x |
QUARTERLY REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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o
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TRANSITION REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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Delaware | 05-0527861 | |
(State or other jurisdiction of incorporation or organization) | (IRS Employer Identification No.) |
Large accelerated filer o | Accelerated filer x |
Non-accelerated filer o (Do not check if a smaller reporting company) | Smaller reporting company o |
2
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Item 1.
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2
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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
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Item 2.
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35
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Item 3.
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62
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Item 4.
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64
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65
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Item 1.
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65
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Item 1A.
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65
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Item 5.
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65
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Item 6.
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67
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CERTIFICATIONS
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September 30,
2011
(Unaudited)
|
December 31,
2010
(Audited)
|
|||||||
Assets
|
||||||||
Cash
|
$ | 296 | $ | 11,380 | ||||
Accounts and other receivables, less allowance for doubtful accounts of $3,592 and $2,528, respectively
|
99,196 | 95,276 | ||||||
Product exchange receivables
|
25,651 | 9,099 | ||||||
Inventories
|
80,852 | 52,616 | ||||||
Due from affiliates
|
12,279 | 6,437 | ||||||
Fair value of derivatives
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934 | 2,142 | ||||||
Other current assets
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908 | 2,784 | ||||||
Total current assets
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220,116 | 179,734 | ||||||
Property, plant and equipment, at cost
|
689,905 | 632,456 | ||||||
Accumulated depreciation
|
(225,058 | ) | (200,276 | ) | ||||
Property, plant and equipment, net
|
464,847 | 432,180 | ||||||
Goodwill
|
37,268 | 37,268 | ||||||
Investment in unconsolidated entities
|
163,414 | 98,217 | ||||||
Fair value of derivatives
|
144 | — | ||||||
Deferred debt costs
|
13,850 | 13,497 | ||||||
Other assets, net
|
24,239 | 24,582 | ||||||
$ | 923,878 | $ | 785,478 | |||||
Liabilities and Partners’ Capital
|
||||||||
Current portion of capital lease obligations
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$ | 1,201 | $ | 1,121 | ||||
Trade and other accounts payable
|
94,447 | 82,837 | ||||||
Product exchange payables
|
49,702 | 22,353 | ||||||
Due to affiliates
|
14,708 | 6,957 | ||||||
Income taxes payable
|
789 | 811 | ||||||
Fair value of derivatives
|
— | 282 | ||||||
Other accrued liabilities
|
14,261 | 10,034 | ||||||
Total current liabilities
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175,108 | 124,395 | ||||||
Long-term debt and capital leases, less current maturities
|
439,213 | 372,862 | ||||||
Deferred income taxes
|
7,816 | 8,213 | ||||||
Fair value of derivatives
|
— | 4,100 | ||||||
Other long-term obligations
|
1,743 | 1,102 | ||||||
Total liabilities
|
623,880 | 510,672 | ||||||
Partners’ capital
|
298,621 | 273,387 | ||||||
Accumulated other comprehensive income
|
1,377 | 1,419 | ||||||
Total partners’ capital
|
299,998 | 274,806 | ||||||
Commitments and contingencies
|
||||||||
$ | 923,878 | $ | 785,478 |
Three Months Ended
September 30,
|
Nine Months Ended
September 30,
|
|||||||||||||||
2011
|
2010
|
2011
|
2010
|
|||||||||||||
Revenues:
|
||||||||||||||||
Terminalling and storage *
|
$ | 19,381 | $ | 17,357 | $ | 56,831 | $ | 50,062 | ||||||||
Marine transportation *
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20,773 | 21,468 | 57,548 | 57,458 | ||||||||||||
Sulfur services
|
2,850 | — | 8,550 | — | ||||||||||||
Product sales: *
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||||||||||||||||
Natural gas services
|
188,461 | 107,842 | 514,870 | 397,855 | ||||||||||||
Sulfur services
|
67,319 | 36,658 | 198,310 | 113,945 | ||||||||||||
Terminalling and storage
|
17,525 | 12,062 | 55,441 | 30,687 | ||||||||||||
273,305 | 156,562 | 768,621 | 542,487 | |||||||||||||
Total revenues
|
316,309 | 195,387 | 891,550 | 650,007 | ||||||||||||
Costs and expenses:
|
||||||||||||||||
Cost of products sold: (excluding depreciation and amortization)
|
||||||||||||||||
Natural gas services *
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180,499 | 102,487 | 492,120 | 379,433 | ||||||||||||
Sulfur services *
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59,808 | 30,505 | 164,142 | 86,855 | ||||||||||||
Terminalling and storage
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15,676 | 11,363 | 49,631 | 28,771 | ||||||||||||
255,983 | 144,355 | 705,893 | 495,059 | |||||||||||||
Expenses:
|
||||||||||||||||
Operating expenses *
|
35,669 | 29,017 | 104,730 | 86,314 | ||||||||||||
Selling, general and administrative *
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6,849 | 4,542 | 16,889 | 14,650 | ||||||||||||
Depreciation and amortization
|
11,400 | 10,175 | 33,651 | 30,066 | ||||||||||||
Total costs and expenses
|
309,901 | 188,089 | 861,163 | 626,089 | ||||||||||||
Other operating income
|
1,720 | 405 | 1,818 | 450 | ||||||||||||
Operating income
|
8,128 | 7,703 | 32,205 | 24,368 | ||||||||||||
Other income (expense):
|
||||||||||||||||
Equity in earnings of unconsolidated entities
|
1,784 | 2,951 | 6,953 | 7,469 | ||||||||||||
Interest expense
|
(4,297 | ) | (6,051 | ) | (17,102 | ) | (22,248 | ) | ||||||||
Other, net
|
23 | 34 | 127 | 117 | ||||||||||||
Total other income (expense)
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(2,490 | ) | (3,066 | ) | (10,022 | ) | (14,662 | ) | ||||||||
Net income before taxes
|
5,638 | 4,637 | 22,183 | 9,706 | ||||||||||||
Income tax benefit (expense)
|
( 239 | ) | ( 1 | ) | (692 | ) | (224 | ) | ||||||||
Net income
|
$ | 5,399 | $ | 4,636 | $ | 21,491 | $ | 9,482 | ||||||||
General partner’s interest in net income
|
$ | 1,348 | $ | 1,000 | $ | 3,992 | $ | 2,832 | ||||||||
Limited partners’ interest in net income
|
$ | 3,774 | $ | 3,359 | $ | 16,668 | $ | 5,819 | ||||||||
Net income per limited partner unit - basic and diluted
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$ | 0.20 | $ | 0.19 | $ | 0.87 | $ | 0.33 | ||||||||
Weighted average limited partner units - basic
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19,158,334 | 17,700,875 | 19,161,403 | 17,466,200 | ||||||||||||
Weighted average limited partner units - diluted
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19,163,128 | 17,701,719 | 19,163,066 | 17,467,514 |
Revenues:
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||||||||||||||||
Terminalling and storage
|
$ | 14,210 | $ | 12,292 | $ | 40,045 | $ | 34,579 | ||||||||
Marine transportation
|
6,351 | 7,968 | 19,223 | 20,948 | ||||||||||||
Product Sales
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2,024 | 5,265 | 10,745 | 8,647 | ||||||||||||
Costs and expenses:
|
||||||||||||||||
Cost of products sold: (excluding depreciation and amortization)
|
||||||||||||||||
Natural gas services
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31,871 | 16,353 | 80,829 | 57,721 | ||||||||||||
Sulfur services
|
4,762 | 4,212 | 13,407 | 11,448 | ||||||||||||
Expenses:
|
||||||||||||||||
Operating expenses
|
17,223 | 12,215 | 42,966 | 35,986 | ||||||||||||
Selling, general and administrative
|
3,576 | 2,704 | 9,490 | 8,141 |
Partners’ Capital
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||||||||||||||||||||||||||||
Common
|
Subordinated
|
General
Partner
|
Accumulated
Other
Comprehensive
Income
|
|||||||||||||||||||||||||
Units
|
Amount
|
Units
|
Amount
|
Amount
|
(Loss)
|
Total
|
||||||||||||||||||||||
Balances – January 1, 2010
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16,057,832 | $ | 245,683 | 889,444 | $ | 16,613 | $ | 4,731 | $ | (2,076 | ) | $ | 264,951 | |||||||||||||||
Net income
|
— | 6,650 | — | — | 2,832 | — | 9,482 | |||||||||||||||||||||
Recognition of beneficial conversion feature
|
— | (831 | ) | — | 831 | — | — | — | ||||||||||||||||||||
Follow-on public offering
|
2,650,000 | 78,600 | — | — | — | — | 78,600 | |||||||||||||||||||||
Redemption of common units
|
(1,000,000 | ) | (28,070 | ) | — | — | — | — | (28,070 | ) | ||||||||||||||||||
General partner contribution
|
— | — | — | — | 1,089 | — | 1,089 | |||||||||||||||||||||
Distributions to parent
|
— | (4,369 | ) | — | — | — | — | (4,369 | ) | |||||||||||||||||||
Cash distributions
|
— | (38,605 | ) | — | — | (3,580 | ) | — | (42,185 | ) | ||||||||||||||||||
Unit-based compensation
|
3,500 | 66 | — | — | — | — | 66 | |||||||||||||||||||||
Purchase of treasury units
|
(3,500 | ) | (108 | ) | — | — | — | — | (108 | ) | ||||||||||||||||||
Adjustment in fair value of derivatives
|
— | — | — | — | — | 3,906 | 3,906 | |||||||||||||||||||||
Balances – September 30, 2010
|
17,707,832 | $ | 259,016 | 889,444 | $ | 17,444 | $ | 5,072 | $ | 1,830 | $ | 283,362 | ||||||||||||||||
Balances – January 1, 2011
|
17,707,832 | $ | 250,785 | 889,444 | $ | 17,721 | $ | 4,881 | $ | 1,419 | $ | 274,806 | ||||||||||||||||
Net income
|
— | 17,499 | — | — | 3,992 | — | 21,491 | |||||||||||||||||||||
Recognition of beneficial conversion feature
|
— | (831 | ) | — | 831 | — | — | — | ||||||||||||||||||||
Follow-on public offering
|
1,874,500 | 70,330 | — | — | — | — | 70,330 | |||||||||||||||||||||
General partner contribution
|
— | — | — | — | 1,505 | — | 1,505 | |||||||||||||||||||||
Cash distributions
|
— | (43,321 | ) | — | — | (4,635 | ) | — | (47,956 | ) | ||||||||||||||||||
Distribution to parent
|
— | (19,685 | ) | — | — | — | — | (19,685 | ) | |||||||||||||||||||
Unit-based compensation
|
15,350 | 131 | — | — | — | — | 131 | |||||||||||||||||||||
Purchase of treasury units
|
( 14,850 | ) | (582 | ) | — | — | — | — | (582 | ) | ||||||||||||||||||
Unit-based compensation grant forfeitures
|
( 500 | ) | — | — | — | — | — | — | ||||||||||||||||||||
Adjustment in fair value of derivatives
|
— | — | — | — | — | (42 | ) | (42 | ) | |||||||||||||||||||
Balances – September 30, 2011
|
19,582,332 | $ | 274,326 | 889,444 | $ | 18,552 | $ | 5,743 | $ | 1,377 | $ | 299,998 |
Three Months Ended
September 30,
|
Nine Months Ended
September 30,
|
|||||||||||||||
2011
|
2010
|
2011
|
2010
|
|||||||||||||
Net income
|
$ | 5,399 | $ | 4,636 | $ | 21,491 | $ | 9,482 | ||||||||
Changes in fair values of commodity cash flow hedges
|
1,295 | 71 | 1,231 | 816 | ||||||||||||
Commodity cash flow hedging gains (losses) reclassified to earnings
|
(538 | ) | (223 | ) | (1,291 | ) | (609 | ) | ||||||||
Changes in fair value of interest rate cash flow hedges
|
— | — | — | (241 | ) | |||||||||||
Interest rate cash flow hedging losses reclassified to earnings
|
— | 606 | 18 | 3,940 | ||||||||||||
Comprehensive income
|
$ | 6,156 | $ | 5,090 | $ | 21,449 | $ | 13,388 |
Nine Months Ended
September 30,
|
||||||||
2011
|
2010
|
|||||||
Cash flows from operating activities:
|
||||||||
Net income
|
$ | 21,491 | $ | 9,482 | ||||
Adjustments to reconcile net income to net cash provided by operating activities:
|
||||||||
Depreciation and amortization
|
33,651 | 30,066 | ||||||
Amortization of deferred debt issuance costs
|
3,071 | 3,676 | ||||||
Amortization of debt discount
|
262 | 181 | ||||||
Deferred taxes
|
2 | (474 | ) | |||||
(Gain) loss on sale of property, plant and equipment
|
405 | (450 | ) | |||||
Equity in earnings of unconsolidated entities
|
(6,953 | ) | (7,469 | ) | ||||
Distributions in-kind from equity investments
|
9,010 | 7,524 | ||||||
Non-cash mark-to-market on derivatives
|
(3,360 | ) | (3,592 | ) | ||||
Other
|
131 | 66 | ||||||
Change in current assets and liabilities, excluding effects of acquisitions and dispositions:
|
||||||||
Accounts and other receivables
|
(1,516 | ) | 16,171 | |||||
Product exchange receivables
|
(16,552 | ) | 1,372 | |||||
Inventories
|
(28,236 | ) | (15,766 | ) | ||||
Due from affiliates
|
(5,842 | ) | (2,217 | ) | ||||
Other current assets
|
1,477 | (950 | ) | |||||
Trade and other accounts payable
|
11,610 | (5,633 | ) | |||||
Product exchange payables
|
27,350 | 4,165 | ||||||
Due to affiliates
|
7,751 | 467 | ||||||
Income taxes payable
|
(22 | ) | 109 | |||||
Other accrued liabilities
|
4,227 | 9,625 | ||||||
Change in other non-current assets and liabilities
|
(122 | ) | (3,865 | ) | ||||
Net cash provided by operating activities
|
57,835 | 42,488 | ||||||
Cash flows from investing activities:
|
||||||||
Payments for property, plant and equipment
|
(49,634 | ) | (12,616 | ) | ||||
Acquisitions
|
(16,815 | ) | (7,331 | ) | ||||
Payments for plant turnaround costs
|
(2,103 | ) | (1,090 | ) | ||||
Proceeds from sale of property, plant and equipment
|
530 | 1,944 | ||||||
Investment in unconsolidated entities
|
(59,319 | ) | (20,110 | ) | ||||
Return of investments from unconsolidated entities
|
1,668 | 2,430 | ||||||
Distributions from (contributions to) unconsolidated entities for operations
|
(9,603 | ) | 628 | |||||
Net cash used in investing activities
|
(135,276 | ) | (36,145 | ) | ||||
Cash flows from financing activities:
|
||||||||
Payments of long-term debt
|
(389,000 | ) | (383,100 | ) | ||||
Payments of notes payable and capital lease obligations
|
(831 | ) | (260 | ) | ||||
Proceeds from long-term debt
|
456,000 | 392,269 | ||||||
Net proceeds from follow on offering
|
70,330 | 78,600 | ||||||
Redemption of common units
|
— | (28,070 | ) | |||||
General partner contribution
|
1,505 | 1,089 | ||||||
Distribution to parent
|
(19,685 | ) | (4,369 | ) | ||||
Payments of debt issuance costs
|
(3,424 | ) | (7,425 | ) | ||||
Purchase of treasury units
|
(582 | ) | (108 | ) | ||||
Cash distributions paid
|
(47,956 | ) | (42,185 | ) | ||||
Net cash provided by financing activities
|
66,357 | 6,441 | ||||||
Net increase (decrease) in cash
|
(11,084 | ) | 12,784 | |||||
Cash at beginning of period
|
11,380 | 5,956 | ||||||
Cash at end of period
|
$ | 296 | $ | 18,740 |
Three Months Ended
September 30,
|
Nine months
Ended
September 30,
|
|||||||||||||||
2011
|
2010
|
2011
|
2010
|
|||||||||||||
Net income attributable to Martin Midstream Partners L.P.
|
$ | 5,399 | $ | 4,636 | $ | 21,491 | $ | 9,482 | ||||||||
Less general partner’s interest in net income:
|
||||||||||||||||
Distributions payable on behalf of IDRs
|
1,265 | 926 | 3,635 | 2,696 | ||||||||||||
Distributions payable on behalf of general partner interest
|
345 | 304 | 1,000 | 884 | ||||||||||||
Distributions payable to the general partner interest in excess of earnings allocable to the general partner interest
|
(262 | ) | (230 | ) | (643 | ) | (748 | ) | ||||||||
Less beneficial conversion feature
|
277 | 277 | 831 | 831 | ||||||||||||
Limited partners’ interest in net income
|
$ | 3,774 | $ | 3,359 | $ | 16,668 | $ | 5,819 |
Property, plant and equipment
|
9,925 | |||
Other assets
|
15,090 | |||
$ | 25,015 |
September 30,
2011
|
December 31,
2010
|
|||||||
Natural gas liquids
|
$ | 28,239 | $ | 19,775 | ||||
Sulfur
|
27,523 | 15,933 | ||||||
Sulfur Based Products
|
12,643 | 9,027 | ||||||
Lubricants
|
9,912 | 5,267 | ||||||
Other
|
2,535 | 2,614 | ||||||
$ | 80,852 | $ | 52,616 |
Waskom
|
PIPE
|
Matagorda
|
Redbird
|
Total | ||||||||||||||||
Investment in unconsolidated entities, December 31, 2010
|
$ | 93,768 | $ | 1,311 | $ | 3,138 | — | $ | 98,217 | |||||||||||
Distributions in kind
|
(9,010 | ) | — | — | — | (9,010 | ) | |||||||||||||
Contributions to unconsolidated entities:
|
||||||||||||||||||||
Cash contributions (See Note 3)
|
— | — | — | 59,319 | 59,319 | |||||||||||||||
Contributions to unconsolidated entities for operations
|
8,504 | — | 170 | 929 | 9,603 | |||||||||||||||
Return of investments
|
(1,200 | ) | — | (85 | ) | (383 | ) | (1,668 | ) | |||||||||||
Equity in earnings:
|
||||||||||||||||||||
Equity in earnings (losses) from operations
|
7,191 | (32 | ) | 141 | 98 | 7,398 | ||||||||||||||
Amortization of excess investment
|
(412 | ) | (12 | ) | (21 | ) | — | (445 | ) | |||||||||||
Investment in unconsolidated entities, September 30, 2011
|
$ | 98,841 | $ | 1,267 | $ | 3,343 | $ | 59,963 | $ | 163,414 |
Waskom
|
PIPE
|
Matagorda
|
Redbird
|
Total | ||||||||||||||||
Investment in unconsolidated entities, December 31, 2009
|
$ | 75,844 | $ | 1,401 | $ | 3,337 | — | $ | 80,582 | |||||||||||
— | ||||||||||||||||||||
Distributions in kind
|
(7,524 | ) | — | — | — | (7,524 | ) | |||||||||||||
Contributions to unconsolidated entities:
|
— | |||||||||||||||||||
Cash contributions (See Note 3)
|
20,110 | — | — | — | 20,110 | |||||||||||||||
Contributions to (distributions from) unconsolidated entities for operations
|
(748 | ) | 120 | — | — | (628 | ) | |||||||||||||
Return of investments
|
(2,100 | ) | (30 | ) | (300 | ) | — | (2,430 | ) | |||||||||||
Equity in earnings:
|
— | |||||||||||||||||||
Equity in earnings (losses) from operations
|
7,945 | (180 | ) | 148 | — | 7,913 | ||||||||||||||
Amortization of excess investment
|
(412 | ) | (11 | ) | (21 | ) | — | (444 | ) | |||||||||||
Investment in unconsolidated entities, September 30, 2010
|
$ | 93,115 | $ | 1,300 | $ | 3,164 | $ | — | $ | 97,579 |
As of September 30
|
Three Months Ended
September 30
|
Nine months Ended
September 30
|
||||||||||||||||||||||
Total
Assets
|
Partner’s
Capital
|
Revenues
|
Net
Income
|
Revenues
|
Net
Income
|
|||||||||||||||||||
2011
|
||||||||||||||||||||||||
Waskom
|
$ | 136,493 | $ | 118,479 | $ | 29,508 | $ | 3,808 | $ | 95,086 | $ | 14,382 | ||||||||||||
As of December 31
|
||||||||||||||||||||||||
2010
|
||||||||||||||||||||||||
Waskom
|
$ | 128,250 | $ | 108,669 | $ | 32,154 | $ | 5,123 | $ | 60,808 | $ | 9,714 |
Transaction Type
|
Total
Volume
Per Month
|
Pricing Terms
|
Remaining Terms
of Contracts
|
Fair Value
|
|||
Mark to Market Derivatives::
|
|||||||
Crude Oil Swap
|
2,000 BBL
|
Fixed price of $91.20 settled against WTI NYMEX average monthly closings
|
October 2011 to
December 2011
|
67 | |||
Total commodity swaps not designated as hedging instruments
|
$ | 67 | |||||
Cash Flow Hedges:
|
|||||||
Natural Gas Swap
|
10,000 Mmbtu
|
Fixed price of $6.1250 settled against IF_ANR_LA first of the month posting
|
October 2011 to
December 2011
|
71 | |||
Natural Gas Swap
|
20,000 Mmbtu
|
Fixed price of $4.3225 settled against IF_ANR_LA first of the month posting
|
October 2011 to
December 2011
|
35 | |||
Natural Gasoline Swap
|
2,000 BBL
|
Fixed price of $87.10 settled against WTI NYMEX average monthly closings
|
October 2011 to
December 2011
|
42 | |||
Natural Gasoline Swap
|
1,000 BBL
|
Fixed price of $88.85 settled against WTI NYMEX average monthly closings
|
October 2011 to
December 2011
|
26 | |||
Natural Gasoline Swap
|
1,000 BBL
|
Fixed price of $2.383 settled against Mont Belvieu Non-TET OPIS Average
|
October 2011 to
December 2011
|
48 | |||
Crude Oil Swap
|
1,000 BBL
|
Fixed price of $101.90 settled against WTI NYMEX average monthly closings
|
October 2011 to
December 2011
|
65 | |||
Natural Gas Swap
|
10,000 Mmbtu
|
Fixed price of $4.8700 settled against IF_ANR_LA first of the month posting
|
January 2012 to
December 2012
|
81 | |||
Natural Gas Swap
|
20,000 Mmbtu
|
Fixed price of $4.9600 settled against IF_ANR_LA first of the month posting
|
January 2012 to
December 2012
|
184 | |||
Natural Gasoline Swap
|
1,000 BBL
|
Fixed price of $90.20 settled against WTI NYMEX average monthly closings
|
January 2012 to
December 2012
|
112 | |||
Natural Gasoline Swap
|
1,000 BBL
|
Fixed price of $2.340 settled against Mont Belvieu Non-TET OPIS Average
|
January 2012 to
December 2012
|
160 | |||
Crude Oil Swap
|
2,000 BBL
|
Fixed price of $88.63 settled against WTI NYMEX average monthly closings
|
January 2012 to
December 2012
|
187 | |||
Total commodity swaps designated as hedging instruments
|
$ | 1,011 | |||||
Total net fair value of commodity derivatives
|
$ | 1,078 |
|
(d)
|
Tabular Presentation of Fair Value Amounts, and Gains and Losses on Derivative Instruments and Related Hedged Items
|
Fair Values of Derivative Instruments in the Consolidated Balance Sheet | ||||||||||||||||||
Derivative Assets
|
Derivative Liabilities
|
|||||||||||||||||
Fair Values
|
Fair Values
|
|||||||||||||||||
Balance Sheet Location
|
September 30,
2011
|
December 31,,
2010
|
Balance Sheet Location
|
September 30,
2011
|
December 31,
2010
|
|||||||||||||
Derivatives designated
as hedging instruments
|
||||||||||||||||||
Current:
|
Current:
|
|||||||||||||||||
Interest rate contracts
|
Fair value of derivatives
|
$ | — | $ | — |
Fair value of derivatives
|
$ | — | $ | — | ||||||||
Commodity contracts
|
Fair value of derivatives
|
867 | 201 |
Fair value of derivatives
|
— | 230 | ||||||||||||
867 | 201 | — | 230 | |||||||||||||||
Non-current:
|
Non-current:
|
|||||||||||||||||
Interest rate contracts
|
Fair value of derivatives
|
— | — |
Fair value of derivatives
|
— | — | ||||||||||||
Commodity contracts
|
Fair value of derivatives
|
144 | — |
Fair value of derivatives
|
— | 171 | ||||||||||||
144 | — | — | 171 | |||||||||||||||
Total derivatives designated as hedging instruments
|
$ | 1,011 | $ | 201 | $ | — | $ | 401 | ||||||||||
Derivatives not designated as hedging instruments | ||||||||||||||||||
Current:
|
Current:
|
|||||||||||||||||
Interest rate contracts
|
Fair value of derivatives
|
$ | — | $ | 1,941 |
Fair value of derivatives
|
$ | — | $ | — | ||||||||
Commodity contracts
|
Fair value of derivatives
|
67 | — |
Fair value of derivatives
|
— | 51 | ||||||||||||
67 | 1,941 | — | 51 | |||||||||||||||
Non-current:
|
Non-current:
|
|||||||||||||||||
Interest rate contracts
|
Fair value of derivatives
|
— | — |
Fair value of derivatives
|
— | 3,930 | ||||||||||||
Commodity contracts
|
Fair value of derivatives
|
— | — |
Fair value of derivatives
|
— | — | ||||||||||||
— | — | — | 3,930 | |||||||||||||||
Total derivatives not designated as hedging instruments
|
$ | 67 | $ | 1,941 | $ | — | $ | 3,981 |
Effect of Derivative Instruments on the Consolidated Statement of Operations
For the Three Months Ended September 30, 2011 and 2010
|
||||||||||||||||||||||||||
Effective Portion
|
Ineffective Portion and Amount
Excluded from Effectiveness Testing
|
|||||||||||||||||||||||||
Amount of Gain or
(Loss) Recognized in
OCI on Derivatives
|
Location of Gain
or (Loss)
Reclassified from Accumulated OCI
into Income
|
Amount of Gain or
(Loss) Reclassified
from Accumulated OCI
into Income
|
Location of
Gain or (Loss)
Recognized in
Income on
Derivatives
|
Amount of Gain or
(Loss) Recognized
in Income on
Derivatives
|
||||||||||||||||||||||
2011
|
2010
|
2011
|
2010
|
2011 |
2010
|
|||||||||||||||||||||
Derivatives designated as hedging instruments | ||||||||||||||||||||||||||
Interest rate contracts
|
$ | — | $ | — |
Interest Expense
|
$ | — | $ | (606 | ) |
Interest Expense
|
$ | — | $ | — | |||||||||||
Commodity contracts
|
1,295 | 71 |
Natural Gas Services Revenues
|
500 | 205 |
Natural Gas Services Revenues
|
38 | 18 | ||||||||||||||||||
Total derivatives designated as hedging instruments
|
$ | 1,295 | $ | 71 | $ | 500 | $ | (401 | ) | $ | 38 | $ | 18 |
Location of Gain or (Loss)
Recognized in Income on
Derivatives
|
Amount of Gain or (Loss)
Recognized in Income on
Derivatives
|
||||||||
2011
|
2010
|
||||||||
Derivatives not designated as hedging instruments
|
|||||||||
Interest rate contracts
|
Interest Expense
|
$ | 3,244 | $ | 1,563 | ||||
Commodity contracts
|
Natural Gas Services Revenues
|
131 | (13 | ) | |||||
Total derivatives not designated as hedging instruments
|
$ | 3,375 | $ | 1,550 |
Effect of Derivative Instruments on the Consolidated Statement of Operations
For the Nine months Ended September 30, 2011 and 2010
|
||||||||||||||||||||||||||
Effective Portion
|
Ineffective Portion and Amount
Excluded from Effectiveness Testing
|
|||||||||||||||||||||||||
Amount of Gain or
(Loss) Recognized in
OCI on Derivatives
|
Location of Gain
or (Loss)
Reclassified from Accumulated OCI
into Income
|
Amount of Gain or
(Loss) Reclassified
from Accumulated OCI
into Income
|
Location of
Gain or (Loss)
Recognized in
Income on
Derivatives
|
Amount of Gain or
(Loss) Recognized
in Income on
Derivatives
|
||||||||||||||||||||||
2011 | 2010 | 2011 | 2010 | 2011 | 2010 | |||||||||||||||||||||
Derivatives designated as hedging instruments | ||||||||||||||||||||||||||
Interest rate contracts
|
$ | — | $ | (241 | ) |
Interest Expense
|
$ | (18 | ) | $ | (3,940 | ) |
Interest Expense
|
$ | — | $ | — | |||||||||
Commodity contracts
|
1,231 | 816 |
Natural Gas Services Revenues
|
1,264 | 542 |
Natural Gas Services Revenues
|
27 | 67 | ||||||||||||||||||
Total derivatives designated as hedging instruments
|
$ | 1,231 | $ | 575 | $ | 1,246 | $ | (3,398 | ) | $ | 27 | $ | 67 |
Location of Gain or (Loss)
Recognized in Income on
Derivatives
|
Amount of Gain or
(Loss) Recognized in
Income on Derivatives
|
||||||||
2011
|
2010
|
||||||||
Derivatives not designated as hedging instruments
|
|||||||||
Interest rate contracts
|
Interest Expense
|
$ | 5,797 | $ | 1,373 | ||||
Commodity contracts
|
Natural Gas Services Revenues
|
41 | 300 | ||||||
Total derivatives not designated as hedging instruments
|
$ | 5,838 | $ | 1,673 |
Fair Value Measurements at Reporting Date Using
|
||||||||||||||||
Quoted Prices in
Active Markets
for
Identical Assets
|
Significant
Other
Observable
Inputs
|
Significant
Unobservable
Inputs
|
||||||||||||||
Description
|
September
30, 2011
|
(Level 1)
|
(Level 2)
|
(Level 3)
|
||||||||||||
Assets
|
||||||||||||||||
Interest rate derivatives
|
$ | — | $ | — | $ | — | $ | — | ||||||||
Natural gas derivatives
|
371 | — | 371 | — | ||||||||||||
Crude oil derivatives
|
319 | — | 319 | — | ||||||||||||
Natural gas liquids derivatives
|
388 | — | 388 | — | ||||||||||||
Total assets
|
$ | 1,078 | $ | — | $ | 1,078 | $ | — | ||||||||
Liabilities
|
||||||||||||||||
Interest rate derivatives
|
$ | — | $ | — | $ | — | $ | — | ||||||||
Natural gas derivatives
|
— | — | — | — | ||||||||||||
Crude oil derivatives
|
— | — | — | — | ||||||||||||
Natural gas liquids derivatives
|
— | — | — | — | ||||||||||||
Total liabilities
|
$ | — | $ | — | $ | — | $ | — |
Fair Value Measurements at Reporting Date Using
|
||||||||||||||||
Quoted Prices in
Active Markets
for
Identical Assets
|
Significant
Other
Observable
Inputs
|
Significant
Unobservable
Inputs
|
||||||||||||||
Description
|
December 31,
2010
|
(Level 1)
|
(Level 2)
|
(Level 3)
|
||||||||||||
Assets
|
||||||||||||||||
Interest rate derivatives
|
$ | 1,941 | $ | — | $ | 1,941 | $ | — | ||||||||
Natural gas derivatives
|
201 | — | 201 | — | ||||||||||||
Total assets
|
$ | 2,142 | $ | — | $ | 2,142 | $ | — | ||||||||
Liabilities
|
||||||||||||||||
Interest rate derivatives
|
$ | 3,930 | $ | — | $ | 3,930 | $ | — | ||||||||
Natural gas derivatives
|
28 | — | 28 | — | ||||||||||||
Crude oil derivatives
|
177 | — | 177 | — | ||||||||||||
Natural gas liquids derivatives
|
247 | — | 247 | — | ||||||||||||
Total liabilities
|
$ | 4,382 | $ | — | $ | 4,382 | $ | — |
·
|
Accounts and other receivables, trade and other accounts payable, other accrued liabilities, income taxes payable and due from/to affiliates — The carrying amounts approximate fair value because of the short maturity of these instruments.
|
·
|
Long-term debt including current installments — The carrying amount of the revolving and term loan facilities approximates fair value due to the debt having a variable interest rate.
|
·
|
providing terminalling, refining, processing, distribution and midstream logistical services for hydrocarbon products and by-products;
|
·
|
providing marine and other transportation of hydrocarbon products and by-products; and
|
·
|
manufacturing and marketing fertilizers and related sulfur-based products.
|
·
|
the ownership and/or operation on the Partnership’s behalf of any asset or group of assets owned by it or its affiliates;
|
·
|
any business operated by Martin Resource Management, including the following:
|
o
|
providing land transportation of various liquids;
|
o
|
distributing fuel oil, sulfuric acid, marine fuel and other liquids;
|
o
|
providing marine bunkering and other shore-based marine services in Alabama, Florida, Louisiana Mississippi and Texas;
|
o
|
operating a small crude oil gathering business in Stephens, Arkansas;
|
o
|
operating an underground NGL storage facility in Arcadia, Louisiana;
|
o
|
building and marketing sulfur processing equipment; and
|
o
|
developing an underground natural gas storage facility in Arcadia, Louisiana.
|
·
|
any business that Martin Resource Management acquires or constructs that has a fair market value of less than $5,000;
|
·
|
any business that Martin Resource Management acquires or constructs that has a fair market value of $5,000 or more if the Partnership has been offered the opportunity to purchase the business for fair market value, and the Partnership declines to do so with the concurrence of the conflicts committee; and
|
·
|
any business that Martin Resource Management acquires or constructs where a portion of such business includes a restricted business and the fair market value of the restricted business is $5,000 or more and represents less than 20% of the aggregate value of the entire business to be acquired or constructed; provided that, following completion of the acquisition or construction, the Partnership will be provided the opportunity to purchase the restricted business.
|
Three Months Ended
September 30,
|
Nine months Ended
September 30,
|
|||||||||||||||
2011
|
2010
|
2011
|
2010
|
|||||||||||||
Revenues:
|
||||||||||||||||
Terminalling and storage
|
$ | 14,210 | $ | 12,292 | $ | 40,045 | $ | 34,579 | ||||||||
Marine transportation
|
6,351 | 7,968 | 19,223 | 20,948 | ||||||||||||
Product sales:
|
||||||||||||||||
Natural gas services
|
425 | 3,948 | 4,211 | 5,479 | ||||||||||||
Sulfur services
|
1,536 | 1,274 | 6,358 | 3,013 | ||||||||||||
Terminalling and storage
|
63 | 43 | 176 | 155 | ||||||||||||
2,024 | 5,265 | 10,745 | 8,647 | |||||||||||||
$ | 22,585 | $ | 25,525 | $ | 70,012 | $ | 64,174 |
Cost of products sold:
|
||||||||||||||||
Natural gas services
|
$ | 31,871 | $ | 16,353 | $ | 80,829 | $ | 57,721 | ||||||||
Sulfur services
|
4,762 | 4,212 | 13,407 | 11,448 | ||||||||||||
Terminalling and storage
|
45 | 34 | 183 | 257 | ||||||||||||
$ | 36,678 | $ | 20,599 | $ | 94,419 | $ | 69,426 |
Expenses:
|
||||||||||||||||
Operating expenses
|
||||||||||||||||
Marine transportation
|
$ | 8,630 | $ | 6,570 | $ | 21,412 | $ | 19,423 | ||||||||
Natural gas services
|
797 | 545 | 1,972 | 1,674 | ||||||||||||
Sulfur services
|
1,902 | 1,274 | 4,803 | 3,782 | ||||||||||||
Terminalling and storage
|
5,894 | 3,826 | 14,779 | 11,107 | ||||||||||||
$ | 17,223 | $ | 12,215 | $ | 42,966 | $ | 35,986 |
Selling, general and administrative:
|
||||||||||||||||
Marine transportation
|
$ | 19 | $ | — | $ | 49 | $ | — | ||||||||
Natural gas services
|
1,511 | 1,205 | 4,030 | 3,598 | ||||||||||||
Sulfur services
|
1,004 | 583 | 2,285 | 1,794 | ||||||||||||
Indirect overhead allocation, net of reimbursement
|
1,042 | 916 | 3,126 | 2,749 | ||||||||||||
$ | 3,576 | $ | 2,704 | $ | 9,490 | $ | 8,141 |
Operating Revenues
|
Intersegment
Revenues Eliminations
|
Operating
Revenues
after Eliminations
|
Depreciation
and
Amortization
|
Operating
Income (loss)
after
eliminations
|
Capital
Expenditures
|
|||||||||||||||||||
Three months ended September 30, 2011
|
||||||||||||||||||||||||
Terminalling and storage
|
$ | 38,080 | $ | (1,174 | ) | $ | 36,906 | $ | 4,829 | $ | 3,457 | $ | 14,360 | |||||||||||
Natural gas services
|
188,461 | — | 188,461 | 1,523 | 2,611 | 445 | ||||||||||||||||||
Sulfur services
|
70,169 | — | 70,169 | 1,676 | 5,921 | 2,598 | ||||||||||||||||||
Marine transportation
|
22,411 | (1,638 | ) | 20,773 | 3,372 | (896 | ) | 2,061 | ||||||||||||||||
Indirect selling, general and administrative
|
— | — | — | — | (2,965 | ) | — | |||||||||||||||||
Total
|
$ | 319,121 | $ | (2,812 | ) | $ | 316,309 | $ | 11,400 | $ | 8,128 | $ | 19,464 | |||||||||||
Three months ended September 30, 2010
|
||||||||||||||||||||||||
Terminalling and storage
|
$ | 30,495 | $ | (1,076 | ) | $ | 29,419 | $ | 4,181 | $ | 4,308 | $ | 1,574 | |||||||||||
Natural gas services
|
107,842 | — | 107,842 | 1,204 | 710 | 245 | ||||||||||||||||||
Sulfur services
|
36,658 | — | 36,658 | 1,554 | 736 | 2,812 | ||||||||||||||||||
Marine transportation
|
22,728 | (1,260 | ) | 21,468 | 3,236 | 3,534 | 267 | |||||||||||||||||
Indirect selling, general and administrative
|
— | — | — | — | (1,585 | ) | — | |||||||||||||||||
Total
|
$ | 197,723 | $ | (2,336 | ) | $ | 195,387 | $ | 10,175 | $ | 7,703 | $ | 4,898 | |||||||||||
Nine months ended September 30, 2011
|
||||||||||||||||||||||||
Terminalling and storage
|
$ | 115,492 | $ | (3,220 | ) | $ | 112,272 | $ | 14,114 | $ | 9,576 | $ | 24,270 | |||||||||||
Natural gas services
|
514,870 | — | 514,870 | 4,563 | 6,499 | 1,446 | ||||||||||||||||||
Sulfur services
|
206,860 | — | 206,860 | 4,998 | 27,818 | 14,826 | ||||||||||||||||||
Marine transportation
|
63,201 | (5,653 | ) | 57,548 | 9,976 | (5,143 | ) | 9,092 | ||||||||||||||||
Indirect selling, general and administrative
|
— | — | — | — | (6,545 | ) | — | |||||||||||||||||
Total
|
$ | 900,423 | $ | (8,873 | ) | $ | 891,550 | $ | 33,651 | $ | 32,205 | $ | 49,634 | |||||||||||
Nine months ended September 30, 2010
|
||||||||||||||||||||||||
Terminalling and storage
|
$ | 84,081 | $ | (3,332 | ) | $ | 80,749 | $ | 12,337 | $ | 10,736 | $ | 5,017 | |||||||||||
Natural gas services
|
397,855 | — | 397,855 | 3,593 | 3,345 | 1,015 | ||||||||||||||||||
Sulfur services
|
113,945 | — | 113,945 | 4,600 | 11,207 | 5,001 | ||||||||||||||||||
Marine transportation
|
60,926 | (3,468 | ) | 57,458 | 9,536 | 3,695 | 1,583 | |||||||||||||||||
Indirect selling, general and administrative
|
— | — | — | — | (4,615 | ) | — | |||||||||||||||||
Total
|
$ | 656,807 | $ | (6,800 | ) | $ | 650,007 | $ | 30,066 | $ | 24,368 | $ | 12,616 |
Three Months Ended
September 30,
|
Nine months Ended
September 30,
|
|||||||||||||||
2011
|
2010
|
2011
|
2010
|
|||||||||||||
Operating income
|
$ | 8,128 | $ | 7,703 | $ | 32,205 | $ | 24,368 | ||||||||
Equity in earnings of unconsolidated entities
|
1,784 | 2,951 | 6,953 | 7,469 | ||||||||||||
Interest expense
|
(4,297 | ) | (6,051 | ) | (17,102 | ) | (22,248 | ) | ||||||||
Other net
|
23 | 34 | 127 | 117 | ||||||||||||
Income tax benefit (expense)
|
(239 | ) | (1 | ) | (692 | ) | (224 | ) | ||||||||
Net income
|
$ | 5,399 | $ | 4,636 | $ | 21,491 | $ | 9,482 |
Total assets:
|
September 30,
2011 |
December 31,
2010 |
||||||
Terminalling and storage
|
$ | 219,676 | $ | 188,234 | ||||
Natural gas services
|
390,509 | 314,815 | ||||||
Sulfur services
|
167,027 | 138,224 | ||||||
Marine transportation
|
146,666 | 144,205 | ||||||
Total assets
|
$ | 923,878 | $ | 785,478 |
September 30,
2011
|
December 31,
2010
|
||||||||
** |
$200,000 Senior Notes, 8.875% interest, net of unamortized discount of $2,280 and $2,543, respectively, issued March 2010 and due April 2018, unsecured
|
$ | 197,720 | $ | 197,457 | ||||
*** |
$350,000 Revolving loan facility at variable interest rate (2.91%* weighted average at September 30, 2011), due April 2016, secured by substantially all of the Partnership’s assets, including, without limitation, inventory, accounts receivable, vessels, equipment, fixed assets and the interests in the Partnership’s operating subsidiaries and equity method investees
|
230,000 | 163,000 | ||||||
$7,114 Note payable to bank, interest rate at 7.50%, maturity date of January 2017, secured by equipment
|
6,618 | 7,354 | |||||||
Capital lease obligations | 6,076 | 6,172 | |||||||
Total long-term debt and capital lease obligations | 440,414 | 373,983 | |||||||
Less current installments | 1,201 | 1,121 | |||||||
Long-term debt and capital lease obligations, net of current installments | $ | 439,213 | $ | 372,862 |
Three Months Ended
September 30,
|
Nine months Ended
September 30,
|
|||||||||||||||
2011
|
2010
|
2011
|
2010
|
|||||||||||||
Current:
|
||||||||||||||||
Federal
|
$ | (17 | ) | $ | — | $ | 11 | $ | — | |||||||
State
|
223 | 186 | 679 | 698 | ||||||||||||
206 | 186 | 690 | 698 | |||||||||||||
Deferred:
|
||||||||||||||||
Federal
|
33 | (185 | ) | 2 | (474 | ) | ||||||||||
$ | 239 | $ | 1 | $ | 692 | $ | 224 |
·
|
Terminalling and storage services for petroleum and by-products;
|
·
|
Natural gas services;
|
·
|
Sulfur and sulfur-based products gathering, processing, marketing, manufacturing and distribution; and
|
·
|
Marine transportation services for petroleum products and by-products.
|
·
|
Several gas producers in our areas of operation have reduced drilling activity as compared to their previous levels of activity demonstrating a bias toward newly found shale plays in other areas.
|
·
|
Coupled with the general decline in drilling activity are the federal government’s enhanced safety regulations and inspection requirements as it relates to deep-water drilling in the Gulf of Mexico. In October 2010, the United States Government lifted the moratorium on deep water permitting and drilling. These enhanced safety regulations and inspection requirements of the Bureau of Ocean Energy Management, Regulation, and Enforcement (BOEMRE) continue to provide uncertainty surrounding the requirements for and pace of issuance of permits on the Gulf of Mexico Outer Continental Shelf (OCS). Although permits began to be issued by the BOEMRE again during first quarter 2011, they have not been approved in a timely manner consistent with pre-BP/Macondo spill levels.
|
·
|
There has been a decline in the demand for certain marine transportation services based on decreased refinery production resulting in an oversupply of equipment. This was partially offset in 2010 by the marine transportation services required in the efforts to clean up the BP oil spill in the Gulf of Mexico.
|
·
|
We continue to adjust our business strategy to focus on maximizing our liquidity, maintaining a stable asset base, and improving the profitability of our assets by increasing their utilization while controlling costs. Over the past year we have had access to the capital markets and have appropriate levels of liquidity and operating cash flows to adequately fund our growth. Our goal over the next two years will be to increase growth capital expenditures in primarily in our Terminalling and Storage and Sulfur Services segments.
|
·
|
We continue to evaluate opportunities to enter into interest rate and commodity hedging transactions. We believe these transactions can beneficially remove risks associated with interest rate and commodity price volatility.
|
·
|
During the first three quarters of 2011, we have experienced positive changing market dynamics in certain segments including activity associated with the rapidly developing basins such as the Eagle Ford shale.
|
·
|
providing land transportation of various liquids using a fleet of trucks and road vehicles and road trailers;
|
·
|
distributing fuel oil, asphalt, sulfuric acid, marine fuel and other liquids;
|
·
|
providing marine bunkering and other shore-based marine services in Alabama, Florida, Louisiana, Mississippi and Texas;
|
·
|
operating a small crude oil gathering business in Stephens, Arkansas;
|
·
|
operating a lube oil processing facility in Smackover, Arkansas;
|
·
|
operating an underground NGL storage facility in Arcadia, Louisiana;
|
·
|
supplying employees and services for the operation of our business; and
|
·
|
operating, solely for our account, our asphalt facilities in Omaha, Nebraska, Port Neches, Texas and South Houston, Texas.
|
Operating
Revenues
|
Revenues
Intersegment
Eliminations
|
Operating
Revenues
after
Eliminations
|
Operating
Income (loss)
|
Operating
Income
Intersegment
Eliminations
|
Operating
Income (loss)
after
Eliminations
|
|||||||||||||||||||
(In thousands)
|
||||||||||||||||||||||||
Three months ended September 30, 2011
|
||||||||||||||||||||||||
Terminalling and storage
|
$ | 38,080 | $ | (1,174 | ) | $ | 36,906 | $ | 3,810 | $ | (353 | ) | $ | 3,457 | ||||||||||
Natural gas services
|
188,461 | — | 188,461 | 2,240 | 371 | 2,611 | ||||||||||||||||||
Sulfur services
|
70,169 | — | 70,169 | 4,301 | 1,620 | 5,921 | ||||||||||||||||||
Marine transportation
|
22,411 | (1,638 | ) | 20,773 | 742 | (1,638 | ) | (896 | ) | |||||||||||||||
Indirect selling, general and administrative
|
— | — | — | (2,965 | ) | — | (2,965 | ) | ||||||||||||||||
Total
|
$ | 319,121 | $ | (2,812 | ) | $ | 316,309 | $ | 8,128 | $ | — | $ | 8,128 | |||||||||||
Three months ended September 30, 2010
|
||||||||||||||||||||||||
Terminalling and storage
|
$ | 30,495 | $ | (1,076 | ) | $ | 29,419 | $ | 4,835 | $ | (527 | ) | $ | 4,308 | ||||||||||
Natural gas services
|
107,842 | — | 107,842 | 432 | 278 | 710 | ||||||||||||||||||
Sulfur services
|
36,658 | — | 36,658 | (773 | ) | 1,509 | 736 | |||||||||||||||||
Marine transportation
|
22,728 | (1,260 | ) | 21,468 | 4,794 | (1,260 | ) | 3,534 | ||||||||||||||||
Indirect selling, general and administrative
|
— | — | — | (1,585 | ) | — | (1,585 | ) | ||||||||||||||||
Total
|
$ | 197,723 | $ | (2,336 | ) | $ | 195,387 | $ | 7,703 | $ | — | $ | 7,703 | |||||||||||
Nine months ended September 30, 2011
|
||||||||||||||||||||||||
Terminalling and storage
|
$ | 115,492 | $ | (3,220 | ) | $ | 112,272 | $ | 10,150 | $ | (574 | ) | $ | 9,576 | ||||||||||
Natural gas services
|
514,870 | — | 514,870 | 5,680 | 819 | 6,499 | ||||||||||||||||||
Sulfur services
|
206,860 | — | 206,860 | 22,430 | 5,388 | 27,818 | ||||||||||||||||||
Marine transportation
|
63,201 | (5,653 | ) | 57,548 | 490 | (5,633 | ) | (5,143 | ) | |||||||||||||||
Indirect selling, general and administrative
|
— | — | — | (6,545 | ) | — | (6,545 | ) | ||||||||||||||||
Total
|
$ | 900,423 | $ | (8,873 | ) | $ | 891,550 | $ | 32,205 | $ | — | $ | 32,205 | |||||||||||
Nine months ended September 30, 2010
|
||||||||||||||||||||||||
Terminalling and storage
|
$ | 84,081 | $ | (3,332 | ) | $ | 80,749 | $ | 12,512 | $ | (1,776 | ) | $ | 10,736 | ||||||||||
Natural gas services
|
397,855 | — | 397,855 | 2,381 | 964 | 3,345 | ||||||||||||||||||
Sulfur services
|
113,945 | — | 113,945 | 6,927 | 4,280 | 11,207 | ||||||||||||||||||
Marine transportation
|
60,926 | (3,468 | ) | 57,458 | 7,163 | (3,468 | ) | 3,695 | ||||||||||||||||
Indirect selling, general and administrative
|
— | — | — | (4,615 | ) | — | (4,615 | ) | ||||||||||||||||
Total
|
$ | 656,807 | $ | (6,800 | ) | $ | 650,007 | $ | 24,368 | $ | — | $ | 24,368 |
Three Months Ended
September 30,
|
||||||||
2011
|
2010
|
|||||||
(In thousands)
|
||||||||
Revenues:
|
||||||||
Services
|
$ | 20,555 | $ | 18,433 | ||||
Products
|
17,525 | 12,062 | ||||||
Total revenues
|
38,080 | 30,495 | ||||||
Cost of products sold
|
16,497 | 11,363 | ||||||
Operating expenses
|
12,891 | 10,342 | ||||||
Selling, general and administrative expenses
|
53 | 122 | ||||||
Depreciation and amortization
|
4,829 | 4,181 | ||||||
3,810 | 4,487 | |||||||
Other operating income
|
— | 348 | ||||||
Operating income
|
$ | 3,810 | $ | 4,835 |
Three Months Ended
September 30,
|
||||||||
2011
|
2010
|
|||||||
(In thousands)
|
||||||||
Revenues:
|
||||||||
NGLs
|
$ | 177,165 | $ | 94,119 | ||||
Natural gas
|
9,376 | 12,670 | ||||||
Non-cash mark-to-market adjustment of commodity derivatives
|
570 | (14 | ) | |||||
Gain (loss) on cash settlements of commodity derivatives
|
98 | 223 | ||||||
Other operating fees
|
1,252 | 844 | ||||||
Total revenues
|
188,461 | 107,842 | ||||||
Cost of products sold:
|
||||||||
NGLs
|
171,967 | 90,129 | ||||||
Natural gas
|
8,903 | 12,636 | ||||||
Total cost of products sold
|
180,870 | 102,765 | ||||||
Operating expenses
|
2,077 | 1,771 | ||||||
Selling, general and administrative expenses
|
1,751 | 1,739 | ||||||
Depreciation and amortization
|
1,523 | 1,204 | ||||||
2,240 | 363 | |||||||
Other operating income
|
— | 69 | ||||||
Operating income (loss)
|
$ | 2,240 | $ | 432 | ||||
NGLs Volumes (Bbls)
|
2,657 | 2,053 | ||||||
Natural Gas Volumes (Mmbtu)
|
2,400 | 3,112 | ||||||
Information above does not include activities relating to Waskom, PIPE, Matagorda and Redbird investments.
|
||||||||
Equity in Earnings of Unconsolidated Entities
|
$ | 1,784 | $ | 2,951 | ||||
Waskom:
|
Plant Inlet Volumes (Mmcf/d)
|
263 | 298 | ||||||
Frac Volumes (Bbls/d)
|
8,528 | 10,587 |
Three Months Ended
September 30,
|
||||||||
2011 | 2010 | |||||||
(In thousands) | ||||||||
Revenues:
|
||||||||
Services
|
$ | 2,850 | $ | — | ||||
Products
|
67,319 | 36,658 | ||||||
Total revenues
|
70,169 | 36,658 | ||||||
Cost of products sold
|
59,899 | 30,596 | ||||||
Operating expenses
|
4,930 | 4,447 | ||||||
Selling, general and administrative expenses
|
774 | 822 | ||||||
Depreciation and amortization
|
1,676 | 1,554 | ||||||
2,890 | (761 | ) | ||||||
Other operating income
|
1,411 | (12 | ) | |||||
Operating income
|
$ | 4,301 | $ | (773 | ) | |||
Sulfur (long tons)
|
310.2 | 326.0 | ||||||
Fertilizer (long tons)
|
54.2 | 60.7 | ||||||
Sulfur Services Volumes (long tons)
|
364.4 | 386.7 |
Three Months Ended
September 30,
|
||||||||
2011
|
2010
|
|||||||
(In thousands)
|
||||||||
Revenues
|
$ | 22,411 | $ | 22,728 | ||||
Operating expenses
|
17,300 | 14,424 | ||||||
Selling, general and administrative expenses
|
1,306 | 274 | ||||||
Depreciation and amortization
|
3,372 | 3,236 | ||||||
433 | 4,794 | |||||||
Other operating income (loss)
|
309 | — | ||||||
Operating income (loss)
|
$ | 742 | $ | 4,794 |
Nine Months Ended
September 30,
|
||||||||
2011
|
2010
|
|||||||
(In thousands)
|
||||||||
Revenues:
|
||||||||
Services
|
$ | 60,031 | $ | 53,394 | ||||
Products
|
55,461 | 30,687 | ||||||
Total revenues
|
115,492 | 84,081 | ||||||
Cost of products sold
|
52,277 | 28,771 | ||||||
Operating expenses
|
38,145 | 30,626 | ||||||
Selling, general and administrative expenses
|
229 | 183 | ||||||
Depreciation and amortization
|
14,114 | 12,337 | ||||||
10,727 | 12,164 | |||||||
Other operating income
|
(577 | ) | 348 | |||||
Operating income
|
$ | 10,150 | $ | 12,512 |
Nine months Ended
September 30,
|
||||||||
2011
|
2010
|
|||||||
(In thousands)
|
||||||||
Revenues:
|
||||||||
NGLs
|
$ | 478,952 | $ | 358,395 | ||||
Natural gas
|
30,312 | 35,450 | ||||||
Non-cash mark-to-market adjustment of commodity derivatives
|
1,389 | 404 | ||||||
Gain (loss) on cash settlements of commodity derivatives
|
(58 | ) | 505 | |||||
Other operating fees
|
4,275 | 3,101 | ||||||
Total revenues
|
514,870 | 397,855 | ||||||
Cost of products sold:
|
||||||||
NGLs
|
463,915 | 345,443 | ||||||
Natural gas
|
29,024 | 34,954 | ||||||
Total cost of products sold
|
492,939 | 380,397 | ||||||
Operating expenses
|
6,303 | 5,538 | ||||||
Selling, general and administrative expenses
|
5,385 | 6,015 | ||||||
Depreciation and amortization
|
4,563 | 3,593 | ||||||
5,680 | 2,312 | |||||||
Other operating income
|
— | 69 | ||||||
Operating income (loss)
|
$ | 5,680 | $ | 2,381 | ||||
NGLs Volumes (Bbls)
|
7,335 | 7,177 | ||||||
Natural Gas Volumes (Mmbtu)
|
7,704 | 8,121 | ||||||
Information above does not include activities relating to Waskom, PIPE, Matagorda and Redbird investments.
|
||||||||
Equity in Earnings of Unconsolidated Entities
|
$ | 6,953 | $ | 7,469 | ||||
Waskom: |
Plant Inlet Volumes (Mmcf/d)
|
272 | 276 | ||||||
Frac Volumes (Bbls/d)
|
8,927 | 9,874 |
Nine months Ended
September 30,
|
||||||||
2011 | 2010 | |||||||
(In thousands)
|
||||||||
Revenues:
|
||||||||
Services
|
$ | 8,550 | $ | — | ||||
Products
|
198,310 | 113,945 | ||||||
Total revenues
|
206,860 | 113,945 | ||||||
Cost of products sold
|
164,414 | 87,127 | ||||||
Operating expenses
|
14,587 | 12,683 | ||||||
Selling, general and administrative expenses
|
2,517 | 2,596 | ||||||
Depreciation and amortization
|
4,998 | 4,600 | ||||||
20,344 | 6,939 | |||||||
Other operating income
|
2,086 | (12 | ) | |||||
Operating income
|
$ | 22,430 | $ | 6,927 | ||||
Sulfur (long tons)
|
998.7 | 910.7 | ||||||
Fertilizer (long tons)
|
189.7 | 201.4 | ||||||
Sulfur Services Volumes (long tons)
|
1,188.4 | 1,112.1 |
Nine months Ended
September 30,
|
||||||||
2011
|
2010
|
|||||||
(In thousands)
|
||||||||
Revenues
|
$ | 63,201 | $ | 60,926 | ||||
Operating expenses
|
50,831 | 43,031 | ||||||
Selling, general and administrative expenses
|
2,213 | 1,241 | ||||||
Depreciation and amortization
|
9,976 | 9,536 | ||||||
181 | 7,118 | |||||||
Other operating income (loss)
|
309 | 45 | ||||||
Operating income (loss)
|
$ | 490 | $ | 7,163 |
·
|
maintenance capital expenditures, which are capital expenditures made to replace assets to maintain our existing operations and to extend the useful lives of our assets; and
|
·
|
expansion capital expenditures, which are capital expenditures made to grow our business, to expand and upgrade our existing terminalling, marine transportation, storage and manufacturing facilities, and to construct new terminalling facilities, plants, storage facilities and new marine transportation assets.
|
·
|
For the nine months ended September 30, 2011, we spent $39.5 million for expansion and $10.1 million for maintenance. Our expansion capital expenditures were made in connection with construction projects associated with our terminalling and storage and sulfur services segments. Our maintenance capital expenditures were primarily made in our sulfur services segment for routine maintenance on the facilities as well as in the marine transportation segment for dry dockings of our vessels pursuant to the United States Coast Guard requirements.
|
·
|
For the nine months ended September 30, 2010, we spent $9.1 million for expansion and $3.5 million for maintenance. Our expansion capital expenditures were made in connection with construction projects associated with our terminalling and storage and sulfur services segments. Our maintenance capital expenditures were primarily made in our terminalling and storage and sulfur services segment for routine maintenance on the facilities as well as in the marine transportation segment for dry dockings of our vessels pursuant to the United States Coast Guard requirements.
|
Payment due by period
|
||||||||||||||||||||
Type of Obligation
|
Total
Obligation
|
Less than One Year
|
1-3
Years
|
3-5
Years
|
Due Thereafter
|
|||||||||||||||
Long-Term Debt
|
||||||||||||||||||||
Revolving credit facility
|
$ | 231,000 | $ | — | $ | — | $ | 231,000 | $ | — | ||||||||||
Senior unsecured notes
|
197,720 | — | — | — | 197,720 | |||||||||||||||
Note payable
|
6,618 | 1,048 | 2,348 | 2,727 | 495 | |||||||||||||||
Capital leases including current maturities
|
6,076 | 186 | 505 | 5,385 | — | |||||||||||||||
Non-competition agreements
|
150 | 50 | 100 | — | — | |||||||||||||||
Redbird Class A investment commitment
|
8,500 | 8,500 | — | — | — | |||||||||||||||
Throughput commitment
|
64,025 | 2,214 | 11,203 | 12,598 | 38,010 | |||||||||||||||
Operating leases
|
49,701 | 11,713 | 22,188 | 9,089 | 6,711 | |||||||||||||||
Interest expense: ¹
|
||||||||||||||||||||
Revolving credit facility
|
30,407 | 6,694 | 13,388 | 10,325 | — | |||||||||||||||
Senior unsecured notes
|
115,375 | 17,750 | 35,500 | 35,500 | 26,625 | |||||||||||||||
Note payable
|
1,434 | 461 | 672 | 293 | 8 | |||||||||||||||
Capital leases
|
4,298 | 952 | 1,802 | 1,544 | — | |||||||||||||||
Total contractual cash obligations
|
$ | 715,304 | $ | 49,568 | $ | 87,706 | $ | 308,461 | $ | 269,569 | ||||||||||
_____________________ |
(1)
|
Interest commitments are estimated using our current interest rates for the respective credit agreements over their remaining terms.
|
Leverage Ratio
|
Base Rate
Loans
|
Eurodollar
Rate
Loans
|
Letter of
Credit
Fees
|
|||
Less than 2.25 to 1.00
|
1.00%
|
2.00%
|
2.00%
|
|||
Greater than or equal to 2.25 to 1.00 and less than 3.00 to 1.00
|
1.25%
|
2.25%
|
2.25%
|
|||
Greater than or equal to 3.00 to 1.00 and less than 3.50 to 1.00
|
1.50%
|
2.50%
|
2.50%
|
|||
Greater than or equal to 3.50 to 1.00 and less than 4.00 to 1.00
|
1.75%
|
2.75%
|
2.75%
|
|||
Greater than or equal to 4.00 to 1.00
|
2.00%
|
3.00%
|
3.00%
|
|||
Greater than or equal to 4.50 to 1.00
|
2.25%
|
3.25%
|
3.25%
|
|
●
|
grant or assume liens;
|
|
●
|
make investments (including investments in our joint ventures) and acquisitions;
|
|
●
|
enter into certain types of hedging agreements;
|
|
●
|
incur or assume indebtedness;
|
|
●
|
sell, transfer, assign or convey assets;
|
|
●
|
repurchase our equity, make distributions and certain other restricted payments, but the credit facility permits us to make quarterly distributions to unitholders so long as no default or event of default exists under the credit facility;
|
|
●
|
change the nature of our business;
|
|
●
|
engage in transactions with affiliates.
|
|
●
|
enter into certain burdensome agreements;
|
|
●
|
make certain amendments to the omnibus agreement and our material agreements;
|
|
●
|
make capital expenditures; and
|
|
●
|
permit our joint ventures to incur indebtedness or grant certain liens.
|
|
●
|
failure to pay any principal, interest, fees, expenses or other amounts when due;
|
|
●
|
failure to meet the quarterly financial covenants;
|
|
●
|
failure to observe any other agreement, obligation, or covenant in the credit facility or any related loan document, subject to cure periods for certain failures;
|
|
●
|
the failure of any representation or warranty to be materially true and correct when made;
|
|
●
|
our or any of our subsidiaries’ default under other indebtedness that exceeds a threshold amount;
|
|
●
|
bankruptcy or other insolvency events involving us or any of our subsidiaries;
|
|
●
|
judgments against us or any of our subsidiaries, in excess of a threshold amount;
|
|
●
|
certain ERISA events involving us or any of our subsidiaries, in excess of a threshold amount;
|
|
●
|
a change in control (as defined in the credit facility);
|
|
●
|
the termination of any material agreement or certain other events with respect to material agreements;
|
|
●
|
the invalidity of any of the loan documents or the failure of any of the collateral documents to create a lien on the collateral; and
|
|
●
|
any of our joint ventures incurs debt or liens in excess of a threshold amount.
|
1)
|
Percent-of-liquids contracts: Under these contracts, we receive a fee in the form of a percentage of the NGLs recovered, and the producer bears all of the cost of natural gas shrink. Therefore, margins increase during periods of high NGL prices and decrease during periods of low NGL prices.
|
2)
|
Percent-of-proceeds contracts: Under these contracts, we generally gather and process natural gas on behalf of certain producers, sell the resulting residue gas and NGLs at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price. In other cases, instead of remitting cash payments to the producer, we deliver an agreed upon percentage of the residue gas and NGLs to the producer and sell the volumes kept to third parties at market prices. Under these types of contracts, revenues and gross margins increase as natural gas prices and NGL prices increase, and revenues and gross margins decrease as natural gas and NGL prices decease.
|
●
|
Natural gas contracts - monthly posting for ANR Pipeline Co. - Louisiana as posted in Platts Inside FERC’s Gas Market Report;
|
●
|
Crude oil contracts - WTI NYMEX average for the month of the daily closing prices; and
|
●
|
Natural gasoline contracts - Mt. Belvieu Non-TET average monthly postings as reported by the Oil Price Information Service (OPIS).
|
Period
|
Underlying
|
Notional Volume
|
Commodity Price
We Receive
|
Commodity
Price
We Pay
|
Fair Value
Asset
(In Thousands)
|
Fair Value
Liability
(In Thousands)
|
||||||
October 2011-December 2011
|
Natural Gas
|
30,000 (Mmbtu)
|
Index
|
$6.125/Mmbtu
|
71 | — | ||||||
October 2011-December 2011
|
Natural Gas
|
60,000 (Mmbtu)
|
Index
|
$4.3225/Mmbtu
|
35 | — | ||||||
October 2011-December 2011
|
Crude Oil
|
6,000 (BBL)
|
Index
|
$91.20/Bbl
|
67 | — | ||||||
October 2011-December 2011
|
Crude Oil
|
3,000 (BBL)
|
Index
|
$101.90/Bbl
|
65 | — | ||||||
October 2011-December 2011
|
Natural Gasoline
|
6,000 (BBL)
|
Index
|
$87.10/Bbl
|
42 | — | ||||||
October 2011-December 2011
|
Natural Gasoline
|
3,000 (BBL)
|
Index
|
$88.85/Bbl
|
26 | — | ||||||
October 2011-December 2011
|
Natural Gasoline
|
3,000 (BBL)
|
Index
|
$2.383/Gal
|
48 | — | ||||||
January 2012-December 2012
|
Natural Gas
|
120,000 (Mmbtu)
|
Index
|
$4.870/Mmbtu
|
81 | — | ||||||
January 2012-December 2012
|
Natural Gas
|
240,000 (Mmbtu)
|
Index
|
$4.960/Mmbtu
|
184 | — | ||||||
January 2012-December 2012
|
Crude Oil
|
48,000 (BBL)
|
Index
|
$88.63/Bbl
|
187 | — | ||||||
January 2012-December 2012
|
Natural Gasoline
|
12,000 (BBL)
|
Index
|
$90.20/Bbl
|
112 | — | ||||||
January 2012-December 2012
|
Natural Gasoline
|
12,000 (BBL)
|
Index
|
$2.340/Gal
|
160 | — | ||||||
$ | 1,078 | $ | — |
Martin Midstream Partners L.P.
|
||||
|
By:
|
Martin Midstream GP LLC | ||
Its General Partner | ||||
Date: November 7, 2011 | By: | /s/ Ruben S. Martin | ||
Ruben S. Martin | ||||
President and Chief Executive Officer |
Exhibit
Number
|
Exhibit Name
|
|
3.1
|
Certificate of Limited Partnership of Martin Midstream Partners L.P. (the “Partnership”), dated June 21, 2002 (filed as Exhibit 3.1 to the Partnership’s Registration Statement on Form S-1 (Reg. No. 333-91706), filed July 1, 2002, and incorporated herein by reference).
|
|
3.2
|
Second Amended and Restated Agreement of Limited Partnership of the Partnership, dated as of November 25, 2009 (filed as Exhibit 10.1 to the Partnership’s Amendment to Current Report on Form 8-K/A, filed January 19, 2010, and incorporated herein by reference).
|
|
3.3
|
Amendment No. 2 to the Second Amended and Restated Agreement of Limited Partnership dated January 31, 2011 (filed as Exhibit 3.1 to the Partnership’s Current Report on Form 8-K , filed February 1, 2011, and incorporated herein by reference.
|
|
3.4
|
Certificate of Limited Partnership of Martin Operating Partnership L.P. (the “Operating Partnership”), dated June 21, 2002 (filed as Exhibit 3.3 to the Partnership’s Registration Statement on Form S-1 (Reg. No. 333-91706), filed July 1, 2002, and incorporated herein by reference).
|
|
3.5
|
Amended and Restated Agreement of Limited Partnership of the Operating Partnership, dated November 6, 2002 (filed as Exhibit 3.2 to the Partnership’s Current Report on Form 8-K, filed November 19, 2002, and incorporated herein by reference).
|
|
3.6
|
Certificate of Formation of Martin Midstream GP LLC (the “General Partner”), dated June 21, 2002 (filed as Exhibit 3.5 to the Partnership’s Registration Statement on Form S-1 (Reg. No. 333-91706), filed July 1, 2002, and incorporated herein by reference).
|
|
3.7
|
Limited Liability Company Agreement of the General Partner, dated June 21, 2002 (filed as Exhibit 3.6 to the Partnership’s Registration Statement on Form S-1 (Reg. No. 33-91706), filed July 1, 2002, and incorporated herein by reference).
|
|
3.8 | Certificate of Formation of Martin Operating GP LLC (the “Operating General Partner”), dated June 21, 2002 (filed as Exhibit 3.7 to the Partnership’s Registration Statement on Form S-1 (Reg. No. 333-91706), filed July 1, 2002, and incorporated herein by reference). | |
3.9
|
Limited Liability Company Agreement of the Operating General Partner, dated June 21, 2002 (filed as Exhibit 3.8 to the Partnership’s Registration Statement on Form S-1 (Reg. No. 333-91706), filed July 1, 2002, and incorporated herein by reference).
|
|
4.1
|
Specimen Unit Certificate for Common Units (contained in Exhibit 3.2).
|
|
4.2
|
Specimen Unit Certificate for Subordinated Units (filed as Exhibit 4.2 to Amendment No. 4 to the Partnership’s Registration Statement on Form S-1 (Reg. No. 333-91706), filed October 25, 2002, and incorporated herein by reference).
|
|
4.3
|
Indenture, dated as of March 26, 2010, by and among the Partnership, Martin Midstream Finance Corp., the Guarantors named therein and Wells Fargo Bank, National Association, as trustee (filed as Exhibit 4.1 to the Partnership’s Current Report on Form 8-K, filed March 26, 2010, and incorporated herein by reference).
|
|
Ninth Amendment to Second Amended and Restated Credit Agreement, dated as of September 7, 2011, among Martin Operating Partnership L.P., the Partnership, Martin Operating GP LLC, Prism Gas Systems I, L.P., Prism Gas Systems GP, L.L.C., Prism Gulf Coast Systems, L.L.C., McLeod Gas Gathering and Processing Company, L.L.C., Woodlawn Pipeline Co., Inc., Prism Liquids Pipeline, LLC, the financial institutions party to the Credit Agreement and Royal Bank of Canada, as administrative agent and collateral agent.
|
||
KPMG Preferability Letter on Change in Annual Date for Goodwill and Other Intangibles Impairment Testing Date.
|
||
Certifications of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
|
||
Certifications of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
|
||
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. Pursuant to SEC Release 34-47551, this Exhibit is furnished to the SEC and shall not be deemed to be “filed.”
|
||
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. Pursuant to SEC Release 34-47551, this Exhibit is furnished to the SEC and shall not be deemed to be “filed.”
|
||
101
|
Interactive Data: the following financial information from Martin Midstream Partners L.P.’s Quarterly Report on Form 10-Q for the fiscal quarter ended September 30, 2011, formatted in Extensible Business Reporting Language: (1) the Consolidated Balance Sheets; (2) the Consolidated Statements of Income; (3) the Consolidated Statements of Cash Flows; (4) the Consolidated Statements of Capital; (5) the Consolidated Statements of Other Comprehensive Income; and (6) the Notes to Consolidated Financial Statements, tagged as blocks of text.
|
MARTIN OPERATING PARTNERSHIP L.P.,
|
||||
a Delaware limited partnership, as Borrower
|
||||
By:
|
MARTIN OPERATING GP LLC,
|
|||
its General Partner
|
||||
By:
|
MARTIN MIDSTREAM PARTNERS L.P.,
|
|||
its Sole Member | ||||
By: | MARTIN MIDSTREAM GP LLC, | |||
its General Partner | ||||
By: | /s/ Robert D. Bondurant | |||
Executive Vice President and Chief | ||||
Financial Officer |
MARTIN MIDSTREAM PARTNERS L.P.,
|
||
a Delaware limited partnership, as a Guarantor
|
||
By:
|
MARTIN MIDSTREAM GP LLC,
|
|
its General Partner
|
||
By:
|
/s/ Robert D. Bondurant
|
|
Robert D. Bondurant | ||
Executive Vice President and Chief | ||
Financial Officer |
MARTIN OPERATING GP LLC,
|
|||
a Delaware limited liability company, as a Guarantor
|
|||
By:
|
MARTIN MIDSTREAM PARTNERS L.P.,
|
||
its Sole Member
|
|||
By:
|
MARTIN MIDSTREAM PARTNERS L.P.,
|
||
its General Partner | |||
By: | /s/ Robert D. Bondurant | ||
Robert D. Bondurant | |||
Executive Vice President and Chief | |||
Financial Officer |
PRISM GAS SYSTEMS I, L.P., a Texas limited partnership, as a Guarantor
|
||
By:
|
Prism Gas Systems GP, L.L.C., its General Partner
|
|
By:
|
/s/ Robert D. Bondurant | |
Robert D. Bondurant | ||
Treasurer |
PRISM GAS SYSTEMS GP, L.L.C., as a Guarantor
|
|
By:
|
/s/ Robert D. Bondurant |
Robert D. Bondurant | |
Treasurer |
PRISM GULF COAST SYSTEMS, L.L.C., as a Guarantor
|
|
By:
|
/s/ Robert D. Bondurant |
Robert D. Bondurant | |
Treasurer |
MCLEOD GAS GATHERING AND PROCESSING
|
|
COMPANY, L.L.C., as a Guarantor
|
|
By:
|
/s/ Ruben S. Martin |
Ruben S. Martin | |
Sole Manager |
WOODLAWN PIPELINE CO., INC.,
|
|
a Texas corporation, as a Guarantor
|
|
By:
|
/s/ Robert D. Bondurant |
Robert D. Bondurant | |
Executive Vice President |
PRISM LIQUIDS PIPELINE, LLC,
|
|
Texas limited liability company, as a Guarantor
|
|
By:
|
/s/ Robert D. Bondurant |
Robert D. Bondurant | |
Executive Vice President |
ROYAL BANK OF CANADA, as Administrative Agent and Collateral Agent
|
|||
|
By:
|
/s/Ann Hurley | |
Name: Ann Hurley | |||
Title: Manager, Agency |
ROYAL BANK OF CANADA, as a Lender and as L/C Issuer
|
|||
|
By:
|
/s/ Jason S. York | |
Jason S. York | |||
Authorized Signatory |
WELLS FARGO BANK, N.A., as Syndication Agent and a Lender
|
|||
|
By:
|
/s/ Thomas E. Stelmar, Jr. | |
Name: Thomas E. Stelmar, Jr. | |||
Title: Vice President |
THE ROYAL BANK OF SCOTLAND PLC, as Co-Documentation Agent and a Lender
|
|||
|
By:
|
/s/ Matthew Allen | |
Name: Matthew Allen | |||
Title: Authorized Signatory |
REGIONS BANK, as Co-Documentation Agent and a Lender
|
|||
|
By:
|
/s/ Randy Petersen | |
Name: Randy Petersen | |||
Title: Senior Vice President |
UBS LOAN FINANCE, LLC, as Co-Documentation Agent and a Lender
|
|||
|
By:
|
/s/ Mary E. Evans | |
Name: Mary E. Evans | |||
Title: Associate Director |
|
By:
|
/s/ Joselin Fernandes | |
Name: Joselin Fernandes | |||
Title: Associate Director |
SUNTRUST BANK, as a Lender
|
|||
|
By:
|
/s/ Carmen Malizia | |
Name: Carmen Malizia | |||
Title: Vice President |
COMPASS BANK, as a Lender
|
|||
|
By:
|
/s/ Brandon Kelley | |
Name: Brandon Kelley | |||
Title: Senior Vice President |
COMERICA BANK, as a Lender
|
|||
|
By:
|
/s/ Brian Enzler | |
Name: Brian Enzler | |||
Title: Vice President |
BANK OF AMERICA, N.A., as a Lender
|
|||
|
By:
|
/s/ David A. Batson | |
Name: David A. Batson | |||
Title: Senior Vice President |
CITIBANK, N.A., as a Lender
|
|||
|
By:
|
/s/ Stephen Oglesby | |
Name: Stephen Oglesby | |||
Title: Region Manager |
NATIXIS, as a Lender
|
|||
|
By:
|
/s/ Louis P. Laville | |
Name: Louis P. Laville | |||
Title: Managing Director |
|
By:
|
/s/ Daniel Payer | |
Name: Daniel Payer | |||
Title: Managing Director |
RAYMOND JAMES BANK, FSB, as a Lender
|
|||
|
By:
|
/s/ Garrett McKinnon | |
Name: Garrett McKinnon | |||
Title: Senior Vice President |
BRANCH BANKING AND TRUST COMPANY, as a Lender
|
|||
|
By:
|
/s/ Mark B. Grover | |
Name: Mark B. Grover | |||
Title: Senior Vice President |
Description of Assets
|
Explanation Why May
Not be Pledged
|
When Assets must be
Pledged/Mortgaged
|
1. Prism Gas Systems I, L.P. ownership interests in Waskom Gas Processing Company
|
Waskom Gas Processing Company Partnership Agreement grants right of first refusal to partner
|
At such time as (x) Waskom Gas Processing Company is a wholly owned direct or indirect Subsidiary of the Borrower or (y) partner does not have right of first refusal
|
2. Prism Gas Systems, Inc. ownership interests in Waskom Gas Processing Company
|
same as above
|
same
|
3. Assets owned by Prism Gas Systems, Inc.
|
For tax reasons, Prism Gas Systems, Inc. has adopted a plan of dissolution, and will be dissolved no earlier than one year after the Closing Date, and no later than one year and one week after the Closing Date. Prism Gas Systems, Inc. has no assets other than the 1% equity interest in Waskom Gas Processing Company (this 1% equity interest cannot be pledged – see the analysis in point 1 above), and Prism owns no other assets, other than cash of less than $25,000
|
One year and one week after the Closing Date, if Prism Gas Systems, Inc. has not been dissolved
|
4. Martin Operating Partnership L.P.’s or Redbird Gas Storage LLC’s ownership interest in Cardinal Gas Storage Partners LLC
|
Cardinal Gas Storage Partners LLC’s Limited Liability Company Agreement prohibits a pledge of the equity interest without consent of the other members
|
At such time as (x) Cardinal Gas Storage Partners LLC is a wholly owned direct or indirect Subsidiary of Martin Operating Partnership L.P., (y) Cardinal Gas Storage Partners LLC’s Limited Liability Company Agreement no longer prohibits a pledge of the equity interest, or (z) consent to pledge of the equity interest is obtained from the other members
|
5. Whole of the vessel known as M 6000 (Official Number 1215084)
|
Previously pledged to RBS Asset Finance, Inc. pursuant to that certain First Preferred Ship Mortgage dated December 30, 2009, and filed at the National Vessel Documentation Center on December 30, 2009
|
Not applicable
|
Description of Guaranty
|
Explanation Why May Not be Pledged
|
When Assets must be
Pledged/Mortgaged
|
Guaranty by Prism Gas Systems, Inc.
|
The incurrence of debt (via a guaranty) by Prism Gas Systems, Inc. after it has already begun liquidation might have adverse tax consequences.
|
One year and one week after the Closing Date, if Prism Gas Systems, Inc. has not been dissolved
|
Very truly yours, |
/s/KPMG LLP
|
Shreveport, Louisiana |
Date: November 7, 2011 | |
/s/ Ruben S. Martin
|
|
Ruben S. Martin, President and | |
Chief Executive Officer of | |
Martin Midstream GP LLC, | |
the General Partner of Martin Midstream Partners L.P. |
Date: November 7, 2011 | |
/s/ Robert D. Bondurant
|
|
Robert D. Bondurant, Executive Vice President and | |
Chief Financial Officer of | |
Martin Midstream GP LLC, | |
the General Partner of Martin Midstream Partners L.P. |
/s/ Ruben S. Martin | ||
Ruben S. Martin, | ||
Chief Executive Officer of Martin Midstream GP LLC,
|
||
General Partner of Martin Midstream Partners L.P. | ||
November 7, 2011
|
/s/ Robert D. Bondurant | ||
|
Robert D. Bondurant,
|
|
Chief Financial Officer | ||
of Martin Midstream GP LLC, | ||
General Partner of Martin Midstream Partners L.P. | ||
November 7, 2011 |
CONSOLIDATED AND CONDENSED STATEMENTS OF OPERATIONS (Unaudited) (USD $) In Thousands, except Share data | 3 Months Ended | 9 Months Ended | ||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Sep. 30, 2011 | Sep. 30, 2010 | Sep. 30, 2011 | Sep. 30, 2010 | |||||||||||
Revenues: | ||||||||||||||
Terminalling and storage | $ 19,381 | [1] | $ 17,357 | [1] | $ 56,831 | [1] | $ 50,062 | [1] | ||||||
Marine transportation | 20,773 | [1] | 21,468 | [1] | 57,548 | [1] | 57,458 | [1] | ||||||
Sulfur services | 2,850 | [1] | 0 | [1] | 8,550 | [1] | 0 | [1] | ||||||
Product sales: | ||||||||||||||
Natural gas services | 188,461 | [1] | 107,842 | [1] | 514,870 | [1] | 397,855 | [1] | ||||||
Sulfur services | 67,319 | [1] | 36,658 | [1] | 198,310 | [1] | 113,945 | [1] | ||||||
Terminalling and storage | 17,525 | [1] | 12,062 | [1] | 55,441 | [1] | 30,687 | [1] | ||||||
Total product sales | 273,305 | [1] | 156,562 | [1] | 768,621 | [1] | 542,487 | [1] | ||||||
Total revenues | 316,309 | 195,387 | 891,550 | 650,007 | ||||||||||
Cost of products sold: (excluding depreciation and amortization) | ||||||||||||||
Natural gas services | 180,499 | [2] | 102,487 | [2] | 492,120 | [2] | 379,433 | [2] | ||||||
Sulfur services | 59,808 | [2] | 30,505 | [2] | 164,142 | [2] | 86,855 | [2] | ||||||
Terminalling and storage | 15,676 | 11,363 | 49,631 | 28,771 | ||||||||||
Total cost of products sold (excluding depreciation and amortization) | 255,983 | 144,355 | 705,893 | 495,059 | ||||||||||
Expenses: | ||||||||||||||
Operating expenses | 35,669 | [3] | 29,017 | [3] | 104,730 | [3] | 86,314 | [3] | ||||||
Selling, general and administrative | 6,849 | [3] | 4,542 | [3] | 16,889 | [3] | 14,650 | [3] | ||||||
Depreciation and amortization | 11,400 | 10,175 | 33,651 | 30,066 | ||||||||||
Total costs and expenses | 309,901 | 188,089 | 861,163 | 626,089 | ||||||||||
Other operating income | 1,720 | 405 | 1,818 | 450 | ||||||||||
Operating income | 8,128 | 7,703 | 32,205 | 24,368 | ||||||||||
Other income (expense): | ||||||||||||||
Equity in earnings of unconsolidated entities | 1,784 | 2,951 | 6,953 | 7,469 | ||||||||||
Interest expense | (4,297) | (6,051) | (17,102) | (22,248) | ||||||||||
Other, net | 23 | 34 | 127 | 117 | ||||||||||
Total other income (expense) | (2,490) | (3,066) | (10,022) | (14,662) | ||||||||||
Net income before taxes | 5,638 | 4,637 | 22,183 | 9,706 | ||||||||||
Income tax benefit (expense) | (239) | (1) | (692) | (224) | ||||||||||
Net income | 5,399 | 4,636 | 21,491 | 9,482 | ||||||||||
General partner's interest in net income | 1,348 | 1,000 | 3,992 | 2,832 | ||||||||||
Limited partners' interest in net income | $ 3,774 | $ 3,359 | $ 16,668 | $ 5,819 | ||||||||||
Net income per limited partner unit - basic and diluted | $ 0.20 | $ 0.19 | $ 0.87 | $ 0.33 | ||||||||||
Weighted average limited partner units - basic (in units) | 19,158,334 | 17,700,875 | 19,161,403 | 17,466,200 | ||||||||||
Weighted average limited partner units - diluted (in units) | 19,163,128 | 17,701,719 | 19,163,066 | 17,467,514 | ||||||||||
|
CONSOLIDATED AND CONDENSED STATEMENTS OF OPERATIONS (Unaudited) (Parenthetical) (USD $) In Thousands | 3 Months Ended | 9 Months Ended | ||
---|---|---|---|---|
Sep. 30, 2011 | Sep. 30, 2010 | Sep. 30, 2011 | Sep. 30, 2010 | |
Revenues: | ||||
Terminalling and storage | $ 14,210 | $ 12,292 | $ 40,045 | $ 34,579 |
Marine transportation | 6,351 | 7,968 | 19,223 | 20,948 |
Product Sales | 2,024 | 5,265 | 10,745 | 8,647 |
Costs and expenses: | ||||
Natural gas services | 31,871 | 16,353 | 80,829 | 57,721 |
Sulfur services | 4,762 | 4,212 | 13,407 | 11,448 |
Expenses: | ||||
Operating expenses | 17,223 | 12,215 | 42,966 | 35,986 |
Selling, general and administrative | $ 3,576 | $ 2,704 | $ 9,490 | $ 8,141 |
Document And Entity Information (USD $) | 9 Months Ended | ||
---|---|---|---|
Sep. 30, 2011 | Nov. 07, 2011 | Jun. 30, 2010 | |
Entity Registrant Name | MARTIN MIDSTREAM PARTNERS LP | ||
Entity Central Index Key | 0001176334 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Filer Category | Accelerated Filer | ||
Entity Public Float | $ 206,544,787 | ||
Entity Common Stock, Shares Outstanding | 19,582,332 | ||
Document Fiscal Year Focus | 2011 | ||
Document Fiscal Period Focus | Q3 | ||
Document Type | 10-Q | ||
Amendment Flag | false | ||
Document Period End Date | Sep. 30, 2011 |
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Investments in Unconsolidated Entities and Joint Ventures | 9 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Sep. 30, 2011 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Investments in Unconsolidated Entities and Joint Ventures [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Investments in Unconsolidated Entities and Joint Ventures | (5) Investments in Unconsolidated Entities and Joint Ventures Prism Gas owns an unconsolidated 50% interest in Waskom, the Matagorda Gathering System (“Matagorda”) and Panther Interstate Pipeline Energy LLC (“PIPE”). As a result, these assets are accounted for by the equity method. In accounting for the acquisition of the interests in Waskom, Matagorda and PIPE, the carrying amount of these investments exceeded the underlying net assets by approximately $46,176. The difference was attributable to property and equipment of $11,872 and equity-method goodwill of $34,304. The excess investment relating to property and equipment is being amortized over an average life of 20 years, which approximates the useful life of the underlying assets. Such amortization amounted to $148 and $445 for the three and nine months ended September 30, 2011 and 2010, respectively, and has been recorded as a reduction of equity in earnings of unconsolidated entities. The remaining unamortized excess investment relating to property and equipment was $8,458 and $8,903 at September 30, 2011 and December 31, 2010, respectively. The equity-method goodwill is not amortized; however, it is analyzed for impairment annually or when changes in circumstance indicate that a potential impairment exists. No impairment was recognized for the nine months ended September 30, 2011 or 2010. As a partner in Waskom, the Partnership receives distributions in kind of natural gas liquids (“NGLs”) that are retained according to Waskom's contracts with certain producers. The NGLs are valued at prevailing market prices. In addition, cash distributions are received and cash contributions are made to fund operating and capital requirements of Waskom. The Partnership and Martin Resource Management formed Redbird, a natural gas storage joint venture formed to invest in Cardinal. The Partnership owns all the Class B equity interests in Redbird. Redbird owns an unconsolidated 40.08% interest in Cardinal. These assets are accounted for by the equity method. Activity related to these investment accounts for the nine months ended September 30, 2011 and 2010 is as follows:
Select financial information for significant unconsolidated equity-method investees is as follows:
As of September 30, 2011 and December 31, 2010, the amount of the Partnership's consolidated retained earnings that represents undistributed earnings related to the unconsolidated equity-method investees is $45,793 and $36,964, respectively. There are no material restrictions to transfer funds in the form of dividends, loans or advances related to the equity-method investees. As of September 30, 2011 and December 31, 2010, the Partnership's interest in cash of the unconsolidated equity-method investees was $839 and $1,145, respectively. |
Long-Term Debt and Capital Leases | 9 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Sep. 30, 2011 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Debt Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Long-Term Debt and Capital Leases | (10) Long-Term Debt and Capital Leases At September 30, 2011 and December 31, 2010, long-term debt consisted of the following:
________________________________ * Interest rate fluctuates based on the LIBOR rate plus an applicable margin set on the date of each advance. The margin above LIBOR is set every three months. Indebtedness under the credit facility bears interest at LIBOR plus an applicable margin or the base prime rate plus an applicable margin. The applicable margin for revolving loans that are LIBOR loans ranges from 2.00% to 3.25% and the applicable margin for revolving loans that are base prime rate loans ranges from 1.00% to 2.25%. The applicable margin for existing LIBOR borrowings is 2.50%. Effective October 1, 2011, the applicable margin for existing LIBOR borrowings remained at 2.50%. Effective January 1, 2012, the applicable margin for existing LIBOR borrowings will increase to 2.75%. ** Effective September 2010, the Partnership entered into an interest rate swap that swapped $40,000 of fixed rate to floating rate. The floating rate cost was the applicable three-month LIBOR rate. This interest rate swap was scheduled to mature in April 2018, but was terminated in August 2011. ** Effective September 2010, the Partnership entered into an interest rate swap that swapped $60,000 of fixed rate to floating rate. The floating rate cost was the applicable three-month LIBOR rate. This interest rate swap was scheduled to mature in April 2018, but was terminated in August 2011. *** Effective October 2008, the Partnership entered into a cash flow hedge that swapped $40,000 of floating rate to fixed rate. The fixed rate cost was 2.820% plus the Partnership's applicable LIBOR borrowing spread. Effective April 2009, the Partnership entered into two subsequent swaps to lower its effective fixed rate to 2.580% plus the Partnership's applicable LIBOR borrowing spread. These cash flow hedges were scheduled to mature in October 2010, but were terminated in March 2010. *** Effective January 2008, the Partnership entered into a cash flow hedge that swapped $25,000 of floating rate to fixed rate. The fixed rate cost was 3.400% plus the Partnership's applicable LIBOR borrowing spread. Effective April 2009, the Partnership entered into two subsequent swaps to lower its effective fixed rate to 3.050% plus the Partnership's applicable LIBOR borrowing spread. These cash flow hedges matured in January 2010. *** Effective September 2007, the Partnership entered into a cash flow hedge that swapped $25,000 of floating rate to fixed rate. The fixed rate cost was 4.605% plus the Partnership's applicable LIBOR borrowing spread. Effective March 2009, the Partnership entered into two subsequent swaps to lower its effective fixed rate to 4.305% plus the Partnership's applicable LIBOR borrowing spread. These cash flow hedges were scheduled to mature in September 2010, but were terminated in March 2010. *** Effective November 2006, the Partnership entered into an interest rate swap that swapped $30,000 of floating rate to fixed rate. The fixed rate cost was 4.765% plus the Partnership's applicable LIBOR borrowing spread. This cash flow hedge matured in March 2010. *** Effective March 2006, the Partnership entered into a cash flow hedge that swapped $75,000 of floating rate to fixed rate. The fixed rate cost was 5.25% plus the Partnership's applicable LIBOR borrowing spread. Effective February 2009, the Partnership entered into two subsequent swaps to lower its effective fixed rate to 5.10% plus the Partnership's applicable LIBOR borrowing spread. These cash flow hedges were scheduled to mature in November 2010, but were terminated in March 2010. (a) Senior Notes In March 2010, the Partnership and Martin Midstream Finance Corp. (“FinCo”), a subsidiary of the Partnership (collectively, the “Issuers”), entered into (i) a Purchase Agreement, dated as of March 23, 2010 (the “Purchase Agreement”), by and among the Issuers, certain subsidiary guarantors (the “Guarantors”) and Wells Fargo Securities, LLC, RBC Capital Markets Corporation and UBS Securities LLC, as representatives of a group of initial purchasers (collectively, the “Initial Purchasers”), (ii) an Indenture, dated as of March 26, 2010 (the “Indenture”), among the Issuers, the Guarantors and Wells Fargo Bank, National Association, as trustee (the “Trustee”) and (iii) a Registration Rights Agreement, dated as of March 26, 2010 (the “Registration Rights Agreement”), among the Issuers, the Guarantors and the Initial Purchasers, in connection with a private placement to eligible purchasers of $200,000 in aggregate principal amount of the Issuers' 8.875% senior unsecured notes due 2018 (the “Senior Notes”). The Partnership completed the aforementioned Senior Notes offering on March 26, 2010, and received proceeds of approximately $197,200, after deducting initial purchasers' discounts and the expenses of the private placement. The proceeds were primarily used to repay borrowings under the Partnership's revolving credit facility. In connection with the issuance of the Senior Notes, all “non-issuer” wholly-owned subsidiaries of the Partnership issued full, irrevocable, and unconditional guarantees of the Senior Notes. As discussed in Note 15, the Partnership does not provide separate financial statements of the Operating Partnership because the Partnership has no independent assets or operations, the guarantees are full and unconditional, and the other subsidiary of the Partnership is minor. Indenture. On March 26, 2010, the Issuers issued the Senior Notes pursuant to the Indenture in a transaction exempt from registration requirements under the Securities Act. The Senior Notes were resold to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside the United States pursuant to Regulation S under the Securities Act. Interest and Maturity. The Senior Notes will mature on April 1, 2018. The interest payment dates are April 1 and October 1. Optional Redemption. Prior to April 1, 2013, the Issuers have the option on any one or more occasions to redeem up to 35% of the aggregate principal amount of the Senior Notes issued under the Indenture at a redemption price of 108.875% of the principal amount, plus accrued and unpaid interest, if any, to the redemption date of the Senior Notes with the proceeds of certain equity offerings. Prior to April 1, 2014, the Issuers may on any one or more occasions redeem all or a part of the Senior Notes at the redemption price equal to the sum of (i) the principal amount thereof, plus (ii) a make whole premium at the redemption date, plus accrued and unpaid interest, if any, to the redemption date. On or after April 1, 2014, the Issuers may on any one or more occasions redeem all or a part of the Senior Notes at redemption prices (expressed as percentages of principal amount) equal to 104.438% for the twelve-month period beginning on April 1, 2014, 102.219% for the twelve-month period beginning on April 1, 2015 and 100.00% for the twelve-month period beginning on April 1, 2016 and at any time thereafter, plus accrued and unpaid interest, if any, to the applicable redemption date on the Senior Notes. Certain Covenants. The Indenture restricts the Partnership's ability and the ability of certain of its subsidiaries to: (i) sell assets including equity interests in its subsidiaries; (ii) pay distributions on, redeem or repurchase its units or redeem or repurchase its subordinated debt; (iii) make investments; (iv) incur or guarantee additional indebtedness or issue preferred units; (v) create or incur certain liens; (vi) enter into agreements that restrict distributions or other payments from its restricted subsidiaries to the Partnership; (vii) consolidate, merge or transfer all or substantially all of its assets; (viii) engage in transactions with affiliates; (ix) create unrestricted subsidiaries; (x) enter into sale and leaseback transactions or (xi) engage in certain business activities. These covenants are subject to a number of important exceptions and qualifications. If the Senior Notes achieve an investment grade rating from each of Moody's Investors Service, Inc. and Standard & Poor's Ratings Services and no Default (as defined in the Indenture) has occurred and is continuing, many of these covenants will terminate. Events of Default. The Indenture provides that each of the following is an Event of Default: (i) default for 30 days in the payment when due of interest on the Senior Notes; (ii) default in payment when due of the principal of, or premium, if any, on the Senior Notes; (iii) failure by the Partnership to comply with certain covenants relating to asset sales, repurchases of the Senior Notes upon a change of control and mergers or consolidations; (iv) failure by the Partnership for 180 days after notice to comply with its reporting obligations under the Securities Exchange Act of 1934; (v) failure by the Partnership for 60 days after notice to comply with any of the other agreements in the Indenture; (vi) default under any mortgage, indenture or instrument governing any indebtedness for money borrowed or guaranteed by the Partnership or any of its restricted subsidiaries, whether such indebtedness or guarantee now exists or is created after the date of the Indenture, if such default: (a) is caused by a payment default; or (b) results in the acceleration of such indebtedness prior to its stated maturity, and, in each case, the principal amount of the indebtedness, together with the principal amount of any other such indebtedness under which there has been a payment default or acceleration of maturity, aggregates $20,000 or more, subject to a cure provision; (vii) failure by the Partnership or any of its restricted subsidiaries to pay final judgments aggregating in excess of $20,000, which judgments are not paid, discharged or stayed for a period of 60 days; (viii) except as permitted by the Indenture, any subsidiary guarantee is held in any judicial proceeding to be unenforceable or invalid or ceases for any reason to be in full force or effect, or any Guarantor, or any person acting on behalf of any Guarantor, denies or disaffirms its obligations under its subsidiary guarantee and (ix) certain events of bankruptcy, insolvency or reorganization described in the Indenture with respect to the Issuers or any of the Partnership's restricted subsidiaries that is a significant subsidiary or any group of restricted subsidiaries that, taken together, would constitute a significant subsidiary of the Partnership. Upon a continuing Event of Default, the Trustee, by notice to the Issuers, or the holders of at least 25% in principal amount of the then outstanding Senior Notes, by notice to the Issuers and the Trustee, may declare the Senior Notes immediately due and payable, except that an Event of Default resulting from entry into a bankruptcy, insolvency or reorganization with respect to the Issuers, any restricted subsidiary of the Partnership that is a significant subsidiary or any group of its restricted subsidiaries that, taken together, would constitute a significant subsidiary of the Partnership, will automatically cause the Senior Notes to become due and payable. Registration Rights Agreement. Under the Registration Rights Agreement, the Issuers and the Guarantors filed with the SEC a registration statement an offer to exchange the Senior Notes for substantially identical notes that are registered under the Securities Act. The Partnership exchanged the Senior Notes for registered 8.875% senior unsecured notes due April 2018. (b) Credit Facility On November 10, 2005, the Partnership entered into a multi-bank credit facility, which has subsequently been amended including most recently on September 7, 2011, when the Partnership amended its revolving credit facility to (1) increase the maximum amount of investments made in permitted joint ventures to $50,000, and (2) increase the maximum amount of investments made in Redbird Gas Storage and Cardinal Gas Storage to $120,000. Under the amended and restated credit facility, as of September 30, 2011, the Partnership had $230,000 outstanding under the revolving credit facility. As of September 30, 2011, irrevocable letters of credit issued under the Partnership's credit facility totaled $120. As of September 30, 2011, the Partnership had $119,880 available under its revolving credit facility. The revolving credit facility is used for ongoing working capital needs and general partnership purposes, and to finance permitted investments, acquisitions and capital expenditures. During the current fiscal year, draws on the Partnership's credit facility ranged from a low of $135,000 to a high of $254,000. The Partnership's obligations under the credit facility are secured by substantially all of the Partnership's assets, including, without limitation, inventory, accounts receivable, vessels, equipment, fixed assets and the interests in its operating subsidiaries and equity method investees. The Partnership may prepay all amounts outstanding under this facility at any time without penalty. In addition, the credit facility contains various covenants, which, among other things, limit the Partnership's ability to: (i) incur indebtedness; (ii) grant certain liens; (iii) merge or consolidate unless it is the survivor; (iv) sell all or substantially all of its assets; (v) make certain acquisitions; (vi) make certain investments; (vii) make certain capital expenditures; (viii) make distributions other than from available cash; (ix) create obligations for some lease payments; (x) engage in transactions with affiliates; (xi) engage in other types of business; and (xii) incur indebtedness or grant certain liens through its joint ventures. The credit facility includes financial covenants that are tested on a quarterly basis, based on the rolling four-quarter period that ends on the last day of each fiscal quarter. The maximum permitted leverage ratio is 5.00 to 1.00. The maximum permitted senior leverage ratio (as defined in the new credit facility but generally computed as the ratio of total secured funded debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges) is 3.25 to 1.00. The minimum consolidated interest coverage ratio (as defined in the new credit facility but generally computed as the ratio of consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges to consolidated interest charges) is 2.75 to 1.00. The Partnership was in compliance with the covenants contained in the credit facility as of September 30, 2011. The credit facility also contains certain default provisions relating to Martin Resource Management. If Martin Resource Management no longer controls the Partnership's general partner, or if Ruben Martin is not the chief executive officer of the Partnership's general partner or a successor acceptable to the administrative agent and lenders providing more than 50% of the commitments under the Partnership's credit facility is not appointed, the lenders under the Partnership's credit facility may declare all amounts outstanding thereunder immediately due and payable. In addition, an event of default by Martin Resource Management under its credit facility could independently result in an event of default under the Partnership's credit facility if it is deemed to have a material adverse effect on the Partnership. Any event of default and corresponding acceleration of outstanding balances under the Partnership's credit facility could require the Partnership to refinance such indebtedness on unfavorable terms and would have a material adverse effect on the Partnership's financial condition and results of operations as well as its ability to make distributions to unitholders. The Partnership is required to make certain prepayments under the credit facility. If the Partnership receives greater than $15,000 from the incurrence of indebtedness other than under the credit facility, it must prepay indebtedness under the credit facility with all such proceeds in excess of $15,000. The Partnership must prepay revolving loans under the credit facility with the net cash proceeds from any issuance of its equity. The Partnership must also prepay indebtedness under the credit facility with the proceeds of certain asset dispositions. Other than these mandatory prepayments, the credit facility requires interest only payments on a quarterly basis until maturity. All outstanding principal and unpaid interest must be paid by April 15, 2016. The credit facility contains customary events of default, including, without limitation, payment defaults, cross-defaults to other material indebtedness, bankruptcy-related defaults, change of control defaults and litigation-related defaults. In March 2010, the Partnership terminated all of its existing interest rate swaps resulting in termination fees of $3,850. In August, 2011, the Partnership terminated all of its existing interest rate swap agreements with an aggregate notional amount of $100,000, which it had entered to hedge its exposure to changes in the fair value of Senior Notes. These interest rate swap contracts were not designated as fair value hedges and therefore, did not receive hedge accounting but were marked to market through earnings. The Partnership received $2,800 upon cancellation of these swap agreements. The Partnership paid cash interest in the amount of $2,813 and $1,519 for the three months ended September 30, 2011 and 2010, respectively and $6,662 and $12,517 for the nine months ended September 30, 2011 and 2010, respectively. Capitalized interest was $127 and $24 for the three months ended September 30, 2011 and 2010, respectively, and $373 and $79 for the nine months ended September 30, 2011 and 2010, respectively. |
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General | (1) General Martin Midstream Partners L.P. (the “Partnership”) is a publicly traded limited partnership with a diverse set of operations focused primarily in the United States Gulf Coast region. Its four primary business lines include: terminalling and storage services for petroleum products and by-products, natural gas services, sulfur and sulfur-based products processing, manufacturing, marketing and distribution, and marine transportation services for petroleum products and by-products. The Partnership's unaudited consolidated and condensed financial statements have been prepared in accordance with the requirements of Form 10-Q and United States generally accepted accounting principles for interim financial reporting. Accordingly, these financial statements have been condensed and do not include all of the information and footnotes required by generally accepted accounting principles for annual audited financial statements of the type contained in the Partnership's annual reports on Form 10-K. In the opinion of the management of the Partnership's general partner, all adjustments and elimination of significant intercompany balances necessary for a fair presentation of the Partnership's results of operations, financial position and cash flows for the periods shown have been made. All such adjustments are of a normal recurring nature. Results for such interim periods are not necessarily indicative of the results of operations for the full year. These financial statements should be read in conjunction with the Partnership's audited consolidated financial statements and notes thereto included in the Partnership's annual report on Form 10-K for the year ended December 31, 2010, filed with the Securities and Exchange Commission (the “SEC”) on March 2, 2011. (a) Use of Estimates Management has made a number of estimates and assumptions relating to the reporting of assets and liabilities and the disclosure of contingent assets and liabilities to prepare these consolidated financial statements in conformity with accounting principles generally accepted in the United States. Actual results could differ from those estimates. (b) Unit Grants In May 2011, the Partnership issued 6,250 restricted common units to non-employee directors under its long-term incentive plan from 5,750 treasury units purchased by the Partnership in the open market for $235 and 500 treasury units from forfeitures. These units vest in 25% increments beginning in January 2012 and will be fully vested in January 2015. In February 2011, the Partnership issued 9,100 restricted common units to certain Martin Resource Management employees under its long-term incentive plan from 9,100 treasury units purchased by the Partnership in the open market for $347. These units vest in 25% increments beginning in February 2012 and will be fully vested in February 2015. In August 2010, the Partnership issued 1,500 restricted common units to each of two new non-employee directors under its long-term incentive plan from 500 treasury units purchased by the Partnership in the open market for $16 and 2,500 common units from forfeited unit grants. These units vest in 25% increments beginning in January 2011 and will be fully vested in January 2014. In May 2010, the Partnership issued 1,000 restricted common units to each of its three independent, non-employee directors under its long-term incentive plan from treasury shares purchased by the Partnership in the open market for $92. These units vest in 25% increments beginning in January 2011 and will be fully vested in January 2014. The cost resulting from share-based payment transactions was $36 and $28 for the three months ended September 30, 2011 and 2010, respectively, and $131 and $66 for the nine months ended September 30, 2011 and 2010, respectively. (c) Incentive Distribution Rights The Partnership's general partner, Martin Midstream GP LLC, holds a 2% general partner interest and certain incentive distribution rights (“IDRs”) in the Partnership. IDRs are a separate class of non-voting limited partner interest that may be transferred or sold by the general partner under the terms of the partnership agreement of the Partnership (the “Partnership Agreement”), and represent the right to receive an increasing percentage of cash distributions after the minimum quarterly distribution and any cumulative arrearages on common units once certain target distribution levels have been achieved. The Partnership is required to distribute all of its available cash from operating surplus, as defined in the Partnership Agreement. The target distribution levels entitle the general partner to receive 2% of quarterly cash distributions up to $0.55 per unit, 15% of quarterly cash distributions in excess of $0.55 per unit until all unitholders have received $0.625 per unit, 25% of quarterly cash distributions in excess of $0.625 per unit until all unitholders have received $0.75 per unit and 50% of quarterly cash distributions in excess of $0.75 per unit. For the three months ended September 30, 2011 and 2010 the general partner received $1,265 and $926, respectively, in incentive distributions. For the nine months ended September 30, 2011 and 2010, the general partner received $3,635 and $2,696, respectively, in incentive distributions. (d) Net Income per Unit The Partnership follows the provisions of Financial Accounting Standards Board(“FASB”) Accounting Standards Codification Topic (“ASC”) 260-10 related to earnings per share, which addresses the application of the two-class method in determining income per unit for master limited partnerships having multiple classes of securities that may participate in partnership distributions accounted for as equity distributions. To the extent the Partnership Agreement does not explicitly limit distributions to the general partner, any earnings in excess of distributions are to be allocated to the general partner and limited partners utilizing the distribution formula for available cash specified in the Partnership Agreement. When current period distributions are in excess of earnings, the excess distributions for the period are to be allocated to the general partner and limited partners based on their respective sharing of losses specified in the Partnership Agreement. The provisions of ASC 260-10 did not impact the Partnership's computation of earnings per limited partner unit as cash distributions exceeded earnings for the three and nine months ended September 30, 2011 and 2010, respectively, and the IDRs do not share in losses under the Partnership Agreement. In the event the Partnership's earnings exceed cash distributions, ASC 260-10 will have an impact on the computation of the Partnership's earnings per limited partner unit. For the three months and nine months ended September 30, 2011 and 2010, the general partner's interest in net income, including the IDRs, represents distributions declared after period-end on behalf of the general partner interest and IDRs less the allocated excess of distributions over earnings for the periods. For purposes of computing diluted net income per unit, the Partnership uses the more dilutive of the two-class and if-converted methods. Under the if-converted method, the beneficial conversion feature is added back to net income available to common limited partners, the weighted-average number of subordinated units outstanding for the period is added to the weighted-average number of common units outstanding for purposes of computing basic net income per unit and the resulting amount is compared to the diluted net income per unit computed using the two-class method. The following table reconciles net income to limited partners' interest in net income:
The weighted average units outstanding for basic net income per unit were 19,158,334 and 19,161,403 for the three months and nine months ended September 30, 2011, respectively, and 17,700,875 and 17,466,200 for the three months and nine months ended September 30, 2010, respectively. For diluted net income per unit, the weighted average units outstanding were increased by 4,794 and 1,663 for the three and nine months ended September 30, 2011, respectively, and 844 and 1,314 for the three and nine months ended September 30, 2010, respectively, due to the dilutive effect of restricted units granted under the Partnership's long-term incentive plan. (e) Goodwill and Other Intangible Assets. The Partnership has historically performed its annual impairment testing of goodwill and indefinite-lived intangible assets as of September 30 of each year. During the third quarter of fiscal 2011, the Partnership changed the annual impairment testing date from September 30 to August 31. The Partnership believes this change, which represents a change in the method of applying an accounting principle, is preferable in the circumstances as the earlier date provides additional time prior to the Partnership's quarter-end to complete the goodwill impairment testing and report the results in its quarterly report on Form 10-Q. A preferability letter from the Partnership's independent registered public accounting firm regarding this change in the method of applying an accounting principle has been filed as an exhibit to this quarterly report on Form 10-Q for the quarter ended September 30, 2011. (f) Income Taxes With respect to the Partnership's taxable subsidiary, Woodlawn Pipeline Co., Inc. (“Woodlawn”), income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. |
Fair Value Measurements | 9 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Fair Value Measurements [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair Value Measurements | (7) Fair Value Measurements The Partnership provides disclosures pursuant to certain provisions of ASC 820, which provides a framework for measuring fair value and expanded disclosures about fair value measurements. ASC 820 applies to all assets and liabilities that are being measured and reported on a fair value basis. This statement enables the reader of the financial statements to assess the inputs used to develop those measurements by establishing a hierarchy for ranking the quality and reliability of the information used to determine fair values. ASC 820 establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value of each asset and liability carried at fair value into one of the following categories: Level 1: Quoted market prices in active markets for identical assets or liabilities. Level 2: Observable market based inputs or unobservable inputs that are corroborated by market data. Level 3: Unobservable inputs that are not corroborated by market data. The Partnership's derivative instruments, which consist of commodity and interest rate swaps, are required to be measured at fair value on a recurring basis. The fair value of the Partnership's derivative instruments is determined based on inputs that are readily available in public markets or can be derived from information available in publicly quoted markets, which is considered Level 2. Refer to Note 6 for further information on the Partnership's derivative instruments and hedging activities. The following items are measured at fair value on a recurring basis subject to the disclosure requirements of ASC 820 at September 30, 2011:
The following items are measured at fair value on a recurring basis subject to the disclosure requirements of ASC 820 at December 31, 2010:
ASC 825-10-65, related to disclosures about fair value of financial instruments, requires that the Partnership disclose estimated fair values for its financial instruments. Fair value estimates are set forth below for the Partnership's financial instruments. The following methods and assumptions were used to estimate the fair value of each class of financial instrument:
The estimated fair value of the Senior Notes was approximately $210,468 and $216,366 based on market prices of similar debt at September 30, 2011 and December 31, 2010, respectively. |
Stanolind Tank Damage | 9 Months Ended |
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Sep. 30, 2011 | |
Stanolid Tank Damage [Abstract] | |
Stanolind Tank Damage | (12) Stanolind Tank Damage During the third quarter of 2011, a single tank fire occurred at the Partnership's Stanolind Terminal in Beaumont, Texas. This specific tank stores No. 6 oil for Martin Resource Management under a through-put agreement. The tank contained approximately 3,200 barrels of No. 6 oil at the time the incident occurred, all of which is the property of Martin Resource Management. Physical damage to the Partnership's asset caused by the fire as well as the related removal and recovery costs, are fully covered by the Partnership's non-windstorm insurance policy subject to a deductible of $443 which has been expensed and included in “operating expenses” in the consolidated and condensed statements of income for the three month and nine month periods ended September 30, 2011. Insurance proceeds received as a result of the this claim will be used to replace the tank and, in the event the proceeds exceed the net book value of the tank that was destroyed, the Partnership will recognize a gain equal to the amount of the excess. The actual fire damage costs incurred for the three month and nine month periods ended September 30, 2011 was $234. |
Related Party Transactions | 9 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Related Party Transactions [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Related Party Transactions | (8) Related Party Transactions As of September 30, 2011, Martin Resource Management owns 5,703,823 of the Partnership's common units and 889,444 subordinated units collectively representing approximately 32.2% of the Partnership's outstanding limited partnership units. The Partnership's general partner is a wholly-owned subsidiary of Martin Resource Management. The Partnership's general partner owns a 2.0% general partner interest in the Partnership and the Partnership's incentive distribution rights. The Partnership's general partner's ability, as general partner, to manage and operate the Partnership, and Martin Resource Management's ownership as of September 30, 2011, of approximately 32.2% of the Partnership's outstanding limited partnership units, effectively gives Martin Resource Management the ability to veto some of the Partnership's actions and to control the Partnership's management. The following is a description of the Partnership's material related party transactions: Omnibus Agreement Omnibus Agreement. The Partnership and its general partner are parties to an omnibus agreement dated November 1, 2002, with Martin Resource Management that governs, among other things, potential competition and indemnification obligations among the parties to the agreement, related party transactions, the provision of general administration and support services by Martin Resource Management and the Partnership's use of certain of Martin Resource Management's trade names and trademarks. The omnibus agreement was amended on November 24, 2009, to include processing crude oil into finished products including naphthenic lubricants, distillates, asphalt and other intermediate cuts. Non-Competition Provisions. Martin Resource Management has agreed for so long as it controls the general partner of the Partnership, not to engage in the business of:
This restriction does not apply to:
Services. Under the omnibus agreement, Martin Resource Management provides the Partnership with corporate staff, support services, and administrative services necessary to operate the Partnership's business. The omnibus agreement requires the Partnership to reimburse Martin Resource Management for all direct expenses it incurs or payments it makes on the Partnership's behalf or in connection with the operation of the Partnership's business. There is no monetary limitation on the amount the Partnership is required to reimburse Martin Resource Management for direct expenses. In addition to the direct expenses, Martin Resource Management is entitled to reimbursement for a portion of indirect general and administrative and corporate overhead expenses. Under the omnibus agreement, the Partnership is required to reimburse Martin Resource Management for indirect general and administrative and corporate overhead expenses. Effective October 1, 2010, through September 30, 2011, the Conflicts Committee of the board of directors of the general partner of the Partnership (the “Conflicts Committee”) approved an annual reimbursement amount for indirect expenses of $4,168. The Partnership reimbursed Martin Resource Management for $1,042 and $916 of indirect expenses for the three months ended September 30, 2011 and 2010, respectively. The Partnership reimbursed Martin Resource Management for $3,126 and $2,748 of indirect expenses for the nine months ended September 30, 2011 and 2010, respectively. The Conflicts Committee will review and approve future adjustments in the reimbursement amount for indirect expenses, if any, annually. These indirect expenses are intended to cover the centralized corporate functions Martin Resource Management provides for the Partnership, such as accounting, treasury, clerical billing, information technology, administration of insurance, general office expenses and employee benefit plans and other general corporate overhead functions the Partnership shares with Martin Resource Management retained businesses. The provisions of the omnibus agreement regarding Martin Resource Management's services will terminate if Martin Resource Management ceases to control the general partner of the Partnership. Related Party Transactions. The omnibus agreement prohibits the Partnership from entering into any material agreement with Martin Resource Management without the prior approval of the conflicts committee of the general partner's board of directors. For purposes of the omnibus agreement, the term material agreements means any agreement between the Partnership and Martin Resource Management that requires aggregate annual payments in excess of then-applicable agreed upon reimbursable amount of indirect general and administrative expenses. Please read “Services” above. License Provisions. Under the omnibus agreement, Martin Resource Management has granted the Partnership a nontransferable, nonexclusive, royalty-free right and license to use certain of its trade names and marks, as well as the trade names and marks used by some of its affiliates. Amendment and Termination. The omnibus agreement may be amended by written agreement of the parties; provided, however, that it may not be amended without the approval of the conflicts committee of the Partnership's general partner if such amendment would adversely affect the unitholders. The omnibus agreement was amended on November 24, 2009, to permit the Partnership to provide refining services to Martin Resource Management. Such amendment was approved by the conflicts committee of the Partnership's general partner. The omnibus agreement, other than the indemnification provisions and the provisions limiting the amount for which the Partnership will reimburse Martin Resource Management for general and administrative services performed on behalf, will terminate if the Partnership is no longer an affiliate of Martin Resource Management. Motor Carrier Agreement Motor Carrier Agreement. The Partnership is a party to a motor carrier agreement effective January 1, 2006, with Martin Transport, Inc., a wholly owned subsidiary of Martin Resource Management through which Martin Resource Management operates its land transportation operations. This agreement replaced a prior agreement effective November 1, 2002, between the Partnership and Martin Transport, Inc. for land transportation services. Under the agreement, Martin Transport Inc. agreed to ship our NGL shipments as well as other liquid products. Term and Pricing. This agreement was amended in November 2006, January 2007, April 2007 and January 2008 to add additional point-to-point rates and to modify certain fuel and insurance surcharges being charged to the Partnership. The agreement has an initial term that expired in December 2007 but automatically renews for consecutive one-year periods unless either party terminates the agreement by giving written notice to the other party at least 30 days prior to the expiration of the then-applicable term. The Partnership has the right to terminate this agreement at any time by providing 90 days prior notice. Under this agreement, Martin Transport, Inc. transports the Partnership's NGL shipments as well as other liquid products. These rates are subject to any adjustment to which are mutually agreed or in accordance with a price index. Additionally, during the term of the agreement, shipping charges are also subject to fuel surcharges determined on a weekly basis in accordance with the U.S. Department of Energy's national diesel price list. Marine Agreements Marine Transportation Agreement. The Partnership is a party to a marine transportation agreement effective January 1, 2006, which was amended January 1, 2007, under which the Partnership provides marine transportation services to Martin Resource Management on a spot-contract basis at applicable market rates. This agreement replaced a prior agreement effective November 1, 2002 between the Partnership and Martin Resource Management covering marine transportation services which expired November 2005. Effective each January 1, this agreement automatically renews for consecutive one-year periods unless either party terminates the agreement by giving written notice to the other party at least 60 days prior to the expiration of the then applicable term. The fees the Partnership charges Martin Resource Management are based on applicable market rates. Cross Marine Charter Agreements. Cross entered into four marine charter agreements with the Partnership effective March 1, 2007. These agreements have an initial term of five years and continue indefinitely thereafter subject to cancellation after the initial term by either party upon a 30 day written notice of cancellation. The charter hire payable under these agreements will be adjusted annually to reflect the percentage change in the Consumer Price Index. Marine Fuel. The Partnership is a party to an agreement with Martin Resource Management under which Martin Resource Management provides the Partnership with marine fuel from its locations in the Gulf of Mexico at a fixed rate over the Platt's U.S. Gulf Coast Index for #2 Fuel Oil. Under this agreement, the Partnership agreed to purchase all of its marine fuel requirements that occur in the areas serviced by Martin Resource Management. Terminal Services Agreements Diesel Fuel Terminal Services Agreement. The Partnership is a party to an agreement under which the Partnership provides terminal services to Martin Resource Management. This agreement was amended and restated as of October 27, 2004, and was set to expire in December 2006, but automatically renewed and will continue to automatically renew on a month-to-month basis until either party terminates the agreement by giving 60 days written notice. The per gallon throughput fee the Partnership charges under this agreement may be adjusted annually based on a price index. Miscellaneous Terminal Services Agreements. The Partnership is currently party to several terminal services agreements and from time to time the Partnership may enter into other terminal service agreements for the purpose of providing terminal services to related parties. Individually, each of these agreements is immaterial but when considered in the aggregate they could be deemed material. These agreements are throughput based with a minimum volume commitment. Generally, the fees due under these agreements are adjusted annually based on a price index. Other Agreements Cross Tolling Agreement. The Partnership is a party to an agreement under which it processes crude oil into finished products, including naphthenic lubricants, distillates, asphalt and other intermediate cuts for Cross. The Tolling Agreement has a 12 year term which expires November 24, 2021. Under this Tolling Agreement, Martin Resource Management agreed to process a minimum of 6,500 barrels per day of crude oil at the facility at a fixed price per barrel. Any additional barrels are processed at a modified price per barrel. In addition, Martin Resource Management agreed to pay a monthly reservation fee and a periodic fuel surcharge fee based on certain parameters specified in the Tolling Agreement. All of these fees (other than the fuel surcharge) are subject to escalation annually based upon the greater of 3% or the increase in the Consumer Price Index for a specified annual period. In addition, every three years, the parties can negotiate an upward or downward adjustment in the fees subject to their mutual agreement. Sulfuric Acid Sales Agency Agreement. The Partnership is party to an agreement under which Martin Resource Management purchases and markets the sulfuric acid produced by the Partnership's sulfuric acid production plant at Plainview, Texas, and which is not consumed by the Partnership's internal operations. This agreement, which was amended and restated in July 2011, will remain in place until the Partnership terminates it by providing 180 days' written notice. Under this agreement, the Partnership sells all of its excess sulfuric acid to Martin Resource Management. Martin Resource Management then markets such acid to third-parties and the Partnership shares in the profit of Martin Resource Management's sales of the excess acid to such third parties. Other Miscellaneous Agreements. From time to time the Partnership enters into other miscellaneous agreements with Martin Resource Management for the provision of other services or the purchase of other goods. The tables below summarize the related party transactions that are included in the related financial statement captions on the face of the Partnership's Consolidated Statements of Operations. The revenues, costs and expenses reflected in these tables are tabulations of the related party transactions that are recorded in the corresponding caption of the consolidated financial statement and do not reflect a statement of profits and losses for related party transactions. The impact of related party revenues from sales of products and services is reflected in the consolidated financial statement as follows:
The impact of related party cost of products sold is reflected in the consolidated financial statement as follows:
The impact of related party operating expenses is reflected in the consolidated financial statement as follows:
The impact of related party selling, general and administrative expenses is reflected in the consolidated financial statement as follows:
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Derivative Instruments and Hedging Activities | 9 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Derivative Instruments and Hedging Activities [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Derivative Instruments and Hedging Activities | (6) Derivative Instruments and Hedging Activities The Partnership's results of operations are materially impacted by changes in crude oil, natural gas and NGL prices and interest rates. In an effort to manage its exposure to these risks, the Partnership periodically enters into various derivative instruments, including commodity and interest rate hedges. The Partnership is required to recognize all derivative instruments as either assets or liabilities at fair value on the Partnership's Consolidated Balance Sheets and to recognize certain changes in the fair value of derivative instruments on the Partnership's Consolidated Statements of Operations. The Partnership performs, at least quarterly, a retrospective assessment of the effectiveness of its hedge contracts, including assessing the possibility of counterparty default. If the Partnership determines that a derivative is no longer expected to be highly effective, the Partnership discontinues hedge accounting prospectively and recognizes subsequent changes in the fair value of the hedge in earnings. As a result of its effectiveness assessment at September 30, 2011, the Partnership believes certain hedge contracts will continue to be effective in offsetting changes in cash flow or fair value attributable to the hedged risk. All derivatives and hedging instruments are included on the balance sheet as an asset or a liability measured at fair value and changes in fair value are recognized currently in earnings unless specific hedge accounting criteria are met. If a derivative qualifies for hedge accounting, changes in the fair value can be offset against the change in the fair value of the hedged item through earnings or recognized in accumulated other comprehensive income (“AOCI”) until such time as the hedged item is recognized in earnings. The Partnership is exposed to the risk that periodic changes in the fair value of derivatives qualifying for hedge accounting will not be effective, as defined, or that derivatives will no longer qualify for hedge accounting. To the extent that the periodic changes in the fair value of the derivatives are not effective, that ineffectiveness is recorded to earnings. Likewise, if a hedge ceases to qualify for hedge accounting, any change in the fair value of derivative instruments since the last period is recorded to earnings; however, any amounts previously recorded to AOCI would remain there until such time as the original forecasted transaction occurs, then would be reclassified to earnings or if it is determined that continued reporting of losses in AOCI would lead to recognizing a net loss on the combination of the hedging instrument and the hedge transaction in future periods, then the losses would be immediately reclassified to earnings. For derivative instruments that are designated and qualify as cash flow hedges, the effective portion of the gain or loss on the derivative is reported as a component of AOCI and reclassified into earnings in the same period during which the hedged transaction affects earnings. The effective portion of the derivative represents the change in fair value of the hedge that offsets the change in fair value of the hedged item. To the extent the change in the fair value of the hedge does not perfectly offset the change in the fair value of the hedged item; the ineffective portion of the hedge is immediately recognized in earnings. (a) Commodity Derivative Instruments The Partnership is exposed to market risks associated with commodity prices and uses derivatives to manage the risk of commodity price fluctuation. The Partnership has established a hedging policy and monitors and manages the commodity market risk associated with its commodity risk exposure. The Partnership has entered into hedging transactions through 2012 to protect a portion of its commodity exposure. These hedging arrangements are in the form of swaps for crude oil, natural gas and natural gasoline. In addition, the Partnership is focused on utilizing counterparties for these transactions whose financial condition is appropriate for the credit risk involved in each specific transaction. Due to the volatility in commodity markets, the Partnership is unable to predict the amount of ineffectiveness each period, including the loss of hedge accounting, which is determined on a derivative by derivative basis. This may result, and has resulted, in increased volatility in the Partnership's financial results. Factors that have and may continue to lead to ineffectiveness and unrealized gains and losses on derivative contracts include: a substantial fluctuation in energy prices, the number of derivatives the Partnership holds and significant weather events that have affected energy production. The number of instances in which the Partnership has discontinued hedge accounting for specific hedges is primarily due to those reasons. However, even though these derivatives may not qualify for hedge accounting, the Partnership continues to hold the instruments as it believes they continue to afford the Partnership opportunities to manage commodity risk exposure. As of September 30, 2011 and 2010, the Partnership has both derivative instruments qualifying for hedge accounting with fair value changes being recorded in AOCI as a component of partners' capital and derivative instruments not designated as hedges being marked to market with all market value adjustments being recorded in earnings. Set forth below is the summarized notional amount and terms of all instruments held for price risk management purposes at September 30, 2011 (all gas quantities are expressed in British Thermal Units, crude oil and natural gas liquids are expressed in barrels). As of September 30, 2011, the remaining term of the contracts extend no later than December 2012, with no single contract longer than one year. For the three months and nine months ended September 30, 2011 and 2010, changes in the fair value of the Partnership's derivative contracts were recorded in both earnings and in AOCI as a component of partners' capital.
Based on estimated volumes, as of September 30, 2011, the Partnership had hedged approximately 49% and 36% of its commodity risk by volume for 2011 and 2012, respectively. The Partnership anticipates entering into additional commodity derivatives on an ongoing basis to manage its risks associated with these market fluctuations and will consider using various commodity derivatives, including forward contracts, swaps, collars, futures and options, although there is no assurance that the Partnership will be able to do so or that the terms thereof will be similar to the Partnership's existing hedging arrangements. The Partnership's credit exposure related to commodity cash flow hedges is represented by the positive fair value of contracts to the Partnership at September 30, 2011. These outstanding contracts expose the Partnership to credit loss in the event of nonperformance by the counterparties to the agreements. The Partnership has incurred no losses associated with counterparty nonperformance on derivative contracts. On all transactions where the Partnership is exposed to a counterparty risk, the Partnership analyzes the counterparty's financial condition prior to entering into an agreement, has established a maximum credit limit threshold pursuant to its hedging policy, and monitors the appropriateness of these limits on an ongoing basis. The Partnership has agreements with four counterparties containing collateral provisions. Based on those current agreements, cash deposits are required to be posted whenever the net fair value of derivatives associated with the individual counterparty exceed a specific threshold. If this threshold is exceeded, cash is posted by the Partnership if the value of derivatives is a liability to the Partnership. As of September 30, 2011, the Partnership has no cash collateral deposits posted with counterparties. The Partnership's principal customers with respect to Prism Gas' natural gas gathering and processing are large, natural gas marketing services, oil and gas producers and industrial end-users. In addition, substantially all of the Partnership's natural gas and NGL sales are made at market-based prices. The Partnership's standard gas and NGL sales contracts contain adequate assurance provisions which allows for the suspension of deliveries, cancellation of agreements or discontinuance of deliveries to the buyer unless the buyer provides security for payment in a form satisfactory to the Partnership. (b) Impact of Commodity Cash Flow Hedges Crude Oil. For the three months ended September 30, 2011 and 2010, net gains on swap hedge contracts increased crude revenue by $361 and $17, respectively. For the nine months ended September 30, 2011 and 2010, net gains on swap hedge contracts increased crude revenue by $658 and $270, respectively. As of September 30, 2011 an unrealized derivative fair value gain of $428, related to current and terminated cash flow hedges of crude oil price risk, was recorded in AOCI. Fair value gains of $247 and $181 are expected to be reclassified into earnings in 2011 and 2012, respectively. The actual reclassification to earnings for contracts remaining in effect will be based on mark-to-market prices at the contract settlement date or for those terminated contracts based on the recorded values at September 30, 2011, adjusted for any impairment, along with the realization of the gain or loss on the related physical volume, which is not reflected above. Natural Gas. For the three months ended September 30, 2011 and 2010, net gains on swap hedge contracts increased gas revenue by $72 and $152, respectively. For the nine months ended September 30, 2011 and 2010, net gains on swap hedge contracts increased gas revenue $215 and $409, respectively. As of September 30, 2011 an unrealized derivative fair value gain of $359 related to cash flow hedges of natural gas was recorded in AOCI. Fair value gains of $100 and $259 are expected to be reclassified into earnings in 2011 and 2012, respectively. The actual reclassification to earnings will be based on mark-to-market prices at the contract settlement date, along with the realization of the gain or loss on the related physical volume, which is not reflected above. Natural Gas Liquids. For the three months ended September 30, 2011 and 2010, net gains on swap hedge contracts increased natural gas liquids revenue by $236 and $41, respectively. For the nine months ended September 30, 2011 and 2010, net gains and losses on swap hedge contracts increased natural gas liquids revenue $458 and $230, respectively. As of September 30, 2011 an unrealized derivative fair value gain of $590 related to cash flow hedges of natural gas was recorded in AOCI. Fair value gains of $329 and $260 are expected to be reclassified into earnings in 2011 and 2012, respectively. The actual reclassification to earnings will be based on mark-to-market prices at the contract settlement date, along with the realization of the gain or loss on the related physical volume, which is not reflected above. For information regarding fair value amounts and gains and losses on commodity derivative instruments and related hedged items, see “Tabular Presentation of Fair Value Amounts, and Gains and Losses on Derivative Instruments and Related Hedged Items” within this Note. (c) Impact of Interest Rate Derivative Instruments The Partnership is exposed to market risks associated with interest rates. The Partnership enters into interest rate swaps to manage interest rate risk associated with the Partnership's variable rate debt and term loan credit facilities. All derivatives and hedging instruments are included on the balance sheet as an asset or a liability measured at fair value and changes in fair value are recognized currently in earnings unless specific hedge accounting criteria are met. If a derivative qualifies for hedge accounting, changes in the fair value can be offset against the change in the fair value of the hedged item through earnings or recognized in AOCI until such time as the hedged item is recognized in earnings. In August 2011, the Partnership terminated all of its existing interest swap agreements with an aggregate notional amount of $100,000, which it had entered to hedge its exposure to changes in the fair value of Senior Notes as described in Note 10. These interest rate swap contracts were not designated as fair value hedges and therefore, did not receive hedge accounting but were marked to market through earnings. Termination fees of $2,800 were received on the early extinguishment of the interest rate swap agreements in August 2011. In March 2010, in connection with a pay down of the Partnership's revolving credit facility, the Partnership terminated all of its existing cash flow hedge agreements with an aggregate notional amount of $140,000, which it had entered to hedge its exposure to increases in the benchmark interest rate underlying its variable rate revolving and term loan credit facilities. Termination fees of $3,850 were paid on the early extinguishment of all interest rate swap agreements in March 2010. The amounts remaining in AOCI were reclassified into interest expense over the original term of the terminated interest rate derivatives. The Partnership recognized decreases in interest expense of $3,244 and $5,779 for the three and nine months ended September 30, 2011, respectively, related to the difference between the fixed rate and the floating rate of interest on the interest rate swap and net cash settlement of interest rate swaps and hedges. The Partnership recognized increases (decreases) in interest expense of $(957) and $2,567 for the three and nine months ended September 30, 2010, respectively, related to the difference between the fixed rate and the floating rate of interest on the interest rate swap and net cash settlement of interest rate swaps and hedges. For information regarding fair value amounts and gains and losses on interest rate derivative instruments and related hedged items, see “Tabular Presentation of Fair Value Amounts, and Gains and Losses on Derivative Instruments and Related Hedged Items” below.
The following table summarizes the fair values and classification of the Partnership's derivative instruments in its Consolidated Balance Sheet:
Amounts expected to be reclassified into earnings for the subsequent twelve-month period are gains of $1,238 for commodity cash flow hedges. |
CONSOLIDATED AND CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (USD $) In Thousands | 3 Months Ended | 9 Months Ended | ||
---|---|---|---|---|
Sep. 30, 2011 | Sep. 30, 2010 | Sep. 30, 2011 | Sep. 30, 2010 | |
CONSOLIDATED AND CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) [Abstract] | ||||
Net income | $ 5,399 | $ 4,636 | $ 21,491 | $ 9,482 |
Changes in fair values of commodity cash flow hedges | 1,295 | 71 | 1,231 | 816 |
Commodity cash flow hedging gains (losses) reclassified to earnings | (538) | (223) | (1,291) | (609) |
Changes in fair value of interest rate cash flow hedges | 0 | 0 | 0 | (241) |
Interest rate cash flow hedging losses reclassified to earnings | 0 | 606 | 18 | 3,940 |
Comprehensive income | $ 6,156 | $ 5,090 | $ 21,449 | $ 13,388 |
New Accounting Pronouncements | 9 Months Ended |
---|---|
Sep. 30, 2011 | |
New Accounting Pronouncements [Abstract] | |
New Accounting Pronouncements | (2) New Accounting Pronouncements In September 2011, the FASB amended the provisions of ASC 350 related to testing goodwill for impairment. This update simplifies the goodwill impairment assessment by allowing a company to first review qualitative factors to determine the likelihood of whether the fair value of a reporting unit is less than its carrying amount before applying the two-step goodwill impairment test. If it is determined that it is more likely than not that the fair value of a reporting unit is greater than its carrying amount, the company would not be required to perform the two-step goodwill impairment test for that reporting unit. This update is effective for interim and annual goodwill impairment tests performed for fiscal years beginning after December 15, 2011 with early adoption permitted which for the Partnership means January 1, 2012. This amended guidance will be adopted by the Partnership effective January 1, 2012. In June 2011, the FASB amended the provisions of ASC 220 related to other comprehensive income. This newly issued guidance (1) eliminates the option to present the components of other comprehensive income as part of the statement of changes in stockholders' equity; (2) requires the consecutive presentation of the statement of net income and other comprehensive income; and (3) requires an entity to present reclassification adjustments on the face of the financial statements from other comprehensive income to net income. The amendments in this guidance do not change the items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income nor do the amendments affect how earnings per share is calculated or presented. This guidance is required to be applied retrospectively and is effective for fiscal years and interim periods within those years beginning after December 15, 2011, which for the Partnership means January 1, 2012. As this new guidance only requires enhanced disclosure, adoption will not impact the Partnership's financial position or results of operations. |
Acquisitions | 9 Months Ended | |||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Sep. 30, 2011 | ||||||||||||||||
Acquisitions [Abstract] | ||||||||||||||||
Acquisitions | (3) Acquisitions Redbird Gas Storage On May 31, 2011, the Partnership acquired all of the Class B equity interests in Redbird Gas Storage LLC (“Redbird”) for approximately $59,319. This amount was recorded as an investment in an unconsolidated entity. Redbird, a subsidiary of Martin Resource Management, is a natural gas storage joint venture formed to invest in Cardinal Gas Storage Partners LLC (“Cardinal”). Cardinal is a joint venture between Redbird and Energy Capital Partners that is focused on the development, construction, operation and management of natural gas storage facilities across North America. Redbird owns an unconsolidated 40.08% interest in Cardinal. Concurrent with the closing of this transaction, Cardinal acquired all of the outstanding equity interests in Monroe Gas Storage Company, LLC (“Monroe”) as well as an option on development rights to an adjacent depleted reservoir facility. This acquisition was funded by borrowings under the Partnership's revolving loan facility. In August 2011, the board of directors of the general partner of the Partnership approved aggregate investments not to exceed $8,500 in the Class A equity interests of Redbird through December 31, 2011. Redbird will utilize the investments by the Partnership to invest in Cardinal to fund projects for natural gas storage facilities other than Monroe. In 2012, the Partnership will have additional opportunities to invest in the Class A equity interests of Redbird which will be evaluated on a case by case basis to determine whether or not to undertake such additional investments. Terminalling Facilities On January 31, 2011, the Partnership acquired 13 shore-based marine terminalling facilities, one specialty terminalling facility and certain terminalling related assets from Martin Resource Management for $36,500. These assets are located across the Louisiana Gulf Coast. This acquisition was funded by borrowings under the Partnership's revolving loan facility. These terminalling assets were acquired by Martin Resource Management in its acquisition of L&L Holdings LLC (“L&L”) on January 31, 2011. During the second quarter, Martin Resource Management finalized the purchase price allocation for the acquisition of L&L, including the final determination of the fair value of the terminalling assets acquired by the Partnership. The Partnership recorded an adjustment in the amount of $19,685 to reduce property, plant and equipment and partners' capital for the difference between the purchase price and the fair value of the terminalling assets acquired based on Martin Resource Management's final purchase price allocation. The impact on first quarter depreciation expense as a result of the finalization of the purchase price allocation is accounted for retrospectively and was a reduction of $241. On August 26, 2010, the Partnership acquired certain shore-based marine terminalling assets from Martin Resource Management for $11,700. The net book value of the acquired assets was $7,331 and was recorded in property, plant and equipment. The remaining $4,369 was recorded as a distribution to Martin Resource Management. These assets are located in Theodore, Alabama and Pascagoula, Mississippi. Marine Equipment On December 22, 2010, the Partnership acquired a 60,000 bbl. offshore tank barge from Martin Resource Management for a total purchase price of $17,000. The Partnership paid cash in the amount of $9,600 and assumed a note payable to a third party for $7,400. The net book value of the acquired assets was $16,805 and was recorded in property, plant, and equipment. The remaining $195 was recorded as a distribution to Martin Resource Management. Darco Gathering System On November 1, 2010, the Partnership, through its wholly owned subsidiary, Prism Gas, acquired approximately 20 miles of natural gas gathering pipeline and various equipment located in Harrison County, Texas. The final purchase price of approximately $25,015 was funded by borrowings under the Partnership's credit agreement. The purchase price including other intangibles reflected as other assets was allocated as follows:
The identifiable intangible asset of $15,090 is a life of lease contract with an active producer in the Haynesville Shale and Cotton Valley sand. The contract is subject to amortization over an approximate useful life of twenty years. Harrison Gathering System On January 15, 2010, the Partnership, through Prism Gas Systems I, L.P. (“Prism Gas”), as 50% owner and the operator of Waskom Gas Processing Company (“Waskom”), through Waskom's wholly-owned subsidiary Waskom Midstream LLC, acquired from Crosstex North Texas Gathering, L.P., a 100% interest in approximately 62 miles of gathering pipeline, two 35 MMcfd dew point control plants and equipment referred to as the Harrison Gathering System. The Partnership's share of the acquisition cost was approximately $20,000 and was recorded as an investment in an unconsolidated entity. |
Equity Offerings | 9 Months Ended |
---|---|
Sep. 30, 2011 | |
Equity Offering [Abstract] | |
Equity Offering | (11) Equity Offering On February 9, 2011, the Partnership completed a public offering of 1,874,500 common units at a price of $39.35 per common unit, before the payment of underwriters' discounts, commissions and offering expenses (per unit value is in dollars, not thousands). Total proceeds from the sale of the 1,874,500 common units, net of underwriters' discounts, commissions and offering expenses were $70,330. The Partnership's general partner contributed $1,505 in cash to the Partnership in conjunction with the issuance in order to maintain its 2% general partner interest in the Partnership. On February 9, 2011, the Partnership made a $65,500 payment to reduce the outstanding balance under its revolving credit facility. On August 17, 2010, the Partnership completed a public offering of 1,000,000 common units, representing limited partner interests at a purchase price of $29.13 per common unit. The Partnership received net proceeds of approximately $28,070 after payment of underwriters' discounts. The Partnership used the net proceeds of $28,070 to redeem from subsidiaries of Martin Resource Management an aggregate number of common units equal to the number of common units issued in the offering. Martin Resource Management reimbursed the Partnership for its payments of commissions and offering expenses. As a result of these simultaneous transactions, the Partnership's general partner was not required to contribute cash to the Partnership in conjunction with the issuance of these units in order to maintain its 2% general partner interest in the Partnership since there was no net increase in the outstanding limited partner units. On February 8, 2010, the Partnership completed a public offering of 1,650,000 common units at a price of $32.35 per common unit, before the payment of underwriters' discounts, commissions and offering expenses (per unit value is in dollars, not thousands). The common units sold in the offering were registered under the Securities Act pursuant to the Partnership's existing shelf registration statement. Following this offering, the common units represented a 93.3% limited partnership interest in the Partnership. Total proceeds from the sale of the 1,650,000 common units, net of underwriters' discounts, commissions and offering expenses were $50,530. The Partnership's general partner contributed $1,089 in cash to the Partnership in conjunction with the issuance in order to maintain its 2% general partner interest in the Partnership. On February 8, 2010, the Partnership made a $45,000 payment to reduce the outstanding balance under its revolving credit facility. |
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