Attached files
file | filename |
---|---|
EX-31.1 - EX-31.1 - JP Energy Partners LP | a14-20915_1ex31d1.htm |
EX-32.1 - EX-32.1 - JP Energy Partners LP | a14-20915_1ex32d1.htm |
EX-32.2 - EX-32.2 - JP Energy Partners LP | a14-20915_1ex32d2.htm |
EX-31.2 - EX-31.2 - JP Energy Partners LP | a14-20915_1ex31d2.htm |
EXCEL - IDEA: XBRL DOCUMENT - JP Energy Partners LP | Financial_Report.xls |
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2014
OR
o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission file number 001-36647
JP ENERGY PARTNERS LP
(Exact name of registrant as specified in its charter)
Delaware |
|
27-2504700 |
(State or other jurisdiction of |
|
(I.R.S. Employer |
600 East Las Colinas Blvd
Suite 2000
Irving, Texas 75039
(Address of principal executive offices) (Zip Code)
(Registrants telephone number, including area code): (972) 444-0300
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 o NO x
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). YES x NO o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of large accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the Exchange Act.
Large accelerated filer o |
|
Accelerated filer o |
|
|
|
Non-accelerated filer x |
|
Smaller reporting company o |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). YES o NO x
At November 5, 2014, there were 18,213,502 common units and 18,213,502 subordinated units outstanding.
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2 | |
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3 | |
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4 | |
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5 | |
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6 | |
Managements Discussion and Analysis of Financial Condition and Results of Operations |
22 | |
42 | ||
43 | ||
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45 | ||
45 | ||
45 | ||
45 | ||
47 |
JP ENERGY PARTNERS LP
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
|
|
September 30, |
|
December 31, |
| ||
|
|
2014 |
|
2013 |
| ||
|
|
(in thousands, except unit data) |
| ||||
ASSETS |
|
|
|
|
| ||
|
|
|
|
|
| ||
Current assets |
|
|
|
|
| ||
Cash and cash equivalents |
|
$ |
9,933 |
|
$ |
3,234 |
|
Restricted cash |
|
600 |
|
|
| ||
Accounts receivable less allowance for doubtful accounts of $1,230 and $1,207, respectively |
|
132,988 |
|
122,919 |
| ||
Receivables from related parties |
|
7,477 |
|
2,742 |
| ||
Inventory |
|
34,736 |
|
38,579 |
| ||
Prepaid expenses and other current assets |
|
6,750 |
|
4,991 |
| ||
Total Current Assets |
|
192,484 |
|
172,465 |
| ||
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|
|
|
|
| ||
Non-current assets |
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|
|
|
| ||
Property, plant and equipment, net |
|
244,612 |
|
238,093 |
| ||
Goodwill |
|
248,721 |
|
250,705 |
| ||
Intangible assets, net |
|
153,093 |
|
175,101 |
| ||
Deferred financing costs and other assets, net |
|
10,848 |
|
7,038 |
| ||
Total Non-Current Assets |
|
657,274 |
|
670,937 |
| ||
Total Assets |
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$ |
849,758 |
|
$ |
843,402 |
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| ||
LIABILITIES AND PARTNERS CAPITAL |
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|
|
|
| ||
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Current liabilities |
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|
|
|
| ||
Accounts payable |
|
$ |
119,570 |
|
$ |
95,765 |
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Payables to related parties |
|
35 |
|
1,274 |
| ||
Accrued liabilities |
|
25,144 |
|
22,748 |
| ||
Capital leases and short-term debt |
|
107 |
|
538 |
| ||
Customer deposits and advances |
|
5,198 |
|
2,722 |
| ||
Current portion of long-term debt |
|
236 |
|
698 |
| ||
Total Current Liabilities |
|
150,290 |
|
123,745 |
| ||
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Non-current liabilities |
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|
|
|
| ||
Long-term debt |
|
196,854 |
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183,148 |
| ||
Note payable to related party |
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|
|
1,000 |
| ||
Other long-term liabilities |
|
2,144 |
|
2,116 |
| ||
Total Liabilities |
|
349,288 |
|
310,009 |
| ||
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Commitments and contingencies |
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Partners capital |
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Predecessor capital |
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304,065 |
| ||
Series D preferred units |
|
40,656 |
|
|
| ||
General partner interest |
|
(12,323 |
) |
404 |
| ||
Class A common units (20,929,938 and 8,004,368 units authorized, issued and outstanding at September 30, 2014 and December 31, 2013, respectively) |
|
389,143 |
|
140,752 |
| ||
Class B common units (1,340,508 units authorized and 1,296,844 and 1,206,844 issued and outstanding at September 30, 2014 and December 31, 2013, respectively) |
|
10,796 |
|
11,366 |
| ||
Class C common units (3,254,781 units authorized, issued and outstanding at September 30, 2014 and December 31, 2013, respectively) |
|
72,198 |
|
76,806 |
| ||
Total Partners Capital |
|
500,470 |
|
533,393 |
| ||
Total Liabilities and Partners Capital |
|
$ |
849,758 |
|
$ |
843,402 |
|
See accompanying notes to condensed consolidated financial statements.
JP ENERGY PARTNERS LP
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
|
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Three Months Ended September 30, |
|
Nine Months Ended September 30, |
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2014 |
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2013 |
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2014 |
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2013 |
| ||||
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(in thousands except unit and per unit data) |
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REVENUES: |
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|
| ||||
Crude oil sales |
|
$ |
369,064 |
|
$ |
515,253 |
|
$ |
1,094,879 |
|
$ |
1,392,571 |
|
Gathering, transportation and storage fees |
|
10,689 |
|
6,199 |
|
31,074 |
|
14,247 |
| ||||
NGL and refined product sales (including sales to related parties of $476, $1,003, $7,409 and $9,254 in the three and nine months ended September 30, 2014 and 2013, respectively) |
|
42,458 |
|
36,940 |
|
149,555 |
|
127,439 |
| ||||
Refined products terminals and storage fees (including sales to related parties of $74, $486, $1,521 and $2,096 in the three and nine months ended September 30, 2014 and 2013, respectively) |
|
3,143 |
|
3,512 |
|
8,811 |
|
9,476 |
| ||||
Other revenues |
|
3,237 |
|
2,654 |
|
10,086 |
|
8,630 |
| ||||
Total revenues |
|
428,591 |
|
564,558 |
|
1,294,405 |
|
1,552,363 |
| ||||
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| ||||
COSTS AND EXPENSES: |
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|
|
|
|
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|
|
| ||||
Cost of sales, excluding depreciation and amortization |
|
392,662 |
|
532,458 |
|
1,190,859 |
|
1,451,415 |
| ||||
Operating expense |
|
17,048 |
|
16,510 |
|
52,304 |
|
44,713 |
| ||||
General and administrative |
|
11,315 |
|
10,656 |
|
35,196 |
|
30,968 |
| ||||
Depreciation and amortization |
|
10,395 |
|
7,790 |
|
30,569 |
|
22,976 |
| ||||
Loss on disposal of assets, net |
|
533 |
|
478 |
|
1,193 |
|
1,477 |
| ||||
Total costs and expenses |
|
431,953 |
|
567,892 |
|
1,310,121 |
|
1,551,549 |
| ||||
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|
|
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| ||||
OPERATING (LOSS) INCOME |
|
(3,362 |
) |
(3,334 |
) |
(15,716 |
) |
814 |
| ||||
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| ||||
OTHER INCOME (EXPENSE) |
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| ||||
Interest expense |
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(2,406 |
) |
(2,279 |
) |
(7,957 |
) |
(6,094 |
) | ||||
Loss on extinguishment of debt |
|
|
|
|
|
(1,634 |
) |
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| ||||
Other income, net |
|
|
|
82 |
|
506 |
|
277 |
| ||||
|
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|
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|
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| ||||
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAXES |
|
(5,768 |
) |
(5,531 |
) |
(24,801 |
) |
(5,003 |
) | ||||
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|
|
|
|
|
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|
| ||||
Income tax benefit (expense) |
|
158 |
|
(42 |
) |
2 |
|
(346 |
) | ||||
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|
|
|
|
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| ||||
LOSS FROM CONTINUING OPERATIONS |
|
(5,610 |
) |
(5,573 |
) |
(24,799 |
) |
(5,349 |
) | ||||
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| ||||
DISCONTINUED OPERATIONS |
|
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|
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| ||||
Net loss from discontinued operations, including loss on disposal of $7,288 in 2014 |
|
|
|
(64 |
) |
(9,608 |
) |
(87 |
) | ||||
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|
|
|
|
|
|
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| ||||
NET LOSS |
|
$ |
(5,610 |
) |
$ |
(5,637 |
) |
$ |
(34,407 |
) |
$ |
(5,436 |
) |
|
|
|
|
|
|
|
|
|
| ||||
Net (income) loss attributable to preferred unitholders |
|
$ |
(766 |
) |
$ |
207 |
|
$ |
(656 |
) |
$ |
572 |
|
Net (income) loss attributable to predecessor capital |
|
|
|
(1,075 |
) |
2,046 |
|
(6,139 |
) | ||||
Net loss attributable to common unitholders |
|
$ |
(6,376 |
) |
$ |
(6,505 |
) |
$ |
(33,017 |
) |
$ |
(11,003 |
) |
|
|
|
|
|
|
|
|
|
| ||||
Basic and diluted loss per unit: |
|
|
|
|
|
|
|
|
| ||||
Weighted average number of common units outstanding |
|
22,635,930 |
|
10,730,947 |
|
20,756,036 |
|
10,225,844 |
| ||||
Basic and diluted loss per common unit from continuing operations |
|
$ |
(0.28 |
) |
$ |
(0.60 |
) |
$ |
(1.13 |
) |
$ |
(1.07 |
) |
Basic and diluted loss per common unit from discontinued operations |
|
$ |
|
|
$ |
(0.01 |
) |
$ |
(0.46 |
) |
$ |
(0.01 |
) |
Basic and diluted loss per common unit |
|
$ |
(0.28 |
) |
$ |
(0.61 |
) |
$ |
(1.59 |
) |
$ |
(1.08 |
) |
Distribution per common unit |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
1.00 |
|
See accompanying notes to condensed consolidated financial statements.
JP ENERGY PARTNERS LP
CONDENSED CONSOLIDATED STATEMENT OF PARTNERS CAPITAL
(Unaudited)
|
|
Units |
| ||||||||||
|
|
Series D |
|
General |
|
Class A |
|
Class B |
|
Class C |
|
Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance - January 1, 2014 |
|
|
|
45 |
|
8,004,368 |
|
1,206,844 |
|
3,254,781 |
|
12,466,038 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of Class A Common Units |
|
|
|
|
|
363,636 |
|
|
|
|
|
363,636 |
|
Issuance of Class B Common Units |
|
|
|
|
|
|
|
90,000 |
|
|
|
90,000 |
|
Common control acquisition |
|
|
|
|
|
12,561,934 |
|
|
|
|
|
12,561,934 |
|
Issuance of Preferred Units |
|
1,872,727 |
|
|
|
|
|
|
|
|
|
1,872,727 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance - September 30, 2014 |
|
1,872,727 |
|
45 |
|
20,929,938 |
|
1,296,844 |
|
3,254,781 |
|
27,354,335 |
|
|
|
Series D |
|
General |
|
Predecessor |
|
Class A |
|
Class B |
|
Class C |
|
Total |
| |||||||
|
|
(in thousands) |
| |||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
Balance - January 1, 2014 |
|
$ |
|
|
$ |
404 |
|
$ |
304,065 |
|
$ |
140,752 |
|
$ |
11,366 |
|
$ |
76,806 |
|
$ |
533,393 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
Contribution from the Predecessor |
|
|
|
|
|
4,321 |
|
|
|
|
|
|
|
4,321 |
| |||||||
Issuance of Class A Common Units |
|
|
|
|
|
|
|
8,000 |
|
|
|
|
|
8,000 |
| |||||||
Issuance of Preferred Units |
|
40,000 |
|
|
|
|
|
|
|
|
|
|
|
40,000 |
| |||||||
Unit-based compensation |
|
|
|
|
|
|
|
|
|
1,163 |
|
|
|
1,163 |
| |||||||
Common control acquisition |
|
|
|
(12,727 |
) |
(306,340 |
) |
267,067 |
|
|
|
|
|
(52,000 |
) | |||||||
Net loss |
|
656 |
|
|
|
(2,046 |
) |
(26,676 |
) |
(1,733 |
) |
(4,608 |
) |
(34,407 |
) | |||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
Balance - September 30, 2014 |
|
$ |
40,656 |
|
$ |
(12,323 |
) |
$ |
|
|
$ |
389,143 |
|
$ |
10,796 |
|
$ |
72,198 |
|
$ |
500,470 |
|
See accompanying notes to condensed consolidated financial statements.
JP ENERGY PARTNERS LP
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
|
|
Nine Months Ended September 30, |
| ||||
|
|
2014 |
|
2013 |
| ||
|
|
(in thousands) |
| ||||
CASH FLOWS FROM OPERATING ACTIVITIES |
|
|
|
|
| ||
Net loss |
|
$ |
(34,407 |
) |
$ |
(5,436 |
) |
Adjustments to reconcile net loss to net cash provided by operating activities including discontinued operations: |
|
|
|
|
| ||
Depreciation and amortization |
|
32,002 |
|
25,110 |
| ||
Goodwill impairment |
|
1,984 |
|
|
| ||
Derivative valuation changes |
|
1,215 |
|
(994 |
) | ||
Amortization of deferred financing costs |
|
678 |
|
809 |
| ||
Loss on extinguishment of debt |
|
1,634 |
|
|
| ||
Unit-based compensation expenses |
|
1,163 |
|
673 |
| ||
Loss on disposal of assets |
|
8,242 |
|
1,477 |
| ||
Bad debt expense |
|
651 |
|
434 |
| ||
Other non-cash items |
|
(18 |
) |
96 |
| ||
Changes in working capital, net of acquired assets and liabilities: |
|
|
|
|
| ||
Accounts receivable |
|
(10,788 |
) |
2,834 |
| ||
Receivable from related parties |
|
(4,735 |
) |
225 |
| ||
Inventory |
|
3,813 |
|
(23,532 |
) | ||
Prepaid expenses and other current assets |
|
(2,300 |
) |
4,440 |
| ||
Accounts payable and other accrued liabilities |
|
24,735 |
|
16,829 |
| ||
Payables to related parties |
|
(1,429 |
) |
1,879 |
| ||
Customer deposits and advances |
|
2,476 |
|
727 |
| ||
Changes in other assets and liabilities |
|
(1,206 |
) |
97 |
| ||
NET CASH PROVIDED BY OPERATING ACTIVITIES |
|
23,710 |
|
25,668 |
| ||
|
|
|
|
|
| ||
CASH FLOWS FROM INVESTING ACTIVITIES |
|
|
|
|
| ||
Capital expenditures |
|
(34,344 |
) |
(19,961 |
) | ||
Acquisitions of businesses, net of cash acquired |
|
|
|
(1,003 |
) | ||
Proceeds received from sale of assets |
|
10,887 |
|
92 |
| ||
Change in restricted cash |
|
(600 |
) |
|
| ||
NET CASH USED IN INVESTING ACTIVITIES |
|
(24,057 |
) |
(20,872 |
) | ||
|
|
|
|
|
| ||
CASH FLOWS FROM FINANCING ACTIVITIES |
|
|
|
|
| ||
Proceeds from revolving line of credit |
|
288,800 |
|
17,300 |
| ||
Payments on revolving line of credit |
|
(270,757 |
) |
(8,300 |
) | ||
Payments on long-term debt |
|
(4,870 |
) |
(2,466 |
) | ||
Payment of related party note payable |
|
(1,000 |
) |
|
| ||
Payments on capital leases |
|
(82 |
) |
(137 |
) | ||
Payments on financed insurance premium |
|
(49 |
) |
(3,756 |
) | ||
Change in cash overdraft |
|
(386 |
) |
225 |
| ||
Debt issuance costs |
|
(3,192 |
) |
(566 |
) | ||
Distributions to unitholders |
|
|
|
(17,438 |
) | ||
Issuance of Series D preferred units |
|
40,000 |
|
|
| ||
Issuance of common units |
|
8,000 |
|
3,128 |
| ||
Common control acquisition |
|
(52,000 |
) |
|
| ||
Net distribution to /contributions from the Predecessor |
|
4,321 |
|
3,638 |
| ||
Tax withholding on unit-based vesting |
|
(164 |
) |
|
| ||
Other |
|
(1,575 |
) |
(1,644 |
) | ||
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES |
|
7,046 |
|
(10,016 |
) | ||
|
|
|
|
|
| ||
Net change in cash and cash equivalents |
|
6,699 |
|
(5,220 |
) | ||
Cash and cash equivalents balance, beginning of period |
|
3,234 |
|
10,099 |
| ||
Cash and cash equivalents balance, end of period |
|
$ |
9,933 |
|
$ |
4,879 |
|
|
|
|
|
|
| ||
SUPPLEMENTAL DISCLOSURES: |
|
|
|
|
| ||
Non-cash investing and financing transactions: |
|
|
|
|
| ||
Accrued capital expenditures |
|
$ |
2,051 |
|
$ |
514 |
|
See accompanying notes to condensed consolidated financial statements.
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1. Business and Basis of Presentation
Business. The unaudited condensed consolidated financial statements presented herein contain the results of JP Energy Partners LP, a Delaware limited partnership, and its subsidiaries (JPE or the Partnership). The Partnership was formed in May 2010 by members of management and was further capitalized in June 2011 by ArcLight Capital Partners, LLC (ArcLight) to own, operate, develop and acquire a diversified portfolio of midstream energy assets. The Partnerships operations currently consist of: (i) crude oil pipelines and storage; (ii) crude oil supply and logistics; (iii) refined products terminals and storage; and (iv) natural gas liquid (NGL) distribution and sales, which together provide midstream infrastructure solutions for the growing supply of crude oil, refined products and NGLs in the United States. JP Energy GP II LLC (GP II) is the Partnerships general partner. The Partnership completed its initial public offering (IPO) on October 7, 2014. See Initial Public Offering below for additional details about this subsequent event.
JP Development. On July 12, 2012, ArcLight and the owners of JPE formed JP Energy Development LP, a Delaware limited partnership (JP Development), for the express purpose of supporting JPEs growth. Since its formation, JP Development has acquired a portfolio of midstream assets that have been developed for eventual sale to JPE. JPE and JP Development are under common control because a majority of the equity interests in each entity and their general partners are owned by ArcLight. JP Development has made the following acquisitions since its formation in July 2012:
· On August 3, 2012, JP Development acquired Parnon Gathering LLC, a Delaware limited liability company (Parnon Gathering), which provides midstream gathering and transportation services to companies engaged in the production, distribution and marketing of crude oil. Subsequent to the acquisition, Parnon Gathering LLC was renamed JP Energy Marketing LLC (JPEM).
· On July 15, 2013, JP Development acquired substantially all of the retail propane assets of BMH Propane, LLC, an Arkansas limited liability company (BMH), which is engaged in the retail and wholesale propane and refined fuel distribution business.
· On August 30, 2013, JP Development, through JPEM, acquired substantially all the operating assets of Alexander Oil Field Service, Inc., a Texas Corporation (AOFS), which is engaged in the crude oil trucking business.
· On October 7, 2013, JP Development acquired Wildcat Permian Services LLC, a Texas limited liability (Wildcat Permian) that was later merged with and into JP Energy Permian, LLC, a Delaware limited liability company (JP Permian). JP Permian is engaged in the transportation of crude oil by pipeline.
· On October 10, 2013, JP Liquids, LLC, a Delaware limited liability company and wholly owned subsidiary of JP Development (JP Liquids), acquired substantially all of the assets of Highway Pipeline, Inc., a Texas corporation (Highway Pipeline), which is engaged in the transportation of natural gas liquids and condensate via hard shell tank trucks.
Common Control Acquisition between JPE and JP Development. On February 12, 2014, pursuant to a Membership Interest and Asset Purchase Agreement, the Partnership acquired (i) certain marketing and trucking businesses of JPEM (the Parnon Gathering Assets), (ii) the assets and liabilities associated with AOFS, (iii) the retail propane assets acquired from BMH and (iv) all of the issued and outstanding membership interests in JP Permian and JP Liquids (collectively, the Dropdown Assets) from JP Development for an aggregate purchase price of approximately $319.1 million (the Common Control Acquisition), which was comprised of 12,561,934 JPE Class A Common Units and $52.0 million cash. The Partnership financed the cash portion of the purchase price through borrowings under its revolving credit facility.
Basis of Presentation. Because JPE and JP Development are under common control, JPE is required under generally accepted accounting principles in the United States (GAAP) to account for this Common Control Acquisition in a manner similar to the pooling of interests method of accounting. Under this method of accounting, JPE reflected in its balance sheet the Dropdown Assets at JP Developments historical carryover basis instead of reflecting the fair market value of assets and liabilities of the Dropdown Assets. JPE also retrospectively adjusted its financial statements to include the operating results of
the Dropdown Assets from the dates these assets were originally acquired by JP Development (the dates upon which common control began).
The historical assets and liabilities and the operating results of the Dropdown Assets have been carved out from JP Developments consolidated financial statements using JP Developments historical basis in the assets and liabilities of the businesses and reflects assumptions and allocations made by management to separate the Dropdown Assets on a stand-alone basis. JPEs historical consolidated financial statements include all revenues, costs, expenses, assets and liabilities directly attributable to the Dropdown Assets, as well as allocations that include certain expenses for services, including, but not limited to, general corporate expenses related to finance, legal, information technology, shared services, employee benefits and incentives and insurance. These expenses have been allocated based on the most relevant allocation method to the services provided, primarily on the relative percentage of revenue, relative percentage of headcount, or specific identification. Management believes the assumptions underlying the consolidated financial statements are reasonable. However, the combined financial statements do not fully reflect what the Partnership, including the Dropdown Assets balance sheets, results of operations and cash flows would have been, had the Dropdown Assets been under JPE management during the periods presented. As a result, historical financial information is not necessarily indicative of what the Partnerships balance sheet, results of operations, and cash flows will be in the future.
JP Development has a centralized cash management that covers all of its subsidiaries. The net amounts due from/to JP Development by the Dropdown Assets relate to a variety of intercompany transactions including the collection of trade receivables, payment of accounts payable and accrued liabilities, charges of allocated corporate expenses and payments by JP Development on behalf of the Dropdown Assets. Such amounts have been treated as deemed contributions from/deemed distributions to JP Development for the nine months ended September 30, 2014 and 2013. The total net effect of the deemed contributions is reflected as contribution from the predecessor in the statements of cash flows as a financing activity. The net balances due to JPE from the Dropdown Assets were settled in cash based on the outstanding balances at the effective date of Common Control Acquisition.
The total purchase price from the Common Control Acquisition exceeded the book value of the assets acquired. As a result, the excess of the total purchase price over the book value of the assets acquired of $12.7 million was considered a deemed distribution by the general partner and is included as a reduction in general partner interest in Partners Capital.
The predecessor capital included in Partners Capital represented JP Developments net investment in the Dropdown Assets, which included the net income or loss allocated to the Dropdown Assets, and contributions from and distributions to JP Development. Certain transactions between the Dropdown Assets and other related parties that are wholly-owned subsidiaries of JP Development were not cash settled and, as a result, were considered deemed contributions or distributions and are included in JP Developments net investment.
Net income (loss) attributable to the Dropdown Assets prior to the Partnerships acquisition of such assets was not available for distribution to the Partnerships unitholders. Therefore, this income (loss) was not allocated to the limited partners for the purpose of calculating net income (loss) per common unit; instead, the income (loss) was allocated to predecessor capital.
Initial Public Offering. On October 7, 2014, the Partnership completed its IPO. Prior to the closing of the IPO, but subsequent to September 30, 2014, the following recapitalization transactions occurred:
· the Partnership distributed approximately $92.1 million of accounts receivable that comprise the Partnerships working capital assets to the existing partners, pro rata in accordance with their ownership interests, of which $72.5 million, $6.0 million and $3.3 million was distributed to Lonestar, Truman Arnold Companies (TAC) and JP Development, respectively, all of which are related parties;
· each Class A common unit, Class B common unit and Class C common unit (collectively, the Existing Common Units) were split into approximately 0.89 common units, resulting in an aggregate of 22,677,004 outstanding Existing Common Units; and
· an aggregate of 18,213,502 Existing Common Units held by the existing partners were automatically converted into 18,213,502 subordinated units representing a 80.3% interest in the Partnership prior to the IPO, and a 50.0% interest in the Partnership after the closing of the IPO, with 4,463,502 Existing Common Units remaining representing a 19.7% interest in the Partnership (the Remaining Existing Common Units).
Subsequent to the closing of the IPO, the following recapitalization transactions occurred:
· the Remaining Existing Common Units were automatically converted on a one-to-one basis into 4,463,502 common units representing a 12.3% interest in the Partnership;
· the 45 general partner units in the Partnership held by the general partner were recharacterized as a non-economic general partner interest in the Partnership; and
· the Partnership issued 13,750,000 common units to the public representing a 37.7% interest in the Partnership.
The Partnership used the proceeds from its IPO of approximately $257.1 million, net of underwriting discounts and structuring fees, to:
· pay offering expenses of approximately $2.0 million;
· redeem 100% of the Partnerships issued and outstanding Series D preferred units for approximately $42.4 million;
· repay $195.6 million of the debt outstanding under the Partnerships revolving credit facility; and
· replenish $17.1 million of working capital that was distributed to the then existing partners immediately prior to the IPO.
Immediately following the repayment of the debt outstanding under the Partnerships revolving credit facility, the Partnership borrowed approximately $75.0 million thereunder in order to replenish the remainder of working capital that was distributed to existing partners immediately prior to the IPO.
Partnership Agreement. In connection with its IPO, the Partnership executed the Third Amended and Restated Agreement of Limited Partnership (Amended Partnership Agreement) on October 7, 2014. The Amended Partnership Agreement requires that, within 45 days after the end of each quarter, beginning with the quarter ending December 31, 2014, the Partnership distribute all of its available cash to unitholders of record on the applicable record date, subject to certain terms and conditions. The Partnership anticipates declaring a prorated distribution for the period from October 7, 2014 to December 31, 2014 in early 2015.
Interim Results of Operations. The results of operations for the three and nine months ended September 30, 2014 and 2013 are not necessarily indicative of results expected for the full year. In our opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments consisting of normal recurring accruals necessary for fair presentation of the financial position and results of operations for such interim periods in accordance with GAAP. Although the Partnership believes the disclosures in these financial statements are adequate and make the information presented not misleading, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been omitted pursuant to the rules and regulations of the Securities and Exchange Commission (SEC). These unaudited condensed consolidated interim financial statements and the notes thereto should be read in conjunction with the audited consolidated financial statements and notes for the year ended December 31, 2013 included in our final prospectus dated October 1, 2014 and filed with the SEC pursuant to Rule 424(b) under the Securities Act of 1933, as amended, on October 2, 2014.
2. Summary of Significant Accounting Policies
Principles of Consolidation. The unaudited condensed consolidated financial statements of the Partnership have been prepared in accordance with GAAP for interim financial information. All intercompany accounts and transactions have been eliminated in the preparation of the accompanying unaudited condensed consolidated financial statements.
Use of Estimates. The unaudited condensed consolidated financial statements have been prepared in conformity with GAAP, which includes the use of estimates and assumptions made by management that affect the reported amounts of assets, liabilities, revenues, expenses and disclosure of contingent assets and liabilities that exist at the date of the condensed consolidated financial statements. Although these estimates are based on managements available knowledge of current and expected future events, actual results could be different from those estimates.
Fair value measurement. The Partnership utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs to the extent possible. The Partnership determines fair value based on assumptions that
market participants would use in pricing an asset or liability in the principal or most advantageous market. When considering market participant assumptions in fair value measurements, the following fair value hierarchy distinguishes between observable and unobservable inputs, which are categorized in one of the following levels:
Level 1 InputsUnadjusted quoted prices in active markets for identical assets or liabilities accessible to the reporting entity at the measurement date.
Level 2 InputsOther than quoted prices included in Level 1 inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the asset or liability.
Level 3 InputsUnobservable inputs for the asset or liability used to measure fair value to the extent that observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at measurement date.
The fair value of the Partnerships derivatives (see Note 8) was estimated using industry standard valuation models using market-based observable inputs, including commodity pricing and interest rate curves (Level 2). The Partnership does not have any other assets or liabilities measured at fair value on a recurring basis.
The Partnerships other financial instruments consist primarily of cash and cash equivalents and long-term debt. The fair value of long-term debt approximates the carrying value as the underlying instruments are at rates similar to current rates offered to the Partnership for debt with the same remaining maturities.
Restricted Cash. Restricted cash consists of cash balances that are restricted as to withdrawal or usage and include cash to secure crude oil production taxes payable to the applicable taxing authorities.
Goodwill. The Partnership has recorded goodwill in connection with its historical acquisitions. Upon acquisition, these companies have been either combined into one of the Partnerships existing operating units or managed on a stand-alone basis as an individual operating unit. Goodwill recorded in connection with these acquisitions is subject to an annual assessment for impairment, which the Partnership performs at the operating level for each operating unit that carries a balance of goodwill. Each of the Partnerships operating units is organized into one of four business segments: Crude Oil Pipelines and Storage, Crude Oil Supply and Logistics, Refined Products Terminals and Storage, and NGL Distribution and Sales. Goodwill is required to be measured for impairment at the operating segment level or one level below the operating segment level for which discrete financial information is available, and the Partnership has determined the following reporting units for the purpose of assessing goodwill impairment.
Operating Segments |
|
Reporting Units |
|
Crude Oil Pipelines and Storage |
|
JP Permian |
|
|
|
JPE Storage |
|
Crude Oil Supply and Logistics |
|
JPE Product Supply and Logistics |
|
Refined Product Terminals and Storage |
|
North Little Rock and Caddo Mills |
|
NGL Distribution and Sales |
|
Pinnacle Propane |
|
|
|
Pinnacle Propane Express |
|
|
|
JP Liquids |
|
The Partnerships goodwill impairment assessment is performed at year-end, or more frequently if events or circumstances arise which indicate that goodwill may be impaired.
The Partnership has the option to first assess qualitative factors to determine whether it is necessary to perform the two-step fair value-based impairment test described below. The Partnership can choose to perform the qualitative assessment on none, some or all of its reporting units. The Partnership can also bypass the qualitative assessment for any reporting unit in any period and proceed directly to step one of the impairment test, and then resume performing the qualitative assessment in any subsequent period. Qualitative indicators including deterioration in macroeconomic conditions, declining financial performance that, among other things, may trigger the need for annual or interim impairment testing of goodwill associated with one or all of the reporting units. If the Partnership believes that, as a result of its qualitative assessment, it is more likely than not that the fair value of a reporting unit is less than its carrying amount, the quantitative impairment test is required. The first step of the two-step fair value-based test involves comparing the fair value of each of the Partnerships reporting units with its carrying value, including goodwill. If the carrying value of the reporting unit exceeds its fair value, the second step is performed. The second step compares the carrying amount of the reporting units goodwill to the implied fair value of its goodwill. If the implied fair
value of goodwill is less than the carrying amount, an impairment loss would be recorded as a reduction to goodwill with a corresponding charge to operating expense.
The Partnership determines the fair value of its reporting units using a weighted combination of the discounted cash flow and market multiple valuation approaches, with heavier weighting on the discounted cash flow method, as in managements opinion, this method currently results in the most accurate calculation of a reporting units fair value. Determining the fair value of a reporting unit requires judgment and the use of significant estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating margins, discount rates, weighted average costs of capital and future market conditions, among others. The Partnership believes the estimates and assumptions used in its impairment assessments are reasonable and based on available market information, but variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated.
Under the discounted cash flow method, the Partnership determines fair value based on estimated future cash flows of each reporting unit (including estimates for capital expenditures), discounted to present value using risk-adjusted industry rates, which reflect the overall level of inherent risk of a reporting unit and the rate of return an outside investor would expect to earn. Cash flow projections are derived from budgeted amounts and operating forecasts (typically a one-year model) plus an estimate of later period cash flows, all of which are evaluated by management. Subsequent period cash flows are developed for each reporting unit using growth rates that management believes are reasonably likely to occur, along with a terminal value derived from the reporting units earnings before interest, taxes, depreciation and amortization, as well as other non-cash items or one-time non-recurring items (Adjusted EBITDA) using the Gordon Growth Model.
Under the market multiple approach, the Partnership determines the estimated fair value of each of its reporting units by applying transaction multiples derived from observable market data to each reporting units projected Adjusted EBITDA and then averaging that estimate with similar historical calculations using either a one, two or three year average. The Partnership adds a reasonable control premium, which is estimated as the premium that would be received in a sale of the reporting unit in an orderly transaction between market participants.
During the second quarter of 2014, due to the actual operating results for the six months period ended June 30, 2014 being significantly below managements budget for certain reporting units, a two-step fair-value based goodwill impairment analysis was performed for five of seven of the Partnerships reporting units, namely JP Permian, JPE Product Supply and Logistics, Pinnacle Propane, Pinnacle Propane Express and JP Liquids. Management engaged a third party valuation expert to assist performing the analysis using the valuation approaches described in the preceding paragraphs. The analysis indicated that the implied fair value of each of these reporting units was in excess for its carrying value. Based on the analysis, management concluded that no impairment was indicated at any reporting unit.
During the second quarter of 2014, immediately prior to the sale of the Bakken Business (defined in Note 3) within the JPE Product Supply and Logistics reporting unit, the Partnership allocated $1,984,000 of goodwill to the Bakken Business, which was based on the relative fair value of the disposed Bakken Business and the portion of the reporting unit that was retained by the Partnership. The $1,984,000 allocation contributed to the overall net loss from discontinued operations.
Comprehensive Income. For the three and nine months ended September 30, 2014 and 2013, comprehensive income (loss) was equal to net income (loss).
Recent Accounting Pronouncements. In June 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2014-12, Compensation - Stock Compensation, Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period. ASU 2014-12 provides explicit guidance on accounting for share-based payments requiring a specific performance target to be achieved in order for employees to become eligible to vest in the awards when that performance target may be achieved after the requisite service period for the award. The ASU requires that such performance targets be treated as a performance condition, and should not be reflected in the estimate of the grant-date fair value of the award. Instead, compensation cost should be recognized in the period in which it becomes probable the performance target will be achieved. ASU 2014-12 is effective for interim and annual periods beginning after December 15, 2015, with early adoption permitted. The adoption of ASU 2014-12 is not expected to have a material impact on the Partnerships consolidated financial statements.
In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers. ASU 2014-09 supersedes the existing revenue recognition guidance under GAAP. The core principle of ASU 2014-09 is to recognize revenues when promised goods or services are transferred to customers in an amount that reflects the consideration to which an entity expects to be entitled for those goods or services. ASU 2014-09 defines a five step process to achieve this core principle and, in doing so, more judgment and estimates may be required within the revenue recognition process than are required under existing GAAP.
ASU 2014-09 is effective for interim and annual periods beginning after December 15, 2016 using either of the following transition methods: (i) a full retrospective approach reflecting the application of the standard in each prior reporting period with the option to elect certain practical expedients, or (ii) a retrospective approach with the cumulative effect of initially adopting ASU 2014-09 recognized at the date of adoption (which includes additional footnote disclosures). Early adoption is not permitted. The Partnership is currently evaluating the impact of the adoption of ASU 2014-09, but do not anticipate a material impact to its consolidated financial statements.
In April 2014, the FASB issued No. ASU 2014-08, Presentation of Financial Statements and Property, Plant, and Equipment: Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. ASU 2014-08 changes the requirements for reporting discontinued operations. A discontinued operation may include a component of an entity or a group of components of an entity, or a business. A disposal of a component of an entity or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entitys operations and financial results. Examples include a disposal of a major geographic area, a major line of business or a major equity method investment. Additionally, the update requires expanded disclosures about discontinued operations that will provide financial statement users with more information about the assets, liabilities, income and expenses of discontinued operations. ASU 2014-08 is effective for interim and annual periods beginning after December 15, 2014, with early adoption permitted. The adoption of ASU 2014-08 primarily involves presentation and disclosure and therefore is not expected to have a material impact on the Partnerships consolidated financial statements.
3. Discontinued Operations
On June 30, 2014, the Partnership (Seller) entered into and simultaneously closed an Asset Purchase Agreement (the Purchase Agreement) with Gold Spur Trucking, LLC (Buyer), pursuant to which the Seller sold all the trucking and related assets and activities in North Dakota, Montana and Wyoming (the Bakken Business) to the Buyer for a purchase price of $9,100,000. As a result, the Partnership recognized a loss on this sale of approximately $7,288,000 during the second quarter of 2014, which primarily relates to the write-off of a customer contract intangible asset associated with the Bakken Business. In addition, immediately prior to the sale, the Partnership allocated $1,984,000 of goodwill to the Bakken Business, which was based on the relative fair value of the disposed Bakken Business and the portion of the crude oil supply and logistics reporting unit that was retained by the Partnership. The $1,984,000 allocation contributed to the overall net loss from discontinued operations.
The Bakken Businesss operations have been classified as discontinued operations for all periods in the condensed consolidated statements of operations. Prior to the classification as discontinued operations, the Partnership had reported the Bakken Business in its crude oil supply and logistics segment. The following table summarizes selected financial information related to the Bakken Businesss operations in the three and nine months ended September 30, 2014 and 2013.
|
|
Three months ended September 30, |
|
Nine months ended September 30, |
| ||||||||
|
|
2014 |
|
2013 |
|
2014 |
|
2013 |
| ||||
|
|
(in thousands) |
| ||||||||||
Revenues from discontinued operations |
|
$ |
|
|
$ |
4,371 |
|
$ |
7,865 |
|
$ |
14,746 |
|
Net loss of discontinued operations, net of taxes, including loss on disposal of $7,288 in 2014 |
|
|
|
(64 |
) |
(9,608 |
) |
(87 |
) | ||||
4. Net Income (Loss) Per Unit
Income (loss) per limited partner unit is calculated in accordance with the two-class method for determining income per unit for master limited partnerships (MLPs) when incentive distribution rights (IDRs) and other participating securities are present. The two-class method requires that income per limited partner unit be calculated as if all earnings for the period were distributed as cash, and allocated by applying the provisions of the partnership agreement, and requires a separate calculation for each quarter and year-to-date period. Under the two-class method, any excess of distributions declared over net income is allocated to the partners based on their respective sharing of income specified in the partnership agreement. Prior to the closing of the IPO, but subsequent to September 30, 2014, the Existing Common Units where split into approximately 0.89 common units. As a result, income (loss) per unit was adjusted on a retroactive basis. For the three and nine months ended September 30, 2014 and 2013, diluted income (loss) per unit was equal to basic income (loss) per unit because all instruments were antidilutive.
The following data show securities that could potentially dilute earnings per unit in the future that were not included in the computation of diluted earnings per unit because to do so would have been antidilutive for the periods presented.
|
|
Three Months Ended |
|
Nine Months Ended |
|
|
|
|
|
|
|
Series D Preferred Units |
|
1,872,727 |
|
1,872,727 |
|
The Series A, Series B and Series C preferred units earned cumulative distributions each quarter equal to the greater of (a) the amount of aggregate distributions in cash for such quarter that would be payable if the preferred units had been converted into common and (b) the minimum quarterly distribution of $0.50 per unit. The net income attributable to preferred units includes cumulative distributions declared and the Series A, Series B and Series C preferred units proportionate share of net income for the three and six months ended September 30, 2013. On August 1, 2013, all then-outstanding Series A, Series B and Series C preferred units were converted to common units on a one-for-one basis.
The Series D preferred units (see Note 9) earned cumulative distributions each quarter, commencing with the quarter ending June 30, 2014, equal to the greater of (a) the amount of aggregate distributions in cash for such quarter that would be payable if the preferred units had been converted into common and (b) $0.66 per unit. For the three and nine months ended September 30, 2014 the Partnership recorded a Paid-in-Kind (PIK) distribution of $1,235,998 and $2,435,998, respectively. The net loss attributable to preferred units includes the Series D preferred units proportionate share of net loss for the three and nine months ended September 30, 2014. As described in Note 1, on October 7, 2014, all then outstanding Series D preferred units were redeemed by the Partnership.
5. Inventory
Inventory consists of the following as of September 30, 2014 and December 31, 2013:
|
|
September 30, |
|
December 31, |
| ||
|
|
2014 |
|
2013 |
| ||
|
|
(in thousands) |
| ||||
Crude oil |
|
$ |
27,802 |
|
$ |
31,099 |
|
NGLs |
|
4,726 |
|
5,274 |
| ||
Diesel |
|
347 |
|
438 |
| ||
Materials, supplies and equipment |
|
1,861 |
|
1,768 |
| ||
Total inventory |
|
$ |
34,736 |
|
$ |
38,579 |
|
6. Goodwill and Intangible Assets
Intangible assets consist of the following at December 31, 2013 and September 30, 2014:
|
|
Balance at |
|
|
|
|
|
|
|
Balance at |
| |||||
|
|
December 31, |
|
|
|
|
|
|
|
September 30, |
| |||||
|
|
2013 |
|
Additions |
|
Disposals |
|
Amortization |
|
2014 |
| |||||
|
|
(in thousands) |
| |||||||||||||
Customer relationships |
|
$ |
72,991 |
|
$ |
|
|
$ |
|
|
$ |
(5,544 |
) |
$ |
67,447 |
|
Noncompete agreements |
|
2,336 |
|
|
|
|
|
(682 |
) |
1,654 |
| |||||
Trade names |
|
1,863 |
|
|
|
|
|
(225 |
) |
1,638 |
| |||||
Customer contracts |
|
97,674 |
|
|
|
(8,060 |
) |
(7,463 |
) |
82,151 |
| |||||
Other |
|
237 |
|
3 |
|
|
|
(37 |
) |
203 |
| |||||
Total |
|
$ |
175,101 |
|
$ |
3 |
|
$ |
(8,060 |
) |
$ |
(13,951 |
) |
$ |
153,093 |
|
The estimated future amortization expense for amortizable intangible assets to be recognized is as follows (in thousands):
2014 |
|
$ |
4,354 |
|
2015 |
|
17,337 |
| |
2016 |
|
16,944 |
| |
2017 |
|
16,092 |
| |
2018 |
|
15,149 |
| |
Thereafter |
|
83,217 |
| |
Total |
|
$ |
153,093 |
|
Goodwill activity in the nine months ended September 30, 2014 consists of the following:
|
|
Crude oil |
|
Crude oil |
|
Refined |
|
NGL |
|
Total |
| |||||
|
|
(in thousands) |
| |||||||||||||
Balance at December 31, 2013 |
|
$ |
108,162 |
|
$ |
50,045 |
|
$ |
61,163 |
|
$ |
31,335 |
|
$ |
250,705 |
|
Disposals |
|
|
|
(1,984 |
) |
|
|
|
|
(1,984 |
) | |||||
Balance at September 30, 2014 |
|
$ |
108,162 |
|
$ |
48,061 |
|
$ |
61,163 |
|
$ |
31,335 |
|
$ |
248,721 |
|
7. Long-Term Debt
Long-term debt consists of the following at September 30, 2014 and December 31, 2013:
|
|
September 30, 2014 |
|
December 31, 2013 |
| ||
|
|
(in thousands) |
| ||||
Wells Fargo revolving loan |
|
$ |
|
|
$ |
177,557 |
|
Bank of America revolving loan |
|
195,600 |
|
|
| ||
F&M bank loans |
|
|
|
4,135 |
| ||
HBH notes payable |
|
1,261 |
|
1,470 |
| ||
Related party note payable |
|
|
|
1,000 |
| ||
Reynolds note payable |
|
|
|
344 |
| ||
Noncompete notes payable |
|
229 |
|
340 |
| ||
Total long-term debt |
|
$ |
197,090 |
|
$ |
184,846 |
|
Less: Current maturities |
|
(236 |
) |
(698 |
) | ||
Total long-term debt, net of current maturities |
|
$ |
196,854 |
|
$ |
184,148 |
|
Wells Fargo Credit Agreement. The Partnership had a $20,000,000 working capital revolving credit facility and a $180,000,000 acquisition revolving credit facility with Wells Fargo Bank, N.A. (the WFB Credit Agreement). The Partnerships outstanding borrowings under the WFB Credit Agreement were collateralized by substantially all of the Partnerships assets.
On February 12, 2014, the Partnership entered into a credit agreement with Bank of America and used the borrowings under the Bank of America credit facility to repay all outstanding balances under the WFB Credit Agreement. As a result of the termination of the WFB Credit Agreement, the Partnership wrote off $1,634,000 of deferred financing costs during the nine months ended September 30, 2014.
Bank of America Credit Agreement. On February 12, 2014, the Partnership entered into a credit agreement with Bank of America, N.A. (the BOA Credit Agreement), which is available for refinancing and repayment of certain existing indebtedness, working capital, capital expenditures, permitted acquisitions and general partnership purposes, including distributions, not in contravention of law of the loan documents and to pay off its existing WFB commitments and F&M Loans (as described below). The BOA Credit Agreement consists of a $275,000,000 revolving loan, which includes a sub-limit of up to
$100,000,000 for letters of credit, and contains an accordion feature that will allow the Partnership to increase the borrowing capacity thereunder from $275,000,000 up to $425,000,000, subject to obtaining additional or increased lender commitments. The BOA Credit Agreement will mature on February 12, 2019. The Partnerships obligations under the BOA Credit Agreement are collateralized by substantially all of the Partnerships assets.
Borrowings under the BOA Credit Agreement bear interest at a rate per annum equal to, at our option, either (a) a base rate determined by reference to the highest of (1) the federal funds effective rate plus 0.50%, (2) the prime rate of Bank of America, and (3) LIBOR, subject to certain adjustments, plus 1.00% or (b) LIBOR, in each case plus an applicable margin. The initial applicable margin is (a) 2.00% for prime rate borrowings and 3.00% for LIBOR borrowings. The applicable margin is subject to an adjustment each quarter based on (i) prior to the IPO, the Consolidated Total Leverage Ratio, as defined in the BOA Credit Agreement (ii) on or after the IPO, the Consolidated Net Total Leverage Ratio, as defined in the BOA Credit Agreement.
As of September 30, 2014, the unused balance of the BOA Credit Agreement was $44,870,000. Issued and outstanding letters of credit, which reduced available borrowings under the BOA Credit Agreement, totaled $34,530,000 at September 30, 2014. The Partnership is required to pay a commitment fee on the unused commitments under the BOA Credit Agreement, which initially is 0.50% per annum. The commitment fee is subject to adjustment each quarter based on (i) prior to the IPO, the Consolidated Total Leverage Ratio, as defined in the BOA Credit Agreement and (ii) on or after the IPO, the Consolidated Net Total Leverage Ratio, as defined in the BOA Credit Agreement.
The BOA Credit Agreement contains various restrictive covenants and compliance requirements including:
Prior to the IPO
· Maintenance of certain financial covenants including a consolidated total leverage ratio of not more than 4.50 to 1.00 prior to the issuance of certain unsecured notes (which will be increased to 4.75 to 1.00 for certain measurement periods following the consummation of certain acquisitions), a consolidated total leverage ratio of not more than 4.75 to 1.00 from and after the issuance of certain unsecured notes, a consolidated senior secured leverage ratio of not more than 3.00 to 1.00 from and after the issuance of certain unsecured notes and a consolidated interest coverage ratio of not less than 2.50 to 1.00.
· Financial statement reporting requirements, including quarterly unaudited financial statement reporting and annual audited financial statement reporting.
· Restrictions on cash distributions, including cash distributions to holders of equity units, unless certain leverage and coverage ratios are maintained before and after the cash distribution.
After the IPO
· Maintenance of certain financial covenants including a consolidated net total leverage ratio of not more than 4.50 to 1.00 prior to the issuance of certain unsecured notes (which will be increased to 5.00 to 1.00 for certain measurement periods following the consummation of certain acquisitions), a consolidated net total leverage ratio of not more than 5.00 to 1.00 from and after the issuance of certain unsecured notes (which will be increased to 5.50 to 1.00 for certain measurement periods following the consummation of certain acquisitions), a consolidated senior secured net leverage ratio of not more than 3:50 to 1:00 from and after the issuance of certain unsecured notes and a consolidated interest coverage ratio of not less than 2.50 to 1.00.
· Financial statement reporting requirements, including quarterly unaudited financial statement reporting and annual audited financial statement reporting.
· Restrictions on cash distributions, including cash distributions to holders of equity units, unless certain leverage and coverage ratios are maintained before and after the cash distribution.
The Partnership was not in compliance with the leverage ratio covenant as of June 30, 2014, which noncompliance was waived pursuant to a waiver received by the Partnership on August 5, 2014. The Partnership was in compliance with all covenants as of September 30, 2014.
F&M Bank Loans. The F&M Bank loans had a credit commitment of $9,000,000. The F&M Bank loans were paid in full on February 12, 2014, with the proceeds from the BOA Credit Agreement.
Related Party Note Payable. On November 5, 2013, the Partnership issued a $1,000,000 promissory note to JP Development for working capital requirements. The note was to mature on November 5, 2016 and bore interest at 4.75%. On March 20, 2014, the Partnership repaid the promissory note in full.
8. Derivative Instruments
The Partnership is exposed to certain market risks related to the volatility of commodity prices and changes in interest rates. To monitor and manage these market risks, the Partnership has established comprehensive risk management policies and procedures. The Partnership does not enter into derivative instruments for any purpose other than hedging commodity price risk and interest rate risk. That is, the Partnership does not speculate using derivative instruments.
Commodity Price Risk. The Partnerships NGL distribution and sales segment is exposed to market risks related to the volatility of propane prices. Management believes it is prudent to limit the variability of a portion of the Partnerships propane purchases. To meet this objective, the Partnership uses swap contracts to manage its exposure to market fluctuations in propane prices. As of September 30, 2014, the Partnerships outstanding swap contracts contained a notional amount of 22,849,000 gallons of propane with maturity dates ranging from October 2014 through December 2016.
Interest Rate Risk. The Partnership is exposed to variable interest rate risk as a result of variable-rate borrowings under its revolving credit facility. Management believes it is prudent to limit the variability of a portion of the Partnerships interest payments. To meet this objective, the Partnership entered into interest rate swap agreements to manage the fluctuation in cash flows resulting from interest rate risk on a portion of its debt with a variable-rate component. These swaps ultimately change the variable-rate cash flow exposure on the debt obligations to fixed cash flows. Under the terms of the interest rate swaps, the Partnership receives variable interest rate payments and makes fixed interest rate payments, thereby creating the equivalent of fixed-rate debt for the portion of debt that is swapped. As of September 30, 2014, the Partnerships outstanding interest rate swap contracts contained a notional amount of $75,000,000 with maturity dates ranging from July 2015 through September 2015.
Credit Risk. By using derivative instruments to economically hedge exposure to changes in commodity prices and interest rates, the Partnership exposes itself to counterparty credit risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Partnership, which creates credit risk for the Partnership. When the fair value of a derivative is negative, the Partnership owes the counterparty and, therefore, it does not possess credit risk. The Partnership minimizes the credit risk in derivative instruments by entering into transactions with high-quality counterparties. The Partnership has entered into Master International Swap Dealers Association (IDSA) Agreements that allow for netting of swap contract receivables and payables in the event of default by either party.
Fair Value of Derivative Instruments. The Partnership measures derivative instruments at fair value using the income approach which discounts the future net cash settlements expected under the derivative contracts to a present value. These valuations utilize primarily observable (level 2) inputs, including contractual terms, commodity prices, interest rates and yield curves observable at commonly quoted intervals. None of the Partnerships derivative contracts are designated as hedging instruments for accounting purposes. The following table summarizes the fair values of the Partnerships derivative contracts included in the condensed consolidated balance sheets as of September 30, 2014 and December 31, 2013.
|
|
|
|
Asset Derivatives |
|
Liability Derivatives |
| ||||||||
Derivatives not designated |
|
|
|
September 30, |
|
December 31, |
|
September 30, |
|
December 31, |
| ||||
as hedging contracts: |
|
Balance Sheet Location |
|
2014 |
|
2013 |
|
2014 |
|
2013 |
| ||||
|
|
|
|
(in thousands) |
| ||||||||||
Commodity swap contracts |
|
Prepaid expenses and other current assets |
|
$ |
|
|
$ |
498 |
|
$ |
|
|
$ |
|
|
Commodity swap contracts |
|
Accrued liabilities |
|
|
|
|
|
391 |
|
|
| ||||
Commodity swap contracts |
|
Other long-term liabilities |
|
|
|
|
|
324 |
|
|
| ||||
Interest rate swap contracts |
|
Accrued liabilities |
|
|
|
|
|
207 |
|
200 |
| ||||
Interest rate swap contracts |
|
Other long-term liabilities |
|
|
|
|
|
|
|
4 |
| ||||
The Partnership presents the fair value of derivative contracts on a gross basis on the condensed consolidated balance sheets. In the condensed consolidated statements of cash flows, the effects of settlements of derivative instruments are classified as operating activities, consistent with the related transactions.
The following table summarize the amounts recognized with respect to the Partnerships derivative instruments within the condensed consolidated statements of operations.
|
|
|
|
Amount of Gain/(Loss) Recognized in Income on Derivatives |
| ||||||||||
Derivatives not designated as |
|
Location of Gain/(Loss) Recognized in |
|
Three months ended |
|
Nine months ended |
| ||||||||
hedging contracts: |
|
Income on Derivatives |
|
September 30, 2014 |
|
September 30, 2013 |
|
September 30, 2014 |
|
September 30, 2013 |
| ||||
|
|
|
|
(in thousands) |
| ||||||||||
Commodity derivatives |
|
Cost of sales |
|
$ |
(762 |
) |
$ |
1,022 |
|
$ |
(730 |
) |
$ |
413 |
|
Interest rate swaps |
|
Interest expense |
|
(11 |
) |
(182 |
) |
(206 |
) |
(106 |
) | ||||
9. Partners Capital
Common Units. On February 12, 2014, the Partnership issued 363,636 Class A Common Units to Lonestar Midstream Holdings, LLC (Lonestar), an affiliate of ArcLight for total net proceeds of $8,000,000.
Series D Preferred Units. On March 28, 2014 (the Issue Date), the Partnership authorized and issued to Lonestar 1,818,182 Series D Convertible Redeemable Preferred Units (the Series D Preferred Units) for a cash purchase price of $22.00 per unit pursuant to the terms of a Series D Subscription Agreement (the Subscription Agreement) by and among the Partnership, GP II, and Lonestar. This transaction resulted in proceeds to the Partnership of $40,000,000.
The Series D Preferred Units are a new class of voting equity security that ranks senior to all of the Partnerships other classes of equity securities with the respect to distribution rights and rights upon liquidation. The Series D Preferred Units have voting rights identical to the voting rights of the Partnerships Class A Common Units and will vote with the Partnerships common units as a single class, such that each Series D Preferred Unit (including each Series D Preferred Unit issued as an in-kind distribution, discussed below) is entitled to one vote for each common unit into which such Series D Preferred Unit is convertible on each matter with respect to which each common unit is entitled to vote.
Each Series D Preferred Unit (including Series D PIK Units issued as in-kind distributions) earns a cumulative distribution that is payable in either cash or Series D PIK Units as described below. The distribution rate for any such unit is (A) with respect to any distribution for the four consecutive quarters commencing with the quarter ended June 30, 2014, an amount equal to the greater of (i) the amount of aggregate distributions in cash for such quarter that would be payable with respect to such unit as such unit had been converted into a common unit of the Partnership as of the date of determination and (ii) $0.66, and (B) with respect to any distribution for any quarterly period after the quarter ending March 31, 2015, (i) the amount of aggregate distributions in cash for such quarter that would be payable with respect to such unit if such unit had been converted into a common unit of the Partnership as of the date of determination and (ii) $0.825. If the Partnership does not have sufficient available cash to make cash distributions with respect to the common units, the Partnership may pay all of any portion of the Series D Distribution in-kind during each quarter commencing on the Issue Date and ending on March 31, 2015. The amount of Series D PIK Units is determined based on any unpaid cash distribution divided by $22.00 and shall be made on the first day of the quarter following the quarter in which such payment of Series D PIK Units was due. During the three and nine months ended September 30, 2014, the Partnership issued to Lonestar 54,545 Series D PIK Units related to the distribution earned for the three months ended June 30, 2014. On October 1, 2014, the Partnership issued to Lonestar an additional 56,182 Series D PIK Units related to the distribution earned for the three months ended September 30, 2014.
The Series D Preferred Units (including Series D PIK Units issued as in-kind distributions) are convertible into common units of the Partnership on a one-for-one basis by Lonestar at any time after December 31, 2014. The Partnership may redeem the Series D Preferred Units (A) at any time prior to the Partnerships initial public offering of its common units or (B) during the period commencing on the Issue Date and ending on April 1, 2015, whichever is later, in each case at a price of $22.00 per Series D Preferred Unit, subject to adjustment pursuant to the provisions of the Partnership Agreement. On October 7, 2014, the Partnership paid $42,435,998 from proceeds related to the IPO to redeem all then outstanding Series D Preferred Units.
Subsequent to September 30, 2014, the Partnership amended its Partnership Agreement and completed recapitalization transactions in conjunction with its IPO. See Note 1 for details of the amended Partnership Agreement and the recapitalization transactions.
10. Commitments and Contingencies
Legal Matters. The Partnership is involved in legal proceedings and litigation in the ordinary course of business. In the opinion of management, the outcome of such matters will not have a material adverse effect on the Partnerships condensed consolidated financial position, results of operations, or liquidity.
Environmental Matters. The Partnership is subject to various federal, state and local laws and regulations relating to the protection of the environment. Such environmental laws and regulations impose numerous obligations, including the acquisition of permits to conduct regulated activities, the incurrence of capital expenditures to comply with applicable laws and restrictions on the generation, handling, treatment, storage, disposal and transportation of certain materials and wastes.
Failure to comply with such environmental laws and regulations can result in the assessment of substantial administrative, civil and criminal penalties, the imposition of remedial liabilities and even the issuance of injunctions restricting or prohibiting the Partnerships activities. The Partnership has established procedures for the ongoing evaluation of its operations, to identify potential environmental exposures and to comply with regulatory policies and procedures.
The Partnership accounts for environmental contingencies in accordance with Accounting Standards Codifications (ASC) Topic 410 related to accounting for contingencies. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, and do not contribute to current or future revenue generation, are expensed.
Liabilities are recorded when environmental assessments and/or clean- ups are probable, and the costs can be reasonably estimated. At September 30, 2014 and December 31, 2013, the Partnership had no material environmental matters.
Refined Products Terminals. In the third quarter of 2014, the Partnership discovered that certain elements of the product measurement and quality control at its refined products terminal in North Little Rock, Arkansas were not in compliance with industry standards and certain regulations. As a result, the terminal could under-deliver refined products to its customers and, consequently, recognize excessive gains on refined products generated through the terminals normal terminal and storage process. The Partnership recognized revenues for refined product gains as the products are sold at the terminal based on current market prices. The Partnership has undertaken procedures to improve and remediate its measurement and quality control processes to be in compliance with industry standards and regulations, and is in the process of discussing this matter with its customers and returning to them a certain amount of refined products. Because there are numerous elements inherent in the product measurement process that could affect the amount of refined product gains generated at the terminal, it is not practicable for the Partnership to accurately quantify this amount or the discrete period of refined product gains previously recognized that were caused by these specific issues. However, the Partnership, using available operational data and certain management assumptions, has reasonably estimated the volume of refined products to be returned to its customers of approximately 24,000 barrels, which amounts to an estimated value of $2,579,000 as of September 30, 2014. Accordingly, the Partnership recorded this charge to operating expense in the consolidated statement of operations for the nine months ended September 30, 2014 and will update the estimated accrual each reporting period based on changes in estimate related to volumes returned, market prices and other changes. The Partnership intends to return the estimated refined products to its customers during the fourth quarter of 2014.
11. Reportable Segments
The Partnerships operations are located in the United States and are organized into four reportable segments: crude oil pipelines and storage; crude oil supply and logistics; refined products terminals and storage; and NGL distribution and sales.
Crude oil pipelines and storage. The crude oil pipelines and storage segment consists of a crude oil pipeline operation and a crude oil storage facility. The crude oil pipeline operates in the Permian Basin and consists of approximately 50 miles of high-pressure steel pipeline with throughput capacity of approximately 100,000 barrels per day and a related system of truck terminals, LACT bay facilities, crude oil receipt points and crude oil storage facilities with an aggregate of 40,000 barrels of storage capacity. The Partnership also operates a crude oil storage facility that has an aggregate storage capacity of approximately 3,000,000 barrels in Cushing, Oklahoma.
Crude oil supply and logistics. The crude oil supply and logistics segment consists of crude oil supply activities and a fleet of crude oil gathering and transportation trucks. The Partnership conducts crude oil supply activities by purchasing crude oil for its own account from producers, aggregators and traders and selling crude oil to traders and refiners. The Partnership also owns a fleet of crude oil gathering and transportation trucks operating in and around high-growth drilling areas such as the Midcontinent, the Eagle Ford shale, and the Permian Basin. As described in Note 3, the disposition of the Bakken Business impacts the crude oil supply and logistics segment, as the results of those operations are now presented within discontinued operations and excluded from the segment information tables. Accordingly, the Partnership has recast the segment information.
Refined products terminals and storage. The refined products terminals and storage segment has aggregate storage capacity of 1.3 million barrels from two refined products terminals located in North Little Rock, Arkansas and Caddo Mills, Texas. The North Little Rock terminal consists of 11 storage tanks with an aggregate capacity of approximately 550,000 barrels
and has eight loading lanes with automated truck loading equipment. The Caddo Mills terminal consists of 10 storage tanks with an aggregate capacity of approximately 770,000 barrels and has five loading lanes with automated truck loading equipment. The North Little Rock terminal and the Caddo Mills terminal are primarily served by the Enterprise TE Products Pipeline Company LLC and the Explorer Pipeline, respectively.
NGL distribution and sales. The NGL distribution and sales segment consists of three businesses: (i) portable cylinder tank exchange (ii) sales of NGLs through our retail, commercial and wholesale distribution business and (iii) a NGL gathering and transportation business. Currently, the cylinder exchange network covers 48 states through a network of over 17,700 locations, which includes grocery chains, pharmacies, convenience stores and hardware stores. Additionally, in seven states in the southwest region of the U.S., the Partnership sells NGLs to retailers, wholesalers, industrial end-users and commercial and residential customers. The Partnership also owns a fleet of NGL gathering and transportation operations trucks operating in the Eagle Ford shale and the Permian Basin.
Corporate and other. Corporate and other includes general partnership expenses associated with managing all of the Partnerships reportable segments.
The Partnership accounts for intersegment revenues as if the revenues were generated from sales to third parties.
The Partnerships chief operating decision maker evaluates the segments operating performance based on Adjusted EBITDA. Adjusted EBITDA is defined by the Partnership as net income (loss) plus (minus) interest expense (income), income tax expense (benefit), depreciation and amortization expense, asset impairments, (gains) losses on asset sales, certain non-cash charges such as non-cash equity compensation, non-cash vacation expense, non-cash (gains) losses on commodity derivative contracts (total (gain) loss on commodity derivatives less net cash flow associated with commodity derivatives settled during the period), and selected (gains) charges and transaction costs that are unusual or non-recurring.
The following tables reflect certain financial data for each reportable segment for the three and nine months ended September 30, 2014 and 2013.
|
|
Three months ended September 30, |
|
Nine months ended September 30, |
| ||||||||
|
|
2014 |
|
2013 |
|
2014 |
|
2013 |
| ||||
|
|
(in thousands) |
| ||||||||||
External Revenues: |
|
|
|
|
|
|
|
|
| ||||
Crude oil pipelines and storage |
|
$ |
19,331 |
|
$ |
3,600 |
|
$ |
59,756 |
|
$ |
10,800 |
|
Crude oil supply and logistics |
|
358,944 |
|
517,869 |
|
1,062,945 |
|
1,396,142 |
| ||||
Refined products terminals and storage |
|
3,839 |
|
4,970 |
|
17,728 |
|
18,093 |
| ||||
NGL distribution and sales |
|
46,477 |
|
38,119 |
|
153,976 |
|
127,328 |
| ||||
Total revenues |
|
$ |
428,591 |
|
$ |
564,558 |
|
$ |
1,294,405 |
|
$ |
1,552,363 |
|
|
|
|
|
|
|
|
|
|
| ||||
Intersegment Revenues: |
|
|
|
|
|
|
|
|
| ||||
Crude oil pipelines and storage |
|
$ |
64 |
|
$ |
|
|
$ |
64 |
|
$ |
|
|
Crude oil supply and logistics |
|
11,236 |
|
|
|
36,462 |
|
|
| ||||
Refined products terminals and storage |
|
|
|
|
|
|
|
|
| ||||
NGL distribution and sales |
|
14 |
|
|
|
14 |
|
|
| ||||
Intersegment eliminations |
|
(11,314 |
) |
|
|
(36,540 |
) |
|
| ||||
Total intersegment revenues |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Cost of Sales, excluding depreciation and amortization: |
|
|
|
|
|
|
|
|
| ||||
Crude oil pipelines and storage |
|
$ |
12,894 |
|
$ |
|
|
$ |
40,952 |
|
$ |
|
|
Crude oil supply and logistics |
|
361,946 |
|
511,487 |
|
1,084,705 |
|
1,376,522 |
| ||||
Refined products terminals and storage |
|
266 |
|
306 |
|
4,349 |
|
3,179 |
| ||||
NGL distribution and sales |
|
27,856 |
|
21,695 |
|
95,450 |
|
72,653 |
| ||||
Intersegment eliminations |
|
(11,314 |
) |
|
|
(36,540 |
) |
|
| ||||
Amounts not included in segment Adjusted EBITDA |
|
1,014 |
|
(1,030 |
) |
1,943 |
|
(939 |
) | ||||
Total cost of sales, excluding depreciation and amortization |
|
$ |
392,662 |
|
$ |
532,458 |
|
$ |
1,190,859 |
|
$ |
1,451,415 |
|
|
|
|
|
|
|
|
|
|
| ||||
Operating Expense: |
|
|
|
|
|
|
|
|
| ||||
Crude oil pipelines and storage |
|
$ |
1,011 |
|
$ |
659 |
|
$ |
2,946 |
|
$ |
1,889 |
|
Crude oil supply and logistics |
|
1,937 |
|
2,383 |
|
5,045 |
|
5,807 |
| ||||
Refined products terminals and storage |
|
570 |
|
500 |
|
4,570 |
|
1,716 |
| ||||
NGL distribution and sales |
|
13,291 |
|
13,022 |
|
39,037 |
|
34,986 |
| ||||
Amounts not included in segment Adjusted EBITDA |
|
239 |
|
(54 |
) |
706 |
|
315 |
| ||||
Total operating expenses |
|
$ |
17,048 |
|
$ |
16,510 |
|
$ |
52,304 |
|
$ |
44,713 |
|
|
|
|
|
|
|
|
|
|
| ||||
Adjusted EBITDA: |
|
|
|
|
|
|
|
|
| ||||
Crude oil pipelines and storage |
|
$ |
5,301 |
|
$ |
2,931 |
|
$ |
15,447 |
|
$ |
8,954 |
|
Crude oil supply and logistics |
|
5,477 |
|
3,175 |
|
7,139 |
|
11,672 |
| ||||
Refined products terminals and storage |
|
2,525 |
|
3,899 |
|
7,666 |
|
12,726 |
| ||||
NGL distribution and sales |
|
2,256 |
|
386 |
|
9,902 |
|
11,527 |
| ||||
Total Adjusted EBITDA from reportable segments |
|
$ |
15,559 |
|
$ |
10,391 |
|
$ |
40,154 |
|
$ |
44,879 |
|
A reconciliation of total Adjusted EBITDA from reportable segments to net loss from continuing operations is included in the table below.
|
|
Three months ended September 30, |
|
Nine months ended September 30, |
| ||||||||
|
|
2014 |
|
2013 |
|
2014 |
|
2013 |
| ||||
|
|
(in thousands) |
| ||||||||||
Total Adjusted EBITDA from reportable segments |
|
$ |
15,559 |
|
$ |
10,391 |
|
$ |
40,154 |
|
$ |
44,879 |
|
Other expenses not allocated to reportable segments |
|
(5,966 |
) |
(6,036 |
) |
(19,502 |
) |
(18,254 |
) | ||||
Depreciation and amortization |
|
(10,395 |
) |
(7,790 |
) |
(30,569 |
) |
(22,976 |
) | ||||
Interest expense |
|
(2,406 |
) |
(2,279 |
) |
(7,957 |
) |
(6,094 |
) | ||||
Loss on extinguishment of debt |
|
|
|
|
|
(1,634 |
) |
|
| ||||
Income tax benefit (expense) |
|
158 |
|
(42 |
) |
2 |
|
(346 |
) | ||||
Loss on disposal of assets, net |
|
(533 |
) |
(478 |
) |
(1,193 |
) |
(1,477 |
) | ||||
Unit-based compensation |
|
(578 |
) |
(302 |
) |
(1,163 |
) |
(673 |
) | ||||
Total (loss) gain on commodity derivatives |
|
(762 |
) |
1,022 |
|
(730 |
) |
413 |
| ||||
Net cash payments (receipts) for commodity derivatives settled during the period |
|
105 |
|
8 |
|
(483 |
) |
526 |
| ||||
Transaction costs and other non-cash items |
|
(792 |
) |
(67 |
) |
(1,724 |
) |
(1,347 |
) | ||||
Net loss from continuing operations |
|
$ |
(5,610 |
) |
$ |
(5,573 |
) |
$ |
(24,799 |
) |
$ |
(5,349 |
) |
Total assets from the Partnerships reportable segments as of September 30, 2014 and December 31, 2013 were as follows:
|
|
September 30, |
|
December 31, |
| ||
|
|
(in thousands) |
| ||||
Crude oil pipelines and storage |
|
$ |
324,475 |
|
$ |
313,580 |
|
Crude oil supply and logistics |
|
203,305 |
|
208,420 |
| ||
Refined products terminals and storage |
|
129,878 |
|
132,325 |
| ||
NGL distribution and sales |
|
169,275 |
|
178,450 |
| ||
Corporate and other |
|
22,825 |
|
10,627 |
| ||
Total assets |
|
$ |
849,758 |
|
$ |
843,402 |
|
12. Related Party Transactions
The Partnership entered into transactions with CAMS Bluewire, an entity in which ArcLight holds a non-controlling interest. CAMS Bluewire provides IT support for the Partnership. The Partnership paid $131,000 and $85,000, for the three months ended and $347,000 and $527,000 for the nine months ended September 30, 2014 and 2013, respectively, for IT support and consulting services, and for the purchases of IT equipment which are included in operating expense, general and administrative and property, plant and equipment, net, in the condensed consolidated statements of operations and the condensed consolidated balance sheets.
As a result of the acquisition of the North Little Rock, Arkansas refined product terminal (ATT) in November 2012, TAC owns certain Class C common units in the Partnership. In addition, Mr. Greg Arnold, President and CEO of TAC, is also a director of the Partnership. The Partnerships refined products terminals and storage segment sells refined products to TAC. The Partnerships revenue from TAC was $550,000 and $1,489,000 for the three months ended September 30, 2014 and 2013, respectively, and $8,930,000 and $11,350,000 for the nine months ended September 30, 2014 and 2013, respectively. As of September 30, 2014 and December 31, 2013, the Partnership had trade receivable balances due from TAC of $94,000 and $1,048,000, respectively, which are included in receivables from related parties on the condensed consolidated balance sheets.
Beginning in the fourth quarter of 2013, the Partnerships NGL distribution and sales segment began purchasing refined products from TAC. The Partnership paid $554,000 and $1,402,000 for refined product purchases from TAC during the three and nine months ended September 30, 2014, respectively, which are included in cost of sales in the condensed consolidated statements of operations.
Beginning in July 2013, the Partnership has no employees. The employees supporting the operations of the Partnership are employees of GP II, and as such, the Partnership funds GP II for payroll and other payroll-related expenses incurred by the Partnership. As of September 30, 2014 and December 31, 2013, the Partnership had a payable balance due to GP II of $35,000
and a receivable balance due from GP II of $1,611,000, respectively, as a result of the timing of payroll funding, which is included in receivables from related parties on the condensed consolidated balance sheets.
The Partnership performs certain management services for JP Development. The Partnership receives a monthly fee of $50,000 for these services which reduced the general and administrative expenses in the condensed consolidated statements of operations by $150,000 and $450,000 for each of the three and nine months ended September 30, 2014 and 2013.
JP Development has a pipeline transportation business that provides crude oil pipeline transportation services to the Partnerships crude oil supply and logistics segment. As a result of utilizing JP Developments pipeline transportation services, the Partnership incurred pipeline tariff fees of $2,093,000 and $2,053,000 for the three months ended September 30, 2014 and 2013, respectively, and $7,047,000 and $5,898,000 for the nine months ended September 30, 2014 and 2013, respectively, which are included in costs of sales on the condensed consolidated statements of operations.
As discussed in Note 1, prior to the closing of the IPO, but subsequent to September 30, 2014, the Partnership distributed approximately $72,518,000, $5,988,000 and $3,286,000 of accounts receivable to Lonestar, TAC and JP Development, respectively.
13. Subsequent Events
On October 7, 2014, the Partnership completed its IPO (See Note 1).
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations.
Unless the context otherwise requires, references in this Quarterly Report on Form 10-Q (this report or this Form 10-Q) to JP Energy Partners, the Partnership, we, our, us, or like terms refer to JP Energy Partners LP and its subsidiaries, and references to our general partner refer to JP Energy GP II LLC, our general partner. References to our sponsor or Lonestar refer to Lonestar Midstream Holdings, LLC, which, together with JP Energy GP LLC, CB Capital Holdings II, LLC and the Greg Alan Arnold Separate Property Trust, entities owned by certain members of our management, owns and controls our general partner. References to ArcLight Capital refer to ArcLight Capital Partners, LLC and references to ArcLight Fund V refer to ArcLight Energy Partners Fund V, L.P. References to ArcLight refer collectively to ArcLight Capital and ArcLight Fund V. ArcLight Capital manages ArcLight Fund V, which controls our general partner through its ownership and control of Lonestar.
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the unaudited historical condensed consolidated financial statements and notes in Item 1. Financial Statements contained herein and our audited historical consolidated financial statements as of December 31, 2013 and 2012 and for the years ended December 31, 2013, 2012, and 2011 included in our final prospectus (our IPO Prospectus) dated October 1, 2014 and filed with the Securities and Exchange Commission (the SEC) pursuant to Rule 424(b) under the Securities Act of 1933, as amended (the Securities Act), on October 2, 2014. Among other things, those historical consolidated financial statements include more detailed information regarding the basis of presentation for the following information. This discussion contains forward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those discussed below as a result of various risk factors, including those that may not be in the control of management. Factors that could cause or contribute to such differences include, but are not limited to, those identified below and those discussed in the section entitled Risk Factors included in our IPO Prospectus. See also Forward-Looking Statements.
Forward-Looking Statements
Certain statements and information in this Form 10-Q may constitute forward-looking statements. The words believe, expect, anticipate, plan, intend, foresee, should, would, could or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions. Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, those summarized below:
· the price of, and the demand for, crude oil, refined products and NGLs in the markets we serve;
· the volumes of crude oil that we gather, transport and store, the throughput volumes at our refined products terminals and our NGL sales volumes;
· the fees we receive for the crude oil, refined products and NGL volumes we handle;
· pressures from our competitors, some of which may have significantly greater resources than us;
· the cost of propane that we buy for resale, including due to disruptions in its supply, and whether we are able to pass along cost increases to our customers;
· competitive pressures from other energy sources such as natural gas, which could reduce existing demand for propane;
· the risk of contract cancellation, non-renewal or failure to perform by our customers, and our inability to replace such contracts and/or customers;
· leaks or releases of hydrocarbons into the environment that result in significant costs and liabilities;
· the level of our operating, maintenance and general and administrative expenses;
· regulatory action affecting our existing contracts, our operating costs or our operating flexibility;
· failure to secure or maintain contracts with our largest customers, or non-performance of any of those customers under the applicable contract;
· competitive conditions in our industry;
· changes in the long-term supply of and demand for oil and natural gas;
· volatility of fuel prices;
· actions taken by our customers, competitors and third-party operators;
· our ability to complete growth projects on time and on budget;
· inclement or hazardous weather conditions, including flooding, and the physical impacts of climate change;
· environmental hazards;
· industrial accidents;
· changes in laws and regulations (or the interpretation thereof) related to the transportation, storage or terminaling of crude oil and refined products or the distribution and sales of NGLs;
· fires, explosions or other accidents;
· the effects of future litigation; and
· other factors discussed in this Form 10-Q.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.
General
We are a growth-oriented limited partnership formed in May 2010 by members of management and further capitalized in June 2011 by ArcLight to own, operate, develop and acquire a diversified portfolio of midstream energy assets. Our operations currently consist of four business segments: (i) crude oil pipelines and storage, (ii) crude oil supply and logistics, (iii) refined products terminals and storage and (iv) NGL distribution and sales. Together our businesses provide midstream infrastructure solutions for the growing supply of crude oil, refined products and NGLs in the United States. Since our formation, our primary business strategy has been to focus on:
· owning, operating and developing midstream assets serving areas experiencing dramatic increases in drilling activity and production growth, as well as serving key crude oil, refined product and NGL distribution hubs;
· providing midstream infrastructure solutions to users of liquid petroleum products in order to capitalize on changing product flows between producing and consuming markets resulting from the significant growth in hydrocarbon production across the United States; and
· operating one of the largest portable propane cylinder exchange businesses in the United States and capitalizing on the increase in demand and extended applications for portable propane cylinders.
We conduct our business through fee-based and margin-based arrangements.
Fee-based. We charge our customers a capacity, throughput or volume-based fee that is not contingent on commodity price changes. Our fee-based services include the operations in our crude oil pipelines and storage segment, our refined products terminals and storage segment, and the NGL transportation services we provide in our NGL distribution and sales segment. Our fee-based businesses are governed by tariffs or other negotiated fee agreements between us and our customers with terms ranging from one month to 10 years.
Margin-based. We purchase and sell crude oil in our crude oil supply and logistics segment and NGLs and refined products in our NGL distribution and sales segment. A substantial portion of our margin related to the purchase and sale of crude oil in our crude oil supply and logistics segment is derived from fee equivalent transactions in which we concurrently purchase and sell crude oil at prices that are based on the same index, thereby generating revenue consisting of a margin plus our
purchase, transportation, handling and storage costs. In our NGL distribution and sales segment, sales prices to our customers generally provide for a margin plus the cost of our products to our customers. We also perform blending services in our crude oil supply and logistics segment and our refined products terminals and storage segment, which allows us to generate additional margin based on the difference between our cost to purchase and blend the products and the market sales price of the finished blended product. We manage commodity price exposure through the structure of our sales and supply contracts and through a managed hedging program. Our risk management policy permits the use of financial instruments to reduce the exposure to changes in commodity prices that occur in the normal course of business but prohibits the use of financial instruments for trading or to speculate on future changes in commodity prices.
Recent Developments
Commission of Silver Dollar Pipeline System Expansions
Subsequent to September 30, 2014, we completed expansions of our Silver Dollar Pipeline System located in the Permian Basin. These expansions add an incremental 36 miles to the existing pipeline system, resulting in a total length of approximately 94 miles. As a result of these expansion projects, we amended an existing contract with one of our major customers, which increased the minimum volume commitment and extended the contract term by five years. In addition, the throughput capacity of our Silver Dollar Pipeline System increased by 30,000 barrels per day.
Initial Public Offering of Common Units
On October 7, 2014, we completed our initial public offering of 13,750,000 common units representing limited partner interests in us (the IPO), the effects of which are not included in our financial statements for the three and nine months ended September 30, 2014. Prior to the closing of our IPO, the following recapitalization transactions occurred:
· we distributed approximately $92.1 million of accounts receivable that comprise our working capital assets to the existing partners, pro rata in accordance with their ownership interests;
· each Class A common unit, Class B common unit and Class C common unit (collectively, the Existing Common Units) were split into approximately 0.89 common units, resulting in an aggregate of 22,677,004 outstanding Existing Common Units; and
· an aggregate of 18,213,502 Existing Common Units held by our existing partners were automatically converted into 18,213,502 subordinated units representing a 80.3% interest in us prior to the IPO, and a 50.0% interest in us after the closing of the IPO, with 4,463,502 Existing Common Units remaining representing a 19.7% interest in us (the Remaining Existing Common Units).
Subsequent to the closing of the IPO, the following recapitalization transactions occurred:
· the Remaining Existing Common Units were automatically converted on a one-to-one basis into 4,463,502 common units representing a 12.3% interest in us;
· the 45 general partner units in us held by our general partner were recharacterized as a non-economic general partner interest in us; and
· we issued 13,750,000 common units to the public representing a 37.7% interest in the Partnership.
The common units sold in the IPO were sold to the public at a price of $20.00 per common unit, less an underwriting discount of $1.20 per common unit. Net proceeds to us from the IPO were $257.1 million, after underwriting discounts and structuring fees.
We used the net proceeds from the IPO to (i) pay estimated offering expenses of approximately $2.0 million, (ii) redeem 100% of our issued and outstanding Series D Preferred Units for approximately $42.4 million, (iii) repay $195.6 million of debt outstanding under our revolving credit facility and (iv) replenish approximately $17.1 million of working capital that was distributed to existing partners immediately prior to the IPO.
Immediately following our repayment of the debt outstanding under our revolving credit facility, we borrowed approximately $75.0 million thereunder in order to replenish the remainder of the working capital that was distributed to existing partners immediately prior to the IPO.
Disposition of Assets
On June 30, 2014, we entered into and simultaneously closed an Asset Purchase Agreement (the Purchase Agreement) with Gold Spur Trucking, LLC (Buyer) pursuant to which we sold all of our trucking and related assets and activities in North Dakota, Montana and Wyoming (the Bakken Business) to the Buyer for a purchase price of $9.1 million. As a result, we recognized a loss on this sale of approximately $9.3 million during the second quarter of 2014, which primarily relates to the write-off of a customer contract intangible and goodwill associated with the Bakken Business.
JP Development Acquisition and Recast of Historical Financial Statements
On February 12, 2014, we acquired from our affiliate JP Development LP (JP Development) an intrastate crude oil pipeline system as well as a portfolio of crude oil logistics and NGL transportation and distribution assets (collectively, the Dropdown Assets) for approximately $319.1 million, inclusive of a working capital adjustment (the JP Development Dropdown). The consideration consisted of 12,561,934 of our Class A common units and $52.0 million in cash. The cash portion of the acquisition was funded from borrowings under our credit agreement with Bank of America, N.A. as administrative agent. The acquisition expanded our presence in the Permian Basin, one of the most prolific, high-growth, oil and liquids-rich basins in the United States.
Because the JP Development Dropdown was a transaction between commonly controlled entities (i.e. the buyer and seller are each affiliates of ArcLight), we were required to account for the transaction in a manner similar to the pooling of interests method of accounting. Under this method of accounting, we reflected in our balance sheet the Dropdown Assets at JP Developments historical carryover basis instead of reflecting the fair market value of assets and liabilities of the Dropdown Assets. In addition, we have retrospectively adjusted our financial statements to include the operating results of the Dropdown Assets from the dates these assets were originally acquired by JP Development (the dates upon which common control began).
We refer herein to acquisitions made by JP Development of the assets that were subsequently acquired by us through the JP Development Dropdown as our acquisitions because we include the operating results of those assets in our financial statements from the date JP Development acquired them. However, we do not include capital expenditures made by JP Development to acquire assets subsequently acquired by us in the discussion of our capital expenditures.
How We Evaluate Our Operations
Our management uses a variety of financial and operational metrics to analyze our performance. We view these metrics as important factors in evaluating our profitability and review these measurements for consistency and trend analysis. These metrics include volumes, revenues, cost of sales, excluding depreciation and amortization, operating expenses, Adjusted EBITDA and distributable cash flow.
Volumes and revenues
· Crude oil pipelines and storage. The amount of revenue we generate from our crude oil pipelines business depends primarily on throughput volumes. We generate a substantial majority of our crude oil pipeline revenues through long-term contracts containing acreage dedications or minimum volume commitments. Throughput volumes on our pipeline system are affected primarily by the supply of crude oil in the market served by our assets. The volume of crude oil stored at our crude oil storage facility in Cushing, Oklahoma has no impact on the revenue generated by our crude oil storage business because we receive a fixed monthly fee per barrel of shell capacity that is not contingent on the usage of our storage tanks.
· Crude oil supply and logistics. The revenue generated from our crude oil supply and logistics business depends on the volume of crude oil we purchase from producers, aggregators and traders and then sell to producers, traders and refiners as well as the volumes of crude oil that we gather and transport. The volume of our crude oil supply and logistics activities and the volumes transported by our crude oil gathering and transportation trucks are affected by the supply of crude oil in the markets served directly or indirectly by our assets. Accordingly, we actively monitor producer activity in the areas served by our crude oil supply and logistics business and other producing areas in the
United States to compete for volumes from crude oil producers. Revenues in this segment are also impacted by changes in the market price of commodities that we pass through to our customers.
· Refined products terminals and storage. The amount of revenue we generate from our refined products terminals depends primarily on the volume of refined products that we handle. These volumes are affected primarily by the supply of and demand for refined products in the markets served directly or indirectly by our refined products terminals, which we believe are strategically located to take advantage of infrastructure development opportunities resulting from growing markets.
· NGL distribution and sales. The amount of revenue we generate from our NGL distribution and sales segment depends on the gallons of NGLs we sell through our cylinder exchange and NGL sales businesses. In addition, our NGL transportation operations generate revenue based on the number of gallons of NGLs we gather and the distance we transport those gallons for our customers. Revenues in this segment are also impacted by changes in the market price of commodities that we pass through to our customers.
Cost of sales, excluding depreciation and amortization. Our management attempts to minimize cost of sales, excluding depreciation and amortization, in order to enhance the profitability of our operations. Cost of sales, excluding depreciation and amortization, includes the costs to purchase the product and any costs incurred to transport the product to the point of sale and to store the product until it is sold. We seek to minimize cost of sales, excluding depreciation and amortization, by attempting to acquire the products which we use in each of our segments at times and prices which are most optimal based on our knowledge of the industry and the regions in which we operate.
Operating expenses. Our management seeks to maximize the profitability of our operations in part by minimizing operating expenses. These expenses are comprised of payroll, wages and benefits, utility costs, fleet costs, repair and maintenance costs, rent, fuel, insurance premiums, taxes and other operating costs, some of which are independent of the volumes we handle.
Adjusted EBITDA and adjusted gross margin. Our management uses Adjusted EBITDA and adjusted gross margin to analyze our performance. We define Adjusted EBITDA as net income (loss) plus (minus) interest expense (income), income tax expense (benefit), depreciation and amortization expense, asset impairments, (gains) losses on asset sales, certain non-cash charges such as non-cash equity compensation, non-cash vacation expense, non-cash (gains) losses on commodity derivative contracts (total (gain) loss on commodity derivatives less net cash flow associated with commodity derivatives settled during the period) and selected (gains) charges and transaction costs that are unusual or non-recurring. We define adjusted gross margin as total revenues minus cost of sales, excluding depreciation and amortization, and certain non-cash charges such as non-cash vacation expense and non-cash gains (losses) on derivative contracts (total gain (losses) on commodity derivatives less net cash flow associated with commodity derivatives settled during the period).
Adjusted EBITDA and adjusted gross margin are supplemental, non-GAAP financial measures used by management and by external users of our financial statements, such as investors and commercial banks, to assess:
· our operating performance as compared to those of other companies in the midstream sector, without regard to financing methods, historical cost basis or capital structure;
· the ability of our assets to generate sufficient cash flow to make distributions to our unitholders;
· our ability to incur and service debt and fund capital expenditures; and
· the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.
Adjusted EBITDA and adjusted gross margin are not financial measures presented in accordance with GAAP. We believe that the presentation of these non-GAAP financial measures provides information useful to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to Adjusted EBITDA and adjusted gross margin are net income (loss) and operating income (loss), respectively. Adjusted EBITDA and adjusted gross margin should not be considered as an alternative to net income (loss), operating income (loss) or any other measure of financial performance or liquidity presented in accordance with GAAP. Adjusted EBITDA and adjusted gross margin exclude some, but not all, items that affect net income (loss) and operating income (loss) and these measures may vary among other companies. As a result, Adjusted EBITDA and adjusted gross margin may not be comparable to similarly titled measures of other companies,
thereby diminishing their utility.
Set forth below are reconciliations of Adjusted EBITDA and adjusted gross margin to their most directly comparable financial measure calculated in accordance with GAAP.
|
|
Three months ended September 30, |
|
Nine months ended September 30, |
| ||||||||
($ in thousands) |
|
2014 |
|
2013 |
|
2014 |
|
2013 |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
Net loss |
|
$ |
(5,610 |
) |
$ |
(5,637 |
) |
$ |
(34,407 |
) |
$ |
(5,436 |
) |
Interest expense |
|
2,406 |
|
2,279 |
|
7,957 |
|
6,094 |
| ||||
Income tax (benefit) expense |
|
(158 |
) |
42 |
|
(2 |
) |
346 |
| ||||
Depreciation and amortization |
|
10,395 |
|
7,790 |
|
30,569 |
|
22,976 |
| ||||
Discontinued operations (1) |
|
|
|
736 |
|
10,591 |
|
2,336 |
| ||||
Loss on disposal of assets, net |
|
533 |
|
478 |
|
1,193 |
|
1,477 |
| ||||
Total loss (gain) on commodity derivatives |
|
762 |
|
(1,022 |
) |
730 |
|
(413 |
) | ||||
Net cash (payments) receipts for commodity derivatives settled during the period |
|
(105 |
) |
(8 |
) |
483 |
|
(526 |
) | ||||
Unit-based compensation |
|
578 |
|
302 |
|
1,163 |
|
673 |
| ||||
Loss on extinguishment of debt |
|
|
|
|
|
1,634 |
|
|
| ||||
Transaction costs and other non-cash items |
|
792 |
|
67 |
|
1,724 |
|
1,347 |
| ||||
Adjusted EBITDA |
|
$ |
9,593 |
|
$ |
5,027 |
|
$ |
21,635 |
|
$ |
28,874 |
|
(1) In June 2014, we completed the sale of our crude oil logistics operations in the Bakken region of North Dakota, Montana and Wyoming.
|
|
Three Months Ended September 30, |
|
Nine Months Ended September 30, |
| ||||||||
($ in thousands) |
|
2014 |
|
2013 |
|
2014 |
|
2013 |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
Reconciliation of adjusted gross margin to operating income (loss) |
|
|
|
|
|
|
|
|
| ||||
Adjusted gross margin |
|
|
|
|
|
|
|
|
| ||||
Crude oil pipelines and storage |
|
$ |
6,501 |
|
$ |
3,600 |
|
$ |
18,868 |
|
$ |
10,800 |
|
Crude oil supply and logistics |
|
8,234 |
|
6,382 |
|
14,702 |
|
19,620 |
| ||||
Refined products terminals and storage |
|
3,573 |
|
4,664 |
|
13,379 |
|
14,914 |
| ||||
NGL distribution and sales |
|
18,635 |
|
16,424 |
|
58,540 |
|
54,675 |
| ||||
Total Adjusted gross margin |
|
36,943 |
|
31,070 |
|
105,489 |
|
100,009 |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
Operating expenses |
|
(17,048 |
) |
(16,510 |
) |
(52,304 |
) |
(44,713 |
) | ||||
General and administrative |
|
(11,315 |
) |
(10,656 |
) |
(35,196 |
) |
(30,968 |
) | ||||
Depreciation and amortization |
|
(10,395 |
) |
(7,790 |
) |
(30,569 |
) |
(22,976 |
) | ||||
Loss on disposal of assets |
|
(533 |
) |
(478 |
) |
(1,193 |
) |
(1,477 |
) | ||||
Total gain (loss) on commodity derivatives |
|
(762 |
) |
1,022 |
|
(730 |
) |
413 |
| ||||
Net cash (receipts) payments for commodity derivatives settled during the period |
|
105 |
|
8 |
|
(483 |
) |
526 |
| ||||
Other non-cash items |
|
(357 |
) |
|
|
(730 |
) |
|
| ||||
Operating (loss) income |
|
$ |
(3,362 |
) |
$ |
(3,334 |
) |
$ |
(15,716 |
) |
$ |
814 |
|
Results of Operations
The following table summarizes our results of operations for the periods presented (dollars in thousands).
|
|
Three Months Ended September 30, |
|
Nine Months Ended September 30, |
| ||||||||
|
|
2014 |
|
2013 (1) |
|
2014 |
|
2013 (1) |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
REVENUES: |
|
|
|
|
|
|
|
|
| ||||
Crude oil sales |
|
$ |
369,064 |
|
$ |
515,253 |
|
$ |
1,094,879 |
|
$ |
1,392,571 |
|
Gathering, transportation and storage fees |
|
10,689 |
|
6,199 |
|
31,074 |
|
14,247 |
| ||||
NGL and refined product sales |
|
42,458 |
|
36,940 |
|
149,555 |
|
127,439 |
| ||||
Refined products terminals and storage fees |
|
3,143 |
|
3,512 |
|
8,811 |
|
9,476 |
| ||||
Other revenues |
|
3,237 |
|
2,654 |
|
10,086 |
|
8,630 |
| ||||
Total revenues |
|
428,591 |
|
564,558 |
|
1,294,405 |
|
1,552,363 |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
COSTS AND EXPENSES: |
|
|
|
|
|
|
|
|
| ||||
Cost of sales, excluding depreciation and amortization |
|
392,662 |
|
532,458 |
|
1,190,859 |
|
1,451,415 |
| ||||
Operating expense |
|
17,048 |
|
16,510 |
|
52,304 |
|
44,713 |
| ||||
General and administrative |
|
11,315 |
|
10,656 |
|
35,196 |
|
30,968 |
| ||||
Depreciation and amortization |
|
10,395 |
|
7,790 |
|
30,569 |
|
22,976 |
| ||||
Loss on disposal of assets, net |
|
533 |
|
478 |
|
1,193 |
|
1,477 |
| ||||
Total costs and expenses |
|
431,953 |
|
567,892 |
|
1,310,121 |
|
1,551,549 |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
OPERATING (LOSS) INCOME |
|
(3,362 |
) |
(3,334 |
) |
(15,716 |
) |
814 |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
OTHER INCOME (EXPENSE) |
|
|
|
|
|
|
|
|
| ||||
Interest expense |
|
(2,406 |
) |
(2,279 |
) |
(7,957 |
) |
(6,094 |
) | ||||
Loss on extinguishment of debt |
|
|
|
|
|
(1,634 |
) |
|
| ||||
Other income, net |
|
|
|
82 |
|
506 |
|
277 |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAXES |
|
(5,768 |
) |
(5,531 |
) |
(24,801 |
) |
(5,003 |
) | ||||
|
|
|
|
|
|
|
|
|
| ||||
Income tax benefit (expense) |
|
158 |
|
(42 |
) |
2 |
|
(346 |
) | ||||
LOSS FROM CONTINUING OPERATIONS |
|
(5,610 |
) |
(5,573 |
) |
(24,799 |
) |
(5,349 |
) | ||||
|
|
|
|
|
|
|
|
|
| ||||
DISCONTINUED OPERATIONS (2) |
|
|
|
|
|
|
|
|
| ||||
Net loss from discontinued operations |
|
|
|
(64 |
) |
(9,608 |
) |
(87 |
) | ||||
|
|
|
|
|
|
|
|
|
| ||||
NET LOSS |
|
$ |
(5,610 |
) |
$ |
(5,637 |
) |
$ |
(34,407 |
) |
$ |
(5,436 |
) |
(1) Our historical condensed consolidated financial and operating data for the three and nine months ended September 30, 2013 have been retrospectively adjusted for the JP Development Dropdown. Please read Managements Discussion and Analysis of Financial Condition and Results of Operations Recent Developments JP Development Acquisition and Recast of Historical Financial Statements.
(2) In June 2014, we completed the sale of our crude oil logistics operations in the Bakken region of North Dakota, Montana and Wyoming.
Three Months Ended September 30, 2014 Compared to Three Months Ended September 30, 2013
Consolidated Results
|
|
Three months ended September 30, |
| |||||||
($ in thousands) |
|
2014 |
|
2013 |
|
Change |
| |||
|
|
|
|
|
|
|
| |||
Segment Adjusted EBITDA |
|
|
|
|
|
|
| |||
Crude oil pipelines and storage (1) |
|
$ |
5,301 |
|
$ |
2,931 |
|
$ |
2,370 |
|
Crude oil supply and logistics (1) |
|
5,477 |
|
3,175 |
|
2,302 |
| |||
Refined products terminals and storage (1) |
|
2,525 |
|
3,899 |
|
(1,374 |
) | |||
NGLs distribution and sales (1) |
|
2,256 |
|
386 |
|
1,870 |
| |||
Discontinued operations (2) |
|
|
|
672 |
|
(672 |
) | |||
Corporate and other |
|
(5,966 |
) |
(6,036 |
) |
70 |
| |||
Total Adjusted EBITDA |
|
9,593 |
|
5,027 |
|
4,566 |
| |||
Depreciation and amortization |
|
(10,395 |
) |
(7,790 |
) |
(2,605 |
) | |||
Interest expense |
|
(2,406 |
) |
(2,279 |
) |
(127 |
) | |||
Income tax benefit (expense), net |
|
158 |
|
(42 |
) |
200 |
| |||
Loss on disposal of assets |
|
(533 |
) |
(478 |
) |
(55 |
) | |||
Unit-based compensation |
|
(578 |
) |
(302 |
) |
(276 |
) | |||
Total gain (loss) on commodity derivatives |
|
(762 |
) |
1,022 |
|
(1,784 |
) | |||
Net cash (receipts) payments for commodity derivatives settled during the period |
|
105 |
|
8 |
|
97 |
| |||
Discontinued operations (2) |
|
|
|
(736 |
) |
736 |
| |||
Transaction costs and other non-cash items |
|
(792 |
) |
(67 |
) |
(725 |
) | |||
Net loss |
|
$ |
(5,610 |
) |
$ |
(5,637 |
) |
$ |
27 |
|
(1) See further analysis of Adjusted EBITDA of each reportable segment below.
(2) In June 2014, we completed the sale of our crude oil logistics operations in the Bakken region of North Dakota, Montana and Wyoming.
Depreciation and amortization expense. Depreciation and amortization expense for the three months ended September 30, 2014 increased to $10.4 million from $7.8 million for the three months ended September 30, 2013. The increase was primarily due to three acquisitions completed during or after August 2013. These acquisitions accounted for two more months of depreciation and amortization activity in the three months ended September 30, 2014, which was not included in our financial results for the three months ended September 30, 2013. Our property, plant and equipment base increased from $196.9 million as of September 30, 2013 to $244.6 million as of September 30, 2014. Intangible assets subject to amortization increased from $108.5 million as of September 30, 2013 to $153.1 million as of September 30, 2014.
Total (gain) on commodity derivatives and net cash (receipts) payments for commodity derivatives settled during the period. The sum of the total gain (loss) on commodity derivatives and net cash (receipts) payments for commodity derivatives settled during the period represents the total non-cash gain (loss) on commodity derivatives that was recognized in our statements of operations but excluded from our Adjusted EBITDA calculation. Total non-cash loss on commodity derivatives was $0.7 million for the three months ended September 30, 2014 compared to a gain of $1.0 million for the three months ended September 30, 2013. The change is due to the less favorable position of our propane hedges during the three months ended September 30, 2014 compared to the three months ended September 30, 2013.
Transaction costs and other non-cash items. Transaction costs and other non-cash items increased for the three months ended September 30, 2014 to $0.8 million from $0.1 million for the three months ended September 30, 2013 primarily due to an increase in non-cash vacation expense of $0.6 million related to an increase in employee headcount to support the growth of our business.
Segment Operating Results
Crude Oil Pipelines and Storage
|
|
Three months ended September 30, |
| |||||||
($ in thousands, unless otherwise noted) |
|
2014 |
|
2013 |
|
Change |
| |||
|
|
|
|
|
|
|
| |||
Volumes: |
|
|
|
|
|
|
| |||
Crude oil pipeline throughput (Bbsl/d) (1) |
|
20,411 |
|
|
(2) |
|
(2) | |||
|
|
|
|
|
|
|
| |||
Revenues: |
|
|
|
|
|
|
| |||
Crude oil sales |
|
$ |
12,782 |
|
$ |
|
|
$ |
12,782 |
|
Gathering, transportation and storage fees (3) |
|
6,210 |
|
3,600 |
|
2,610 |
| |||
Other revenues |
|
403 |
|
|
|
403 |
| |||
Total Revenues |
|
19,395 |
|
3,600 |
|
15,795 |
| |||
|
|
|
|
|
|
|
| |||
Cost of sales, excluding depreciation and amortization (4) (5) |
|
(12,894 |
) |
|
|
(12,894 |
) | |||
Adjusted gross margin |
|
6,501 |
|
3,600 |
|
2,901 |
| |||
|
|
|
|
|
|
|
| |||
Operating expenses (5) |
|
(1,011 |
) |
(659 |
) |
(352 |
) | |||
General and administrative (5) |
|
(189 |
) |
(10 |
) |
(179 |
) | |||
Segment Adjusted EBITDA |
|
$ |
5,301 |
|
$ |
2,931 |
|
$ |
2,370 |
|
(1) Represents the average daily throughput volume in our crude oil pipelines operations. The volumes in our crude oil storage operations have no effect on operations as we receive a set fee per month that does not fluctuate with the volume of crude oil stored.
(2) Not applicable because the Silver Dollar Pipeline System was acquired by JP Development in October 2013.
(3) Includes intersegment revenues of $0.1 million in the three months ended September 30, 2014. The intersegment revenues were eliminated upon consolidation.
(4) Includes intersegment cost of sales, excluding depreciation and amortization of $11.2 million in the three months ended September 30, 2014. The intersegment cost of sales, excluding depreciation and amortization were eliminated upon consolidation.
(5) Certain non-cash or non-recurring expenses have been excluded from cost of sales, excluding depreciation and amortization, operating expenses and general and administrative expenses for the purpose of calculating segment Adjusted EBITDA.
Adjusted gross margin. Adjusted gross margin increased to $6.5 million for the three months ended September 30, 2014 from $3.6 million for the three months ended September 30, 2013. The increase was due to the acquisition of Wildcat Permian in October 2013, which owns the Silver Dollar Pipeline System.
Operating expenses. Operating expenses increased to $1.0 million for the three months ended September 30, 2014 from $0.7 million for the three months ended September 30, 2013. The increase was due to the acquisition of Wildcat Permian in October 2013.
General and administrative. Substantially all general and administrative expenses for the three months ended September 30, 2014 were due to the acquisition of Wildcat Permian in October 2013.
Crude Oil Supply and Logistics
|
|
Three months ended September 30, |
| |||||||
($ in thousands, unless otherwise noted) |
|
2014 |
|
2013 |
|
Change |
| |||
|
|
|
|
|
|
|
| |||
Volumes: |
|
|
|
|
|
|
| |||
Crude oil sales (Bbls/d) (1) |
|
43,063 |
|
53,213 |
|
(10,150 |
) | |||
|
|
|
|
|
|
|
| |||
Revenues: |
|
|
|
|
|
|
| |||
Crude oil sales (2) |
|
$ |
367,518 |
|
$ |
515,253 |
|
$ |
(147,735 |
) |
Gathering, transportation and storage fees |
|
2,638 |
|
2,599 |
|
39 |
| |||
Other revenues |
|
24 |
|
17 |
|
7 |
| |||
Total Revenues |
|
370,180 |
|
517,869 |
|
(147,689 |
) | |||
|
|
|
|
|
|
|
| |||
Cost of sales, excluding depreciation and amortization (3) (4) |
|
(361,946 |
) |
(511,487 |
) |
149,541 |
| |||
Adjusted gross margin |
|
8,234 |
|
6,382 |
|
1,852 |
| |||
|
|
|
|
|
|
|
| |||
Operating expenses (4) |
|
(1,937 |
) |
(2,383 |
) |
446 |
| |||
General and administrative (4) |
|
(853 |
) |
(825 |
) |
(28 |
) | |||
Other income (expenses), net |
|
33 |
|
1 |
|
32 |
| |||
Segment Adjusted EBITDA |
|
$ |
5,477 |
|
$ |
3,175 |
|
$ |
2,302 |
|
(1) Represents the average daily sales volume in our crude oil supply and logistics operations.
(2) Includes intersegment revenues of $11.2 million in the three months ended September 30, 2014. The intersegment revenues were eliminated upon consolidation.
(3) Includes intersegment cost of sales, excluding depreciation and amortization of $0.1 million in the three months ended September 30, 2014. The intersegment cost of sales, excluding depreciation and amortization were eliminated upon consolidation.
(4) Certain non-cash or non-recurring expenses have been excluded from cost of sales, excluding depreciation and amortization, operating expenses and general and administrative expenses for the purpose of calculating segment Adjusted EBITDA.
Volumes. Crude oil sales volumes decreased to 43,063 barrels per day for the three months ended September 30, 2014 from 53,213 barrels per day for the three months ended September 30, 2013. The decrease was primarily due to an increase in available pipeline capacity in our area of operations.
Adjusted gross margin. Adjusted gross margin increased to $8.2 million for the three months ended September 30, 2014 from $6.4 million for the three months ended September 30, 2013. The significant increase in oil production growth in North America has generally created regional supply and demand imbalances, due to the lack of sufficient infrastructure to support the movement of such production, which increased certain crude oil location pricing differentials. The lack of existing pipeline takeaway capacity and associated logistical challenges has created market conditions that provided us with opportunities to capture above-baseline margins over the last few years. The favorable impact of widening pricing differentials in the third quarter of 2014 led to a $3.7 million increase in adjusted gross margin for the three months ended September 30, 2014 compared to the three months ended September 30, 2013. The increase was partially offset by a $1.9 million decrease in adjusted gross margin for the three months ended September 30, 2014 compared to the three months ended September 30, 2013 from a reduction in sales volumes as explained above.
Operating expenses. Operating expenses decreased to $2.0 million for the three months ended September 30, 2014 from $2.4 million for the three months ended September 30, 2013. The decrease was primarily due to decreases in fleet repair expenses ($0.2 million) and workers compensation claims ($0.2 million), related to our process improvement efforts set in place during 2014.
Refined Products Terminals and Storage
|
|
Three months ended September 30, |
| |||||||
($ in thousands, unless otherwise noted) |
|
2014 |
|
2013 |
|
Change |
| |||
|
|
|
|
|
|
|
| |||
Volumes: |
|
|
|
|
|
|
| |||
Terminal and storage throughput (Bbls/d) (1) |
|
67,628 |
|
77,516 |
|
(9,888 |
) | |||
|
|
|
|
|
|
|
| |||
Revenues: |
|
|
|
|
|
|
| |||
Refined product sales |
|
$ |
709 |
|
$ |
1,459 |
|
$ |
(750 |
) |
Refined products terminals and storage fees |
|
3,130 |
|
3,511 |
|
(381 |
) | |||
Total Revenues |
|
3,839 |
|
4,970 |
|
(1,131 |
) | |||
|
|
|
|
|
|
|
| |||
Cost of sales, excluding depreciation and amortization (2) |
|
(266 |
) |
(306 |
) |
40 |
| |||
Adjusted gross margin |
|
3,573 |
|
4,664 |
|
(1,091 |
) | |||
|
|
|
|
|
|
|
| |||
Operating expenses (2) |
|
(570 |
) |
(500 |
) |
(70 |
) | |||
General and administrative (2) |
|
(481 |
) |
(269 |
) |
(212 |
) | |||
Other income (expenses) |
|
3 |
|
4 |
|
(1 |
) | |||
Segment Adjusted EBITDA |
|
$ |
2,525 |
|
$ |
3,899 |
|
$ |
(1,374 |
) |
(1) Represents the average daily throughput volume in our refined products terminals and storage segment.
(2) Certain non-cash or non-recurring expenses have been excluded from cost of sales, excluding depreciation and amortization, operating expenses and general and administrative expenses for the purpose of calculating segment Adjusted EBITDA.
Revenues. Revenues decreased to $3.8 million for the three months ended September 30, 2014 from $5.0 million for the three months ended September 30, 2013. The decrease was primarily due to a decrease in refined product sales ($0.8 million) as a result of the improved measurement and quality control process we were undertaking during the third quarter of 2014 as well as a decrease in terminal and storage throughput volumes ($0.4 million) related to reduced throughput at our North Little Rock terminal attributable to supply disruptions and competition.
General and administrative. General and administrative expenses increased to $0.5 million for the three months ended September 30, 2014 from $0.3 million for the three months ended September 30, 2013. The increase was primarily due to an increase in employee salary and benefit expenses of $0.2 million related to the addition of personnel to support our refined products terminals and storage business.
NGL Distribution and Sales
|
|
Three months ended September 30, |
| |||||||
($ in thousands, unless otherwise noted) |
|
2014 |
|
2013 |
|
Change |
| |||
|
|
|
|
|
|
|
| |||
Volumes: |
|
|
|
|
|
|
| |||
NGL and refined product sales (Mgal/d) (1) |
|
176 |
|
137 |
|
39 |
| |||
|
|
|
|
|
|
|
| |||
Revenues: |
|
|
|
|
|
|
| |||
Gathering, transportation and storage fees |
|
$ |
1,892 |
|
$ |
|
|
$ |
1,892 |
|
NGL and refined product sales |
|
41,763 |
|
35,481 |
|
6,282 |
| |||
Other revenues |
|
2,836 |
|
2,638 |
|
198 |
| |||
Total Revenues |
|
46,491 |
|
38,119 |
|
8,372 |
| |||
|
|
|
|
|
|
|
| |||
Cost of sales, excluding depreciation and amortization (2) |
|
(27,856 |
) |
(21,695 |
) |
(6,161 |
) | |||
Adjusted gross margin |
|
18,635 |
|
16,424 |
|
2,211 |
| |||
|
|
|
|
|
|
|
| |||
Operating expenses (2) |
|
(13,291 |
) |
(13,022 |
) |
(269 |
) | |||
General and administrative (2) |
|
(3,214 |
) |
(3,091 |
) |
(123 |
) | |||
Other income (expenses), net |
|
126 |
|
75 |
|
51 |
| |||
Segment Adjusted EBITDA |
|
$ |
2,256 |
|
$ |
386 |
|
$ |
1,870 |
|
(1) Represents the average daily sales volume in our NGL distribution and sales segment.
(2) Certain non-cash or non-recurring expenses have been excluded from cost of sales, excluding depreciation and amortization, operating expenses and general and administrative expenses for the purpose of calculating segment Adjusted EBITDA.
Adjusted gross margin. Adjusted gross margin increased to $18.6 million for the three months ended September 30, 2014 from $16.4 million for the three months ended September 30, 2013. The major components of this increase were as follows:
· an increase in NGL and refined product sales volumes ($4.6 million) partially offset by a decrease in the average sales price of propane ($3.0 million). Sales volumes increased as a result of an expansion in our wholesale customer base in 2014 and the average sales price of propane decreased due to a greater mix of wholesale propane sales in 2014; and
· the acquisition of Highway Pipeline, Inc. (HPI) in October 2013, which generated $0.6 million of adjusted gross margin from the gathering and transportation of NGLs in the three months ended September 30, 2014, compared to zero in the three months ended September 30, 2013.
Nine Months Ended September 30, 2014 Compared to Nine Months Ended September 30, 2013
Consolidated Results
|
|
Nine months ended September 30, |
| |||||||
($ in thousands) |
|
2014 |
|
2013 |
|
Change |
| |||
|
|
|
|
|
|
|
| |||
Segment Adjusted EBITDA |
|
|
|
|
|
|
| |||
Crude oil pipelines and storage (1) |
|
$ |
15,447 |
|
$ |
8,954 |
|
$ |
6,493 |
|
Crude oil supply and logistics (1) |
|
7,139 |
|
11,672 |
|
(4,533 |
) | |||
Refined products terminals and storage (1) |
|
7,666 |
|
12,726 |
|
(5,060 |
) | |||
NGLs distribution and sales (1) |
|
9,902 |
|
11,527 |
|
(1,625 |
) | |||
Discontinued operations (2) |
|
983 |
|
2,249 |
|
(1,266 |
) | |||
Corporate and other |
|
(19,502 |
) |
(18,254 |
) |
(1,248 |
) | |||
Total Adjusted EBITDA |
|
21,635 |
|
28,874 |
|
(7,239 |
) | |||
Depreciation and amortization |
|
(30,569 |
) |
(22,976 |
) |
(7,593 |
) | |||
Interest expense |
|
(7,957 |
) |
(6,094 |
) |
(1,863 |
) | |||
Loss on extinguishment of debt |
|
(1,634 |
) |
|
|
(1,634 |
) | |||
Income tax benefit (expense), net |
|
2 |
|
(346 |
) |
348 |
| |||
Loss on disposal of assets |
|
(1,193 |
) |
(1,477 |
) |
284 |
| |||
Unit-based compensation |
|
(1,163 |
) |
(673 |
) |
(490 |
) | |||
Total gain (loss) on commodity derivatives |
|
(730 |
) |
413 |
|
(1,143 |
) | |||
Net cash (receipts) payments for commodity derivatives settled during the period |
|
(483 |
) |
526 |
|
(1,009 |
) | |||
Discontinued operations (2) |
|
(10,591 |
) |
(2,336 |
) |
(8,255 |
) | |||
Transaction costs and other non-cash items |
|
(1,724 |
) |
(1,347 |
) |
(377 |
) | |||
Net loss |
|
$ |
(34,407 |
) |
$ |
(5,436 |
) |
$ |
(28,971 |
) |
(1) See further analysis of Adjusted EBITDA of each reportable segment below.
(2) In June 2014, we completed the sale of our crude oil logistics operations in the Bakken region of North Dakota, Montana and Wyoming.
Discontinued operations Adjusted EBITDA. Adjusted EBITDA related to the Bakken Business included previously in our crude oil supply and logistics segment decreased to $1.0 million for the nine months ended September 30, 2014 from $2.2 million for the nine months ended September 30, 2013. The decrease was primarily due to a decrease in transported crude oil volumes of our Bakken crude oil logistics business. Due to increased competition and rising employee costs in the region, in June 2014, we completed the sale of our crude oil logistics operations in the Bakken region of North Dakota, Montana and Wyoming.
Corporate and other Adjusted EBITDA. Corporate and other Adjusted EBITDA primarily represents corporate expenses not allocated to reportable segments. Such expenses increased to $19.5 million for the nine months ended September 30, 2014 from $18.3 million for the nine months ended September 30, 2013. The increase was primarily due to an increase in payroll and benefits expenses of $4.0 million related to the addition of corporate office personnel to support the growth of our business. This increase was offset by a decrease in professional fees of $2.8 million related to audit, consulting and legal expenses.
Depreciation and amortization expense. Depreciation and amortization expense for the nine months ended September 30, 2014 increased to $30.6 million from $23.0 million for the nine months ended September 30, 2013. The increase was primarily due to four acquisitions completed during or after July 2013. These acquisitions accounted for at least six more months of depreciation and amortization activity in the nine months ended September 30, 2014, which was not included in our financial results for the nine months ended September 30, 2013. Our property, plant and equipment base increased from $196.9 million as of September 30, 2013 to $244.6 million as of September 30, 2014. Intangible assets subject to amortization increased from $108.5 million as of September 30, 2013 to $153.1 million as of September 30, 2014.
Interest expense. Interest expense for the nine months ended September 30, 2014 increased to $8.0 million from $6.1 million for the nine months ended September 30, 2013 due primarily to an increase in average borrowings from $170.3 million in the nine months ended September 30, 2013 to $198.1 million in the nine months ended September 30, 2014.
Loss on extinguishment of debt. Loss on extinguishment of debt of $1.6 million for the nine months ended September 30, 2014 relates to the write off of deferred financing costs associated with extinguishment of our 2011 revolving credit facility in February 2014.
Total gain (loss) on commodity derivatives and net cash (receipts) payments for commodity derivatives settled during the period. The sum of the total gain (loss) on commodity derivatives and net cash (receipts) payments for commodity derivatives settled during the period represents the total non-cash gain (loss) on commodity derivatives that was recognized in our statements of operations but excluded from our Adjusted EBITDA calculation. Total non-cash loss on commodity derivatives was $1.2 million for the nine months ended September 30, 2014 compared to a $0.9 million gain for the nine months ended September 30, 2013. The change is due to the less favorable position of our propane hedges during the nine months ended September 30, 2014 compared to the nine months ended September 30, 2013.
Discontinued operations. Discontinued operations primarily represents non-cash depreciation and amortization expense and loss on disposal of assets related to the Bakken Business previously owned by our crude oil supply and logistics segment. Such expenses increased to $10.6 million for the nine months ended September 30, 2014 from $2.3 million for the nine months ended September 30, 2013. The increase was primarily due to the loss on the disposal of our Bakken Business of $7.3 million in the nine months ended September 30, 2014.
Segment Operating Results
Crude Oil Pipelines and Storage
|
|
Nine months ended September 30, |
| |||||||
($ in thousands, unless otherwise noted) |
|
2014 |
|
2013 |
|
Change |
| |||
|
|
|
|
|
|
|
| |||
Volumes: |
|
|
|
|
|
|
| |||
Crude oil pipeline throughput (Bbls/d) (1) |
|
19,875 |
|
|
(2) |
|
(2) | |||
|
|
|
|
|
|
|
| |||
Revenues: |
|
|
|
|
|
|
| |||
Crude oil sales |
|
$ |
40,597 |
|
$ |
|
|
$ |
40,597 |
|
Gathering, transportation and storage fees (3) |
|
18,001 |
|
10,800 |
|
7,201 |
| |||
Other revenues |
|
1,222 |
|
|
|
1,222 |
| |||
Total Revenues |
|
59,820 |
|
10,800 |
|
49,020 |
| |||
|
|
|
|
|
|
|
| |||
Cost of sales, excluding depreciation and amortization (4) (5) |
|
(40,952 |
) |
|
|
(40,952 |
) | |||
Adjusted gross margin |
|
18,868 |
|
10,800 |
|
8,068 |
| |||
|
|
|
|
|
|
|
| |||
Operating expenses (5) |
|
(2,946 |
) |
(1,889 |
) |
(1,057 |
) | |||
General and administrative (5) |
|
(475 |
) |
43 |
|
(518 |
) | |||
Segment Adjusted EBITDA |
|
$ |
15,447 |
|
$ |
8,954 |
|
$ |
6,493 |
|
(1) Represents the average daily throughput volume in our crude oil pipelines operations. The volumes in our crude oil storage operations have no effect on operations as we receive a set fee per month that does not fluctuate with the volume of crude oil stored.
(2) Not applicable because the Silver Dollar Pipeline System was acquired by JP Development in October 2013.
(3) Includes intersegment revenues of $0.1 million in the nine months ended September 30, 2014. The intersegment revenues were eliminated upon consolidation.
(4) Includes intersegment cost of sales, excluding depreciation and amortization of $36.5 million in the nine months ended September 30, 2014. The intersegment cost of sales, excluding depreciation and amortization, were eliminated upon consolidation.
(5) Certain non-cash or non-recurring expenses have been excluded from cost of sales, excluding depreciation and amortization, operating expenses and general and administrative expenses for the purpose of calculating segment Adjusted EBITDA.
Adjusted gross margin. Adjusted gross margin increased to $18.9 million for the nine months ended September 30, 2014 from $10.8 million for the nine months ended September 30, 2013. The increase was due to the acquisition of Wildcat Permian in October 2013, which owns the Silver Dollar Pipeline System.
Operating expenses. Operating expenses increased to $2.9 million for the nine months ended September 30, 2014 from $1.9 million for the nine months ended September 30, 2013. The increase was due to the acquisition of Wildcat Permian in October 2013.
General and administrative. Substantially all of the increase in general and administrative for the nine months ended September 30, 2014 was due to the acquisition of Wildcat Permian in October 2013.
Crude Oil Supply and Logistics
|
|
Nine months ended September 30, |
| |||||||
($ in thousands, unless otherwise noted) |
|
2014 |
|
2013 |
|
Change |
| |||
|
|
|
|
|
|
|
| |||
Volumes: |
|
|
|
|
|
|
| |||
Crude oil sales (Bbls/d) (1) |
|
42,630 |
|
51,992 |
|
(9,362 |
) | |||
|
|
|
|
|
|
|
| |||
Revenues: |
|
|
|
|
|
|
| |||
Crude oil sales (2) |
|
$ |
1,090,745 |
|
$ |
1,392,571 |
|
$ |
(301,826 |
) |
Gathering, transportation and storage fees |
|
8,582 |
|
3,447 |
|
5,135 |
| |||
Other revenues |
|
80 |
|
124 |
|
(44 |
) | |||
Total Revenues |
|
1,099,407 |
|
1,396,142 |
|
(296,735 |
) | |||
|
|
|
|
|
|
|
| |||
Cost of sales, excluding depreciation and amortization (3) (4) |
|
(1,084,705 |
) |
(1,376,522 |
) |
291,817 |
| |||
Adjusted gross margin |
|
14,702 |
|
19,620 |
|
(4,918 |
) | |||
|
|
|
|
|
|
|
| |||
Operating expenses (4) |
|
(5,045 |
) |
(5,807 |
) |
762 |
| |||
General and administrative (4) |
|
(2,586 |
) |
(2,143 |
) |
(443 |
) | |||
Other income (expenses), net |
|
68 |
|
2 |
|
66 |
| |||
Segment Adjusted EBITDA |
|
$ |
7,139 |
|
$ |
11,672 |
|
$ |
(4,533 |
) |
(1) Represents the average daily sales volume in our crude oil supply and logistics operations.
(2) Includes intersegment revenues of $36.5 million in the nine months ended September 30, 2014. The intersegment revenues were eliminated upon consolidation.
(3) Includes intersegment cost of sales, excluding depreciation and amortization of $0.1 million in the nine months ended September 30, 2014. The intersegment cost of sales, excluding depreciation and amortization were eliminated upon consolidation.
(4) Certain non-cash or non-recurring expenses have been excluded from cost of sales, excluding depreciation and amortization, operating expenses and general and administrative expenses for the purpose of calculating segment Adjusted EBITDA.
Volumes. Crude oil sales volumes decreased to 42,630 barrels per day for the nine months ended September 30, 2014 from 51,992 barrels per day for the nine months ended September 30, 2013. The decrease was primarily due to an increase in available pipeline capacity in our area of operations.
Adjusted gross margin. Adjusted gross margin decreased to $14.7 million for the nine months ended September 30, 2014 from $19.6 million for the nine months ended September 30, 2013. The significant increase in oil production growth in North America has generally created regional supply and demand imbalances, due to the lack of sufficient infrastructure to support the movement of such production, which increased certain crude oil location pricing differentials. The lack of existing pipeline takeaway capacity and associated logistical challenges has created market conditions that provided us with opportunities to capture above-baseline margins over the last few years. The decrease in adjusted gross margin for the nine months ended September 30, 2014 compared to the nine months ended September 30, 2013 was primarily due to a $3.2 million decrease from the reduction in sales volumes as explained above and a $1.7 million decrease from fewer opportunities to capture above-baseline margins.
Operating expenses. Operating expenses decreased to $5.0 million for the nine months ended September 30, 2014 from $5.8 million for the nine months ended September 30, 2013. The decrease was primarily due to decreases in fleet repair expenses ($0.4 million) and workers compensation claims ($0.4 million), related to our process improvement efforts set in place during 2014.
General and administrative. General and administrative expenses increased to $2.6 million for the nine months ended September 30, 2014 from $2.1 million for the nine months ended September 30, 2013. The increase was primarily due to an increase $0.3 million of personnel and office expenses related to an increase in headcount to support the growing business.
Refined Products Terminals and Storage
|
|
Nine months ended September 30, |
| |||||||
($ in thousands, unless otherwise noted) |
|
2014 |
|
2013 |
|
Change |
| |||
|
|
|
|
|
|
|
| |||
Volumes: |
|
|
|
|
|
|
| |||
Terminal and storage throughput (Bbls/d) (1) |
|
65,100 |
|
70,864 |
|
(5,763 |
) | |||
|
|
|
|
|
|
|
| |||
Revenues: |
|
|
|
|
|
|
| |||
Refined product sales |
|
$ |
8,984 |
|
$ |
8,618 |
|
$ |
366 |
|
Refined products terminals and storage fees |
|
8,744 |
|
9,475 |
|
(731 |
) | |||
Total Revenues |
|
17,728 |
|
18,093 |
|
(365 |
) | |||
|
|
|
|
|
|
|
| |||
Cost of sales, excluding depreciation and amortization (2) |
|
(4,349 |
) |
(3,179 |
) |
(1,170 |
) | |||
Adjusted gross margin |
|
13,379 |
|
14,914 |
|
(1,535 |
) | |||
|
|
|
|
|
|
|
| |||
Operating expenses (2) |
|
(4,570 |
) |
(1,716 |
) |
(2,854 |
) | |||
General and administrative (2) |
|
(1,152 |
) |
(476 |
) |
(676 |
) | |||
Other income (expenses), net |
|
9 |
|
4 |
|
5 |
| |||
Segment Adjusted EBITDA |
|
$ |
7,666 |
|
$ |
12,726 |
|
$ |
(5,060 |
) |
(1) Represents the average daily throughput volume in our refined products terminals and storage segment.
(2) Certain non-cash or non-recurring expenses have been excluded from cost of sales, excluding depreciation and amortization, operating expenses and general and administrative expenses for the purpose of calculating segment Adjusted EBITDA.
Revenues. Revenues decreased to $17.7 million for the nine months ended September 30, 2014 from $18.1 million for the nine months ended September 30, 2013. The decrease was primarily due to a decrease in terminal and storage throughput volumes ($0.7 million) related to increased competition near our North Little Rock Terminal, partially offset by an increase in refined product sales ($0.3 million) from the addition of conventional blendstocks for oxygenate blending (CBOB) in late December 2013.
Cost of sales, excluding depreciation and amortization. Cost of sales, excluding depreciation and amortization increased to $4.3 million for the nine months ended September 30, 2014 from $3.2 million for the nine months ended September 30, 2013. The increase was primarily due to the addition of CBOB at our Caddo Mills terminal in late December 2013, which resulted in additional cost of sales for the nine months ended September 30, 2014 that were not included in the nine months ended September 30, 2013.
Operating expenses. Operating expenses increased to $4.6 million for the nine months ended September 30, 2014 from $1.7 million for the nine months ended September 30, 2013. The increase was primarily due to the recording of a charge of $2.6 million at our North Little Rock, Arkansas terminal in the nine months ended September 30, 2014. In the third quarter of 2014, we discovered that certain elements of our product measurement and quality control at our refined products terminal in North Little Rock, Arkansas were not in compliance with industry standards and certain regulations. As a result, the terminal under-delivered refined products to its customers and consequently, recognized excessive gains on refined products generated during the terminals normal terminal and storage process. We have undertaken procedures to improve and remediate our measurement and quality control processes to be in compliance with industry standards, and we are in the process of returning a certain amount of refined products to customers. We estimated the volume of refined products to be returned to customers of approximately 24,000 barrels, which amounts to an estimated value of $2.6 million as of September 30, 2014. Accordingly, we recorded this charge to operating expenses in the consolidated statement of operations for the nine months ended September 30, 2014 and will update the estimated accrual each reporting period based on changes in estimate related to volumes returned, market prices and other changes. We intend to return the estimated refined products during the fourth quarter of 2014.
General and administrative. General and administrative increased to $1.2 million for the nine months ended September 30, 2014 from $0.5 million for the nine months ended September 30, 2013. The increase was primarily due to an increase in employee salary and benefit expenses of $0.6 million related to the addition of personnel to support our refined products terminals and storage business.
NGL Distribution and Sales
|
|
Nine months ended September 30, |
| |||||||
($ in thousands, unless otherwise noted) |
|
2014 |
|
2013 |
|
Change |
| |||
|
|
|
|
|
|
|
| |||
Volumes: |
|
|
|
|
|
|
| |||
NGL and refined product sales (Mgal/d) (1) |
|
190 |
|
167 |
|
23 |
| |||
|
|
|
|
|
|
|
| |||
Revenues: |
|
|
|
|
|
|
| |||
Gathering, transportation and storage fees |
|
$ |
4,541 |
|
$ |
|
|
$ |
4,541 |
|
NGL and refined product sales |
|
140,585 |
|
118,822 |
|
21,763 |
| |||
Other revenues |
|
8,864 |
|
8,506 |
|
358 |
| |||
Total Revenues |
|
153,990 |
|
127,328 |
|
26,662 |
| |||
|
|
|
|
|
|
|
| |||
Cost of sales, excluding depreciation and amortization (2) |
|
(95,450 |
) |
(72,653 |
) |
(22,797 |
) | |||
Adjusted gross margin |
|
58,540 |
|
54,675 |
|
3,865 |
| |||
|
|
|
|
|
|
|
| |||
Operating expenses (2) |
|
(39,037 |
) |
(34,986 |
) |
(4,051 |
) | |||
General and administrative (2) |
|
(10,051 |
) |
(8,428 |
) |
(1,623 |
) | |||
Other income (expenses), net |
|
450 |
|
266 |
|
184 |
| |||
Segment Adjusted EBITDA |
|
$ |
9,902 |
|
$ |
11,527 |
|
$ |
(1,625 |
) |
(1) Represents the average daily sales volume in our NGL distribution and sales segment.
(2) Certain non-cash or non-recurring expenses have been excluded from cost of sales, excluding depreciation and amortization, operating expenses and general and administrative expenses for the purpose of calculating segment Adjusted EBITDA.
Adjusted gross margin. Adjusted gross margin increased to $58.5 million for the nine months ended September 30, 2014 from $54.7 million for the nine months ended September 30, 2013. The major components of this increase were as follows:
· an increase in NGL and refined product sales volumes ($7.5 million) partially offset by a decrease in the average sales price of propane ($5.5 million). Sales volumes increased as a result of an expansion in our wholesale customer base in 2014, as well as the acquisition of BMH Propane, LLC (BMH) in July 2013; and
· the acquisition of HPI in October 2013, which generated $1.8 million of adjusted gross margin from the gathering and transportation of NGLs in the nine months ended September 30, 2014, compared to zero in the nine months ended September 30, 2013.
Operating expenses. Operating expenses increased to $39.0 million for the nine months ended September 30, 2014 from $35.0 million for the nine months ended September 30, 2013. The major components of this increase were as follows:
· the acquisitions of BMH in July 2013, and HPI in October 2013. These acquired businesses incurred $1.9 million of operating expenses in the nine months ended September 30, 2014, that were not included in the nine months ended September 30, 2013; and
· increases of $1.0 million in business insurance expenses, $0.8 million in repairs and maintenance and $0.5 million in property taxes, as a result of the western expansion of our cylinder exchange business.
General and administrative. General and administrative increased to $10.1 million for the nine months ended September 30, 2014 from $8.4 million for the nine months ended September 30, 2013. The major components of this increase were as follows:
· the acquisitions of BMH in July 2013, and HPI in October 2013. These acquired businesses incurred $0.6 million of general and administrative expenses in the nine months ended September 30, 2014, that were not included in the nine months ended September 30, 2013; and
· increase in employee costs of approximately $0.9 million, as a result of the increase in headcount to support our growing business.
Liquidity and Capital Resources
We principally require liquidity to finance current operations, fund capital expenditures, including acquisitions from time to time, and to service our debt. Historically, our sources of liquidity included cash generated from operations, equity investments by ArcLight and borrowings under our revolving credit facility. We expect our sources of liquidity to include cash generated from operations, borrowings under our revolving credit facility and issuances of debt and equity.
We believe that cash on hand, cash generated from operations and availability under our revolving credit facility will be adequate to meet our operating needs, our planned short-term capital and debt service requirements and our cash distribution requirements. We believe that future internal growth projects or potential acquisitions will be funded primarily through borrowings under our revolving credit facility or through issuances of debt and equity securities.
Distributions
We do not have a legal obligation to pay distributions, except as provided in our partnership agreement. Please read Cash Distribution Policy and Restrictions on Distributions in our IPO Prospectus.
Revolving Credit Facility
Our revolving credit facility has a maturity date of February 12, 2019 and consists of a $275.0 million revolving line of credit, which includes a sub-limit of up to $100.0 million for letters of credit, and contains an accordion feature that will allow us to increase the borrowing capacity thereunder from $275.0 million to $425.0 million, subject to obtaining additional or increased
lender commitments. Our revolving credit facility is available for refinancing and repayment of certain existing indebtedness, working capital, capital expenditures, permitted acquisitions and for general partnership purposes, including distributions, not in contravention of law or the loan documents. Substantially all of our assets, but excluding equity in and assets of unrestricted subsidiaries and other customary exclusions, are pledged as collateral under our revolving credit facility. Our revolving credit facility contains customary covenants, including, among others, those that restrict our ability to make or limit certain payments, distributions, acquisitions, loans, or investments, incur certain indebtedness or create certain liens on our assets.
Subsequent to the IPO, our revolving credit facility also requires compliance with certain financial covenants, which include the following:
· a consolidated interest coverage ratio of not less than 2.50;
· prior to our issuance of certain unsecured notes, a consolidated net total leverage ratio of not more than 4.50, which requirement to maintain a certain consolidated net total leverage ratio is subject to a provision for increases up to 5.00 in connection with certain future acquisitions and (ii) from and after our issuance of certain unsecured notes, a consolidated net total leverage ratio of not more than 5.00, which requirement to maintain a certain consolidated net total ratio is subject to increase up to 5.50 in connection with certain future acquisitions; and
· from and after our issuance of certain unsecured notes, a consolidated senior secured net leverage ratio of not more than 3.50.
We were not in compliance with the leverage ratio covenant as of June 30, 2014, which noncompliance was waived pursuant to a waiver received by us on August 5, 2014. We were in compliance with all covenants as of September 30, 2014.
As of October 31, 2014, we had $80.0 million of outstanding borrowings under our revolving credit facility and a remaining borrowing capacity of $147.9 million thereunder. Issued and outstanding letters of credit, which reduced borrowing capacity, totaled $47.1 million as of October 31, 2014.
Borrowings under our revolving credit facility bear interest at a rate per annum equal to, at our option, either (a) a Base Rate determined by reference to the highest of (1) the federal funds effective rate plus 0.50%, (2) the prime rate of Bank of America, and (3) LIBOR, subject to certain adjustments, plus 1.00% or (b) LIBOR, in each case plus an Applicable Margin (Base Rate, LIBOR and Applicable Margin each as defined in our revolving credit facility). As of September 30, 2014, the Applicable Margin for Base Rate loans range from 0.75% to 2.00% and the Applicable Margin for LIBOR loans range from 1.75% to 3.00%, in each case based on our consolidated net total leverage ratio.
Series D Convertible Preferred Units
On March 28, 2014, we issued 1,818,182 Series D Preferred Units to Lonestar for $22.00 per Series D Preferred Unit for total consideration of $40.0 million in cash. Each Series D Preferred Unit earns a cumulative distribution that is payable in either cash or Series D Paid-in-Kind (PIK) Units. For the nine months ended September 30, 2014, we issued 54,545 Series D PIK Units to Lonestar related to distributions earned for the three months ended June 30, 2014. On October 1, 2014, we issued an additional 56,182 Series D PIK Units to Lonestar related to the distribution earned for the three months ended September 30, 2014. On October 7, 2014, we paid $42.4 million using the proceeds from the IPO and redeemed all then outstanding Series D Preferred Units.
Cash Flow
Cash provided by (used in) operating activities, investing activities and financing activities were as follows for the periods indicated:
|
|
Nine months ended September 30, |
| ||||
($ in thousands) |
|
2014 |
|
2013 |
| ||
|
|
|
|
|
| ||
Operating activities |
|
$ |
23,710 |
|
$ |
25,668 |
|
Investing activities |
|
(24,057 |
) |
(20,872 |
) | ||
Financing activities |
|
7,046 |
|
(10,016 |
) | ||
Cash provided by operating activities. Cash provided by operating activities was $23.7 million for the nine months ended September 30, 2014 compared to $25.7 million for the nine months ended September 30, 2013. The $2.0 million decrease was primarily attributable to a $7.2 million decrease in total Adjusted EBITDA, partially offset by a $5.9 million increase due to the timing of collections and payments.
Cash used in investing activities. Cash used in investing activities was $24.1 million for the nine months ended September 30, 2014 compared to $20.9 million for the nine months ended September 30, 2013. The $3.2 million increase was primarily due to an increase in capital expenditures of $14.3 million in the nine months ended September 30, 2014 associated with our organic growth projects, partially offset by a $10.8 million increase in proceeds from the sale of assets.
Cash provided by (used in) financing activities. Cash provided by financing activities was $7.0 million for the nine months ended September 30, 2014 compared to cash used of $10.0 million for the nine months ended September 30, 2013. The $17.0 million change was primarily due to a $44.9 million increase from the issuance of units, a $17.4 million increase from lower distributions to unitholders, and a $5.7 million increase in net borrowings under our revolving credit facility and term loans. These amounts are partially offset by the $52.0 million of cash used for the JP Development Dropdown in the nine months ending September 30, 2014.
Cash flows from discontinued operations. We combined the cash flows from discontinued operations with the cash flows from continuing operations. The cash flows from discontinued operations related to our operating, investing and financing activities were insignificant. We do not expect the absence of cash flows from these discontinued operations will have a significant impact to our future liquidity.
Capital Expenditures
Our capital spending program is focused on expanding our pipeline and cylinder exchange assets, maintaining our fleet and storage assets and maintaining and updating our information systems. Capital expenditure plans are generally evaluated based on return on investment and estimated incremental cash flow. In addition to annually recurring capital expenditures, potential acquisition opportunities are evaluated based on their anticipated return on invested capital, accretive impact to operating results and strategic fit.
Under our partnership agreement, maintenance capital expenditures are capital expenditures made to maintain our operating income or operating capacity, while expansion capital expenditures are capital expenditures that we expect will increase our operating income or operating capacity over the long-term. Examples of maintenance capital expenditures are those made to replace partially or fully depreciated assets, to maintain the existing operating capacity of our assets and to extend their useful lives, or other capital expenditures that are incurred in maintaining existing system volumes and related cash flows. In contrast, expansion capital expenditures are those made to acquire additional assets to grow our business, to expand and upgrade our systems and facilities and to construct or acquire similar systems or facilities.
As of September 30, 2014, we have spent approximately $34.3 million of capital expenditures of which $4.2 million represents maintenance capital expenditures and $30.1 million represents expansion capital expenditures. We anticipate spending an additional $19.4 million of capital expenditures during the fourth quarter of 2014, of which $10.7 million relates to expansion projects on our Silver Dollar Pipeline System.
We anticipate that our expansion capital expenditures will be funded primarily with external financing sources, including borrowings under our revolving credit facility and the issuance of debt and equity securities.
Working Capital
Our working capital is the amount by which our current assets exceed our current liabilities and is a measure of our ability to pay our liabilities as they come due. Our working capital was $42.2 million and $48.7 million as of September 30, 2014, and December 31, 2013, respectively.
Our working capital requirements have been and will continue to be primarily driven by changes in accounts receivable and accounts payable, which generally fluctuate with changes in the market prices of commodities that we buy and sell in the ordinary course of our business. Other factors impacting changes in accounts receivable and accounts payable could include the timing of collections from customers and payments to suppliers, as well as our level of spending for maintenance and growth capital expenditures. A material adverse change in our operations or available financing under our revolving credit facility could impact our ability to fund our working capital requirements for liquidity and capital resources.
Off-Balance Sheet Arrangements
We have not entered into any transactions, agreements or other contractual arrangements that would result in off balance sheet liabilities.
Critical Accounting Policies and Estimates
The critical accounting policies and estimates used in the preparation of our condensed consolidated financial statements are set forth in our IPO Prospectus dated October 1, 2014 and have not changed.
Recent Accounting Pronouncements
In June 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2014-12, Compensation - Stock Compensation, Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period. ASU 2014-12 provides explicit guidance on accounting for share-based payments requiring a specific performance target to be achieved in order for employees to become eligible to vest in the awards when that performance target may be achieved after the requisite service period for the award. The ASU requires that such performance targets be treated as a performance condition, and should not be reflected in the estimate of the grant-date fair value of the award. Instead, compensation cost should be recognized in the period in which it becomes probable the performance target will be achieved. ASU 2014-12 is effective for interim and annual periods beginning after December 15, 2015, with early adoption permitted. The adoption of ASU 2014-12 is not expected to have a material impact on our consolidated financial statements.
In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers. ASU 2014-09 supersedes the existing revenue recognition guidance under GAAP. The core principle of ASU 2014-09 is to recognize revenues when promised goods or services are transferred to customers in an amount that reflects the consideration to which an entity expects to be entitled for those goods or services. ASU 2014-09 defines a five step process to achieve this core principle and, in doing so, more judgment and estimates may be required within the revenue recognition process than are required under existing GAAP. ASU 2014-09 is effective for interim and annual periods beginning after December 15, 2016 using either of the following transition methods: (i) a full retrospective approach reflecting the application of the standard in each prior reporting period with the option to elect certain practical expedients, or (ii) a retrospective approach with the cumulative effect of initially adopting ASU 2014-09 recognized at the date of adoption (which includes additional footnote disclosures). Early adoption is not permitted. We are currently evaluating the impact of the adoption of ASU 2014-09, but do not anticipate a material impact to our consolidated financial statements.
In April 2014, the FASB issued No. ASU 2014-08, Presentation of Financial Statements and Property, Plant, and Equipment: Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. ASU 2014-08 changes the requirements for reporting discontinued operations. A discontinued operation may include a component of an entity or a group of components of an entity, or a business. A disposal of a component of an entity or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entitys operations and financial results. Examples include a disposal of a major geographic area, a major line of business or a major equity method investment. Additionally, the update requires expanded disclosures about discontinued operations that will provide financial statement users with more information about the assets, liabilities, income and expenses of discontinued operations. ASU 2014-08 is effective for interim and annual periods beginning after December 15, 2014, with early adoption permitted. The adoption of ASU 2014-08 primarily involves presentation and disclosure and therefore is not expected to have a material impact on our consolidated financial statements.
Item 3. Quantitative and Qualitative Disclosures about Market Risk.
Commodity price risk. Market risk is the risk of loss arising from adverse changes in market rates and prices. We manage exposure to commodity price risk in our business segments through the structure of our sales and supply contracts and through a managed hedging program. Our risk management policy permits the use of financial instruments to reduce the exposure to changes in commodity prices that occur in the normal course of business but prohibits the use of financial instruments for trading or to speculate on future changes in commodity prices.
We do not have direct exposure to commodity price changes in our crude oil pipelines and storage segment. In our crude oil supply and logistics business, we purchase and take title to a portion of the crude oil that we sell, which exposes us to changes in the price of crude oil in our sales markets. We manage this commodity price risk by limiting our net open positions and through the concurrent purchase and sale of like quantities of crude oil that are intended to lock in positive margins based on
the timing, location or quality of the crude oil purchased and delivered. In our refined products terminals and storage segment, we sell excess volumes of refined products and our gross margin is impacted by changes in the market prices for these sales. We may execute forward sales contracts or financial swaps to reduce the risk of commodity price changes in this segment. In our NGL distribution and sales business, we are generally able to pass through the cost of products through sales prices to our customers. To the extent we enter into fixed price product sales contracts in this business, we generally hedge our supply costs using swap contracts. In our cylinder exchange business, we sell approximately half of our volumes pursuant to contracts of generally two to three years in duration, which allow us to re-negotiate prices at the time of contract renewal, and we sell the remaining volumes on demand or under month-to-month contracts and generally adjust prices on these contracts on an annual basis. We hedge a large majority of the forecasted volumes under our long-term contracts using financial swaps, and we may also use financial swaps to manage commodity price risk on our month-to-month contracts. As of September 30, 2014, our outstanding swap contracts contained a notional amount of 22,849,000 gallons of propane with maturity dates ranging from October 2014 through December 2016, with a total fair value liability of $0.7 million. In our NGL transportation business, we do not take title to the products we transport and, therefore, have no direct commodity price exposure to the price of volumes transported.
Sensitivity analysis. We have prepared a sensitivity analysis to estimate the exposure to market risk of our propane commodity positions. Forward contracts outstanding as of September 30, 2014 that were used in our risk management activities were analyzed assuming a hypothetical 10% adverse change in prices for the delivery month for propane. The potential loss in earnings from these positions due to a 10% adverse movement in market prices of propane was estimated at $2.3 million, as of September 30, 2014. The preceding hypothetical analysis is limited because changes in prices may or may not equal 10% and actual results may differ.
Interest rate risk. Our revolving credit facility bears interest at a variable rate and exposes us to interest rate risk. From time to time, we may use certain derivative instruments to hedge our exposure to variable interest rates. As of September 30, 2014, $75 million of our outstanding debt is economically hedged with interest rate swaps over three years with a weighted average interest rate of 0.48% plus an applicable margin. Based on our overall interest rate exposure to variable rate debt outstanding as of September 30, 2014, a 1% increase or decrease in interest rates would change interest expense by approximately $1.2 million.
We do not hold or purchase financial instruments or derivative financial instruments for trading purposes.
Item 4. Controls and Procedures.
Evaluation of Disclosure Controls and Procedures
An evaluation was performed under the supervision and with the participation of the Partnerships management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rule 13a-15(e) of the Securities and Exchange Act of 1934, as amended (the Exchange Act), as of September 30, 2014. Based on this evaluation, the Partnerships management, including our Chief Executive Officer and Chief Financial Officer, concluded that as of September 30, 2014, our disclosure controls and procedures were not effective to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SECs rules and forms and to provide reasonable assurance that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures because of the material weaknesses in our internal control over financial reporting discussed below.
A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis. We did not have sufficient personnel with an appropriate level of accounting knowledge and experience commensurate with our financial reporting requirements. As a result, we did not design and maintain formal accounting policies and formal review controls. We did not design and maintain effective controls over accounting for business combinations, including controls related to the valuation of assets acquired and liabilities assumed, and the integration of businesses by applying consistent accounting policies and processes to determine compliance with industry standards and regulations. We did not design and maintain adequate policies and procedures with respect to the primary components of information technology general controls, including the approval and review of access controls, system implementation and migration controls, and change management controls. These material weaknesses resulted in audit adjustments in the years ended December 31, 2013, 2012 and 2011 and the three months ended March 31, 2013 and 2012 and six months ended June 30,
2013, and restatements of our financial statements for the years ended December 31, 2012, 2011 and the three months ended March 31, 2013 and 2012. Management has determined that the excessive product gains at a refined products terminal described in Note 10 to the consolidated financial statements for the nine months ended September 30, 2014 was an additional effect of the material weakness related to business combinations and information technology described above. Also, management has determined that the excessive product gains at a refined products terminal relate to not designing and maintaining effective controls to determine compliance with industry standards and regulations during the integration of the acquired business. As a result, the description of the business combination material weakness at June 30, 2014 was expanded to include this aspect of the material weakness related to integration of acquired businesses.
We are currently in the process of remediating the material weaknesses in our internal control over financial reporting and are implementing additional processes and controls designed to address the underlying causes of the material weaknesses. During the course of the implementation, we may identify additional control deficiencies, which could give rise to other material weaknesses, in addition to the material weaknesses described above. Each of the material weaknesses described above or any newly identified material weakness could result in a misstatement of our accounts or disclosures that would result in a material misstatement of our annual or interim consolidated financial statements that would not be prevented or detected.
Changes in Internal Controls over Financial Reporting
Except for the remediation efforts described above, there was no change in our internal control over financial reporting identified in connection with the evaluation required by Rule 13a-15(d) of the Exchange Act that occurred during the period covered by this report that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
The information required for this item is provided in Note 10 Commitments and Contingencies, included in the unaudited notes to condensed consolidated financial statements included under Part I, Item I, which is incorporated herein by reference.
In addition to the information set forth in this Form 10-Q, you should carefully consider the risk factors under the heading Risk Factors discussed in our IPO Prospectus. There has been no material change in our risk factors from those described in our IPO Prospectus. These risks are not the only risks we face. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operations.
Item 2. Unregistered sales of equity securities and use of proceeds.
On October 1, 2014, our registration statement on Form S-1 (File No. 333-195787) was declared effective for our IPO, and on October 7, 2014, we completed our IPO of 13,750,000 common units representing limited partner interests at a price to the public of $20.00 per common unit. Barclays Capital Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, RBC Capital Markets, LLC and Deutsche Bank Securities Inc. acted as the representatives of the underwriters in the offering. Following the sale of the common units in connection with the closing of our IPO, the offering terminated. As a result of the offering, we received gross proceeds of approximately $275.0 million less underwriting discounts and structuring fees. We used the net proceeds of $257.1 million from our IPO to (i) pay estimated offering expenses of approximately $2.0 million, (ii) redeem 100% of our issued and outstanding Series D preferred units for approximately $42.4 million, (iii) repay $195.6 million of debt outstanding under our revolving credit facility and (iv) replenish approximately $17.1 million of working capital.
Exhibit |
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Description |
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3.1 |
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Certificate of Limited Partnership of JP Energy Partners LP (incorporated by reference to Exhibit 3.1 of the Partnerships Registration Statement on Form S-1 (File No. 333-195787) filed with the SEC on May 8, 2014). |
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3.2 |
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Third Amended and Restated Agreement of Limited Partnerships of JP Energy Partners LP dated October 7, 2014 (incorporated by reference to Exhibit 3.1 to the Partnerships Current Report on Form 8-K filed with the SEC on October 7, 2014). |
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4.1 |
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Registration Rights Agreement dated November 27, 2012 among JP Energy Partners LP, Arkansas Terminaling and Training Inc., Michal Coulson, Mary Ann Dawkins and White Properties II Limited Partnership (incorporated by reference to Exhibit 4.1 to the Partnerships Registration Statement on Form S-1 (File No. 333-195787) filed with the SEC on May 8, 2014). |
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10.1 |
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Credit Agreement dated February 12, 2014 among JP Energy Partners LP, Bank of America, N.A. as administrative agent and swing line lender and an L/C issuer, the other lender parties thereto, and Bank of America Merrill Lynch and BMO Harris Financing, Inc., as joint lead arrangers and joint book managers (incorporated by reference to Exhibit 10.1 to the Partnerships Registration Statement on Form S-1 (File No. 333-195787) filed with the SEC on May 8, 2014). |
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10.2 |
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Amendment No. 1 to Credit Agreement, dated as of April 30, 2014 (incorporated by reference to Exhibit 10.2 to the Partnerships Registration Statement on Form S-1 (File No. 333-195787) filed with the SEC on May 8, 2014). |
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10.3 |
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Amendment No. 2 and Waiver to Credit Agreement, dated as of August 5, 2014 (incorporated by reference to Exhibit 10.3 to the Partnerships Registration Statement on Form S-1 (File No. 333-195787) filed with the SEC on September 22, 2014). |
10.4 |
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JP Energy Partners LP 2014 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to the Partnerships Current Report on Form 8-K filed with the SEC on October 7, 2014). |
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10.5 |
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Right of First Offer Agreement dated as of October 7, 2014, by and among JP Energy Partners LP, JP Energy GP II LLC, JP Energy Development LP and Republic Midstream, Holdings LLC (incorporated by reference to Exhibit 10.1 to the Partnerships Current Report on Form 8-K filed with the SEC on October 7, 2014). |
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10.6 |
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Employment Agreement of Patrick J. Welch (incorporated by reference to Exhibit 10.3 to the Partnerships Current Report on Form 8-K filed with the SEC on October 7, 2014). |
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10.7 |
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Employment Agreement of Jeremiah J. Ashcroft III (incorporated by reference to Exhibit 10.4 to the Partnerships Current Report on Form 8-K filed with the SEC on October 7, 2014). |
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10.8 |
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Employment Agreement of Scott Smith (incorporated by reference to Exhibit 10.7 to the Partnerships Registration Statement on Form S-1 (File No. 333-195787) filed with the SEC on September 9, 2014). |
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10.9 |
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Amendment No. 3 and Waiver to Credit Agreement dated as of September 19, 2014 (incorporated by reference to Exhibit 10.8 to the Partnerships Registration Statement on Form S-1 (File No. 333-195787) filed with the SEC on September 22, 2014). |
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31.1 |
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Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
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31.2 |
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Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
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32.1 |
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Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
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32.2 |
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Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
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101.INS |
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XBRL Instance Document |
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101.SCH |
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XBRL Taxonomy Extension Schema |
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101.CAL |
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XBRL Taxonomy Calculation Linkbase |
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101.DEF |
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XBRL Taxonomy Definition Linkbase |
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101.LAB |
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XBRL Taxonomy Label Linkbase |
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101.PRE |
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XBRL Taxonomy Presentation Linkbase |
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.
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JP ENERGY PARTNERS LP | |
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By: |
JP ENERGY GP II LLC, |
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its general partner |
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Date: November 10, 2014 |
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By: |
/s/ J. Patrick Barley |
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J. Patrick Barley |
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President and Chief Executive Officer |
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(Principal Executive Officer) |
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Date: November 10, 2014 |
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By: |
/s/ Patrick J. Welch |
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Patrick J. Welch |
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Executive Vice President and Chief Financial Officer (Principal Financial Officer) |