ | 6.85 | $ | 75 | |||||
December 2017 | 15,306 | $ | 4.85 | $ | 74 |
(1) | Fair value is the closing market price on the grant date of the awards. |
In addition, the independent directors received common unit grants that have no vesting requirement as part of their compensation. The following table includes information on grants made to the directors under the LTIP that have no vesting requirement:
Grant Date | Number of Units | Weighted Average Grant Date Fair Value(1) | Grant Date Total Fair Value (in thousands) | |||||||||
December 2016 | 10,220 | $ | 6.85 | $ | 70 | |||||||
December 2017 | 14,286 | $ | 4.85 | $ | 69 | |||||||
December 2018 | 21,875 | $ | 1.20 | $ | 26 |
Grant Date | Number of Units | Weighted Average Grant Date Fair Value(1) | Grant Date Total Fair Value | |||||||
(in thousands) | ||||||||||
December 2016 | 10,220 | $ | 6.85 | $ | 70 | |||||
December 2017 | 14,286 | $ | 4.85 | $ | 69 |
(1) | Fair value is the closing market price on the grant date of the awards. |
The Partnership also grants phantom units to employees. These grants are equity awards under
ASC 718 – Stock Compensation and, accordingly, the fair value of the awards as of the grant date is expensed over the three-year vesting period. The following table includes information on the outstanding grants:Grant Date | Number of Units | Weighted Average Grant Date Fair Value(1) | Grant Date Total Fair Value (in thousands) | |||||||||
March 2017 | 323,339 | $ | 7.15 | $ | 2,312 | |||||||
March 2018 | 457,984 | $ | 4.77 | $ | 2,185 | |||||||
March 2019 | 524,997 | $ | 1.14 | $ | 598 | |||||||
June 2019 | 46,168 | $ | 1.08 | $ | 50 |
Grant Date | Number of Units | Weighted Average Grant Date Fair Value(1) | Grant Date Total Fair Value | |||||||
(in thousands) | ||||||||||
March 2016 | 416,131 | $ | 4.77 | $ | 1,985 | |||||
October 2016 | 9,960 | $ | 5.85 | $ | 58 | |||||
March 2017 | 323,339 | $ | 7.15 | $ | 2,312 | |||||
March 2018 | 457,984 | $ | 4.77 | $ | 2,185 |
(1) | Fair value is the closing market price on the grant date of the awards. |
The unrecognized estimated compensation cost of outstanding phantom and restricted units at
September 30,The Partnership’s equity-based incentive compensation expense for the three months ended September 30, 20172018 and 2018,2019, was $0.6$0.7 million and $0.7$0.3 million, respectively. The Partnership’s equity-based incentive compensation expense for the nine months ended September 30, 20172018 and 2018,2019, was $1.7$1.8 million and $1.8$0.8 million, respectively.
Activity pertaining to phantom and restricted common unit awards granted under the LTIP is as follows:
Number of Units | Weighted Average Grant Date Fair Value | |||||||
Nonvested at December 31, 2018 | 998,219 | $ | 5.88 | |||||
Granted | 571,165 | 1.14 | ||||||
Vested | 366,282 | 4.80 | ||||||
Forfeited | 104,758 | 4.10 | ||||||
Nonvested at September 30, 2019 | 1,098,344 | $ | 3.45 |
Number of Units | Weighted Average Grant Date Fair Value | |||||
Nonvested at December 31, 2017 | 923,551 | $ | 6.29 | |||
Granted | 457,984 | 4.77 | ||||
Vested | 271,760 | 7.24 | ||||
Forfeited | 106,521 | 5.43 | ||||
Nonvested at September 30, 2018 | 1,003,254 | $ | 5.88 |
11. | EMPLOYEE BENEFIT PLANS |
Under the Partnership’s 401(k) Plan, which was instituted in
2009,The Partnership may also make annual lump-sum contributions to the 401(k) Plan irrespective of the employee’s contribution match. The Partnership may make a discretionary annual contribution in the form of profit sharing calculated as a percentage of an employee’s eligible compensation. This contribution is retirement income under the qualified 401(k) Plan. Annual profit sharing contributions to the 401(k) Plan are submitted to and approved by the Board. The Partnership recognized expense of $0.2less than $0.1 million and less than $0.1$0.2 million for the three months ended September 30, 20172018 and 2018,2019, respectively, for discretionary profit sharing contributions under the 401(k) Plan. The Partnership recognized expense of $0.6$0.1 million and $0.1$0.5 million for the nine months ended September 30, 20172018 and 2018,2019, respectively, for discretionary profit sharing contributions under the 401(k) Plan.
Under the Partnership’s Employee Unit Purchase Plan (the “Unit Purchase Plan”), which was instituted in January 2015, employees have the opportunity to acquire or increase their ownership of common units representing limited partner interests in the Partnership. Eligible employees who enroll in the Unit Purchase Plan may elect to have a designated whole percentage, up to a specified maximum, of their eligible compensation for each pay period withheld for the purchase of common units at a discount to the then current market value. A maximum of 1,000,000 common units may be delivered under the Unit Purchase Plan, subject to adjustment for a recapitalization, split, reorganization, or similar event pursuant to the terms of the Unit Purchase Plan. The Partnership recognized compensation expense of less than $0.1$0.1 million duringfor the each of the three and nine months
12. | FAIR VALUE MEASUREMENTS |
The Partnership uses valuation techniques, such as the market approach (comparable market prices), the income approach (present value of future income or cash flow), and the cost approach (cost to replace the service capacity of an asset or replacement cost) to value assets and liabilities required to be measured at fair value, as appropriate. The Partnership uses an exit price when determining the fair value. The exit price represents amounts that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants.
The Partnership utilizes a three-tier fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three broad levels. The following is a brief description of those three levels:
Level 1 | Observable inputs such as quoted prices (unadjusted) in active markets for identical assets or liabilities. |
Level 2 | Inputs other than quoted prices that are observable for these assets or liabilities, either directly or indirectly. These include quoted prices for similar assets or liabilities in active markets and quoted prices for identical or similar assets or liabilities in markets that are not active. |
Level 3 | Unobservable inputs in which there is little market data, which requires the reporting entity to develop its own assumptions. |
This hierarchy requires the use of observable market data, when available, to minimize the use of unobservable inputs when determining fair value. In periods in which they occur, the Partnership recognizes transfers into and out of Level 3 as of the end of the reporting period. There were no transfers during the nine months ended September 30, 2018.2019. Transfers out of Level 3 represent existing assets and liabilities that were classified previously as Level 3 for which the observable inputs became a more significant portion of the fair value estimates. Determining the appropriate classification of the Partnership’s fair value measurements within the fair value hierarchy requires management’s judgment regarding the degree to which market data is observable or corroborated by observable market data.
The Partnership’s recurring financial assets and liabilities subject to fair value measurements and the necessary disclosures are as follows (in thousands):
Fair Value Measurements as of December 31, 2018 | ||||||||||||||||
Quoted Prices | Significant | |||||||||||||||
in Active | Other | Significant | ||||||||||||||
Markets for | Observable | Unobservable | ||||||||||||||
Identical Assets | Inputs | Inputs | ||||||||||||||
Description | Total | (Level 1) | (Level 2) | (Level 3) | ||||||||||||
Assets: | ||||||||||||||||
Interest rate swap assets | $ | 44 | $ | - | $ | 44 | $ | - | ||||||||
Total swap assets | $ | 44 | $ | - | $ | 44 | $ | - |
As of September 30, 2019, the Partnership had no interest rate swap agreements.
Fair Value Measurements as of December 31, 2017 | |||||||||||||||
Description | Total | Quoted Prices in Active Markets for Identical Assets (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Unobservable Inputs (Level 3) | |||||||||||
Assets: | |||||||||||||||
Interest rate swap assets | $ | 68 | $ | — | $ | 68 | $ | — | |||||||
Total swap assets | $ | 68 | $ | — | $ | 68 | $ | — | |||||||
Liabilities: | |||||||||||||||
Interest rate swap liabilities | $ | 225 | $ | — | $ | 225 | $ | — | |||||||
Total swap liabilities | $ | 225 | $ | — | $ | 225 | $ | — |
Fair Value Measurements as of September 30, 2018 | |||||||||||||||
Description | Total | Quoted Prices in Active Markets for Identical Assets (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Unobservable Inputs (Level 3) | |||||||||||
Assets: | |||||||||||||||
Interest rate swap assets | $ | 120 | $ | — | $ | 120 | $ | — | |||||||
Total swap assets | $ | 120 | $ | — | $ | 120 | $ | — |
Fair Value of Other Financial Instruments
The following disclosure of the estimated fair value of financial instruments is made in accordance with accounting guidance for financial instruments. The Partnership has determined the estimated fair values by using available market information and valuation methodologies. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.
At September 30, 2018,2019, the carrying values on the unaudited condensed consolidated balance sheets for cash and cash equivalents (classified as Level 1), accounts receivable, and accounts payable approximate their fair value because of their short-term nature.
Based on the borrowing rates currently available to the Partnership for credit agreement debt with similar terms and maturities and consideration of the Partnership’s non-performance risk, long-term debt associated with the Partnership’s credit agreement at September 30, 2018,2019, approximates its fair value. The fair value of the Partnership’s long-term debt was calculated using observable inputs (LIBOR for the risk-free component) and unobservable company-specific credit spread information. As such, the Partnership considers this debt to be Level 3.
13. | LEASES |
The Partnership adopted ASC 842 as of January 1, 2019, using the modified retrospective approach applied at the beginning of the period of adoption. The Partnership elected the package of practical expedients permitted under the transition guidance within the new standard, which, among other things, allowed it to carry forward the historical lease classification.
Adoption of the new standard resulted in the recording of additional net right of use operating lease assets and operating lease liabilities of approximately $11.8 million and $11.9 million, respectively, as of January 1, 2019. The standard did not materially impact the consolidated statement of operations and had no impact on cash flows.
The Partnership leases certain office space, land and equipment. Leases with an initial term of 12 months or less are not recorded on the balance sheet; lease expense for these leases is recognized as paid over the lease term. For real property leases, the Partnership has elected the practical expedient to not separate nonlease components (e.g., common-area maintenance costs) from lease components and to instead account for each component as a single lease component. For leases that do not contain an implicit interest rate, the Partnership uses its most recent incremental borrowing rate.
Some real property and equipment leases contain options to renew, with renewal terms that can extend indefinitely. The exercise of such lease renewal options is at the Partnership’s sole discretion. Certain equipment leases also contain purchase options and residual value guarantees. The Partnership determines the lease term at the lease commencement date as the non-cancellable period of the lease, including options to extend or terminate the lease when such an option is reasonably certain to be exercised. The Partnership uses various data to analyze these options, including historical trends, current expectations and useful lives of assets related to the lease.
As of | |||||
Classification | September 30, 2019 | ||||
(thousands) | |||||
Assets | |||||
Operating lease assets | Operating lease assets | $ | 11,374 | ||
Finance lease assets | Other noncurrent assets | 839 | |||
Total leased assets | $ | 12,213 | |||
Liabilities | |||||
Current | |||||
Operating lease liabilities | Current operating lease liability | $ | 2,479 | ||
Finance lease liabilities | Other current liabilities | 336 | |||
Noncurrent | |||||
Operating lease liabilities | Noncurrent operating lease liability | 8,968 | |||
Finance lease liabilities | Other long-term liabilities | 503 | |||
Total lease liabilities | $ | 12,286 |
Future commitments, including options to extend lease terms that are reasonably certain of being exercised, related to leases at September 30, 2019, are summarized below (in thousands):
Operating Leases | Financing Leases | |||||||
Twelve months ending September 30, 2020 | $ | 2,696 | $ | 369 | ||||
Twelve months ending September 30, 2021 | 2,349 | 296 | ||||||
Twelve months ending September 30, 2022 | 1,569 | 183 | ||||||
Twelve months ending September 30, 2023 | 1,470 | 48 | ||||||
Twelve months ending September 30, 2024 | 969 | 2 | ||||||
Thereafter | 6,199 | - | ||||||
Total | 15,252 | 898 | ||||||
Less: Interest | 3,805 | 60 | ||||||
Present value of lease liabilities | $ | 11,447 | $ | 838 |
Future non-cancellable commitments related to operating leases at December 31, 2018, are summarized below (in thousands):
Operating Leases | ||||
Year ending December 31, 2019 | $ | 2,862 | ||
Year ending December 31, 2020 | 1,904 | |||
Year ending December 31, 2021 | 1,242 | |||
Year ending December 31, 2022 | 640 | |||
Year ending December 31, 2023 | 548 | |||
Thereafter | 1,259 | |||
Total future minimum lease payments | $ | 8,455 |
The following table summarizes the Partnership’s total lease cost by type as well as cash flow information (in thousands):
Three Months ended September 30, | Nine Months ended September 30, | ||||||||
Classification | 2019 | 2019 | |||||||
Total Lease Cost by Type: | |||||||||
Operating lease cost(1) | Operating Expense | $ | 1,085 | $ | 3,281 | ||||
Finance lease cost | |||||||||
Amortization of leased assets | Operating Expense | 85 | 236 | ||||||
Interest on lease liabilities | Interest Expense | 10 | 27 | ||||||
Net lease cost | $ | 1,180 | $ | 3,544 | |||||
Supplemental cash flow disclosures: | |||||||||
Cash paid for amounts included in the measurement of lease liabilities: | |||||||||
Operating cash flows from operating leases | $ | 2,195 | |||||||
Operating cash flows from finance leases | $ | 77 | |||||||
Financing cash flows from finance leases | $ | 201 | |||||||
Leased assets obtained in exchange for new operating lease liabilities | $ | 1,714 | |||||||
Leased assets obtained in exchange for new finance lease liabilities | $ | 520 |
(1) | Includes short-term and variable lease costs, which are immaterial. |
As of | ||||
Lease Term and Discount Rate | September 30, 2019 | |||
Weighted-average remaining lease term (years) | ||||
Operating leases | 9.7 | |||
Finance leases | 2.8 | |||
Weighted-average discount rate | ||||
Operating leases | 5.78 | % | ||
Finance leases | 4.83 | % |
The Partnership also incurs costs associated with acquiring and maintaining rights-of-way. The contracts for these generally either extend beyond one year but can be cancelled at any time should they no longer be required for operations or have no contracted term but contain perpetual annual or monthly renewal options. Rights-of-way generally do not provide for exclusive use of the land and as such are not accounted for as leases.
14. | OPERATING SEGMENTS |
The Partnership’s operations consist of
fourASPHALT TERMINALLING SERVICES
—The Partnership provides asphalt product and residual fuel terminalling services, including storage, blending, processing and throughput services. On July 12, 2018, the Partnership sold three asphalt facilities. See Note 6 for additional information. The Partnership has 53 terminalling facilities located in 26 states.CRUDE OIL TERMINALLING SERVICES
—The Partnership provides crude oil terminalling services at its terminalling facility located in Oklahoma.CRUDE OIL PIPELINE SERVICES
—The Partnership owns and operates pipeline systems that gather crude oil purchased by its customers and transports it to refiners, to common carrier pipelines for ultimate delivery to refiners or to terminalling facilities owned by the Partnership and others. The Partnership refers to its pipeline system located in Oklahoma and the Texas Panhandle as the Mid-Continent pipeline system.CRUDE OIL TRUCKING SERVICES
— The Partnership uses its owned and leased tanker trucks to gather crude oil for its customers at remote wellhead locations generally not covered by pipeline and gathering systems and to transport the crude oil to aggregation points and storage facilities located along pipeline gathering and transportation systems.The Partnership’s management evaluates segment performance based upon operating margin, excluding amortization and depreciation, which includes revenues from related parties and external customers and operating expense, excluding depreciation and amortization. The non-GAAP measure of operatingOperating margin, excluding depreciation and amortization (in the aggregate and by segment) is presented in the following table. The Partnership computes the components of operating margin, excluding depreciation and amortization by using amounts that are determined in accordance with GAAP. The Partnership accounts for intersegment product sales as if the sales were to third parties, that is, at current market prices. A reconciliation of operating margin, excluding depreciation and amortization to income before income taxes, which is its nearest comparable GAAP financial measure, is included in the following table. The Partnership believes that investors benefit from having access to the same financial measures being utilized by management. Operating margin, excluding depreciation and amortization is an important measure of the economic performance of the Partnership’s core operations. This measure forms the basis of the Partnership’s internal financial reporting and is used by its management in deciding how to allocate capital resources among segments. Income before income taxes, alternatively, includes expense items, such as depreciation and amortization, general and administrative expenses and interest expense, which management does not consider when evaluating the core profitability of the Partnership’s operations.
The following table reflects certain financial data for each segment for the periods indicated (in thousands):
Three Months ended September 30, | Nine Months ended September 30, | |||||||||||||||
2018 | 2019 | 2018 | 2019 | |||||||||||||
Asphalt Terminalling Services | ||||||||||||||||
Service revenue: | ||||||||||||||||
Third-party revenue | $ | 6,921 | $ | 7,385 | $ | 18,693 | $ | 21,217 | ||||||||
Related-party revenue | 5,211 | 3,892 | 17,512 | 11,991 | ||||||||||||
Lease revenue: | ||||||||||||||||
Third-party revenue | 11,288 | 11,444 | 30,762 | 31,026 | ||||||||||||
Related-party revenue | 5,406 | 5,427 | 20,584 | 15,179 | ||||||||||||
Product sales revenue: | ||||||||||||||||
Related-party revenue | 482 | - | 482 | - | ||||||||||||
Total revenue for reportable segment | 29,308 | 28,148 | 88,033 | 79,413 | ||||||||||||
Operating expense, excluding depreciation and amortization | 11,683 | 11,025 | 38,412 | 34,980 | ||||||||||||
Operating margin, excluding depreciation and amortization | $ | 17,625 | $ | 17,123 | $ | 49,621 | $ | 44,433 | ||||||||
Total assets (end of period) | $ | 143,454 | $ | 145,761 | $ | 143,454 | $ | 145,761 | ||||||||
Crude Oil Terminalling Services | ||||||||||||||||
Service revenue: | ||||||||||||||||
Third-party revenue | $ | 1,923 | $ | 4,225 | $ | 9,418 | $ | 11,819 | ||||||||
Intersegment revenue | 222 | 278 | 392 | 853 | ||||||||||||
Lease revenue: | ||||||||||||||||
Third-party revenue | 9 | - | 35 | - | ||||||||||||
Total revenue for reportable segment | 2,154 | 4,503 | 9,845 | 12,672 | ||||||||||||
Operating expense, excluding depreciation and amortization | 928 | 1,212 | 3,115 | 3,511 | ||||||||||||
Operating margin, excluding depreciation and amortization | $ | 1,226 | $ | 3,291 | $ | 6,730 | $ | 9,161 | ||||||||
Total assets (end of period) | $ | 67,213 | $ | 66,045 | $ | 67,213 | $ | 66,045 |
Three Months ended September 30, | Nine Months ended September 30, | |||||||||||||||
2018 | 2019 | 2018 | 2019 | |||||||||||||
Crude Oil Pipeline Services | ||||||||||||||||
Service revenue: | ||||||||||||||||
Third-party revenue | $ | 1,165 | $ | 1,284 | $ | 4,270 | $ | 5,753 | ||||||||
Related-party revenue | 185 | 64 | 268 | 266 | ||||||||||||
Lease revenue: | ||||||||||||||||
Third-party revenue | 40 | - | 452 | - | ||||||||||||
Product sales revenue: | ||||||||||||||||
Third-party revenue | 97,763 | 55,213 | 146,882 | 173,773 | ||||||||||||
Total revenue for reportable segment | 99,153 | 56,561 | 151,872 | 179,792 | ||||||||||||
Operating expense, excluding depreciation and amortization | 3,094 | 2,638 | 8,420 | 8,109 | ||||||||||||
Intersegment operating expense | 1,644 | 1,642 | 3,243 | 4,971 | ||||||||||||
Third-party cost of product sales | 50,815 | 18,972 | 73,493 | 64,069 | ||||||||||||
Related-party cost of product sales | 44,106 | 32,691 | 67,853 | 99,886 | ||||||||||||
Operating margin, excluding depreciation and amortization | $ | (506 | ) | $ | 618 | $ | (1,137 | ) | $ | 2,757 | ||||||
Total assets (end of period) | $ | 171,841 | $ | 96,221 | $ | 171,841 | $ | 96,221 | ||||||||
Crude Oil Trucking Services | ||||||||||||||||
Service revenue | ||||||||||||||||
Third-party revenue | $ | 2,734 | $ | 2,822 | $ | 11,783 | 8,540 | |||||||||
Intersegment revenue | 1,422 | 1,364 | 2,851 | 4,118 | ||||||||||||
Lease revenue: | ||||||||||||||||
Third-party revenue | 31 | - | 160 | - | ||||||||||||
Product sales revenue: | ||||||||||||||||
Third-party revenue | - | - | 10 | - | ||||||||||||
Total revenue for reportable segment | 4,187 | 4,186 | 14,804 | 12,658 | ||||||||||||
Operating expense, excluding depreciation and amortization | 4,303 | 4,053 | 15,405 | 12,515 | ||||||||||||
Operating margin, excluding depreciation and amortization | $ | (116 | ) | $ | 133 | $ | (601 | ) | $ | 143 | ||||||
Total assets (end of period) | $ | 3,731 | $ | 5,948 | $ | 3,731 | $ | 5,948 | ||||||||
Total operating margin, excluding depreciation and amortization(1) | $ | 18,229 | $ | 21,165 | $ | 54,613 | $ | 56,494 | ||||||||
Total Segment Revenues | $ | 134,802 | $ | 93,398 | $ | 264,554 | $ | 284,535 | ||||||||
Elimination of Intersegment Revenues | (1,644 | ) | (1,642 | ) | (3,243 | ) | (4,971 | ) | ||||||||
Consolidated Revenues | $ | 133,158 | $ | 91,756 | $ | 261,311 | $ | 279,564 |
(1) | The following table reconciles segment operating margin (excluding depreciation and amortization) to income before income taxes (in thousands): |
Three Months ended September 30, | Nine Months ended September 30, | |||||||||||||||
2018 | 2019 | 2018 | 2019 | |||||||||||||
Operating margin, excluding depreciation and amortization | $ | 18,229 | $ | 21,165 | $ | 54,613 | $ | 56,494 | ||||||||
Depreciation and amortization | (7,166 | ) | (6,240 | ) | (21,945 | ) | (19,211 | ) | ||||||||
General and administrative expense | (4,322 | ) | (3,840 | ) | (13,029 | ) | (10,495 | ) | ||||||||
Asset impairment expense | (15 | ) | (83 | ) | (631 | ) | (2,316 | ) | ||||||||
Gain (loss) on sale of assets | (63 | ) | (40 | ) | 300 | 1,765 | ||||||||||
Other income | - | - | - | 268 | ||||||||||||
Gain on sale of unconsolidated affiliate | - | - | 2,225 | - | ||||||||||||
Interest expense | (4,090 | ) | (3,989 | ) | (12,683 | ) | (12,394 | ) | ||||||||
Income before income taxes | $ | 2,573 | $ | 6,973 | $ | 8,850 | $ | 14,111 |
Three Months ended September 30, | Nine Months ended September 30, | |||||||||||||||
2017 | 2018 | 2017 | 2018 | |||||||||||||
Asphalt Terminalling Services | ||||||||||||||||
Service revenue: | ||||||||||||||||
Third-party revenue | $ | 17,690 | $ | 6,921 | $ | 44,172 | $ | 18,693 | ||||||||
Related-party revenue | 14,464 | 5,211 | 41,301 | 17,512 | ||||||||||||
Lease revenue: | ||||||||||||||||
Third-party revenue | — | 11,288 | — | 30,762 | ||||||||||||
Related-party revenue | — | 5,406 | — | 20,584 | ||||||||||||
Product sales revenue: | ||||||||||||||||
Related-party revenue | — | 482 | — | 482 | ||||||||||||
Total revenue for reportable segment | 32,154 | 29,308 | 85,473 | 88,033 | ||||||||||||
Operating expense, excluding depreciation and amortization | 11,608 | 11,683 | 35,864 | 38,412 | ||||||||||||
Operating margin, excluding depreciation and amortization | $ | 20,546 | $ | 17,625 | $ | 49,609 | $ | 49,621 | ||||||||
Total assets (end of period) | $ | 142,571 | $ | 143,454 | $ | 142,571 | $ | 143,454 | ||||||||
Crude Oil Terminalling Services | ||||||||||||||||
Service revenue: | ||||||||||||||||
Third-party revenue | $ | 5,162 | $ | 1,923 | $ | 17,013 | $ | 9,418 | ||||||||
Intersegment revenue | — | 222 | — | 392 | ||||||||||||
Lease revenue: | ||||||||||||||||
Third-party revenue | — | 9 | — | 35 | ||||||||||||
Total revenue for reportable segment | 5,162 | 2,154 | 17,013 | 9,845 | ||||||||||||
Operating expense, excluding depreciation and amortization | 994 | 928 | 2,996 | 3,115 | ||||||||||||
Operating margin, excluding depreciation and amortization | $ | 4,168 | $ | 1,226 | $ | 14,017 | $ | 6,730 | ||||||||
Total assets (end of period) | $ | 68,985 | $ | 67,213 | $ | 68,985 | $ | 67,213 | ||||||||
Three Months ended September 30, | Nine Months ended September 30, | |||||||||||||||
2017 | 2018 | 2017 | 2018 | |||||||||||||
Crude Oil Pipeline Services | ||||||||||||||||
Service revenue: | ||||||||||||||||
Third-party revenue | $ | 2,196 | $ | 1,165 | $ | 7,520 | $ | 4,270 | ||||||||
Related-party revenue | — | 185 | 310 | 268 | ||||||||||||
Lease revenue: | ||||||||||||||||
Third-party revenue | — | 40 | — | 452 | ||||||||||||
Product sales revenue: | ||||||||||||||||
Third-party revenue | 2,375 | 97,763 | 8,252 | 146,882 | ||||||||||||
Total revenue for reportable segment | 4,571 | 99,153 | 16,082 | 151,872 | ||||||||||||
Operating expense, excluding depreciation and amortization | 3,056 | 3,094 | 9,438 | 8,420 | ||||||||||||
Intersegment operating expense | 77 | 1,644 | 321 | 3,243 | ||||||||||||
Third-party cost of product sales | 1,675 | 50,815 | 6,482 | 73,493 | ||||||||||||
Related-party cost of product sales | — | 44,106 | — | 67,853 | ||||||||||||
Intersegment cost of product sales | 150 | — | 150 | — | ||||||||||||
Operating margin, excluding depreciation and amortization | $ | (387 | ) | $ | (506 | ) | $ | (309 | ) | $ | (1,137 | ) | ||||
Total assets (end of period) | $ | 116,720 | $ | 171,841 | $ | 116,720 | $ | 171,841 | ||||||||
Crude Oil Trucking Services | ||||||||||||||||
Service revenue | ||||||||||||||||
Third-party revenue | $ | 5,587 | $ | 2,734 | $ | 18,738 | $ | 11,783 | ||||||||
Intersegment revenue | 77 | 1,422 | 321 | 2,851 | ||||||||||||
Lease revenue: | ||||||||||||||||
Third-party revenue | — | 31 | — | 160 | ||||||||||||
Product sales revenue: | ||||||||||||||||
Third-party revenue | — | — | 385 | 10 | ||||||||||||
Intersegment revenue | 150 | — | 150 | — | ||||||||||||
Total revenue for reportable segment | 5,814 | 4,187 | 19,594 | 14,804 | ||||||||||||
Operating expense, excluding depreciation and amortization | 6,042 | 4,303 | 20,013 | 15,405 | ||||||||||||
Operating margin, excluding depreciation and amortization | $ | (228 | ) | $ | (116 | ) | $ | (419 | ) | $ | (601 | ) | ||||
Total assets (end of period) | $ | 9,781 | $ | 3,731 | $ | 9,781 | $ | 3,731 | ||||||||
Total operating margin, excluding depreciation and amortization(1) | $ | 24,099 | $ | 18,229 | $ | 62,898 | $ | 54,613 | ||||||||
Total Segment Revenues | $ | 47,701 | $ | 134,802 | $ | 138,162 | $ | 264,554 | ||||||||
Elimination of Intersegment Revenues | (227 | ) | (1,644 | ) | (471 | ) | (3,243 | ) | ||||||||
Consolidated Revenues | $ | 47,474 | $ | 133,158 | $ | 137,691 | $ | 261,311 |
Three Months ended September 30, | Nine Months ended September 30, | ||||||||||||||
2017 | 2018 | 2017 | 2018 | ||||||||||||
Operating margin, excluding depreciation and amortization | $ | 24,099 | $ | 18,229 | $ | 62,898 | $ | 54,613 | |||||||
Depreciation and amortization | (7,680 | ) | (7,166 | ) | (23,586 | ) | (21,945 | ) | |||||||
General and administrative expense | (4,093 | ) | (4,322 | ) | (13,000 | ) | (13,029 | ) | |||||||
Asset impairment expense | — | (15 | ) | (45 | ) | (631 | ) | ||||||||
Gain (loss) on sale of assets | (107 | ) | (63 | ) | (986 | ) | 300 | ||||||||
Interest expense | (3,500 | ) | (4,090 | ) | (10,795 | ) | (12,683 | ) | |||||||
Gain on sale of unconsolidated affiliate | 1,112 | — | 5,284 | 2,225 | |||||||||||
Equity earnings in unconsolidated affiliate | — | — | 61 | — | |||||||||||
Income before income taxes | $ | 9,831 | $ | 2,573 | $ | 19,831 | $ | 8,850 |
15. | COMMITMENTS AND CONTINGENCIES |
The Partnership is from time to time subject to various legal actions and claims incidental to its business. Management believes that these legal proceedings will not have a material adverse effect on the financial position, results of operations or cash flows of the Partnership. Once management determines that information pertaining to a legal proceeding indicates that it is probable that a liability has been incurred and the amount of such liability can be reasonably estimated, an accrual is established equal to its estimate of the likely exposure.
The Partnership has contractual obligations to perform dismantlement and removal activities in the event that some of its asphalt product and residual fuel oil terminalling and storage assets are abandoned. These obligations include varying levels of activity including completely removing the assets and returning the land to its original state. The Partnership has determined that the settlement dates related to the retirement obligations are indeterminate. The assets with indeterminate settlement dates have been in existence for many years and with regular maintenance will continue to be in service for many years to come. Also, it is not possible to predict when demands for the Partnership’s terminalling and storage services will cease, and the Partnership does not believe that such demand will cease for the foreseeable future. Accordingly, the Partnership believes the date when these assets will be abandoned is indeterminate. With no reasonably determinable abandonment date, the Partnership cannot reasonably estimate the fair value of the associated asset retirement obligations. Management believes that if the Partnership’s asset retirement obligations were settled in the foreseeable future the present value of potential cash flows that would be required to settle the obligations based on current costs are not material. The Partnership will record asset retirement obligations for these assets in the period in which sufficient information becomes available for it to reasonably determine the settlement dates.
16. | INCOME TAXES |
In relation to the Partnership’s taxable subsidiary, the tax effects of temporary differences between the tax basis of assets and liabilities and their financial reporting amounts at September 30, 2018,2019, are presented below (dollars in thousands):
Deferred Tax Asset | ||||
Difference in bases of property, plant and equipment | $ | 236 | ||
Net operating loss carryforwards | 24 | |||
Deferred tax asset | 260 | |||
Less: valuation allowance | 260 | |||
Net deferred tax asset | $ | - |
Deferred Tax Asset | |||
Difference in bases of property, plant and equipment | $ | 291 | |
Net operating loss carryforwards | — | ||
Deferred tax asset | 291 | ||
Less: valuation allowance | 291 | ||
Net deferred tax asset | $ | — |
The Partnership has considered the taxable income projections in future years, whether the carryforward period is so brief that it would limit realization of tax benefits, whether future revenue and operating cost projections will produce enough taxable income to realize the deferred tax asset based on existing service rates and cost structures and the Partnership’s earnings history exclusive of the loss that created the future deductible amount for the Partnership’s subsidiary that is taxed as a corporation for purposes of determining the likelihood of realizing the benefits of the deferred tax assets. As a result of the Partnership’s consideration of these factors, the Partnership has provided a valuation allowance against its deferred tax asset as of September 30, 2018.2019.
17. | RECENTLY ISSUED ACCOUNTING STANDARDS |
Except as discussed below and in the 20172018 Form 10-K, there have been no new accounting pronouncements that have become effective or have been issued during the nine months ended September 30, 2018,2019, that are of significance or potential significance to the Partnership.
In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842)”. This is a comprehensive update to the lease accounting topic in the Codification intended to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The amendments in ASU 2016-02 include a revised definition of a lease as well as certain scope exceptions. The changes primarily impact lessee accounting, while lessor accounting is largely unchanged from previous GAAP.
As used in this quarterly report, unless we indicate otherwise: (1) “Blueknight Energy Partners,” “our,” “we,” “us” and similar terms refer to Blueknight Energy Partners, L.P., together with its subsidiaries, (2) our “General Partner” refers to Blueknight Energy Partners G.P., L.L.C., (3) “Ergon” refers to Ergon, Inc., its affiliates and subsidiaries (other than our General Partner and us) and (4) “Vitol” refers to Vitol Holding B.V., its affiliates and subsidiaries. The following discussion analyzes the historical financial condition and results of operations of the Partnership and should be read in conjunction with our financial statements and notes thereto, and Management’s Discussion and Analysis of Financial Condition and Results of Operations presented in our Annual Report on Form 10-K for the year ended December 31, 2017,2018, which was filed with the Securities and Exchange Commission (the “SEC”) on March 8, 201812, 2019 (the “2017“2018 Form 10-K”).
Forward-Looking Statements
This report contains forward-looking statements. Statements included in this quarterly report that are not historical facts (including any statements regarding plans and objectives of management for future operations or economic performance, or assumptions or forecasts related thereto), including, without limitation, the information set forth in this Management’s Discussion and Analysis of Financial Condition and Results of Operations, are forward-looking statements. These statements can be identified by the use of forward-looking terminology including “may,” “will,” “should,” “believe,” “expect,” “intend,” “anticipate,” “estimate,” “continue,” or other similar words. These statements discuss future expectations, contain projections of results of operations or of financial condition, or state other “forward-looking” information. We and our representatives may from time to time make other oral or written statements that are also forward-looking statements.
Such forward-looking statements are subject to various risks and uncertainties that could cause actual results to differ materially from those anticipated as of the date of the filing of this report. Although we believe that the expectations reflected in these forward-looking statements are based on reasonable assumptions, no assurance can be given that these expectations will prove to be correct. Important factors that could cause our actual results to differ materially from the expectations reflected in these forward-looking statements include, among other things, those set forth in “Part I, Item 1A. Risk Factors” in the 20172018 Form 10-K.
All forward-looking statements included in this report are based on information available to us on the date of this report. We undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the cautionary statements contained throughout this report.
Overview
We are a publicly traded master limited partnership with operations in 27 states. We provide integrated terminalling, gathering and transportation services for companies engaged in the production, distribution and marketing of liquid asphalt and crude oil. We manage our operations through four operating segments: (i) asphalt terminalling services, (ii) crude oil terminalling services, (iii) crude oil pipeline services and (iv) crude oil trucking services. In April 2018, we sold our producer field services business that has been historically reported along with the crude oil trucking services. As a result
Potential Impact of Crude Oil Market Price Changes and Other Matters on Future Revenues
The crude oil market price and the corresponding forward market pricing curve may fluctuate significantly from period to period. In addition, volatility in the overall energy industry and specifically in publicly traded midstream energy partnerships may impact our partnership in the near term. Factors include the overall market price for crude oil and whether or not the forward price curve is in contango (in which future prices are higher than current prices and a premium is placed on storing product and selling at a later time) or backwardated (in which the current crude oil price per barrel is higher than the future price per barrel and a premium is placed on delivering product to market and selling as soon as possible), changes in crude oil production volume and the demand for storage and transportation capacity in the areas in which we serve, geopolitical concerns and overall changes in our cost of capital. As of October 25, 2018,November 1, 2019, the forward price curve is in a shallow contango. Potential impacts of these factors are discussed below.
Asphalt Terminalling Services - AlthoughHistorically, there is nohave only been limited times in which asphalt prices and volumes have had a direct correlation betweenwith the price of crude oil. As a result, we do not expect that changes in the price of crude oil and the price of asphalt, the asphalt industry tends to benefit from a lower crude oil price environment, a strong economy and an increase in
In 2019, the level of customer throughput volumes through our terminals have varied across the country, primarily impacted by weather patterns, refinery disruptions and the customers’ own supply chain needs. The Midwest has been impacted by higher levels of rain earlier in the year that slowed customer throughput; however, activity has increased later in the season to help make up for this. In addition, during the first half of 2019, several of our asphalt plant was affectedfacilities in the Midwest were damaged by Hurricane Florence in September 2018. Damageflooding. While the facilities were able to successfully execute flood plans to minimize damages, costs related to the plant was primarily limitedfloods are expected to include approximately $0.7 million of expenses for cleanup and the removal and reinstallation of equipment and $1.9 million of capital expenditures to restore land improvements and equipment. As of September 30, 2019, $1.3 million of these amounts have been spent. Impairment expense related to the lossassets was $0.3 million. As of insulation on multiple storage tanks. While the impairment of these assets reflected in the three and nine months ended September 30, 2018, is minimal due to the low net book value2019, we have recognized $0.7 million of the assets, anticipated future-period costs to replace the insulation and clean up debris are currently estimated to be approximately $0.6 million, consisting of $0.5 million in maintenance capital expenditures and $0.1 million in maintenance expense.insurance recoveries. While we are pursuing additional insurance claims for this event,these events, there can be no assurance of the amount or timing of any proceeds we may receive under such claims. The majority of revenues earned at the Wilmington facility are fixed fees; however, we anticipate a loss of throughput revenues as we were unable to deliver product out of the terminal for several weeks. In addition, our Bainbridge, Georgia, asphalt plant was affected by Hurricane Michael in October 2018. We are in the early stages of assessing the damages at this facility, and we anticipate the damages to be limited to loss of insulation on multiple storage tanks. We anticipate future-period costs to replace the insulation and clean up debris to be approximately $0.4 million, consisting of $0.3 million in maintenance capital expenditures and $0.1 million in maintenance expense.
On July 12, 2018, we sold certain asphalt terminals, storage tanks and related real property, contracts, permits, assets and other interests located in Lubbock and Saginaw, Texas and Memphis, Tennessee (the “Divestiture”) to Ergon for a purchase price of $90.0 million, subject to customary adjustments.
Crude Oil Terminalling Services - A contango crude oil curve tends to favor the crude oil storage business as crude oil marketers are incentivized to store crude oil during the current month and sell into the future month. Since March 2016, the crude oil curve has generally been in a shallow contango or backwardation. In these shallow contango or backwardated markets there is no clear incentive for marketers to store barrels.crude oil. A shallow contango or a backwardated market may impact our ability to re-contract expiring contracts and/or decrease the storage rate at which we are able to re-contract. Alternatively, despite a shallow contango curve, we have seen increased activity and interests from customers that are regularly turning over their volumes by blending various crude grades and delivering it out of the terminal or customers utilizing the storage for more operational purposes for their downstream operations. As a result of the current shape of the curve and overallthis change in demand factors for Cushing storage, we anticipate a challengingmore complex recontracting environment which may impacthas the potential to affect both the volumevolumes and rate of storage we are able to successfully recontract and the rate at which we recontract.
Crude Oil Pipeline Services - A backwardated crudeCrude oil curve tends to favorpipeline transportation, while potentially influenced by the shape of the crude oil pipeline transportation business as crude oil marketers are incentivized to transport crude oil to market for sale as soon as possible. However, our crude oil pipeline services business has beencurve, is typically impacted recentlymore by an out-of-service pipeline. Betweenoverall drilling activity. From April 2016 andto July 2018, we had been operating onea portion of our Oklahoma pipeline system insteadwas out of two systems, providing us with aservice, which reduced transportation capacity ofby approximately 20,000 to 25,000 barrels per day (Bpd).Bpd. In July 2018, we were able to restore service to a second system which has increased the transportation capacitythat portion of our pipeline systems by approximately 20,000 Bpd.pipeline. The ability to fully utilize the capacity of these systemsthe system may be impacted by the market price of crude oil and producers’ decisions to increase or decrease production in the areas we serve.
Over the third quarter of 2018,past year, we increased the volumes of crude oil transported for our internal crude oil marketing operations with the objective of increasing the overall utilization of our Oklahoma crude oil pipeline systems.system. Typically, the volume of crude oil we purchase in a given month will be sold in the same month. However, we may have market price exposure for inventory that is carried over month-to-month as well as pipeline linefill we maintain. Since our pipeline tariffs require shippers to carry their share of linefill, our crude oil marketing operations, as a shipper, also carries linefill. We may also be exposed to price risk with respect to the differing qualities of crude oil we transport and our ability to effectively blend them to market specifications.
On May 10, 2018, we, together with affiliates of Ergon and Kingfisher Midstream, LLC, a subsidiary of Alta Mesa Resources, Inc., announced the execution of definitive agreements to form Cimarron Express Pipeline, LLC (“Cimarron Express”). See Note 9 to our unaudited condensed consolidated financial statements for discussion on the suspension of this project.
Crude Oil Trucking Services - Crude oil trucking, while potentially influenced by the shape of the crude oil market curve, is typically impacted more by overall drilling activity and the ability to have the appropriate level of assets located properly to efficiently move the barrels to delivery points for customers.
On April 24, 2018, we sold our producer field services business, which has been historically reported along with the crude oil trucking services.
Our revenues consist of (i) terminalling revenues, (ii) gathering and transportation revenues, (iii) product sales revenues and (iv) fuel surcharge revenues. For the nine months ended September 30, 2018,2019, the Partnership recognized revenues of $38.6$27.2 million and $0.3 million for services provided to Ergon and Cimarron Express, respectively, with the remainder of our services being provided to third parties.
Terminalling revenues consist of (i) storage service fees resulting from short-term and long-term contracts for committed space that may or may not be utilized by the customer in a given month and (ii) terminal throughput feesservice charges to pump crude oil to connecting carriers or to deliver asphalt product out of our terminals. We earn terminalling revenues in two of our segments: (i) asphalt terminalling services and (ii) crude oil terminalling services. Storage service revenues are recognized as the services are provided on a monthly basis. Throughput fees in our asphalt terminalling services segment are recognized straight-line over time. Throughput fees in our crude oil terminalling services segmentsTerminal throughput service charges are recognized as the crude oil or asphalt product is delivered out of our terminal.
We have leases and terminalling agreements with customers for all of our 53 asphalt facilities, including 23 facilities under contract with Ergon. On July 12, 2018, we closed the sale of three of our asphalt facilities to Ergon (see Note 6 to our unaudited condensed consolidated financial statements for additional information). Lease and terminallingThese agreements related to 16 of the remaining facilities have terms that expire at the end of 2018, while the agreements relating to our additional 37 facilities have, on average, fourapproximately 3.8 years remaining under their respective terms. FifteenWhile agreements with one customer for four of the contractsfacilities expire by the end of 2019, we have commercially agreed to all terms on a new contract with the same customer and expect to finalize it in the near term. The remaining agreements expire at varying times thereafter, including agreements for 23 facilities with Ergon that expire in 2018 are with Ergon.2023. We may not be able to extend, renegotiate or replace these contracts when they expire and the terms of any renegotiated contracts may not be as favorable as the contracts they replace. We operate the asphalt facilities pursuant to the terminalling agreements, while our contract counterparties operate the asphalt facilities that are subject to lease agreements.
As of October 25, 2018,November 1, 2019, we had approximately 4.55.2 million barrels of crude oil storage under service contracts, including an intercompany contract for 0.32.5 million barrels and aof crude oil storage contracts that expire in 2019. The decrease in contracted storage barrels from prior quarter is due to the expiration of an intracompany contract for 2.0 million barrels that commences November 1, 2018, out of our total storage capacity of 6.6 million barrels. The intercompany contract expires on October 31, 2018, and a new agreement for 0.5 million barrels, will be effective November 1, 2018. Ofwhich has no net impact on our consolidated financial results. The remaining terms on the third-party storage agreements, service contracts relatingthat extend beyond 2019 range from 3 to 0.326 months. Storage contracts with Vitol represent 2.9 million barrels expire in 2018.
Gathering and transportation services revenues consist of service fees recognized for the gathering of crude oil for our customers and the transportation of crude oil to refiners, to common carrier pipelines for ultimate delivery to refiners or to terminalling facilities owned by us and others. We earn gathering and transportation revenues in two of our segments: (i) crude oil pipeline services and (ii) crude oil trucking services. Revenue for the gathering and transportation of crude oil is recognized when the service is performed and is based upon regulated and non-regulated tariff rates and the related transport volumes.
The following is a summary of our average gathering and transportation volumes for the periods indicated (in thousands of barrels per day):
Three Months ended September 30, | Nine Months ended September 30, | Favorable/(Unfavorable) | |||||||||||||||||||||
Three Months | Nine Months | ||||||||||||||||||||||
2017 | 2018 | 2017 | 2018 | $ | % | $ | % | ||||||||||||||||
Average pipeline throughput volume | 21 | 23 | 22 | 22 | 2 | 10 | % | — | — | % | |||||||||||||
Average trucking transportation volume | 20 | 29 | 21 | 26 | 9 | 45 | % | 5 | 24 | % |
Three Months ended September 30, | Nine Months ended September 30, | Favorable/(Unfavorable) | ||||||||||||||||||||||||||||||
2018 | 2019 | 2018 | 2019 | Three Months | Nine Months | |||||||||||||||||||||||||||
Average pipeline throughput volume | 23 | 23 | 22 | 31 | - | 0 | % | 9 | 41 | % | ||||||||||||||||||||||
Average trucking transportation volume | 29 | 25 | 26 | 26 | (4 | ) | (14 | )% | - | 0 | % |
In July 2018, we restored service in July 2018,on an out-of-service portion of our Oklahoma system, increasing the transportation capacity of our pipeline systems by approximately 20,000 Bpd. See
Product sales revenues are comprised of (i) revenues recognized for the sale of crude oil to our customers that we purchase at production leases and (ii) revenue recognized in buy/sell transactions with our customers. We earn product sales revenue in our crude oil pipeline services operating segment. Product sales revenue is recognized for products upon delivery and when the customer assumes the risks and rewards of ownership.
Fuel surcharge revenues are comprised of revenues recognized for the reimbursement of fuel and power consumed to operate our asphalt terminals. We recognize fuel surcharge revenues in the period in which the related fuel and power expenses are incurred.
Operating expenses decreased by 5%10% for the nine months ended September 30, 2019, as compared to the nine months ended September 30, 2018 as compared. In addition to decreases related to the nine months ended September 30, 2017. This is primarily a resultsale of a decreasethe three asphalt plants in July 2018, depreciation expense decreased due to certain assets reaching the end of their depreciable lives as well as a decrease inand vehicle expenses decreased due to a reduction in the size of our fleet. General and administrative expenses remained relatively consistentdecreased19% for the nine months ended September 30, 2019, as compared to the nine months ended September 30, 2018. The decrease is primarily due to decreased compensation and professional fees expense, as comparedwell as the receipt of a $0.5 million settlement related to a payment made in 2018 to a fraudulent bank account due to a compromise of the vendor’s email system as disclosed in the 2018 Form 10-K, which were offset by expenses related to the Ergon buyout offer of $0.4 million. Our interest expense decreased by 2% for the nine months ended September 30, 2017. Our interest expense increased by $1.9 million for2019, as compared to the nine months ended September 30, 2018 as compared to the nine months ended September 30, 2017.. See
Income Taxes
As part of the process of preparing the unaudited condensed consolidated financial statements, we are required to estimate the federal and state income taxes in each of the jurisdictions in which our subsidiary that is taxed as a corporation operates. This process involves estimating the actual current tax exposure together with assessing temporary differences resulting from differing treatment of items, such as depreciation, for tax and accounting purposes. These differences result in deferred tax assets and liabilities, which are included in our unaudited condensed consolidated balance sheets. We must then assess, using all available positive and negative evidence, the likelihood that the deferred tax assets will be recovered from future taxable income. Unless we believe that recovery is more likely than not, we must establish a valuation allowance. To the extent we establish a valuation allowance or increase or decrease this allowance in a period, we must include an expense or reduction of expense within the tax provisions in the unaudited condensed consolidated statements of operations.
Under
ASC 740 – Accounting for Income Taxes, an enterprise must use judgment in considering the relative impact of negative and positive evidence. The weight given to the potential effect of negative and positive evidence should be commensurate with the extent to which it can be objectively verified. The more negative evidence that exists, (a) the more positive evidence is necessary and (b) the more difficult it is to support a conclusion that a valuation allowance is not needed for some portion or all of the deferred tax asset. Among the more significant types of evidence that we consider are:taxable income projections in future years;
future revenue and operating cost projections that will produce more than enough taxable income to realize the deferred tax asset based on existing service rates and cost structures; and
our earnings history exclusive of the loss that created the future deductible amount coupled with evidence indicating that the loss is an aberration rather than a continuing condition.
Based on the consideration of the above factors for our subsidiary that is taxed as a corporation for purposes of determining the likelihood of realizing the benefits of the deferred tax assets, we have provided a full valuation allowance against our deferred tax asset related to the difference in bases of property, plant and equipment as of
Distributions
The amount of distributions we pay and the decision to make any distribution is determined by the Board of Directors of our General Partner (the “Board”), which has broad discretion to establish cash reserves for the proper conduct of our business and for future distributions to our unitholders. In addition, our cash distribution policy is subject to restrictions on distributions under our credit agreement.
On October 23, 2018,17, 2019, the Board approved a cash distribution of $0.17875$0.17875 per outstanding Preferred Unitpreferred unit for the three months ended September 30, 2018.2019. We will pay this distribution on November 14, 2018,2019, to unitholders of record as of November 2,
In addition, on October 23, 2018, the Board approved a cash distribution of $0.08$0.04 per outstanding common unit for the three months ended September 30, 2018.2019. We will pay this distribution November 14, 2018,2019, to unitholders of record on November 2, 2018.4, 2019. The total distribution will be approximately $3.4$1.7 million, with approximately $3.2$1.6 million and $0.1less than $0.1 million paid to our common unitholders and General Partner, respectively, and $0.1less than $0.1 million paid to holders of phantom and restricted units pursuant to awards granted under our Long-Term Incentive Plan.
Ergon Buyout Offer
On August 5, 2019, Ergon filed an amendment to its Schedule 13D with the SEC disclosing that Ergon made a non-binding proposal to the Board, pursuant to which Ergon would acquire all the outstanding Common Units and Series A Preferred Units of the Partnership not already owned by Ergon and its affiliates. The proposal was referred to the Conflicts Committee of the Board for consideration. The proposal was withdrawn by Ergon on September 11, 2019.
Non-GAAP Financial Measures
To supplement our financial information presented in accordance with GAAP, management uses additional measures that are known as “non-GAAP financial measures” in its evaluation of past performance and prospects for the future. The primary measure used by management is operating margin, excluding depreciation and amortization.
Management believes that the presentation of such additional financial measures provides useful information to investors regarding our performance and results of operations because these measures, when used in conjunction with related GAAP financial measures, (i) provide additional information about our core operating performance and ability to generate and distribute cash flow; (ii) provide investors with the financial analytical framework upon which management bases financial, operational, compensation and planning decisions and (iii) present measurements that investors, rating agencies and debt holders have indicated are useful in assessing us and our results of operations. These additional financial measures are reconciled to the most directly comparable measures as reported in accordance with GAAP, and should be viewed in addition to, and not in lieu of, our unaudited condensed consolidated financial statements and footnotes.
The table below summarizes our financial results for the three and nine months ended September 30,
Operating Results | Three Months ended September 30, | Nine Months ended September 30, | Favorable/(Unfavorable) | ||||||||||||||||||||||||||
Three Months | Nine Months | ||||||||||||||||||||||||||||
(dollars in thousands) | 2017 | 2018 | 2017 | 2018 | $ | % | $ | % | |||||||||||||||||||||
Operating margin, excluding depreciation and amortization: | |||||||||||||||||||||||||||||
Asphalt terminalling services | $ | 20,546 | $ | 17,625 | $ | 49,609 | $ | 49,621 | $ | (2,921 | ) | (14 | )% | $ | 12 | — | % | ||||||||||||
Crude oil terminalling services | 4,168 | 1,226 | 14,017 | 6,730 | (2,942 | ) | (71 | )% | (7,287 | ) | (52 | )% | |||||||||||||||||
Crude oil pipeline services | (387 | ) | (506 | ) | (309 | ) | (1,137 | ) | (119 | ) | (31 | )% | (828 | ) | (268 | )% | |||||||||||||
Crude oil trucking services | (228 | ) | (116 | ) | (419 | ) | (601 | ) | 112 | 49 | % | (182 | ) | (43 | )% | ||||||||||||||
Total operating margin, excluding depreciation and amortization | 24,099 | 18,229 | 62,898 | 54,613 | (5,870 | ) | (24 | )% | (8,285 | ) | (13 | )% | |||||||||||||||||
Depreciation and amortization | (7,680 | ) | (7,166 | ) | (23,586 | ) | (21,945 | ) | 514 | 7 | % | 1,641 | 7 | % | |||||||||||||||
General and administrative expense | (4,093 | ) | (4,322 | ) | (13,000 | ) | (13,029 | ) | (229 | ) | (6 | )% | (29 | ) | — | % | |||||||||||||
Asset impairment expense | — | (15 | ) | (45 | ) | (631 | ) | (15 | ) | N/A | (586 | ) | (1,302 | )% | |||||||||||||||
Gain (loss) on sale of assets | (107 | ) | (63 | ) | (986 | ) | 300 | 44 | 41 | % | 1,286 | 130 | % | ||||||||||||||||
Operating income | 12,219 | 6,663 | 25,281 | 19,308 | (5,556 | ) | (45 | )% | (5,973 | ) | (24 | )% | |||||||||||||||||
Other income (expenses): | |||||||||||||||||||||||||||||
Equity earnings in unconsolidated affiliate | — | — | 61 | — | N/A | N/A | (61 | ) | (100 | )% | |||||||||||||||||||
Gain on sale of unconsolidated affiliate | 1,112 | — | 5,284 | 2,225 | (1,112 | ) | (100 | )% | (3,059 | ) | (58 | )% | |||||||||||||||||
Interest expense | (3,500 | ) | (4,090 | ) | (10,795 | ) | (12,683 | ) | (590 | ) | (17 | )% | (1,888 | ) | (17 | )% | |||||||||||||
Provision for income taxes | (60 | ) | (165 | ) | (147 | ) | (215 | ) | (105 | ) | (175 | )% | (68 | ) | (46 | )% | |||||||||||||
Net income | $ | 9,771 | $ | 2,408 | $ | 19,684 | $ | 8,635 | $ | (7,363 | ) | (75 | )% | $ | (11,049 | ) | (56 | )% |
Three Months ended | Nine Months ended | Favorable/(Unfavorable) | ||||||||||||||||||||||||||||||
Operating results | September 30, | September 30, | Three Months | Nine Months | ||||||||||||||||||||||||||||
(dollars in thousands) | 2018 | 2019 | 2018 | 2019 | $ | % | $ | % | ||||||||||||||||||||||||
Operating margin, excluding depreciation and amortization: | ||||||||||||||||||||||||||||||||
Asphalt terminalling services | $ | 17,625 | $ | 17,123 | $ | 49,621 | $ | 44,433 | $ | (502 | ) | (3 | )% | $ | (5,188 | ) | (10 | )% | ||||||||||||||
Crude oil terminalling services | 1,226 | 3,291 | 6,730 | 9,161 | 2,065 | 168 | % | 2,431 | 36 | % | ||||||||||||||||||||||
Crude oil pipeline services | (506 | ) | 618 | (1,137 | ) | 2,757 | 1,124 | 222 | % | 3,894 | 342 | % | ||||||||||||||||||||
Crude oil trucking services | (116 | ) | 133 | (601 | ) | 143 | 249 | 215 | % | 744 | 124 | % | ||||||||||||||||||||
Total operating margin, excluding depreciation and amortization | 18,229 | 21,165 | 54,613 | 56,494 | 2,936 | 16 | % | 1,881 | 3 | % | ||||||||||||||||||||||
Depreciation and amortization | (7,166 | ) | (6,240 | ) | (21,945 | ) | (19,211 | ) | 926 | 13 | % | 2,734 | 12 | % | ||||||||||||||||||
General and administrative expense | (4,322 | ) | (3,840 | ) | (13,029 | ) | (10,495 | ) | 482 | 11 | % | 2,534 | 19 | % | ||||||||||||||||||
Asset impairment expense | (15 | ) | (83 | ) | (631 | ) | (2,316 | ) | (68 | ) | (453 | )% | (1,685 | ) | (267 | )% | ||||||||||||||||
Gain (loss) on sale of assets | (63 | ) | (40 | ) | 300 | 1,765 | 23 | 37 | % | 1,465 | 488 | % | ||||||||||||||||||||
Operating income | 6,663 | 10,962 | 19,308 | 26,237 | 4,299 | 65 | % | 6,929 | 36 | % | ||||||||||||||||||||||
Other income (expenses): | ||||||||||||||||||||||||||||||||
Other income | - | - | - | 268 | - | 0 | % | 268 | N/A | |||||||||||||||||||||||
Gain on sale of unconsolidated affiliate | - | - | 2,225 | - | - | 0 | % | (2,225 | ) | (100 | )% | |||||||||||||||||||||
Interest expense | (4,090 | ) | (3,989 | ) | (12,683 | ) | (12,394 | ) | 101 | 2 | % | 289 | 2 | % | ||||||||||||||||||
Provision for income taxes | (165 | ) | (14 | ) | (215 | ) | (39 | ) | 151 | 92 | % | 176 | 82 | % | ||||||||||||||||||
Net income | $ | 2,408 | $ | 6,959 | $ | 8,635 | $ | 14,072 | $ | 4,551 | 189 | % | $ | 5,437 | 63 | % |
For the three and nine months ended September 30, 2018,2019, overall operating margin, excluding depreciation and amortization, decreased asincreased compared to the same periodsperiod in 2017.2018. Our asphalt terminalling services segment operating margin, excluding depreciation and amortization, was impacted by both the acquisition of an asphalt facility in March 2018 and the sale of three asphalt terminals to Ergon in July 2018 and the acquisition of two asphalt facilities, one from Ergon in December 2017 and one from a third party in March 2018. The decreaseincrease in our crude oil terminalling services operating margin, excluding depreciation and amortization, wasis primarily due to loweran increase in rented storage rates as well as the expiration of a 2.2-million-barrel storage contract on April 30, 2018. While our second Mid-Continent pipeline was placed back in service in July 2018, marginscapacity. Margins in our crude oil pipeline services segment continued to reflect the impactrecovery of throughput volumes since the restoration of a portion of our Oklahoma system in July 2018, on which we had suspended service sincein April 2016 due to the discovery of a pipeline exposure.exposure on a riverbed in southern Oklahoma. In addition, an $0.8 million sale of crude oil product accumulated over time through customer loss allowance deductions for the nine months ended September 30, 2019, also contributed to the increased margin in our crude oil pipeline services segment; there were no such sales in the same period in 2018. Crude oil trucking services operating margin, excluding depreciation and amortization, improved for the three and nine months ended September 30, 2018,2019, due to an increaseimproved rates beginning in volumesthe fourth quarter of 2018 and longer length of hauls transported.
A more detailed analysis of changes in operating margin by segment follows.
Analysis of Operating Segments
Asphalt terminalling services segment
Our asphalt terminalling services segment operations generally consist of fee-based activities associated with providing terminalling services, including storage, blending, processing and throughput services, for asphalt product and residual fuel oil. Revenue is generated through operating lease contracts and storage, throughput and handling contracts.
The following table sets forth our operating results from our asphalt terminalling services segment for the periods indicated:
Operating results | Three Months ended September 30, | Nine Months ended September 30, | Favorable/(Unfavorable) | |||||||||||||||||||||||||||
Three Months | Nine Months | |||||||||||||||||||||||||||||
(dollars in thousands) | 2017 | 2018 | 2017 | 2018 | $ | % | $ | % | ||||||||||||||||||||||
Service revenue: | ||||||||||||||||||||||||||||||
Third-party revenue | $ | 17,690 | $ | 6,921 | $ | 44,172 | $ | 18,693 | $ | (10,769 | ) | (61 | )% | $ | (25,479 | ) | (58 | )% | ||||||||||||
Related-party revenue | 14,464 | 5,211 | 41,301 | 17,512 | (9,253 | ) | (64 | )% | (23,789 | ) | (58 | )% | ||||||||||||||||||
Lease revenue: | ||||||||||||||||||||||||||||||
Third-party revenue | — | 11,288 | — | 30,762 | 11,288 | N/A | 30,762 | N/A | ||||||||||||||||||||||
Related-party revenue | — | 5,406 | — | 20,584 | 5,406 | N/A | 20,584 | N/A | ||||||||||||||||||||||
Product sales revenue: | ||||||||||||||||||||||||||||||
Related-party revenue | — | 482 | — | 482 | 482 | N/A | 482 | N/A | ||||||||||||||||||||||
Total revenue | 32,154 | 29,308 | 85,473 | 88,033 | (2,846 | ) | (9 | )% | 2,560 | 3 | % | |||||||||||||||||||
Operating expense, excluding depreciation and amortization | 11,608 | 11,683 | 35,864 | 38,412 | (75 | ) | (1 | )% | (2,548 | ) | (7 | )% | ||||||||||||||||||
Operating margin, excluding depreciation and amortization | $ | 20,546 | $ | 17,625 | $ | 49,609 | $ | 49,621 | $ | (2,921 | ) | (14 | )% | $ | 12 | — | % |
Three Months ended | Nine Months ended | Favorable/(Unfavorable) | ||||||||||||||||||||||||||||||
Operating results | September 30, | September 30, | Three Months | Nine Months | ||||||||||||||||||||||||||||
(dollars in thousands) | 2018 | 2019 | 2018 | 2019 | $ | % | $ | % | ||||||||||||||||||||||||
Service revenue: | ||||||||||||||||||||||||||||||||
Third-party revenue | $ | 6,921 | $ | 7,385 | $ | 18,693 | $ | 21,217 | $ | 464 | 7 | % | $ | 2,524 | 14 | % | ||||||||||||||||
Related-party revenue | 5,211 | 3,892 | 17,512 | 11,991 | (1,319 | ) | (25 | )% | (5,521 | ) | (32 | )% | ||||||||||||||||||||
Lease revenue: | ||||||||||||||||||||||||||||||||
Third-party revenue | 11,288 | 11,444 | 30,762 | 31,026 | 156 | 1 | % | 264 | 1 | % | ||||||||||||||||||||||
Related-party revenue | 5,406 | 5,427 | 20,584 | 15,179 | 21 | 0 | % | (5,405 | ) | (26 | )% | |||||||||||||||||||||
Product sales revenue: | ||||||||||||||||||||||||||||||||
Related-party revenue | 482 | - | 482 | - | (482 | ) | (100 | )% | (482 | ) | (100 | )% | ||||||||||||||||||||
Total revenue | 29,308 | 28,148 | 88,033 | 79,413 | (1,160 | ) | (4 | )% | (8,620 | ) | (10 | )% | ||||||||||||||||||||
Operating expense, excluding depreciation and amortization | 11,683 | 11,025 | 38,412 | 34,980 | 658 | 6 | % | 3,432 | 9 | % | ||||||||||||||||||||||
Operating margin, excluding depreciation and amortization | $ | 17,625 | $ | 17,123 | $ | 49,621 | $ | 44,433 | $ | (502 | ) | (3 | )% | $ | (5,188 | ) | (10 | )% |
The following is a discussion of items impacting asphalt terminalling services segment operating margin for the periods indicated:
• | Total revenue decreased for the three and nine months ended September 30, 2019, as compared to the three and nine months ended September 30, 2018. The sale of the three asphalt facilities in July 2018 resulted in a decrease of revenue of $1.2 million and $10.8 million for the three and nine month periods, respectively. The decrease for the nine month period was offset in part by an increase in revenue of $1.5 million due to the asphalt facility acquired in March 2018 and a contract change on another asphalt facility from a related-party lease to a third-party storage contract. |
• | Operating expenses decreased for the three and nine months ended September 30, 2019, as compared to the three and nine months ended September 30, 2018. For the three month comparative periods, the sale of three facilities in July 2018 led to a decrease in operating expenses of $0.6 million. In addition, decreased utility costs at some facilities were offset by net flood-related expenses of $0.1 million as well as increases in other non-flood related repairs. For the nine month comparative periods, the sale of three facilities in July 2018 led to a decrease in operating expenses of $5.4 million, which was partially offset by an increase of $0.8 million related to the acquisition in March 2018, net flood-related expenses of $0.2 million, and increased compensation costs at some facilities. |
Crude oil terminalling services segment
Our crude oil terminalling services segment operations generally consist of fee-based activities associated with providing terminalling services, including storage, blending, processing and throughput services for crude oil. Revenue is generated through short- and long-term storage contracts.
The following table sets forth our operating results from our crude oil terminalling services segment for the periods indicated:
Operating results | Three Months ended September 30, | Nine Months ended September 30, | Favorable/(Unfavorable) | ||||||||||||||||||||||||||
Three Months | Nine Months | ||||||||||||||||||||||||||||
(dollars in thousands) | 2017 | 2018 | 2017 | 2018 | $ | % | $ | % | |||||||||||||||||||||
Service revenue: | |||||||||||||||||||||||||||||
Third-party revenue | $ | 5,162 | $ | 1,923 | $ | 17,013 | $ | 9,418 | $ | (3,239 | ) | (63 | )% | $ | (7,595 | ) | (45 | )% | |||||||||||
Intersegment revenue | — | 222 | — | 392 | 222 | N/A | 392 | N/A | |||||||||||||||||||||
Lease revenue: | |||||||||||||||||||||||||||||
Third-party revenue | — | 9 | — | 35 | 9 | N/A | 35 | N/A | |||||||||||||||||||||
Total revenue | 5,162 | 2,154 | 17,013 | 9,845 | (3,008 | ) | (58 | )% | (7,168 | ) | (42 | )% | |||||||||||||||||
Operating expense, excluding depreciation and amortization | 994 | 928 | 2,996 | 3,115 | 66 | 7 | % | (119 | ) | (4 | )% | ||||||||||||||||||
Operating margin, excluding depreciation and amortization | $ | 4,168 | $ | 1,226 | $ | 14,017 | $ | 6,730 | $ | (2,942 | ) | (71 | )% | $ | (7,287 | ) | (52 | )% | |||||||||||
Average crude oil stored per month at our Cushing terminal (in thousands of barrels) | 5,124 | 779 | 5,520 | 1,249 | (4,345 | ) | (85 | )% | (4,271 | ) | (77 | )% | |||||||||||||||||
Average crude oil delivered to our Cushing terminal (in thousands of barrels per day) | 27 | 32 | 40 | 50 | 5 | 19 | % | 10 | 25 | % |
Three Months ended | Nine Months ended | Favorable/(Unfavorable) | ||||||||||||||||||||||||||||||
Operating results | September 30, | September 30, | Three Months | Nine Months | ||||||||||||||||||||||||||||
(dollars in thousands) | 2018 | 2019 | 2018 | 2019 | $ | % | $ | % | ||||||||||||||||||||||||
Service revenue: | ||||||||||||||||||||||||||||||||
Third-party revenue | $ | 1,923 | $ | 4,225 | $ | 9,418 | $ | 11,819 | $ | 2,302 | 120 | % | $ | 2,401 | 25 | % | ||||||||||||||||
Intersegment revenue | 222 | 278 | 392 | 853 | 56 | 25 | % | 461 | 118 | % | ||||||||||||||||||||||
Lease revenue: | ||||||||||||||||||||||||||||||||
Third-party revenue | 9 | - | 35 | - | (9 | ) | (100 | )% | (35 | ) | (100 | )% | ||||||||||||||||||||
Total revenue | 2,154 | 4,503 | 9,845 | 12,672 | 2,349 | 109 | % | 2,827 | 29 | % | ||||||||||||||||||||||
Operating expense, excluding depreciation and amortization | 928 | 1,212 | 3,115 | 3,511 | (284 | ) | (31 | )% | (396 | ) | (13 | )% | ||||||||||||||||||||
Operating margin, excluding depreciation and amortization | $ | 1,226 | $ | 3,291 | $ | 6,730 | $ | 9,161 | $ | 2,065 | 168 | % | $ | 2,431 | 36 | % | ||||||||||||||||
Average crude oil storage contracted per month at our Cushing terminal (in thousands of barrels) | 2,950 | 5,862 | 4,029 | 5,731 | 2,912 | 99 | % | 1,702 | 42 | % | ||||||||||||||||||||||
Average crude oil stored per month at our Cushing terminal (in thousands of barrels) | 779 | 3,104 | 1,249 | 3,339 | 2,325 | 298 | % | 2,090 | 167 | % | ||||||||||||||||||||||
Average crude oil delivered through our Cushing terminal (in thousands of barrels per day) | 32 | 99 | 50 | 87 | 67 | 209 | % | 37 | 74 | % |
The following is a discussion of items impacting crude oil terminalling services segment operating margin for the periods indicated:
• | Total revenues for three and nine months ended September 30, 2019, increased as compared to the same period in 2018 due to an increase in rented storage capacity and an increase in crude oil delivered through the terminal. |
• | Operating expenses for the three and nine months ended September 30, 2019, increased compared to the three and nine months ended September 30, 2018 due to an increase in tank repair expenses. |
• | As of November 1, 2019, we had approximately 5.2 million barrels of crude oil storage under service contracts, including 2.5 million barrels of crude oil storage contracts that expire in 2019. The decrease in contracted storage barrels from prior quarter is due to the expiration of an intracompany contract for 0.5 million barrels, which has no net impact on our consolidated financial results. The remaining terms on the service contracts that extend beyond 2019 range from 3 to 26 months. Storage contracts with Vitol represent 2.9 million barrels of crude oil storage capacity under contract. |
Crude oil pipeline services segment
Our crude oil pipeline services segment operations include both service and product sales revenue. Service revenue generally consists of tariffs and other fees associated with transporting crude oil products on pipelines. Product sales revenue is comprised of (i) revenues recognized for the sale of crude oil to our customers that we purchase at production leases and (ii) revenue recognized in buy/sell transactions with our customers. Product sales revenue is recognized for products upon delivery and when the customer assumes the risks and rewards of ownership.
The following table sets forth our operating results from our crude oil pipeline services segment for the periods indicated:
Operating results | Three Months ended September 30, | Nine Months ended September 30, | Favorable/(Unfavorable) | ||||||||||||||||||||||||||
Three Months | Nine Months | ||||||||||||||||||||||||||||
(dollars in thousands) | 2017 | 2018 | 2017 | 2018 | $ | % | $ | % | |||||||||||||||||||||
Service revenue: | |||||||||||||||||||||||||||||
Third-party revenue | $ | 2,196 | $ | 1,165 | $ | 7,520 | $ | 4,270 | $ | (1,031 | ) | (47 | )% | $ | (3,250 | ) | (43 | )% | |||||||||||
Related-party revenue | — | 185 | 310 | 268 | 185 | N/A | (42 | ) | (14 | )% | |||||||||||||||||||
Lease revenue: | |||||||||||||||||||||||||||||
Third-party revenue | — | 40 | — | 452 | 40 | N/A | 452 | N/A | |||||||||||||||||||||
Product sales revenue: | |||||||||||||||||||||||||||||
Third-party revenue | 2,375 | 97,763 | 8,252 | 146,882 | 95,388 | 4,016 | % | 138,630 | 1,680 | % | |||||||||||||||||||
Total revenue | 4,571 | 99,153 | 16,082 | 151,872 | 94,582 | 2,069 | % | 135,790 | 844 | % | |||||||||||||||||||
Operating expense, excluding depreciation and amortization | 3,056 | 3,094 | 9,438 | 8,420 | (38 | ) | (1 | )% | 1,018 | 11 | % | ||||||||||||||||||
Intersegment operating expense | 77 | 1,644 | 321 | 3,243 | (1,567 | ) | (2,035 | )% | (2,922 | ) | (910 | )% | |||||||||||||||||
Third-party cost of product sales | 1,675 | 50,815 | 6,482 | 73,493 | (49,140 | ) | (2,934 | )% | (67,011 | ) | (1,034 | )% | |||||||||||||||||
Related-party cost of product sales | — | 44,106 | — | 67,853 | (44,106 | ) | N/A | (67,853 | ) | N/A | |||||||||||||||||||
Intersegment cost of product sales | 150 | — | 150 | — | 150 | 100 | % | 150 | 100 | % | |||||||||||||||||||
Operating margin, excluding depreciation and amortization | $ | (387 | ) | $ | (506 | ) | $ | (309 | ) | $ | (1,137 | ) | $ | (119 | ) | (31 | )% | $ | (828 | ) | (268 | )% | |||||||
Average throughput volume (in thousands of barrels per day) | 21 | 23 | 22 | 22 | 2 | 10 | % | — | — | % |
Three Months ended | Nine Months ended | Favorable/(Unfavorable) | ||||||||||||||||||||||||||||||
Operating results | September 30, | September 30, | Three Months | Nine Months | ||||||||||||||||||||||||||||
(dollars in thousands) | 2018 | 2019 | 2018 | 2019 | $ | % | $ | % | ||||||||||||||||||||||||
Service revenue: | ||||||||||||||||||||||||||||||||
Third-party revenue | $ | 1,165 | $ | 1,284 | $ | 4,270 | $ | 5,753 | $ | 119 | 10 | % | $ | 1,483 | 35 | % | ||||||||||||||||
Related-party revenue | 185 | 64 | 268 | 266 | (121 | ) | (65 | )% | (2 | ) | (1 | )% | ||||||||||||||||||||
Lease revenue: | ||||||||||||||||||||||||||||||||
Third-party revenue | 40 | - | 452 | - | (40 | ) | (100 | )% | (452 | ) | (100 | )% | ||||||||||||||||||||
Product sales revenue: | ||||||||||||||||||||||||||||||||
Third-party revenue | 97,763 | 55,213 | 146,882 | 173,773 | (42,550 | ) | (44 | )% | 26,891 | 18 | % | |||||||||||||||||||||
Total revenue | 99,153 | 56,561 | 151,872 | 179,792 | (42,592 | ) | (43 | )% | 27,920 | 18 | % | |||||||||||||||||||||
Operating expense, excluding depreciation and amortization | 3,094 | 2,638 | 8,420 | 8,109 | 456 | 15 | % | 311 | 4 | % | ||||||||||||||||||||||
Intersegment operating expense | 1,644 | 1,642 | 3,243 | 4,971 | 2 | 0 | % | (1,728 | ) | (53 | )% | |||||||||||||||||||||
Third-party cost of product sales | 50,815 | 18,972 | 73,493 | 64,069 | 31,843 | 63 | % | 9,424 | 13 | % | ||||||||||||||||||||||
Related-party cost of product sales | 44,106 | 32,691 | 67,853 | 99,886 | 11,415 | 26 | % | (32,033 | ) | (47 | )% | |||||||||||||||||||||
Operating margin, excluding depreciation and amortization | $ | (506 | ) | $ | 618 | $ | (1,137 | ) | $ | 2,757 | $ | 1,124 | 222 | % | $ | 3,894 | 342 | % | ||||||||||||||
Pipeline transportation services average throughput volume (in thousands of barrels per day) | 23 | 23 | 22 | 31 | - | 0 | % | 9 | 41 | % | ||||||||||||||||||||||
Crude oil marketing volumes (in thousands of barrels per day) | 15 | 11 | 8 | 11 | (4 | ) | (27 | )% | 3 | 38 | % |
The following is a discussion of items impacting crude oil pipeline services segment operating margin for the periods indicated:
In lateJuly 2018, we restored service on the portion of the pipeline system that had been out of service since April 2016 as a precautionary measure we suspended service on our Mid-Continent pipeline system due to discovery of a pipeline exposure caused by heavy rains and the erosion ofon a riverbed in southern Oklahoma. There was no damageThis restored our transportation capacity to the pipe and no lossfull 50,000 barrels per day.
• | Total throughput volumes are consistent for the three month comparative periods, while the increase in the nine month comparative periods is due to both increased crude oil marketing activities and the restored service on the Oklahoma pipeline system. In addition to the increase in volume, operating margins were positively impacted by improved margins on the crude oil marketing activities. Throughput volumes related to the crude oil marketing business were approximately 11,000 barrels per day, or approximately 48% and 35% of total throughput, for both the three and nine months ended September 30, 2019. The service revenue for this activity associated with pipeline tariffs is eliminated on an intrasegment basis. Our crude oil pipeline recognized $1.5 million and $4.5 million in intrasegment service revenue in the three and nine months ended September 30, 2019, respectively, that is not reflected in revenues in the table above. The intrasegment revenues for three and nine months ended September 30, 2018, were $1.7 million and $3.4 million, respectively. The changes in product sales revenues, intersegment operating expense, and related-party and third-party cost of product sales are all due to changes in our crude oil marketing business. |
Crude oil trucking services segment
Our crude oil trucking services segment operations generally consist of fee-based activity associated with transporting crude oil products on trucks. Revenues are generated primarily through transportation fees. In April 2018, we sold our producer field services business that has been historically reported along with the crude oil trucking services. As a result of the sale of the producer field services business, the Partnership changed the name of this operating segment to crude oil trucking services during the second quarter of 2018.
The following table sets forth our operating results from our crude oil trucking services segment for the periods indicated:
Operating results | Three Months ended September 30, | Nine Months ended September 30, | Favorable/(Unfavorable) | ||||||||||||||||||||||||||
Three Months | Nine Months | ||||||||||||||||||||||||||||
(dollars in thousands) | 2017 | 2018 | 2017 | 2018 | $ | % | $ | % | |||||||||||||||||||||
Service revenue | |||||||||||||||||||||||||||||
Third-party revenue | $ | 5,587 | $ | 2,734 | $ | 18,738 | $ | 11,783 | $ | (2,853 | ) | (51 | )% | $ | (6,955 | ) | (37 | )% | |||||||||||
Intersegment revenue | 77 | 1,422 | 321 | 2,851 | 1,345 | 1,747 | % | 2,530 | 788 | % | |||||||||||||||||||
Lease revenue: | |||||||||||||||||||||||||||||
Third-party revenue | — | 31 | — | 160 | 31 | N/A | 160 | N/A | |||||||||||||||||||||
Product sales revenue: | |||||||||||||||||||||||||||||
Third-party revenue | — | — | 385 | 10 | — | N/A | (375 | ) | (97 | )% | |||||||||||||||||||
Intersegment revenue | 150 | — | 150 | — | (150 | ) | (100 | )% | (150 | ) | (100 | )% | |||||||||||||||||
Total revenue | 5,814 | 4,187 | 19,594 | 14,804 | (1,627 | ) | (28 | )% | (4,790 | ) | (24 | )% | |||||||||||||||||
Operating expense, excluding depreciation and amortization | 6,042 | 4,303 | 20,013 | 15,405 | 1,739 | 29 | % | 4,608 | 23 | % | |||||||||||||||||||
Operating margin, excluding depreciation and amortization | $ | (228 | ) | $ | (116 | ) | $ | (419 | ) | $ | (601 | ) | $ | 112 | 49 | % | $ | (182 | ) | (43 | )% | ||||||||
Average volume (in thousands of barrels per day) | 20 | 29 | 21 | 26 | 9 | 45 | % | 5 | 24 | % |
Three Months ended | Nine Months ended | Favorable/(Unfavorable) | ||||||||||||||||||||||||||||||
Operating results | September 30, | September 30, | Three Months | Nine Months | ||||||||||||||||||||||||||||
(dollars in thousands) | 2018 | 2019 | 2018 | 2019 | $ | % | $ | % | ||||||||||||||||||||||||
Service revenue | ||||||||||||||||||||||||||||||||
Third-party revenue | $ | 2,734 | $ | 2,822 | $ | 11,783 | $ | 8,540 | $ | 88 | 3 | % | $ | (3,243 | ) | (28 | )% | |||||||||||||||
Intersegment revenue | 1,422 | 1,364 | 2,851 | 4,118 | (58 | ) | (4 | )% | 1,267 | 44 | % | |||||||||||||||||||||
Lease revenue: | ||||||||||||||||||||||||||||||||
Third-party revenue | 31 | - | 160 | - | (31 | ) | (100 | )% | (160 | ) | (100 | )% | ||||||||||||||||||||
Product sales revenue: | ||||||||||||||||||||||||||||||||
Third-party revenue | - | - | 10 | - | - | 0 | % | (10 | ) | (100 | )% | |||||||||||||||||||||
Total revenue | 4,187 | 4,186 | 14,804 | 12,658 | (1 | ) | (0 | )% | (2,146 | ) | (14 | )% | ||||||||||||||||||||
Operating expense, excluding depreciation and amortization | 4,303 | 4,053 | 15,405 | 12,515 | 250 | 6 | % | 2,890 | 19 | % | ||||||||||||||||||||||
Operating margin, excluding depreciation and amortization | $ | (116 | ) | $ | 133 | $ | (601 | ) | $ | 143 | $ | 249 | 215 | % | $ | 744 | 124 | % | ||||||||||||||
Average volume (in thousands of barrels per day) | 29 | 25 | 26 | 26 | (4 | ) | (14 | )% | - | 0 | % |
The following is a discussion of items impacting crude oil trucking services segment operating margin for the periods indicated:
Service revenues decreased for the three and nine months ended September 30, 2018, as compared to the three and nine months ended September 30, 2017, by $2.0 million and $4.3 million, respectively, due to the sale of the producer field services business. Additionally, service revenues have decreased despite an increase in volumes as the volumes hauled in 2018 were on average, over a shorter distance than in 2017, which results in lower revenue per barrel transported.
• | Service revenues decreased for the nine months ended September 30, 2019, as compared to the nine months ended September 30, 2018, by $2.7 million due to the sale of the producer field services business in April 2018. This decrease was partially offset by an increase in intersegment service revenues for services provided to our crude oil pipeline services segment’s crude oil marketing business. These volumes transported on an intersegment basis increased from 8,000 barrels per day to 11,000 barrels per day. |
• | Operating expense, excluding depreciation and amortization, decreased for the nine months ended September 30, 2019, as compared to the nine months ended September 30, 2018, by $2.9 million due to the sale of our producer field services business. |
Other Income and Expenses
Depreciation and amortization expense. Depreciation and amortization expense decreased by $1.0 million to $6.2 million for the three months ended September 30, 2017.2019, compared to $7.2 million for the three months ended September 30, 2018. Depreciation and amortization expense decreased by $1.6$2.7 million to $21.9$19.2 million for the nine months ended September 30, 2019, compared to $21.9 million for the nine months ended September 30, 2018 compared to $23.6 million for the nine months ended September 30, 2017.. These decreases are primarily the result of
General and administrative expenses
Asset impairment expense. Asset impairment expense for the three months ended September 30, 2017. General and administrative expenses for the three months ended September 30, 2018, were impacted by $0.9 million in insurance premium payments being made to a fraudulent bank account as a result of a business e-mail compromise attack. While we are pursuing recovery of these funds, there can be no assurance of a successful recovery. General and administrative expenses were consistent at $13.0 million for the both the nine months ended September 30, 20182019, included a change in estimate and 2017. Decreases in compensation and travel expenses were offset by $0.6 million of feesaccrued interest related to the salepush-down impairment of three asphalt facilitiesCimarron Express (see Note 9 to Ergonour unaudited condensed consolidated financial statements for more information) that resulted in July 2018.
Gain (loss) on sale of assets.
Gain on sale of assets wasOther income. Other income for the nine months ended September 30, 2018, compared2019, relates to a loss of $1.0 million for the nine months ended September 30, 2017. We recognized a gain on the sale of our producer field services business of $0.4 million in April 2018. Losses for the nine months ended September 30, 2017, include $0.4 millioninsurance recoveries related to the disposal of anflood damages at certain asphalt tank floor that had to be prematurely replaced due to corrosion. Additional gains and losses in all periods were primarily comprised of sales of surplus, used property and equipment.
Gain on sale of unconsolidated affiliate.
Interest expense.
Interest expense represents interest on borrowings under our credit agreement as well as amortization of debt issuance costs and unrealized gains and losses related to the change in fair value of interest rate swaps.Three Months ended September 30, | Nine Months ended September 30, | Favorable/(Unfavorable) | |||||||||||||||||||||||||||
Three Months | Nine Months | ||||||||||||||||||||||||||||
2017 | 2018 | 2017 | 2018 | $ | % | $ | % | ||||||||||||||||||||||
Credit agreement interest | $ | 3,256 | $ | 3,815 | $ | 9,388 | $ | 11,856 | $ | (559 | ) | (17 | )% | $ | (2,468 | ) | (26 | )% | |||||||||||
Amortization of debt issuance costs | 251 | 251 | 865 | 764 | — | — | 101 | 12 | % | ||||||||||||||||||||
Write-off of debt issuance costs | — | — | 693 | 437 | — | — | % | 256 | 37 | % | |||||||||||||||||||
Interest rate swaps interest expense (income) | 257 | (25 | ) | 1,085 | (49 | ) | 282 | 110 | % | 1,134 | 105 | % | |||||||||||||||||
Loss (gain) on interest rate swaps mark-to-market | (278 | ) | 36 | (1,252 | ) | (276 | ) | (314 | ) | 113 | % | (976 | ) | 78 | % | ||||||||||||||
Other | 14 | 13 | 16 | (49 | ) | 1 | 7 | % | 65 | 406 | % | ||||||||||||||||||
Total interest expense | $ | 3,500 | $ | 4,090 | $ | 10,795 | $ | 12,683 | $ | (590 | ) | (17 | )% | $ | (1,888 | ) | (17 | )% |
Three Months ended | Nine Months ended | Favorable/(Unfavorable) | ||||||||||||||||||||||||||||||
September 30, | September 30, | Three Months | Nine Months | |||||||||||||||||||||||||||||
2018 | 2019 | 2018 | 2019 | $ | % | $ | % | |||||||||||||||||||||||||
Credit agreement interest | $ | 3,815 | $ | 3,714 | $ | 11,856 | $ | 11,585 | $ | 101 | 3 | % | $ | 271 | 2 | % | ||||||||||||||||
Amortization of debt issuance costs | 251 | 251 | 764 | 753 | - | 0 | % | 11 | 1 | % | ||||||||||||||||||||||
Write-off of debt issuance costs | - | - | 437 | - | - | 0 | % | 437 | 100 | % | ||||||||||||||||||||||
Interest rate swaps interest income | (25 | ) | - | (49 | ) | (40 | ) | (25 | ) | (100 | )% | (9 | ) | (18 | )% | |||||||||||||||||
Loss (gain) on interest rate swaps mark-to-market | 36 | - | (276 | ) | 44 | 36 | 100 | % | (320 | ) | (116 | )% | ||||||||||||||||||||
Other | 13 | 24 | (49 | ) | 52 | (11 | ) | (85 | )% | (101 | ) | (206 | )% | |||||||||||||||||||
Total interest expense | $ | 4,090 | $ | 3,989 | $ | 12,683 | $ | 12,394 | $ | 101 | 2 | % | $ | 289 | 2 | % |
Effects of Inflation
In recent years, inflation has been modest and has not had a material impact upon the results of our operations.
Off-Balance Sheet Arrangements
We do not have any off-balance sheet arrangements as defined by Item 303 of Regulation S-K.
Liquidity and Capital Resources
Cash Flows and Capital Expenditures
The following table summarizes our sources and uses of cash for the
Nine Months ended September 30, | |||||||
2017 | 2018 | ||||||
(in millions) | |||||||
Net cash provided by operating activities | $ | 46.2 | $ | 28.2 | |||
Net cash provided by investing activities | $ | 22.3 | $ | 44.0 | |||
Net cash used in financing activities | $ | (69.2 | ) | $ | (72.7 | ) |
Nine Months ended September 30, | ||||||||
2018 | 2019 | |||||||
(in millions) | ||||||||
Net cash provided by operating activities | $ | 28.2 | $ | 38.3 | ||||
Net cash provided by (used in) investing activities | $ | 44.0 | $ | (2.3 | ) | |||
Net cash provided by (used in) financing activities | $ | (72.7 | ) | $ | (34.6 | ) |
Operating Activities. Net cash provided by operating activities increased to $46.2$38.3 million for the nine months ended September 30, 2017,2019, as compared to $28.2 million for the nine months ended September 30, 2018, due to decreasedincreased net income as discussed in
Investing Activities
. Net cashFinancing Activities
. Net cash used in financing activities wasOur Liquidity and Capital Resources
Cash flows from operations and from our credit agreement are our primary sources of liquidity. At September 30, 2018,2019, we had a working capital deficitof $5.3$8.7 million.
Our credit agreement contains certain financial covenants which include a maximum permitted consolidated total leverage ratio, which may limit our availability to borrow funds thereunder. The consolidated total leverage ratio is assessed quarterly based on the trailing twelve months of EBITDA, as defined in the credit agreement. The maximum permitted consolidated total leverage ratio as of September 30, 2019, was 5.00 to 1.00 and decreases to 4.75 to 1.00 as of March 31, 2020, and for each fiscal quarter thereafter. Our consolidated total leverage ratio was 4.24 to 1.00 as of September 30, 2019.
Management evaluates whether conditions and/or events raise substantial doubt about our ability to continue as a going concern within one year after the date that the consolidated financial statements are issued (the “assessment period”). In performing this assessment, management considered the risk associated with its ongoing ability to meet the financial covenants.
Based on forecasted EBITDA during the assessment period, management believes that it will meet the financial covenants. However, there are certain inherent risks associated with our continued ability to comply with our consolidated total leverage ratio covenant. These risks relate, among other things, to potential future (a) decreases in storage volumes and rates as well as throughput and transportation rates realized; (b) weather phenomenon that may potentially hinder the asphalt business activity; and (c) other items affecting forecasted levels of expenditures and uses of cash resources. Violation of the consolidated total leverage ratio covenant would be an event of default under the credit agreement, which would cause our $258.6 million in outstanding debt, as of September 30, 2019, to become immediately due and payable. If this were to occur, we would not expect to have sufficient liquidity to repay these outstanding amounts then due, which could cause the lenders under the credit facility to pursue other remedies. Such remedies could include exercising their collateral rights to our assets. Based on our current forecasts, we believe we will be able to comply with the consolidated total leverage ratio during the assessment period. However, we cannot make any assurances that we will be able to achieve our forecasts. If we are unable to achieve our forecasts, further actions may be necessary to remain in compliance with our consolidated total leverage ratio covenant including, but not limited to, cost reductions, common and preferred unitholder distribution curtailments, and/or asset sales. We can make no assurances that we would be successful in undertaking these actions, or that we will remain in compliance with the consolidated total leverage ratio during the assessment period.
maintenance capital expenditures, which are capital expenditures made to maintain the existing integrity and operating capacity of our assets and related cash flows, further extending the useful lives of the assets; and
expansion capital expenditures, which are capital expenditures made to expand the operating capacity or revenue of existing or new assets, whether through construction, acquisition or modification.
The following table breaks out capital expenditures for organic growth projects, net of reimbursable expenditures of $0.3 million, totaled $23.3 million in the nine months ended September 30, 2018 compared to $6.2 million in the nine months ended September 30, 2017. Expansion capital expenditures for the nine months ended September 30, 2018, included $13.1 million related to crude oil purchases for pipeline linefill and storage tank heels at the Cushing terminal. 2019 (in thousands):
Nine Months ended September 30, | ||||||||
2018 | 2019 | |||||||
Acquisitions | 21,959 | - | ||||||
Gross expansion capital expenditures | 23,617 | 1,969 | ||||||
Reimbursable expenditures | (338 | ) | (61 | ) | ||||
Net expansion capital expenditures | 23,279 | 1,908 | ||||||
Gross maintenance capital expenditures | 5,943 | 7,459 | ||||||
Reimbursable expenditures | (572 | ) | (202 | ) | ||||
Net maintenance capital expenditures | 5,371 | 7,257 |
We currently expect our expansion capital expenditures for organic growth projects to be approximately $24.0$3.5 million to $25.0$4.5 million inclusive of crude oil purchases for Cushing terminal and pipeline linefill and net of reimbursable expenditures, for all of 2018. Maintenance capital expenditures totaled $5.4 million, net of reimbursable expenditures of $0.6 million, in the nine months ended September 30,
Our Ability to Grow Depends on Our Ability to Access External Expansion Capital
. Our partnership agreement requires that we distribute all of our available cash to our unitholders. Available cash is reduced by cash reserves established by our General Partner to provide for the proper conduct of our business (including for future capital expenditures) and to comply with the provisions of our credit agreement. We may not grow as quickly as businesses that reinvest their available cash to expand ongoing operations because we distribute all of our available cash.Recent Accounting Pronouncements
For information regarding recent accounting developments that may affect our future financial statements, see Note 17 to our unaudited condensed consolidated financial statements.
We are exposed to market risk due to variable interest rates under our credit agreement.
As of
During the nine months ended September 30,
Changes in economic conditions could result in higher interest rates, thereby increasing our interest expense and reducing our funds available for capital investment, operations or distributions to our unitholders. Based on borrowings as of September 30, 2018,2019, the terms of our credit agreement, current interest rates and the effect of our interest rate swaps, an increase or decrease of 100 basis points in the interest rate would result in increased or decreased annual interest expense of approximately $1.7$2.6 million.
Evaluation of disclosure controls and procedures
. Our General Partner’s management, including the Chief Executive Officer and Chief Financial Officer of our General Partner, evaluated, as of the end of the period covered by this report, the effectiveness of our disclosure controls and procedures as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer of our General Partner concluded that our disclosure controls and procedures, as of September 30,Changes in internal control over financial reporting
. There were no changes to our internal control over financial reporting that occurred during the three months ended September 30,The information required by this item is included under the caption “Commitments and Contingencies” in Note 15 to our unaudited condensed consolidated financial statements and is incorporated herein by reference thereto.
See the informationrisk factors set forth in this quarterly report, you should carefully consider the risks discussed inPart I, Item 1A, of our Annual Report on Form 10-K for the year ended December 31, 2017. The risks described in our Annual Report on Form 10-K for the year ended December 31, 2017 and in this quarterly report are not the only risks we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results.
The information required by this Item 6 is set forth in the Index to Exhibits accompanying this quarterly report and is incorporated herein by reference.
INDEX TO EXHIBITS
Exhibit Number | Description | |
3.1 | ||
3.2 | ||
3.3 | ||
3.4 | ||
3.5 | ||
3.6 | ||
4.1 | ||
31.1* | ||
31.2* | ||
32.1# | ||
101# | The following financial information from Blueknight Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended September 30, |
____________________
* Filed herewith.
# Furnished herewith
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
BLUEKNIGHT ENERGY PARTNERS, L.P. | |||
By: | Blueknight Energy Partners, G.P., L.L.C. | ||
its General Partner | |||
Date: | By: | /s/ D. Andrew Woodward | |
D. Andrew Woodward | |||
Chief Financial Officer | |||
Date: | By: | /s/ Michael McLanahan | |
Michael McLanahan | |||
Chief Accounting Officer |
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