10-Q
 
 UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549 
_______________________________________________________ 

FORM 10-Q
ý
 
QUARTERLY REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
 For the quarterly period ended September 30, 2015

OR
o
 
TRANSITION REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
 For the transition period from ____________ to ____________
 
Commission File Number
000-50056
MARTIN MIDSTREAM PARTNERS L.P.
(Exact name of registrant as specified in its charter)
Delaware
 
05-0527861
(State or other jurisdiction of incorporation or organization)
 
(IRS Employer Identification No.)
4200 Stone Road
Kilgore, Texas 75662
(Address of principal executive offices, zip code)

Registrant’s telephone number, including area code: (903) 983-6200

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. 
Yes  x
 
No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). 
Yes x
 
No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
 Large accelerated filer                   x
Accelerated filer  o
Non-accelerated filer   o (Do not check if a smaller reporting company)
Smaller reporting company  o

Indicated by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). 
Yes o
 
No x
 
The number of the registrant’s Common Units outstanding at October 28, 2015, was 35,456,612.
 


 
Page
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

1


PART I – FINANCIAL INFORMATION
Item 1.
Financial Statements
MARTIN MIDSTREAM PARTNERS L.P.
CONSOLIDATED AND CONDENSED BALANCE SHEETS
(Unaudited)
(Dollars in thousands)
 
September 30, 2015
 
December 31, 2014
Assets
 
 
 
Cash
$
13

 
$
42

Accounts and other receivables, less allowance for doubtful accounts of $488 and $1,620, respectively
63,881

 
134,173

Product exchange receivables
2,137

 
3,046

Inventories
91,803

 
88,718

Due from affiliates
11,164

 
14,512

Other current assets
6,344

 
6,772

Assets held for sale
—

 
40,488

Total current assets
175,342

 
287,751

 
 
 
 
Property, plant and equipment, at cost
1,382,972

 
1,343,674

Accumulated depreciation
(393,035
)
 
(345,397
)
Property, plant and equipment, net
989,937

 
998,277

 
 
 
 
Goodwill
23,802

 
23,802

Investment in unconsolidated entities
132,458

 
134,506

Note receivable - Martin Energy Trading LLC
15,000

 
15,000

Other assets, net
64,896

 
81,465

Total assets
$
1,401,435

 
$
1,540,801

 
 
 
 
Liabilities and Partners’ Capital
 

 
 

Trade and other accounts payable
$
69,584

 
$
125,332

Product exchange payables
16,756

 
10,396

Due to affiliates
2,937

 
4,872

Income taxes payable
788

 
1,174

Fair value of derivatives
358

 
—

Other accrued liabilities
12,845

 
21,801

Total current liabilities
103,268

 
163,575

 
 
 
 
Long-term debt, net
876,405

 
888,887

Other long-term obligations
2,193

 
2,668

Total liabilities
981,866

 
1,055,130

 
 
 
 
Commitments and contingencies


 


Partners’ capital
419,569

 
485,671

Total liabilities and partners' capital
$
1,401,435

 
$
1,540,801


See accompanying notes to consolidated and condensed financial statements.


2
MARTIN MIDSTREAM PARTNERS L.P.
CONSOLIDATED AND CONDENSED STATEMENTS OF OPERATIONS
(Unaudited)
(Dollars and units in thousands, except per unit amounts)


 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2015
 
2014
 
2015
 
2014
Revenues:
 
 
 
 
 
 
 
Terminalling and storage  *
$
33,578

 
$
31,880

 
$
100,828

 
$
97,848

Marine transportation  *
18,977

 
24,281

 
59,956

 
69,479

Natural gas services
17,120

 
5,764

 
50,171

 
5,764

Sulfur services
3,090

 
3,037

 
9,270

 
9,112

Product sales: *
 
 
 
 
 
 
 
Natural gas services
86,714

 
217,398

 
330,803

 
771,798

Sulfur services
33,213

 
46,993

 
128,544

 
157,706

Terminalling and storage
33,329

 
47,735

 
102,901

 
153,451

 
153,256

 
312,126

 
562,248

 
1,082,955

Total revenues
226,021

 
377,088

 
782,473

 
1,265,158

 
 
 
 
 
 
 
 
Costs and expenses:
 

 
 

 
 

 
 

Cost of products sold: (excluding depreciation and amortization)
 

 
 

 
 

 
 

Natural gas services *
80,709

 
205,828

 
307,039

 
738,561

Sulfur services *
26,144

 
38,841

 
95,685

 
122,009

Terminalling and storage *
28,237

 
42,239

 
87,977

 
137,074

 
135,090

 
286,908

 
490,701

 
997,644

Expenses:
 

 
 

 
 

 
 

Operating expenses  *
45,310

 
47,283

 
138,399

 
137,294

Selling, general and administrative  *
8,666

 
10,161

 
26,507

 
27,222

Depreciation and amortization
23,335

 
16,457

 
68,737

 
44,277

Total costs and expenses
212,401

 
360,809

 
724,344

 
1,206,437

 
 
 
 
 
 
 
 
Impairment of long-lived assets
—

 
(3,445
)
 
—

 
(3,445
)
Other operating income (loss)
(1,586
)
 
347

 
(1,763
)
 
401

Operating income
12,034

 
13,181

 
56,366

 
55,677

 
 
 
 
 
 
 
 
Other income (expense):
 

 
 

 
 

 
 

Equity in earnings of unconsolidated entities
2,363

 
2,655

 
5,752

 
4,297

Interest expense, net
(11,994
)
 
(11,459
)
 
(32,465
)
 
(34,351
)
Gain on retirement of senior unsecured notes
728

 
—

 
728

 
—

Debt prepayment premium
—

 
—

 
—

 
(7,767
)
Reduction in carrying value of investment in Cardinal due to the purchase of the controlling interest
—

 
(30,102
)
 
—

 
(30,102
)
Other, net
399

 
287

 
757

 
170

Total other expense
(8,504
)
 
(38,619
)
 
(25,228
)
 
(67,753
)
 
 
 
 
 
 
 
 
Net income (loss) before taxes
3,530

 
(25,438
)
 
31,138

 
(12,076
)
Income tax expense
(200
)
 
(300
)
 
(814
)
 
(954
)
Income (loss) from continuing operations
3,330

 
(25,738
)
 
30,324

 
(13,030
)
Income (loss) from discontinued operations, net of income taxes
—

 
(1,167
)
 
1,215

 
(3,048
)
Net income (loss)
3,330

 
(26,905
)
 
31,539

 
(16,078
)
Less general partner's interest in net (income) loss
(3,959
)
 
539

 
(12,310
)
 
322

Less (income) loss allocable to unvested restricted units
(16
)
 
62

 
(127
)
 
33

Limited partners' interest in net income (loss)
$
(645
)
 
$
(26,304
)
 
$
19,102

 
$
(15,723
)
 
See accompanying notes to consolidated and condensed financial statements.

*Related Party Transactions Shown Below

3
MARTIN MIDSTREAM PARTNERS L.P.
CONSOLIDATED AND CONDENSED STATEMENTS OF OPERATIONS
(Unaudited)
(Dollars and units in thousands, except per unit amounts)



*Related Party Transactions Included Above
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2015
 
2014
 
2015
 
2014
Revenues:*
 
 
 
 
 
 
 
Terminalling and storage
$
15,091

 
$
19,045

 
$
58,626

 
$
55,798

Marine transportation
6,552

 
6,076

 
19,919

 
18,340

Product Sales
1,731

 
883

 
5,079

 
6,484

Costs and expenses:*
 
 
 
 
 
 
 
Cost of products sold: (excluding depreciation and amortization)
 
 
 
 
 
 
 
Natural gas services
6,470

 
9,908

 
20,198

 
29,169

Sulfur services
3,387

 
4,491

 
10,629

 
13,808

Terminalling and storage
3,227

 
9,174

 
14,261

 
25,571

Expenses:
 
 
 
 
 
 
 
Operating expenses
19,290

 
21,013

 
58,605

 
58,500

Selling, general and administrative
5,922

 
7,230

 
17,765

 
18,103


See accompanying notes to consolidated and condensed financial statements.


4
MARTIN MIDSTREAM PARTNERS L.P.
CONSOLIDATED AND CONDENSED STATEMENTS OF OPERATIONS
(Unaudited)
(Dollars and units in thousands, except per unit amounts)


 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2015
 
2014
 
2015
 
2014
Allocation of net income (loss) attributable to:
 
 
 
 
 
 
 
Limited partner interest:
 
 
 
 
 
 
 
 Continuing operations
$
(645
)
 
$
(25,162
)
 
$
18,366

 
$
(12,743
)
 Discontinued operations
—

 
(1,142
)
 
736

 
(2,980
)
 
$
(645
)
 
$
(26,304
)
 
$
19,102

 
$
(15,723
)
General partner interest:
 
 
 
 
 
 
 
  Continuing operations
$
3,959

 
$
(515
)
 
$
11,836

 
$
(261
)
  Discontinued operations
—

 
(24
)
 
474

 
(61
)
 
$
3,959

 
$
(539
)
 
$
12,310

 
$
(322
)
 
 
 
 
 
 
 
 
Net income (loss) per unit attributable to limited partners:
 
 
 
 
 
 
 
Basic:
 
 
 
 
 
 
 
Continuing operations
$
(0.02
)
 
$
(0.78
)
 
$
0.52

 
$
(0.44
)
Discontinued operations
—

 
(0.04
)
 
0.02

 
(0.10
)
 
$
(0.02
)
 
$
(0.82
)
 
$
0.54

 
$
(0.54
)
 
 
 
 
 
 
 
 
Weighted average limited partner units - basic
35,308

 
32,243

 
35,309

 
29,271

 
 
 
 
 
 
 
 
Diluted:
 
 
 
 
 
 
 
Continuing operations
$
(0.02
)
 
$
(0.78
)
 
$
0.52

 
$
(0.44
)
Discontinued operations
—

 
(0.04
)
 
0.02

 
(0.10
)
 
$
(0.02
)
 
$
(0.82
)
 
$
0.54

 
$
(0.54
)
 
 
 
 
 
 
 
 
Weighted average limited partner units - diluted
35,308

 
32,243

 
35,369

 
29,271






5
MARTIN MIDSTREAM PARTNERS L.P.
CONSOLIDATED AND CONDENSED STATEMENTS OF CAPITAL
(Unaudited)
(Dollars in thousands)



 
Partners’ Capital
 
 
 
Common Limited
 
General Partner Amount
 
 
 
Units
 
Amount
 
 
Total
Balances - January 1, 2014
26,625,026

 
$
254,028

 
$
6,389

 
$
260,417

Net income
—

 
(15,756
)
 
(322
)
 
(16,078
)
Issuance of common units
8,727,673

 
331,571

 
—

 
331,571

Issuance of restricted units
6,900

 
—

 
—

 
—

Forfeiture of restricted units
(3,500
)
 
—

 
—

 
—

General partner contribution
—

 
—

 
6,995

 
6,995

Cash distributions
—

 
(66,473
)
 
(1,506
)
 
(67,979
)
Excess purchase price over carrying value of acquired assets
—

 
(4,948
)
 
—

 
(4,948
)
Unit-based compensation
—

 
589

 
—

 
589

Purchase of treasury units
(6,400
)
 
(277
)
 
—

 
(277
)
Balances - September 30, 2014
35,349,699

 
$
498,734

 
$
11,556

 
$
510,290

 
 
 
 
 
 
 
 
Balances - January 1, 2015
35,365,912

 
$
470,943

 
$
14,728

 
$
485,671

Net income
—

 
19,229

 
12,310

 
31,539

Issuance of common units, net of issuance related costs
—

 
(330
)
 
—

 
(330
)
Issuance of restricted units
91,950

 
—

 
—

 
—

Forfeiture of restricted units
(1,250
)
 
—

 
—

 
—

General partner contribution
—

 
—

 
55

 
55

Cash distributions
—

 
(86,420
)
 
(13,526
)
 
(99,946
)
Unit-based compensation
—

 
1,080

 
—

 
1,080

Reimbursement of excess purchase price over carrying value of acquired assets
—

 
1,500

 
—

 
1,500

Balances - September 30, 2015
35,456,612

 
$
406,002

 
$
13,567

 
$
419,569

 
See accompanying notes to consolidated and condensed financial statements.





6
MARTIN MIDSTREAM PARTNERS L.P.
CONSOLIDATED AND CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited)
(Dollars in thousands)


 
Nine Months Ended
 
September 30,
 
2015
 
2014
Cash flows from operating activities:
 
 
 
Net income (loss)
$
31,539

 
$
(16,078
)
Less: (Income) loss from discontinued operations, net of income taxes
(1,215
)
 
3,048

Net income from continuing operations
30,324

 
(13,030
)
Adjustments to reconcile net income to net cash provided by operating activities:
 

 
 

Depreciation and amortization
68,737

 
44,277

Amortization of deferred debt issuance costs
4,142

 
5,415

Amortization of debt discount
—

 
1,305

Amortization of premium on notes payable
(246
)
 
(164
)
Loss (gain) on sale of property, plant and equipment
1,751

 
(54
)
Impairment of long-lived assets
—

 
3,445

Gain on retirement of senior unsecured notes
(728
)
 
—

Equity in earnings of unconsolidated entities
(5,752
)
 
(4,297
)
Reduction in carrying value of investment in Cardinal due to purchase of the controlling interest
—

 
30,102

Non-cash mark-to-market on derivatives
358

 
489

Unit-based compensation
1,080

 
589

Preferred dividends on MET investment
—

 
1,498

Return on investment in unconsolidated subsidiary
7,800

 
600

Change in current assets and liabilities, excluding effects of acquisitions and dispositions:
 

 
 

Accounts and other receivables
69,967

 
32,345

Product exchange receivables
909

 
(3,624
)
Inventories
(3,134
)
 
(21,793
)
Due from affiliates
3,348

 
(2,482
)
Other current assets
354

 
1,219

Trade and other accounts payable
(59,124
)
 
(28,426
)
Product exchange payables
6,360

 
9,265

Due to affiliates
(1,935
)
 
9,117

Income taxes payable
(386
)
 
(202
)
Other accrued liabilities
(8,490
)
 
(7,214
)
Change in other non-current assets and liabilities
(999
)
 
1,115

Net cash provided by continuing operating activities
114,336

 
59,495

Net cash used in discontinued operating activities
(1,352
)
 
(6,494
)
Net cash provided by operating activities
112,984

 
53,001

Cash flows from investing activities:
 

 
 

Payments for property, plant and equipment
(40,123
)
 
(58,522
)
Acquisitions, less cash acquired
—

 
(100,046
)
Payments for plant turnaround costs
(1,754
)
 
(4,000
)
Proceeds from sale of property, plant and equipment
1,985

 
702

Proceeds from involuntary conversion of property, plant and equipment
—

 
2,475

Investment in unconsolidated entities
—

 
(134,413
)
Return of investments from unconsolidated entities
—

 
726

Contributions to unconsolidated entities
—

 
(3,386
)
Net cash used in continuing investing activities
(39,892
)
 
(296,464
)
Net cash provided by discontinued investing activities
41,250

 
—

Net cash provided by (used in) investing activities
1,358

 
(296,464
)
Cash flows from financing activities:
 

 
 

Payments of long-term debt
(224,310
)
 
(1,458,096
)
Proceeds from long-term debt
209,000

 
1,426,250

Proceeds from issuance of common units, net of issuance related costs
(330
)
 
331,571

General partner contribution
55

 
6,995

Purchase of treasury units
—

 
(277
)
Payment of debt issuance costs
(340
)
 
(3,589
)
Excess purchase price over carrying value of acquired assets
—

 
(4,948
)
Reimbursement of excess purchase price over carrying value of acquired assets
1,500

 
—

Cash distributions paid
(99,946
)
 
(67,979
)
Net cash provided by (used in) financing activities
(114,371
)
 
229,927

Net decrease in cash
(29
)
 
(13,536
)
Cash at beginning of period
42

 
16,542

Cash at end of period
$
13

 
$
3,006

Non-cash additions to property, plant and equipment
$
4,389

 
$
4,208


See accompanying notes to consolidated and condensed financial statements.

7
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2015
(Unaudited)




(1)
General

Martin Midstream Partners L.P. (the "Partnership") is a publicly traded limited partnership ("MLP") with a diverse set of operations focused primarily in the United States ("U.S.") Gulf Coast region. Its four primary business lines include:  terminalling and storage services for petroleum products and by-products including the refining of naphthenic crude oil, blending and packaging of finished lubricants; natural gas services, including liquids transportation and distribution services and natural gas storage; 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 ("U.S. GAAP") for interim financial reporting. Accordingly, these financial statements have been condensed and do not include all of the information and footnotes required by U.S. GAAP 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 financial position, results of operations, 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, 2014, filed with the Securities and Exchange Commission (the "SEC") on March 2, 2015, as amended by Amendment No. 1 on Form 10-K/A for the year ended December 31, 2014 filed on March 5, 2015.

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 and condensed financial statements in conformity with U.S. GAAP.  Actual results could differ from those estimates.

(2)
New Accounting Pronouncements

In September 2015, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments, which requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. This ASU requires that the acquirer record, in the same period's financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. The ASU also requires an entity to present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. This ASU is effective for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. The ASU should be applied prospectively to adjustments to provisional amounts that occur after the effective date of this update with earlier application permitted for financial statements that have not been issued. The Partnership is evaluating the effect that ASU 2015-06 will have on its consolidated and condensed financial statements and related disclosures.

In July 2015, the FASB issued ASU No. 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory, which applies only to inventory for which cost is determined by methods other than last-in, first-out and the retail inventory method. This includes inventory that is measured using first-in, first-out or average cost. Inventory within the scope of this standard is required to be measured at the lower of cost and net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. The new standard will be effective on January 1, 2017. The Partnership is evaluating the effect that ASU 2015-11 will have on its consolidated and condensed financial statements and related disclosures.

In April 2015, the FASB issued ASU No. 2015-06, Earnings Per Share (Topic 260): Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions, which requires an MLP to allocate earnings (losses) of a transferred business entirely to the general partner when computing earnings per unit ("EPU") for periods before the dropdown transaction occurred. The EPU for limited partners that was previously reported would not change as a result of the dropdown

8
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2015
(Unaudited)



transaction. The ASU also requires an MLP to disclose the effects of the dropdown transaction on EPU for the periods before and after the dropdown transaction occurred. This ASU is effective for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. The ASU requires retrospective application and early adoption is permitted. The Partnership is evaluating the effect that ASU 2015-06 will have on its consolidated and condensed financial statements and related disclosures.

In April 2015, the FASB issued ASU No. 2015-03, Interest-Imputation of Interest, which simplifies presentation of debt issuance costs. The amended guidance requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. Early application is permitted under the retrospective transition method. The Partnership has elected to adopt this guidance effective January 1, 2015. The standard only affects presentation on the Partnership's Consolidated and Condensed Balance Sheets and does not affect any of the Partnership's other financial statements. The amount of debt issuance costs, net of accumulated amortization, from the December 31, 2014 audited balance sheet that were reclassified and shown as a reduction of the related long-term debt balances is $13,118.

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. The ASU will replace most existing revenue recognition guidance in U.S. GAAP when it becomes effective. The new standard is effective for the Partnership on January 1, 2018. The standard permits the use of either the retrospective or cumulative effect transition method. The Partnership is evaluating the effect that ASU 2014-09 will have on its consolidated and condensed financial statements and related disclosures. The Partnership has not yet selected a transition method nor has it determined the effect of the standard on its ongoing financial reporting.
        
(3)
Acquisitions
 
Cardinal Gas Storage Partners LLC
On August 29, 2014, the Partnership acquired from Energy Capital Partners ("ECP") all of ECP’s approximate 57.8% Category A membership interest in Cardinal Gas Storage Partners LLC ("Cardinal") for cash consideration of approximately $120,973, subject to certain post-closing adjustments. Prior to the acquisition, the Partnership owned an approximate 42.2% Category A membership interest in Cardinal. Based on the application of purchase accounting, the Partnership reduced the carrying value of its existing investment in Cardinal at the acquisition date by $30,102, which was recognized in the Partnership's Consolidated and Condensed Statements of Operations in the third quarter of 2014. Concurrent with the closing of the transaction, the Partnership retired all of the project level financing of various Cardinal subsidiaries. The Partnership funded the acquisition and repayment of the project financings with borrowings under its revolving credit facility and the use of restricted cash acquired.
The total purchase price is as follows:
Cash payment for 57.8% interest in Cardinal
$
120,973

Fair value of the Partnership's previously owned 42.2% interest in Cardinal
87,613

Total
$
208,586


Assets acquired and liabilities assumed were recorded in the Natural Gas Services segment at fair value in the following purchase price allocation which was finalized in the fourth quarter of 2014:

9
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2015
(Unaudited)



Restricted cash
$
17,566

Other current assets
9,385

Property, plant and equipment
390,895

Intangible and other assets
80,135

Project level finance debt
(282,087
)
Other current liabilities
(6,713
)
Other non-current liabilities
(595
)
   Total
$
208,586


Intangible assets consist of above-market gas storage customer contracts which are amortized based upon the terms of the individual contracts. At the acquisition date, the weighted average life of these contracts, based upon contracted volumes, was 5.1 years.

The Partnership’s results of operations from the Cardinal acquisition include revenues of $16,287 and net income of $3,142 for the three months ended September 30, 2015 and revenues of $49,030 and net income of $9,232 for the nine months ended September 30, 2015.

Natural Gas Liquids ("NGL") Storage Assets

On May 31, 2014, the Partnership acquired certain NGL storage assets from a subsidiary of Martin Resource Management Corporation ("Martin Resource Management") for $7,388. This acquisition is considered a transfer of net assets between entities under common control. The acquisition of these assets was recorded at the historical carrying value of the assets at the acquisition date. The Partnership recorded the purchase in the following allocation:
Property, plant and equipment
$
2,453

Current liabilities
(13
)
 
$
2,440


The excess of the purchase price over the carrying value of the assets of $4,948 was recorded as an adjustment to "Partners' capital." This transaction was funded with borrowings under the Partnership's revolving credit facility. As no individual line item of the historical financial statements of the assets was in excess of 3% of the Partnership's relative financial statement captions, the Partnership elected not to retrospectively recast the historical financial information of these assets.

West Texas LPG Pipeline Limited Partnership

On May 14, 2014, the Partnership acquired from a subsidiary of Atlas Pipeline Partners L.P. ("Atlas"), all of the outstanding membership interests in Atlas Pipeline NGL Holdings, LLC and Atlas Pipeline NGL Holdings II, LLC (collectively, "Atlas Holdings") for cash of approximately $134,400. The purchase price was subsequently reduced $501 due to a post-closing working capital adjustment. This transaction was recorded in "Investments in unconsolidated entities" in the Partnership's Consolidated and Condensed Balance Sheet through a purchase price allocation. Atlas Holdings owned a 19.8% limited partnership interest and a 0.2% general partnership interest in West Texas LPG Pipeline L.P. ("WTLPG"). At the time of the purchase, WTLPG was operated by Chevron Pipe Line Company. The 80.0% interest was subsequently sold to ONEOK Partners, L.P. who assumed operational responsibility. WTLPG owns an approximate 2,300 mile common-carrier pipeline system that transports NGLs from New Mexico and Texas to Mont Belvieu, Texas for fractionation. This acquisition will enable the Partnership to participate in the transportation of the growing NGL production of West Texas and other basins along the WTLPG pipeline route. This acquisition of the WTLPG business complements the Partnership's existing East Texas NGL pipeline that delivers Y-grade NGLs from East Texas production areas into Beaumont, Texas on a smaller scale. This transaction was funded with borrowings under the Partnership's revolving credit facility.


10
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2015
(Unaudited)



Pro Forma Financial Information for Cardinal and WTLPG
    
The following pro forma consolidated results of operations for the three and nine months ended September 30, 2014 have been prepared as if the acquisition of Cardinal and WTLPG occurred at the beginning of fiscal 2014:
 
Three Months Ended September 30, 2014
 
Nine Months Ended September 30, 2014
Revenue:
 
 
 
As reported
$
377,088

 
$
1,265,158

Pro forma
$
388,233

 
$
1,311,646

Net income (loss) from continuing operations attributable to limited partners:
 
 
 
As reported
$
(25,162
)
 
$
(12,743
)
Pro forma
$
1,124

 
$
(3,093
)
Net loss from discontinued operations attributable to limited partners:
 
 
 
As reported
$
(1,142
)
 
$
(2,980
)
Pro forma
$
(1,142
)
 
$
(2,980
)
Net income (loss) from continuing operations per unit attributable to limited partners - basic:
 
 
 
As reported
$
(0.78
)
 
$
(0.44
)
Pro forma
$
0.03

 
$
(0.11
)
Net loss from discontinued operations per unit attributable to limited partners - basic:
 
 
 
As reported
$
(0.04
)
 
$
(0.10
)
Pro forma
$
(0.04
)
 
$
(0.10
)
Net income (loss) from continuing operations per unit attributable to limited partners - diluted:
 
 
 
As reported
$
(0.78
)
 
$
(0.44
)
Pro forma
$
0.03

 
$
(0.11
)
Net loss from discontinued operations per unit attributable to limited partners - diluted:
 
 
 
As reported
$
(0.04
)
 
$
(0.10
)
Pro forma
$
(0.04
)
 
$
(0.10
)

Pro forma adjustments included above are based upon currently available information which includes certain estimates and assumptions. Although actual results could differ from the pro forma results, the Partnership believes the pro forma results provide a reasonable basis for presenting the significant effects of the transactions. However, the pro forma results are not necessarily indicative of the results that would have occurred if the transactions had occurred at the beginning of fiscal 2014.

(4)
Discontinued operations and divestitures

Floating Storage Assets. On February 12, 2015, the Partnership sold all six of its 16,101 barrel liquefied petroleum gas ("LPG") pressure barges, collectively referred to as the "Floating Storage Assets." These assets were acquired on February 28, 2013. On December 19, 2014, the Partnership made the decision to dispose of the Floating Storage Assets. As a result, the Partnership classified the Floating Storage Assets as held for sale at December 31, 2014 and has presented the results of operations and cash flows of the Floating Storage Assets as discontinued operations for the three and nine months ended September 30, 2015 and 2014. The Partnership has retrospectively adjusted its prior period consolidated financial statements to comparably classify the amounts related to the operations and cash flows of the Floating Storage Assets as discontinued operations. The Floating Storage Assets were presented as discontinued operations under the guidance prior to the Partnership's adoption of ASU 2014-08 related to discontinued operations. The adoption of the amended guidance was effective for the Partnership January 1, 2015.


11
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2015
(Unaudited)



The Floating Storage Assets’ operating results, which are included in income from discontinued operations, were as follows:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2015
 
2014
 
2015
 
2014
Total revenues from third parties1      
$
—

 
$
12,895

 
$
791

 
$
46,070

Total costs and expenses and other, net, excluding depreciation and amortization
—

 
13,776

 
1,038

 
48,066

Depreciation and amortization
—

 
286

 
—

 
1,052

Other operating income2
—

 
—

 
1,462

 
—

Income (loss) from discontinued operations before income taxes
—

 
(1,167
)
 
1,215

 
(3,048
)
Income tax expense
—

 
—

 
—

 
—

Income (loss) from discontinued operations, net of income taxes
$
—

 
$
(1,167
)
 
$
1,215

 
$
(3,048
)

1 All revenues for the three months ended September 30, 2015 and 2014 were from third parties. Total revenues from third parties excludes intercompany revenues of $0 and $5,273 for the nine months ended September 30, 2015 and 2014, respectively.

2 Other operating income represents the gain on the disposition of the Floating Storage Assets.

(5)
Inventories

Components of inventories at September 30, 2015 and December 31, 2014 were as follows: 
 
September 30, 2015
 
December 31, 2014
Natural gas liquids
$
39,383

 
$
27,820

Sulfur
14,675

 
12,231

Sulfur based products
14,110

 
16,280

Lubricants
20,442

 
29,096

Other
3,193

 
3,291

 
$
91,803

 
$
88,718


(6)
Investments in Unconsolidated Entities and Joint Ventures

On August 29, 2014, the Partnership acquired ECP’s approximate 57.8% Category A membership interest in Cardinal. Prior to the acquisition, the Partnership owned an approximate 42.2% Category A membership interest in Cardinal which was accounted for by the equity method. See Note 3 for discussion of the acquisition of the remaining membership interests.

On May 14, 2014, the Partnership acquired from a subsidiary of Atlas, all of the outstanding membership interests in Atlas Holdings for cash of approximately $134,400 at closing. The purchase price was subsequently reduced $501 due to a post-closing working capital adjustment. Atlas Holdings owned a 19.8% limited partnership interest and a 0.2% general partnership interest in WTLPG. At the time of the purchase, WTLPG was operated by Chevron Pipe Line Company. The 80% interest was subsequently sold to ONEOK Partners, L.P. who assumed operational responsibility. WTLPG owns an approximate 2,300 mile common-carrier pipeline system that transports NGLs from New Mexico and Texas to Mont Belvieu, Texas for fractionation. The Partnership recognizes its 20% interest in WTLPG as "Investment in unconsolidated entities" on its Consolidated and Condensed Balance Sheets. The Partnership accounts for its ownership interest in WTLPG under the equity method of accounting, with recognition of its ownership interest in the income of WTLPG as "Equity in earnings of unconsolidated entities" on its Consolidated and Condensed Statements of Operations.


12
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2015
(Unaudited)



During March 2013, the Partnership acquired 100% of the preferred interests in Martin Energy Trading LLC ("MET"), a subsidiary of Martin Resource Management, for $15,000. On August 31, 2014, MET converted its preferred equity to subordinated debt. The resulting $15,000 note receivable from MET bears an annual interest rate of 15% and matures August 31, 2026. MET may prepay any or all of the note balance on or after September 1, 2016. See Note 12.

The following tables summarize the components of the investment in unconsolidated entities on the Partnership’s Consolidated and Condensed Balance Sheets, the components of equity in earnings of unconsolidated entities included in the Partnership’s Consolidated and Condensed Statements of Operations, and the components of the cash distributions received from unconsolidated entities:
 
September 30, 2015
 
December 31, 2014
WTLPG
$
132,458

 
$
134,506

    Total investment in unconsolidated entities
$
132,458

 
$
134,506


 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2015
 
2014
 
2015
 
2014
Equity in earnings of WTLPG
$
2,363

 
$
1,138

 
$
5,752

 
$
1,907

Equity in earnings of Cardinal
—

 
1,135

 
—

 
892

Equity in earnings of MET
—

 
382

 
—

 
1,498

    Equity in earnings of unconsolidated entities
$
2,363

 
$
2,655

 
$
5,752

 
$
4,297


 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2015
 
2014
 
2015
 
2014
Distributions from WTLPG
$
3,400

 
$
600

 
$
7,800

 
$
600

Distributions from Cardinal
—

 
—

 
—

 
225

Distributions from MET
—

 
382

 
—

 
1,498

Distributions from unconsolidated entities
$
3,400

 
$
982

 
$
7,800

 
$
2,323


Selected financial information for significant unconsolidated equity-method investees is as follows:
 
As of September 30,
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
Total
Assets
 
Members' Equity
 
Revenues
 
Net Income
 
Revenues
 
Net Income (Loss)
2015
 
 
 
 
 
 
 
 
 
 
 
WTLPG
$
833,299

 
$
819,080

 
$
26,094

 
$
11,815

 
$
70,010

 
$
28,760

 
As of December 31,
 
 

 
 

 
 
 
 
2014
 

 
 

 
 

 
 

 
 
 
 
WTLPG
$
827,697

 
$
818,546

 
$
23,884

 
$
7,403

 
$
71,798

 
$
28,004

Cardinal1
$
—

 
$
—

 
$
11,145

 
$
3,211

 
$
46,488

 
$
2,606


    
1Financial information for Cardinal includes revenues and net income for the 2014 period prior to the Partnership's acquisition of the 57.8% interest not previously owned.


13
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2015
(Unaudited)



As of September 30, 2015 and December 31, 2014, the Partnership’s interest in cash of the unconsolidated equity-method investee was $3,360 and $10, respectively.

(7)
Derivative Instruments and Hedging Activities

The Partnership’s revenues and cost of products sold are materially impacted by changes in NGL prices. Additionally, the Partnership's results of operations are materially impacted by changes in 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 and Condensed Balance Sheets and to recognize certain changes in the fair value of derivative instruments on the Partnership’s Consolidated and Condensed Statements of Operations as they were not designated as hedges for accounting purposes for any of the periods presented.

(a)    Commodity Derivative Instruments

The Partnership from time to time has used derivatives to manage the risk of commodity price fluctuation. Commodity risk is the adverse effect on the value of a liability or future purchase that results from a change in commodity price.  The Partnership has established a hedging policy and monitors and manages the commodity market risk associated with potential commodity risk exposure.  In addition, the Partnership has focused on utilizing counterparties for these transactions whose financial condition is appropriate for the credit risk involved in each specific transaction. The Partnership has entered into hedging transactions through March 31, 2016 to protect a portion of its commodity price risk exposure. These hedging arrangements are in the form of swaps for NGLs. The Partnership has instruments totaling a notional quantity of 320 barrels settling during the period from October 31, 2015 through March 31, 2016. These instruments settle against OPIS Mont Belvieu (non-TET) monthly average price. MET serves as the counterparty for all positions outstanding at September 30, 2015. These instruments are recorded on the Partnership's Consolidated and Condensed Balance Sheets at September 30, 2015 in "Fair value of derivatives" as a current liability of $358.

As of September 30, 2014, the Partnership had a notional quantity of 3,631,740 MMBtu of natural gas call options with a strike price of $4.50 per MMBtu.  These options were in place to manage the purchase of base gas at Monroe Gas Storage Company, LLC for the portion of base gas that was currently leased with Credit Suisse and scheduled to be returned in January and February 2015.  The options were set to settle in two increments of 2,345,498 MMBtu and 1,286,242 MMBtu on January 31, 2015 and February 28, 2015, respectively.  These options were settled on December 31, 2014.

(b)    Interest Rate Derivative Instruments

The Partnership is exposed to market risks associated with interest rates. Market risk is the adverse effect on the value of a financial instrument that results from a change in interest rates. We minimize this market risk by establishing and monitoring parameters that limit the types and degree of market risk that may be undertaken. The Partnership enters into interest rate swaps to manage interest rate risk associated with the Partnership’s variable rate credit facility and its fixed rate senior unsecured notes. 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.

During the nine months ended September 30, 2015, the Partnership entered into contracts which provided the counterparty the option to enter into swap contracts to hedge the Partnership's exposure to changes in the fair value of its senior unsecured notes ("interest rate swaptions") through September 30, 2015. In connection with the interest rate swaption contracts, the Partnership received premiums of $750 and $2,495, which represented their fair value on the date the transactions were initiated and were initially recorded as derivative liabilities on the Partnership's Consolidated and Condensed Balance Sheet, during the three and nine months ended September 30, 2015, respectively. Each of the interest rate swaptions was fully amortized as of September 30, 2015. Interest rate swaption contract premiums received are amortized over the period from initiation of the contract through their termination date. For the three and nine months ended September 30, 2015, the Partnership recognized $750 and $2,495, respectively, of premium in "Interest expense, net" on the Partnership's Consolidated and Condensed Statement of Operations related to the interest rate swaption contracts.

As of September 30, 2014, we had a combined notional principal amount of $250,000 of fixed-to-variable interest rate swap agreements, effectively converting the interest expense associated with a portion of the Partnership's 2021 senior

14
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2015
(Unaudited)



unsecured notes from fixed rates to variable rates based on an interest rate of LIBOR plus a spread. Each of the Partnership's swap agreements have a termination date that corresponds to the maturity date of the 2021 senior unsecured notes. As of September 30, 2014, the maximum length of time over which the Partnership has hedged a portion of its exposure to the variability in the value of this debt due to interest rate risk is through February of 2021.

For information regarding gains and losses on interest rate derivative instruments, see "Tabular Presentation of Gains and Losses on Derivative Instruments" below.

(c)    Tabular Presentation of Gains and Losses on Derivative Instruments

The following table summarizes the fair values and classification of the Partnership’s derivative instruments in its Consolidated and Condensed Balance Sheet:
 
Fair Values of Derivative Instruments in the Consolidated Balance Sheet
 
Derivative Assets
Derivative Liabilities
 
 
Fair Values
 
Fair Values
 
 Balance Sheet Location
September 30, 2015
 
December 31, 2014
 Balance Sheet Location
September 30, 2015
 
December 31, 2014
Derivatives not designated as hedging instruments:
Current:
 
 
 
 
 
 
 
Commodity contracts
Fair value of derivatives
$
—

 
$
—

Fair value of derivatives
$
358

 
$
—

Total derivatives not designated as hedging instruments
 
$
—

 
$
—

 
$
358

 
$
—


Effect of Derivative Instruments on the Consolidated and Condensed Statement of Operations
For the Three Months Ended September 30, 2015 and 2014
 
Location of Gain (Loss)
Recognized in Income on
 Derivatives
Amount of Gain (Loss) Recognized in
Income on Derivatives
 
 
2015
 
2014
Derivatives not designated as hedging instruments:
 
 
Interest rate swaption contracts
Interest expense
$
750

 
$
—

Interest rate contracts
Interest expense
—

 
63

Commodity contracts
Other income
—

 
21

Commodity contracts
Cost of products sold
(358
)
 
—

Total derivatives not designated as hedging instruments
$
392

 
$
84



15
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2015
(Unaudited)



Effect of Derivative Instruments on the Consolidated and Condensed Statement of Operations
For the Nine Months Ended September 30, 2015 and 2014
 
Location of Gain (Loss)
Recognized in Income on
 Derivatives
Amount of Gain (Loss) Recognized in
Income on Derivatives
 
 
2015
 
2014
Derivatives not designated as hedging instruments:
 
 
Interest rate swaption contracts
Interest expense
$
2,495

 
$
—

Interest rate contracts
Interest expense
—

 
(2,864
)
Commodity contracts
Other income
 
 
21

Commodity contracts
Cost of products sold
(358
)
 
—

Total derivatives not designated as hedging instruments
$
2,137

 
$
(2,843
)

(8)
Fair Value Measurements

The Partnership follows the provisions of ASC 820 related to fair value measurements and disclosures, which established a framework for measuring fair value and expanded disclosures about fair value measurements. The adoption of this guidance had no impact on the Partnership’s financial position or results of operations.

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 fair value of the following items are required to be disclosed on a recurring basis subject to the requirements of ASC 820 at September 30, 2015 and December 31, 2014:
 
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, 2015
 
(Level 1)
 
(Level 2)
 
(Level 3)
Assets
 
 
 
 
 
 
 
Note receivable - Martin Energy Trading
$
15,834

 
$
—

 
$
—

 
$
15,834

Total assets
$
15,834

 
$
—

 
$
—

 
$
15,834

 
 
 
 
 
 
 
 
Liabilities
 

 
 

 
 

 
 

2021 Senior unsecured notes
$
360,980

 
$
—

 
$
360,980

 
$
—

Commodity derivative contracts
358

 
 
 
358

 
—

Total liabilities
$
361,338

 
$
—

 
$
361,338

 
$
—

            

16
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2015
(Unaudited)



 
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, 2014
 
(Level 1)
 
(Level 2)
 
(Level 3)
Assets
 
 
 
 
 
 
 
Note receivable - Martin Energy Trading
$
15,852

 
$
—

 
$
—

 
$
15,852

Total assets
$
15,852

 
$
—

 
$
—

 
$
15,852

 
 
 
 
 
 
 
 
Liabilities
 

 
 

 
 

 
 

2021 Senior unsecured notes
$
385,077

 
$
—

 
$
385,077

 
$
—

Total liabilities
$
385,077

 
$
—

 
$
385,077

 
$
—


FASB ASC 825-10-65, 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:

•
Accounts and other receivables, trade and other accounts payable, accrued interest payable, other accrued liabilities, income taxes payable and due from/to affiliates: The carrying amounts approximate fair value due to the short-term maturity and highly liquid nature of these instruments, and as such these have been excluded from the table above. There is negligible credit risk associated with these instruments.

•
Note receivable and long-term debt including current portion: The carrying amount of the revolving credit facility approximates fair value due to the debt having a variable interest rate and is in Level 2.  The Partnership has not had any indicators which represent a change in the market spread associated with its variable interest rate debt. The estimated fair value of the senior unsecured notes is based on market prices of similar debt. The estimated fair value of the note receivable from Martin Energy Trading was determined by calculating the net present value of the interest payments over the life of the note. The note is considered Level 3 due to the lack of observable inputs for similar transactions between related parties.

(9)
Supplemental Balance Sheet Information

Components of "Other assets, net" were as follows:
 
September 30, 2015
 
December 31, 2014
Customer contracts and relationships, net
$
55,831

 
$
72,171

Other intangible assets
1,914

 
2,215

Other
7,151

 
7,079

 
$
64,896

 
$
81,465


Accumulated amortization of intangible assets was $29,558 and $12,125 at September 30, 2015 and December 31, 2014, respectively.
    
Components of "Other accrued liabilities" were as follows:

17
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2015
(Unaudited)



 
September 30, 2015
 
December 31, 2014
Accrued interest
$
3,775

 
$
10,996

Property and other taxes payable
6,496

 
7,524

Accrued payroll
2,447

 
3,125

Other
127

 
156

 
$
12,845

 
$
21,801


(10)
Long-Term Debt

At September 30, 2015 and December 31, 2014, long-term debt consisted of the following:
 
September 30,
2015
 
December 31,
2014
$700,0001 Revolving credit facility at variable interest rate (2.95%2 weighted average at September 30, 2015), due March 2018 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, net of unamortized debt issuance costs of $5,400 and $8,656, respectively4
$
494,600

 
$
491,344

$400,0003 Senior notes, 7.25% interest, net of unamortized debt issuance costs of $3,758 and $4,462, respectively, including unamortized premium of $1,688 and $2,005, respectively, issued $250,000 February 2013 and $150,000 April 2014, due February 2021, unsecured4
381,805

 
397,543

Total long-term debt, net
876,405

 
888,887

Less current installments
—

 
—

Long-term debt, net of current installments
$
876,405

 
$
888,887


1 On August 14, 2015, the Partnership reduced its borrowing capacity under the revolving credit facility from $900,000 to $700,000. The facility can be expanded up to $1,000,000 at any time under the accordion feature of the facility. The reduction in capacity resulted in the write-off of $1,625 of deferred debt costs.
     
2 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. All amounts outstanding at September 30, 2015 and December 31, 2014 were at LIBOR plus an applicable margin. The applicable margin for revolving loans that are LIBOR loans ranges from 1.75% to 2.75% and the applicable margin for revolving loans that are base prime rate loans ranges from 0.75% to 1.75%.  The applicable margin for existing LIBOR borrowings at September 30, 2015 is 2.75%. The credit facility contains various covenants which limit the Partnership’s ability to make certain investments and acquisitions; enter into certain agreements; incur indebtedness; sell assets; and make certain amendments to the Partnership's omnibus agreement with Martin Resource Management (the "Omnibus Agreement"). The Partnership is permitted to make quarterly distributions so long as no event of default exists.

3 In September 2015, the Partnership repurchased on the open market an aggregate $16,125 of 7.25% senior unsecured notes. These transactions resulted in a gain on retirement of $728, including the write-off of applicable pro-rata portion of deferred debt costs and premium.

4 The Partnership is in compliance with all debt covenants as of September 30, 2015.

The Partnership paid cash interest, net of proceeds received from interest rate swaptions, in the amount of $18,017 and $17,346 for the three months ended September 30, 2015 and 2014, respectively.  The Partnership paid cash interest, net of proceeds received from interest rate swaptions, in the amount of $39,121 and $35,770 for the nine months ended September 30, 2015 and 2014, respectively.  Capitalized interest was $427 and $234 for the three months ended September 30, 2015 and 2014, respectively. Capitalized interest was $1,522 and $957 for the nine months ended September 30, 2015 and 2014, respectively.


18
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2015
(Unaudited)



(11)
Partners' Capital

As of September 30, 2015, Partners’ capital consisted of 35,456,612 common limited partner units, representing a 98% partnership interest and a 2% general partner interest. Martin Resource Management, through subsidiaries, owned 6,264,532 of the Partnership's common limited partner units representing approximately 17.7% of the Partnership's outstanding common limited partner units. Martin Midstream GP LLC ("MMGP"), the Partnership's general partner, owns the 2% general partnership interest. Martin Resource Management controls the Partnership's general partner, by virtue of its 51% voting interest in MMGP Holdings, LLC ("Holdings"), the sole member of the Partnership's general partner.

The partnership agreement of the Partnership (the "Partnership Agreement") contains specific provisions for the allocation of net income and losses to each of the partners for purposes of maintaining their respective partner capital accounts.

Issuance of Common Units

On September 29, 2014, the Partnership completed a public offering of 3,450,000 common units at a price of $36.91 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 3,450,000 common units, net of underwriters' discounts, commissions and offering expenses were $122,587. The Partnership's general partner contributed $2,599 in cash to the Partnership in conjunction with the issuance in order to maintain its 2% general partner interest in the Partnership. All of the net proceeds were used to pay down outstanding amounts under the Partnership's revolving credit facility.

On August 29, 2014, the Partnership closed a private equity sale with Martin Resource Management, under which Martin Resource Management invested $45,000 in cash in exchange for 1,171,265 common units. The pricing of $38.42 per common unit was based on the 10-day weighted average price of the Partnership's common units for the 10 trading days ending August 8, 2014. In connection with the issuance of these common units, the Partnership's general partner contributed $918 in order to maintain its 2% general partner interest in the Partnership. The proceeds from the common unit issuances were used to pay down outstanding amounts under the Partnership's revolving credit facility.

On May 12, 2014, the Partnership completed a public offering of 3,600,000 common units at a price of $41.51 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 3,600,000 common units, net of underwriters' discounts, commissions and offering expenses were $143,431.  The Partnership's general partner contributed $3,049 in cash to the Partnership in conjunction with the issuance in order to maintain its 2% general partner interest in the Partnership.  All of the net proceeds were used to pay down outstanding amounts under the Partnership's revolving credit facility.
    
In March 2014, the Partnership entered into an equity distribution agreement with multiple underwriters (the "Sales Agents") for the ongoing distribution of the Partnership's common units. Pursuant to this program, the Partnership offered and sold common unit equity through the Sales Agents for proceeds of $0 and $21,336 during the nine months ended September 30, 2015 and 2014, respectively. The Partnership paid $287 and $382 in equity issuance related costs for the nine months ended September 30, 2015 and 2014, respectively. Under the program, the Partnership issued 0 and 506,408 common units during the nine months ended September 30, 2015 and 2014, respectively. Common units issued were at market prices prevailing at the time of the sale. Under the program, the Partnership also received capital contributions from the general partner of $0 and $356 during the nine months ended September 30, 2015 and 2014, respectively, to maintain its 2% general partner interest in the Partnership. The net proceeds from the common unit issuances were used to pay down outstanding amounts under the Partnership's revolving credit facility.

Incentive Distribution Rights

MMGP 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, 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. On October 2, 2012, the Partnership Agreement was amended to provide that the general partner would forego the next $18,000 in incentive distributions that it would otherwise be entitled to receive. Additionally, on May 5, 2014,

19
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2015
(Unaudited)



the owner of our general partner agreed to forego an additional $3,000 in incentive distributions. As of March 31, 2015, all incentive distributions the general partner agreed to forego were satisfied. The general partner received $3,893 and $11,524 in incentive distributions during the three and nine months ended September 30, 2015. No incentive distributions were paid to the general partner during the three and nine months ended September 30, 2014.
 
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.
 
Distributions of Available Cash

The Partnership distributes all of its available cash (as defined in the Partnership Agreement) within 45 days after the end of each quarter to unitholders of record and to the general partner. Available cash is generally defined as all cash and cash equivalents of the Partnership on hand at the end of each quarter less the amount of cash reserves its general partner determines in its reasonable discretion is necessary or appropriate to: (i) provide for the proper conduct of the Partnership’s business; (ii) comply with applicable law, any debt instruments or other agreements; or (iii) provide funds for distributions to unitholders and the general partner for any one or more of the next four quarters, plus all cash on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter.

Net Income per Unit

The Partnership follows the provisions of the FASB 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. Undistributed earnings are allocated to the general partner and limited partners utilizing the contractual terms of the Partnership Agreement. Distributions to the general partner pursuant to the IDRs are limited to available cash that will be distributed as defined in the Partnership Agreement. Accordingly, the Partnership does not allocate undistributed earnings to the general partner for the IDRs because the general partner's share of available cash is the maximum amount that the general partner would be contractually entitled to receive if all earnings for the period were distributed. 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 income and losses specified in the Partnership Agreement. Additionally, as required under FASB ASC 260-10-45-61A, unvested share-based payments that entitle employees to receive non-forfeitable distributions are considered participating securities, as defined in FASB ASC 260-10-20, for earnings per unit calculations.

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 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 is a reconciliation of net income allocated to the general partner and limited partners for purposes of calculating net income attributable to limited partners per unit:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
Continuing operations:
2015
 
2014
 
2015
 
2014
Income (loss) from continuing operations
$
3,330

 
$
(25,738
)
 
$
30,324

 
$
(13,030
)
Less general partner’s interest in net income:
 
 
 
 
 
 
 
Distributions payable on behalf of IDRs
3,893

 
—

 
11,230

 
—

Distributions payable on behalf of general partner interest
667

 
101

 
1,925

 
1,221

General partner interest in undistributed loss
(601
)
 
(616
)
 
(1,319
)
 
(1,481
)
Less income allocable to unvested restricted units
16

 
(61
)
 
122

 
(27
)
Limited partners’ interest in income (loss) from continuing operations
$
(645
)
 
$
(25,162
)
 
$
18,366

 
$
(12,743
)


20
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2015
(Unaudited)



 
Three Months Ended September 30,
 
Nine Months Ended September 30,
Discontinued operations:
2015
 
2014
 
2015
 
2014
Income (loss) from discontinued operations
$
—

 
$
(1,167
)
 
$
1,215

 
$
(3,048
)
Less general partner’s interest in net income:
 
 
 
 
 
 
 
Distributions payable on behalf of IDRs
—

 
—

 
450

 
—

Distributions payable on behalf of general partner interest
—

 
451

 
77

 
285

General partner interest in undistributed loss
—

 
(475
)
 
(53
)
 
(347
)
Less income allocable to unvested restricted units
—

 
(1
)
 
5

 
(6
)
Limited partners’ interest in income (loss) from discontinued operations
$
—

 
$
(1,142
)
 
$
736

 
$
(2,980
)

The weighted average units outstanding for basic net income per unit were 35,307,583 and 35,308,990 for the three and nine months ended September 30, 2015, respectively. The weighted average units outstanding for basic net income per unit were 32,242,571 and 29,271,205 for the three and nine months ended September 30, 2014, respectively. All outstanding units were included in the computation of diluted earnings per unit and weighted based on the number of days such units were outstanding during the period presented. For diluted net income per unit, the weighted average units outstanding were increased by 59,976 for the nine months ended September 30, 2015, due to the dilutive effect of restricted units granted under the Partnership’s long-term incentive plan. All common unit equivalents were antidilutive for the three months ended September 30, 2015 because the limited partners were allocated a net loss in this period. All common unit equivalents were antidilutive for the three and nine months ended September 30, 2014 because the limited partners were allocated a net loss in these periods.

(12)
Related Party Transactions

As of September 30, 2015, Martin Resource Management owned 6,264,532 of the Partnership’s common units representing approximately 17.7% of the Partnership’s outstanding limited partner units.  Martin Resource Management controls the Partnership's general partner by virtue of its 51% voting interest in Holdings, the sole member of the Partnership's general partner. The Partnership’s general partner, MMGP, owns a 2% general partner interest in the Partnership and the Partnership’s IDRs.  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, 2015, of approximately 17.7% of the Partnership’s outstanding limited partner 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 agreements and transactions:
 
Omnibus Agreement
 
      Omnibus Agreement.  The Partnership and its general partner are parties to the 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 Martin Resource Management trade names and trademarks. The Omnibus Agreement was amended on November 25, 2009, to include processing crude oil into finished products including naphthenic lubricants, distillates, asphalt and other intermediate cuts. The Omnibus Agreement was amended further on October 1, 2012, to permit the Partnership to provide certain lubricant packaging products and services to Martin Resource Management.

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:

•
providing terminalling and storage services for petroleum products and by-products including the refining, blending and packaging of finished lubricants;

•providing marine transportation of petroleum products and by-products;

21
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2015
(Unaudited)




•distributing NGLs; and

•manufacturing and selling sulfur-based fertilizer products and other sulfur-related products.

This restriction does not apply to:

•
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:

◦
providing land transportation of various liquids;

◦
distributing fuel oil, ammonia, 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 crude oil gathering business in Stephens, Arkansas;

◦
providing crude oil gathering, refining, and marketing services of base oils, asphalt, and distillate products in Smackover, Arkansas;

◦
providing crude oil marketing and transportation from the well head to the end market;

◦
operating an environmental consulting company;

◦
operating an engineering services company;

◦
supplying employees and services for the operation of the Partnership's business;

◦
operating a natural gas optimization business; and

◦
operating, solely for the Partnership's account, the asphalt facilities in Omaha, Nebraska, Port Neches, Texas and South Houston, Texas.

•
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 of the board of directors of the general partner of the Partnership (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.
    
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, under the Omnibus Agreement, the Partnership is required to reimburse Martin Resource Management for indirect general and administrative and corporate overhead expenses.

22
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2015
(Unaudited)




Effective January 1, 2015, through December 31, 2015, the Conflicts Committee approved an annual reimbursement amount for indirect expenses of $13,679.  The Partnership reimbursed Martin Resource Management for $3,420 and $3,134 of indirect expenses for the three months ended September 30, 2015 and 2014, respectively.  The Partnership reimbursed Martin Resource Management for $10,259 and $9,401 of indirect expenses for the nine months ended September 30, 2015 and 2014, 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, engineering, legal, 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. 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 the 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 if such amendment would adversely affect the unitholders. The Omnibus Agreement was first amended on November 25, 2009, to permit the Partnership to provide refining services to Martin Resource Management.  The Omnibus Agreement was amended further on October 1, 2012, to permit the Partnership to provide certain lubricant packaging products and services to Martin Resource Management.  Such amendments were approved by the Conflicts Committee.  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 its 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, as amended, with Martin Transport, Inc., a wholly owned subsidiary of Martin Resource Management through which Martin Transport, Inc. operates its land transportation operations. Under the agreement, Martin Transport, Inc. agreed to transport the Partnership's NGLs as well as other liquid products.

Term and Pricing. 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. These rates are subject to any adjustments which are mutually agreed upon 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.

Indemnification.  Martin Transport, Inc. has indemnified the Partnership against all claims arising out of the negligence or willful misconduct of Martin Transport, Inc. and its officers, employees, agents, representatives and subcontractors. The Partnership indemnified Martin Transport, Inc. against all claims arising out of the negligence or willful misconduct of the Partnership and its officers, employees, agents, representatives and subcontractors. In the event a claim is the result of the joint negligence or misconduct of Martin Transport, Inc. and the Partnership, indemnification obligations will be shared in proportion to each party’s allocable share of such joint negligence or misconduct.

23
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2015
(Unaudited)




Marine Agreements

Marine Transportation Agreement. The Partnership is a party to a marine transportation agreement effective January 1, 2006, as amended, under which the Partnership provides marine transportation services to Martin Resource Management on a spot-contract basis at applicable market rates.  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.

Marine Fuel.  The Partnership is a party to an agreement with Martin Resource Management dated November 1, 2002, under which Martin Resource Management provides the Partnership with marine fuel from its locations in the Gulf of Mexico at a fixed rate in excess of 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.  Effective January 1, 2015, the Partnership entered into a new terminalling services agreement under which the Partnership provides terminal services to Martin Resource Management for marine fuel distribution. This agreement replaced the prior agreement that was in place concerning the same services which was dated October 27, 2004 and consolidated it with the (i) terminalling services agreement entered into in connection with the acquisition of Talen's Marine & Fuel, LLC ("Talen's") and (ii) terminalling services agreement entered into in connection with the acquisition of L&L Holdings LLC ("L&L") into a single agreement. The minimum throughput requirements of the three superseded agreements were aggregated in the new agreement. 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 a 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 amended and restated tolling agreement with Cross Oil Refining and Marketing, Inc. ("Cross") dated October 28, 2014, under which the Partnership processes crude oil into finished products, including naphthenic lubricants, distillates, asphalt and other intermediate cuts for Cross.  The tolling agreement expires November 25, 2031.  Under this tolling agreement, Cross 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, Cross 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, on the third, sixth and ninth anniversaries of the agreement, 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 a second amended and restated sulfuric acid sales agency agreement dated August 5, 2013, under which Martin Resource Management purchases and markets the sulfuric acid produced by the Partnership’s sulfuric acid production plant at Plainview, Texas, that is not consumed by the Partnership’s internal operations.  This agreement, as amended, 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.

24
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2015
(Unaudited)




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 and Condensed 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 captions of the consolidated and condensed financial statements 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 and condensed financial statements as follows:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2015
 
2014
 
2015
 
2014
Revenues:
 
 
 
 
 
 
 
Terminalling and storage
$
15,091

 
$
19,045

 
$
58,626

 
$
55,798

Marine transportation
6,552

 
6,076

 
19,919

 
18,340

Product sales:
 
 
 
 
 
 
 
Natural gas services
479

 
—

 
779

 
3,046

Sulfur services
864

 
708

 
2,908

 
2,931

Terminalling and storage
388

 
175

 
1,392

 
507

 
1,731

 
883

 
5,079

 
6,484

 
$
23,374

 
$
26,004

 
$
83,624

 
$
80,622


The impact of related party cost of products sold is reflected in the consolidated and condensed financial statements as follows:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2015
 
2014
 
2015
 
2014
Cost of products sold:
 
 
 
 
 
 
 
Natural gas services
$
6,470

 
$
9,908

 
$
20,198

 
$
29,169

Sulfur services
3,387

 
4,491

 
10,629

 
13,808

Terminalling and storage
3,227

 
9,174

 
14,261

 
25,571

 
$
13,084

 
$
23,573

 
$
45,088

 
$
68,548


The impact of related party operating expenses is reflected in the consolidated and condensed financial statements as follows:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2015
 
2014
 
2015
 
2014
Operating expenses:
 
 
 
 
 
 
 
Marine transportation
$
8,055

 
$
10,198

 
$
24,653

 
$
28,685

Natural gas services
2,218

 
1,510

 
6,373

 
2,914

Sulfur services
1,649

 
2,121

 
5,348

 
5,641

Terminalling and storage
7,368

 
7,184

 
22,231

 
21,260

 
$
19,290

 
$
21,013

 
$
58,605

 
$
58,500


The impact of related party selling, general and administrative expenses is reflected in the consolidated and condensed financial statements as follows:

25
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2015
(Unaudited)



 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2015
 
2014
 
2015
 
2014
Selling, general and administrative:
 
 
 
 
 
 
 
Marine transportation
$
6

 
$
8

 
$
22

 
$
23

Natural gas services
1,263

 
2,647

 
3,664

 
4,751

Sulfur services
661

 
840

 
2,099

 
2,503

Terminalling and storage
572

 
317

 
1,721

 
1,045

Indirect overhead allocation, net of reimbursement
3,420

 
3,418

 
10,259

 
9,781

 
$
5,922

 
$
7,230

 
$
17,765

 
$
18,103


Other Related Party Transactions

As discussed in Note 6, during March 2013, the Partnership acquired 100% of the preferred interests in MET, a subsidiary of Martin Resource Management, for $15,000. On August 31, 2014, MET converted its preferred equity to subordinated debt. The resulting $15,000 note receivable from MET bears an annual interest rate of 15% and matures August 31, 2026. MET may prepay any or all of the note balance on or after September 1, 2016. The note is recorded in "Note receivable - Martin Energy Trading LLC" on the Partnership's Consolidated and Condensed Balance Sheet. Interest income for the three and nine months ended September 30, 2015 was $567 and $1,683, respectively, and is included in "Interest expense, net" in the Consolidated and Condensed Statements of Operations. Interest income for the three and nine months ended September 30, 2014 was $185 and is included in "Interest expense, net" in the Consolidated and Condensed Statements of Operations.

As discussed in Note 7, during the three months ended September 30, 2015, the Partnership entered into certain derivative financial instruments through March 31, 2016 to protect a portion of its commodity price risk exposure related to NGLs. MET serves as counterparty to the outstanding positions at September 30, 2015.

(13)
Income Taxes

The operations of the Partnership are generally not subject to income taxes because its income is taxed directly to its partners.
    
The Partnership is subject to the Texas margin tax which is included in income tax expense on the Consolidated and Condensed Statements of Operations. The Texas margin tax restructured the state business tax by replacing the taxable capital and earned surplus components of the existing franchise tax with a new "taxable margin" component. Since the tax base on the Texas margin tax is derived from an income-based measure, the margin tax is construed as an income tax and, therefore, the recognition of deferred taxes applies to the margin tax. The impact on deferred taxes as a result of this provision is immaterial.  State income taxes attributable to the Texas margin tax of $200 and $300 were recorded in income tax expense for the three months ended September 30, 2015 and 2014, respectively. State income taxes attributable to the Texas margin tax of $814 and $954 were recorded in income tax expense for the nine months ended September 30, 2015 and 2014, respectively.

(14)
Business Segments

The Partnership has four reportable segments: terminalling and storage, natural gas services, sulfur services and marine transportation. The Partnership’s reportable segments are strategic business units that offer different products and services. The operating income of these segments is reviewed by the chief operating decision maker to assess performance and make business decisions.

The accounting policies of the operating segments are the same as those described in Note 2 in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2014, filed with the SEC on March 2, 2015, as amended, by Amendment No. 1 on Form 10-K/A filed on March 5, 2015. The Partnership evaluates the performance of its reportable segments based on operating income. There is no allocation of administrative expenses or interest expense.    


26
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2015
(Unaudited)



Three Months Ended September 30, 2015
Operating Revenues
 
Intersegment Revenues Eliminations
 
Operating Revenues after Eliminations
 
Depreciation and Amortization
 
Operating Income (Loss) after Eliminations
 
Capital Expenditures and Plant Turnaround Costs
Terminalling and storage
$
68,473

 
$
(1,566
)
 
$
66,907

 
$
9,624

 
$
7,786

 
$
7,928

Natural gas services
103,834

 
—

 
103,834

 
8,522

 
6,265

 
3,784

Sulfur services
36,303

 
—

 
36,303

 
2,129

 
2,908

 
289

Marine transportation
19,522

 
(545
)
 
18,977

 
3,060

 
23

 
717

Indirect selling, general and administrative
—

 
—

 
—

 
—

 
(4,948
)
 
—

Total
$
228,132

 
$
(2,111
)
 
$
226,021

 
$
23,335

 
$
12,034

 
$
12,718

Three Months Ended September 30, 2014
Operating Revenues
 
Intersegment Revenues Eliminations
 
Operating Revenues after Eliminations
 
Depreciation and Amortization
 
Operating Income (Loss) after Eliminations
 
Capital Expenditures and Plant Turnaround Costs
Terminalling and storage
$
80,948

 
$
(1,333
)
 
$
79,615

 
$
9,512

 
$
5,920

 
$
9,825

Natural gas services
223,162

 
—

 
223,162

 
2,398

 
8,651

 
4,611

Sulfur services
50,030

 
—

 
50,030

 
2,078

 
1,635

 
694

Marine transportation
25,858

 
(1,577
)
 
24,281

 
2,469

 
1,454

 
2,245

Indirect selling, general and administrative
—

 
—

 
—

 
—

 
(4,479
)
 
—

Total
$
379,998

 
$
(2,910
)
 
$
377,088

 
$
16,457

 
$
13,181

 
$
17,375

Nine Months Ended September 30, 2015
Operating Revenues
 
Intersegment Revenues Eliminations
 
Operating Revenues after Eliminations
 
Depreciation and Amortization
 
Operating Income (Loss) after Eliminations
 
Capital Expenditures and Plant Turnaround Costs
Terminalling and storage
$
207,794

 
$
(4,065
)
 
$
203,729

 
$
29,030

 
$
20,771

 
$
25,810

Natural gas services
380,974

 
—

 
380,974

 
25,297

 
24,412

 
17,893

Sulfur services
137,814

 
—

 
137,814

 
6,360

 
18,174

 
650

Marine transportation
62,354

 
(2,398
)
 
59,956

 
8,050

 
7,267

 
1,913

Indirect selling, general and administrative
—

 
—

 
—

 
—

 
(14,258
)
 
—

Total
$
788,936

 
$
(6,463
)
 
$
782,473

 
$
68,737

 
$
56,366

 
$
46,266

Nine Months Ended September 30, 2014
Operating Revenues
 
Intersegment Revenues Eliminations
 
Operating Revenues after Eliminations
 
Depreciation and Amortization
 
Operating Income (Loss) after Eliminations
 
Capital Expenditures and Plant Turnaround Costs
Terminalling and storage
$
255,162

 
$
(3,863
)
 
$
251,299

 
$
27,902

 
$
22,596

 
$
43,131

Natural gas services
777,562

 
—

 
777,562

 
2,811

 
25,812

 
5,185

Sulfur services
166,818

 
—

 
166,818

 
6,092

 
17,589

 
3,775

Marine transportation
73,254

 
(3,775
)
 
69,479

 
7,472

 
3,894

 
10,431

Indirect selling, general and administrative
—

 
—

 
—

 
—

 
(14,214
)
 
—

Total
$
1,272,796

 
$
(7,638
)
 
$
1,265,158

 
$
44,277

 
$
55,677

 
$
62,522



27
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2015
(Unaudited)



The Partnership's assets by reportable segment as of September 30, 2015 and December 31, 2014, are as follows:
 
September 30, 2015
 
December 31, 2014
Total assets:
 
 
 
Terminalling and storage
$
423,328

 
$
446,313

Natural gas services
702,318

 
795,462

Sulfur services
135,641

 
145,852

Marine transportation
140,148

 
153,174

Total assets
$
1,401,435

 
$
1,540,801


(15)
Unit Based Awards

The Partnership recognizes compensation cost related to unit-based awards to employees in its consolidated financial statements in accordance with certain provisions of ASC 718. The Partnership recognizes compensation costs related to unit-based awards to directors under certain provisions of ASC 505-50-55 related to equity-based payments to non-employees. Amounts recognized in selling, general, and administrative expense in the consolidated and condensed financial statements with respect to these plans are as follows:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2015
 
2014
 
2015
 
2014
Employees
$
333

 
$
145

 
$
985

 
$
429

Non-employee directors
(3
)
 
56

 
95

 
160

   Total unit-based compensation expense
$
330

 
$
201

 
$
1,080

 
$
589


Long-Term Incentive Plans
    
      The Partnership's general partner has a long-term incentive plan for employees and directors of the general partner and its affiliates who perform services for the Partnership.
  
The plan consists of two components: restricted units and unit options. The plan currently permits the grant of awards covering an aggregate of 725,000 common units, 241,667 of which may be awarded in the form of restricted units and 483,333 of which may be awarded in the form of unit options. The plan is administered by the compensation committee of the general partner’s board of directors (the "Compensation Committee").
  
Restricted Units.  A restricted unit is a unit that is granted to grantees with certain vesting restrictions. Once these restrictions lapse, the grantee is entitled to full ownership of the unit without restrictions. In addition, the restricted units will vest upon a change of control of the Partnership, the general partner or Martin Resource Management or if the general partner ceases to be an affiliate of Martin Resource Management. The Partnership intends the issuance of the common units upon vesting of the restricted units under the plan to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of the common units. Therefore, plan participants will not pay any consideration for the common units they receive, and the Partnership will receive no remuneration for the units. The restricted units issued to directors generally vest in equal annual installments over a four-year period. Restricted units issued to employees generally cliff vest after three years of service.
  

28
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2015
(Unaudited)



 The restricted units are valued at their fair value at the date of grant which is equal to the market value of common units on such date. A summary of the restricted unit activity for the nine months ended September 30, 2015 is provided below:
 
Number of Units
 
Weighted Average Grant-Date Fair Value Per Unit
Non-vested, beginning of period
63,824

 
$
31.02

   Granted
91,950

 
$
28.18

   Vested
(3,550
)
 
$
32.47

   Forfeited
(1,250
)
 
$
30.55

Non-Vested, end of period
150,974

 
$
29.26

 
 
 
 
Aggregate intrinsic value, end of period
$
3,635

 
 
  
A summary of the restricted units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) during the three and nine months ended September 30, 2015 and 2014 is provided below:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2015
 
2014
 
2015
 
2014
Aggregate intrinsic value of units vested
$
—

 
$
—

 
$
110

 
$
249

Fair value of units vested
$
—

 
$
—

 
$
113

 
$
247


As of September 30, 2015, there was $2,227 of unrecognized compensation cost related to non-vested restricted units. That cost is expected to be recognized over a weighted-average period of 1.62 years.

In conjunction with restricted unit issuances during the nine months ended September 30, 2015, the Partnership received $55 in capital contributions from its general partner to maintain its 2% general partnership interest in the Partnership.

Unit Options.  The plan currently permits the grant of options covering common units. As of September 30, 2015, the Partnership has not granted any common unit options to directors or employees of the Partnership's general partner, or its affiliates. In the future, the Compensation Committee may determine to make grants under the plan to employees and directors containing such terms as the Compensation Committee shall determine. Unit options will have an exercise price that, in the discretion of the Compensation Committee, may not be less than the fair market value of the units on the date of grant. In addition, the unit options will become exercisable upon a change in control of the Partnership's general partner, Martin Resource Management, or if the general partner ceases to be an affiliate of Martin Resource Management or upon the achievement of specified financial objectives.

(16)
Condensed Consolidating Financial Information

The Partnership's operations are conducted by its operating subsidiaries as it has no independent assets or operations. Martin Operating Partnership L.P. (the "Operating Partnership"), the Partnership’s wholly-owned subsidiary, and the Partnership's other operating subsidiaries have issued in the past, and may issue in the future, unconditional guarantees of senior or subordinated debt securities of the Partnership. The guarantees that have been issued are full, irrevocable and unconditional and joint and several. In addition, the Operating Partnership may also issue senior or subordinated debt securities which, if issued, will be fully, irrevocably and unconditionally guaranteed by the Partnership. Substantially all of the Partnership's operating subsidiaries are subsidiary guarantors of its outstanding senior unsecured notes and any subsidiaries other than the subsidiary guarantors are minor.
    

29
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
September 30, 2015
(Unaudited)



(17)
Commitments and Contingencies

From time to time, the Partnership is subject to various claims and legal actions arising in the ordinary course of business.  In the opinion of management, the ultimate disposition of these matters will not have a material adverse effect on the Partnership.
    
Pursuant to a Purchase Price Reimbursement Agreement between the Partnership and Martin Resource Management related to the Partnership’s acquisition of the Redbird Gas Storage LLC ("Redbird") Class A interests on October 2, 2012, beginning in the second quarter of 2015, Martin Resource Management will reimburse the Partnership $750 each quarter for four consecutive quarters as a reduction in the purchase price of the Redbird Class A interests.  These payments are a result of Cardinal not achieving certain financial targets set forth in the Purchase Price Reimbursement Agreement.  These payments are considered a reduction of the excess of the purchase price over the carrying value of the assets transferred to the Partnership from Martin Resource Management and will be recorded as an adjustment to "Partners' capital" in each quarter the payments are made. The agreement further provides for purchase price reimbursements of up to $4,500 in 2016 in the event certain financial conditions are not met. Currently, the Partnership has made no determination if the conditions are expected to be met in 2016. For the three and nine months ended September 30, 2015, the Partnership received $750 and $1,500, respectively, related to the Purchase Price Reimbursement Agreement.

The Partnership has been named as a defendant in a case in Cameron Parish, Louisiana that was served on July 17, 2015. The plaintiff alleges that the Partnership has breached a lease agreement by failing to perform work to the plaintiff's property as required under the lease agreement. Prior to this litigation, the Partnership planned to spend $1,600 for such work in 2015. The Partnership intends to vigorously defend this matter and at this time is unable to ascertain the damages, if any, that could ultimately be awarded against it.

(18)
Subsequent Events

Quarterly Distribution. On October 22, 2015, the Partnership declared a quarterly cash distribution of $0.8125 per common unit for the third quarter of 2015, or $3.25 per common unit on an annualized basis, which will be paid on November 13, 2015 to unitholders of record as of November 6, 2015. Additionally, the Partnership expects to pay a distribution to its general partner in the amount of $4,560. Of this amount, $667 is related to the base general partner distribution and $3,893 represents incentive distribution rights paid to the general partner.

    


30


Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations

References in this quarterly report on Form 10-Q to "Martin Resource Management" refer to Martin Resource Management Corporation and its subsidiaries, unless the context otherwise requires. You should read the following discussion of our financial condition and results of operations in conjunction with the consolidated and condensed financial statements and the notes thereto included elsewhere in this quarterly report.

Forward-Looking Statements

This quarterly report on Form 10-Q includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Statements included in this quarterly report that are not historical facts (including any statements concerning plans and objectives of management for future operations or economic performance, or assumptions or forecasts related thereto), including, without limitation, the information set forth in Management’s Discussion and Analysis of Financial Condition and Results of Operations, are forward-looking statements. These statements can be identified by the use of forward-looking terminology including "forecast," "may," "believe," "will," "expect," "anticipate," "estimate," "continue," or other similar words. These statements discuss future expectations, contain projections of results of operations or of financial condition or state other "forward-looking" information. We and our representatives may from time to time make other oral or written statements that are also forward-looking statements.

These forward-looking statements are made based upon management’s current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number of risks and uncertainties. We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements.

Because these forward-looking statements involve risks and uncertainties, actual results could differ materially from those expressed or implied by these forward-looking statements for a number of important reasons, including those discussed under "Item 1A. Risk Factors" of our Form 10-K for the year ended December 31, 2014, filed with the Securities and Exchange Commission (the "SEC") on March 2, 2015, as amended, by Amendment No. 1 on Form 10-K/A for the year ended December 31, 2014 filed on March 5, 2015, and in this report.

Overview
 
We are a publicly traded limited partnership with a diverse set of operations focused primarily in the United States ("U.S.") Gulf Coast region. Our four primary business lines include:

•
Terminalling and storage services for petroleum products and by-products including the refining of naphthenic crude oil, blending and packaging of finished lubricants;

•
Natural gas liquids transportation and distribution services and natural gas storage;

•
Sulfur and sulfur-based products gathering, processing, marketing, manufacturing and distribution; and

•
Marine transportation services for petroleum products and by-products.

The petroleum products and by-products we collect, transport, store and market are produced primarily by major and independent oil and gas companies who often turn to third parties, such as us, for the transportation and disposition of these products. In addition to these major and independent oil and gas companies, our primary customers include independent refiners, large chemical companies, fertilizer manufacturers and other wholesale purchasers of these products. We operate primarily in the U.S. Gulf Coast region. This region is a major hub for petroleum refining, natural gas gathering and processing, and support services for the exploration and production industry.

We were formed in 2002 by Martin Resource Management, a privately-held company whose initial predecessor was incorporated in 1951 as a supplier of products and services to drilling rig contractors. Since then, Martin Resource Management has expanded its operations through acquisitions and internal expansion initiatives as its management identified and capitalized on the needs of producers and purchasers of petroleum products and by-products and other bulk liquids. Martin Resource Management is an important supplier and customer of ours. As of September 30, 2015, Martin Resource Management owned 17.7% of our total outstanding common limited partner units. Furthermore, Martin Resource Management

31

controls Martin Midstream GP LLC ("MMGP"), our general partner, by virtue of its 51% voting interest in MMGP Holdings, LLC ("Holdings"), the sole member of MMGP. MMGP owns a 2% general partner interest in us and all of our incentive distribution rights. Martin Resource Management directs our business operations through its ownership interests in and control of our general partner.

We entered into an omnibus agreement dated November 1, 2002, with Martin Resource Management (the "Omnibus Agreement") 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 our use of certain of Martin Resource Management’s trade names and trademarks. Under the terms of the Omnibus Agreement, the employees of Martin Resource Management are responsible for conducting our business and operating our assets.

Martin Resource Management has operated our business since 2002.  Martin Resource Management began operating our natural gas services business in the 1950s and our sulfur business in the 1960s. It began our marine transportation business in the late 1980s. It entered into our fertilizer and terminalling and storage businesses in the early 1990s. In recent years, Martin Resource Management has increased the size of our asset base through expansions and strategic acquisitions.

Recent Developments

We believe one of the rationales driving investment in master limited partnerships, including us, is the opportunity for distribution growth offered by the partnerships. Such distribution growth is a function of having access to liquidity in the financial markets used for incremental capital investment (development projects and acquisitions) to grow distributable cash flow.
 
We continually adjust our business strategy to focus on maximizing liquidity, maintaining a stable asset base which generates fee based revenues not sensitive to commodity prices, and improving profitability by increasing asset utilization and 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.

Reduction of Commitments Under Revolving Credit Facility. On August 14, 2015, we notified the Royal Bank of Canada, the administrative agent of our revolving credit facility, that we were reducing the aggregate committed sum (as defined in the underlying credit agreement) from $900.0 million to $700.0 million. We have the ability to exercise the accordion feature of our revolving credit facility at any time and expand the facility up to an aggregate committed sum of $1.0 billion. As a result of the decreased capacity, we expect to reduce the amount of commitment fees under our revolving credit facility by approximately $1.0 million on an annual basis.

Disposition of Floating Storage Assets. On February 12, 2015, we sold six liquefied petroleum gas pressure barges (collectively referred to as the "Floating Storage Assets") for $41.3 million. These assets were primarily operated under the floating storage component of our NGL distribution business. The proceeds from the disposition were used to reduce outstanding indebtedness under our revolving credit facility.    

Public Offering. On September 29, 2014, we completed a public offering of 3,450,000 common units at a price of $36.91 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 3,450,000 common units, net of underwriters' discounts, commissions and offering expenses, were $122.2 million.  Our general partner contributed $2.6 million in cash to us in conjunction with the issuance in order to maintain its 2.0% general partner interest in us.  All of the net proceeds were used to reduce outstanding indebtedness under our revolving credit facility.

Cardinal Gas Storage. On August 29, 2014, Redbird Gas Storage LLC ("Redbird"), a wholly owned subsidiary of the Partnership, completed the previously announced purchase of all of the outstanding membership interests of Cardinal Gas Storage Partners LLC ("Cardinal") from Energy Capital Partners I, LP, Energy Capital Partners I-A, LP, Energy Capital Partners I-B IP, LP and Energy Capital Partners I (Cardinal IP), LP (together, "ECP") for cash of approximately $121.0 million. Prior to the acquisition, we owned an approximate 42.2% interest in the Category A membership interests in Cardinal. As a result of the acquisition, Redbird owns 100% of the outstanding membership interests in Cardinal. Concurrent with the closing of the transaction, we retired all of the project level financing of various Cardinal subsidiaries. This transaction and repayment of the project financings was funded with borrowings under our revolving credit facility. On October 27, 2014, Cardinal merged with and into Redbird, and Redbird subsequently changed its name to Cardinal.


32

Subsequent Events

Quarterly Distribution.  On October 22, 2015, we declared a quarterly cash distribution of $0.8125 per common unit for the third quarter of 2015, or $3.25 per common unit on an annualized basis, which will be paid on November 13, 2015 to unitholders of record as of November 6, 2015. Additionally, we expect to pay a distribution to our general partner in the amount of $4.6 million. Of this amount, $0.7 million is related to the base general partner distribution and $3.9 million represents incentive distribution rights paid to our general partner.

Critical Accounting Policies and Estimates    

Our discussion and analysis of our financial condition and results of operations are based on the historical consolidated and condensed financial statements included elsewhere herein. We prepared these financial statements in conformity with United States generally accepted accounting principles ("U.S. GAAP" or "GAAP"). The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. We base our estimates on historical experience and on various other assumptions we believe to be reasonable under the circumstances. We routinely evaluate these estimates, utilizing historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Our results may differ from these estimates, and any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Changes in these estimates could materially affect our financial position, results of operations or cash flows. You should also read Note 2, "Significant Accounting Policies" in Notes to Consolidated Financial Statements included within our Annual Report on Form 10-K for the year ended December 31, 2014. The following table evaluates the potential impact of estimates utilized during the periods ended September 30, 2015 and 2014:

Description
 
Judgments and Uncertainties
 
Effect if Actual Results Differ from Estimates and Assumptions
Allowance for Doubtful Accounts
We evaluate our allowance for doubtful accounts on an ongoing basis and record adjustments when, in management's judgment, circumstances warrant. Reserves are recorded to reduce receivables to the amount ultimately expected to be collected.
 
We evaluate the collectability of our accounts receivable based on factors such as the customer's ability to pay, the age of the receivable and our historical collection experience. A deterioration in any of these factors could result in an increase in the allowance for doubtful accounts balance.
 
If actual collection results are not consistent with our judgments, we may experience an increase in uncollectible receivables. A 10% increase in our allowance for doubtful accounts would not significantly impact net income.
Depreciation
Depreciation expense is computed using the straight-line method over the useful life of the assets.
 
Determination of depreciation expense requires judgment regarding estimated useful lives and salvage values of property, plant and equipment. As circumstances warrant, estimates are reviewed to determine if any changes in the underlying assumptions are needed.
 
The lives of our fixed assets range from 3 - 50 years. If the depreciable lives of our assets were decreased by 10%, we estimate that annual depreciation expense would increase approximately $7.4 million, resulting in a corresponding reduction in net income.
Impairment of Long-Lived Assets
We periodically evaluate whether the carrying value of long-lived assets has been impaired when circumstances indicate the carrying value of the assets may not be recoverable. These evaluations are based on undiscounted cash flow projections over the remaining useful life of the asset. The carrying value is not recoverable if it exceeds the sum of the undiscounted cash flows. Any impairment loss is measured as the excess of the asset's carrying value over its fair value.
 
Our impairment analyses require management to use judgment in estimating future cash flows and useful lives, as well as assessing the probability of different outcomes.
 
Applying this impairment review methodology, we recorded an impairment charge of $3.4 million in our Marine Transportation segment during the three and nine month periods ended September 30, 2014. No impairment was recored during the three and nine months ended September 30, 2015.
Impairment of Goodwill

33

Goodwill is subject to a fair-value based impairment test on an annual basis, or more frequently if events or changes in circumstances indicate that the fair value of any of our reporting units is less than its carrying amount.
 
We determine fair value using accepted valuation techniques, including discounted cash flow, the guideline public company method and the guideline transaction method. These analyses require management to make assumptions and estimates regarding industry and economic factors, future operating results and discount rates. We conduct impairment testing using present economic conditions, as well as future expectations.
 
We are in the process of completing the most recent annual review of goodwill as of August 31, 2015. Based on the preliminary results of the evaluation, no impairment is indicated.
Purchase Price Allocations
We allocate the purchase price of an acquired business to its identifiable assets (including identifiable intangible assets) and liabilities based on their fair values at the date of acquisition. Any excess of purchase price in excess of amounts allocated to identifiable assets and liabilities is recorded as goodwill. As additional information becomes available, we may adjust the preliminary allocation for a period of up to one year.
 
The determination of fair values of acquired assets and liabilities requires a significant level of management judgment. Fair values are estimated using various methods as deemed appropriate. For significant transactions, third party assessments may be engaged to assist in the valuation process.
 
If subsequent factors indicate that estimates and assumptions used to allocate costs to acquired assets and liabilities differ from actual results, the allocation between goodwill, other intangible assets and fixed assets could significantly differ. Any such differences could impact future earnings through depreciation and amortization expense. Additionally, if estimated results supporting the valuation of goodwill or other intangible assets are not achieved, impairments could result.
Asset Retirement Obligations
Asset retirement obligations ("AROs") associated with a contractual or regulatory remediation requirement are recorded at fair value in the period in which the obligation can be reasonably estimated and depreciated over the life of the related asset or contractual term. The liability is determined using a credit-adjusted risk-free interest rate and is accreted over time until the obligation is settled.
 
Determining the fair value of AROs requires management judgment to evaluate required remediation activities, estimate the cost of those activities and determine the appropriate interest rate.
 
If actual results differ from judgments and assumptions used in valuing an ARO, we may experience significant changes in ARO balances. The establishment of an ARO has no initial impact on earnings.
Environmental Liabilities
We estimate environmental liabilities using both internal and external resources. Activities include feasibility studies and other evaluations management considers appropriate. Environmental liabilities are recorded in the period in which the obligation can be reasonably estimated.
 
Estimating environmental liabilities requires significant management judgment as well as possible use of third party specialists knowledgeable in such matters.
 
Environmental liabilities have not adversely affected our results of operations or financial condition in the past, and we do not anticipate that they will in the future.

Our Relationship with Martin Resource Management
 
Martin Resource Management is engaged in the following principal business activities:
 
•
providing land transportation of various liquids using a fleet of trucks and road vehicles and road trailers;

•
distributing fuel oil, ammonia, asphalt, sulfuric acid, marine fuel and other liquids;

•
providing marine bunkering and other shore-based marine services in Alabama, Louisiana, Florida, Mississippi and Texas;

•
operating a crude oil gathering business in Stephens, Arkansas;

•
providing crude oil gathering, refining, and marketing services of base oils, asphalt, and distillate products in Smackover, Arkansas;

34


•
providing crude oil marketing and transportation from the well head to the end market;

•
operating an environmental consulting company;

•
operating an engineering services company;

•
supplying employees and services for the operation of our business;

•
operating a natural gas optimization business;

•
operating, for its account and our account, the docks, roads, loading and unloading facilities and other common use facilities or access routes at our Stanolind terminal; and

•
operating, solely for our account, the asphalt facilities in Omaha, Nebraska, Port Neches, Texas and South Houston, Texas.

We are and will continue to be closely affiliated with Martin Resource Management as a result of the following relationships.

Ownership

Martin Resource Management owns approximately 17.7% of the outstanding limited partner units. In addition, Martin Resource Management controls MMGP, our general partner, by virtue of its 51% voting interest in Holdings, the sole member of MMGP. MMGP owns a 2% general partner interest in us and all of our incentive distribution rights.

Management

Martin Resource Management directs our business operations through its ownership interests in and control of our general partner. We benefit from our relationship with Martin Resource Management through access to a significant pool of management expertise and established relationships throughout the energy industry. We do not have employees. Martin Resource Management employees are responsible for conducting our business and operating our assets on our behalf.

Related Party Agreements

The Omnibus Agreement requires us to reimburse Martin Resource Management for all direct expenses it incurs or payments it makes on our behalf or in connection with the operation of our business.  We reimbursed Martin Resource Management for $34.9 million of direct costs and expenses for the three months ended September 30, 2015 compared to $48.4 million for the three months ended September 30, 2014. We reimbursed Martin Resource Management for $111.2 million of direct costs and expenses for the nine months ended September 30, 2015 compared to $135.4 million for the nine months ended September 30, 2014. There is no monetary limitation on the amount we are required to reimburse Martin Resource Management for direct expenses.

In addition to the direct expenses, under the Omnibus Agreement, we are required to reimburse Martin Resource Management for indirect general and administrative and corporate overhead expenses.  For the three months ended September 30, 2015 and 2014, the conflicts committee of our general partner's board of directors ("Conflicts Committee") approved reimbursement amounts of $3.4 million and $3.1 million, respectively, reflecting our allocable share of such expenses. For the nine months ended September 30, 2015 and 2014, the Conflicts Committee approved reimbursement amounts of $10.3 million and $9.4 million million, respectively. The Conflicts Committee will review and approve future adjustments in the reimbursement amount for indirect expenses, if any, annually.  These indirect expenses covered the centralized corporate functions Martin Resource Management provides for us, such as accounting, treasury, clerical, engineering, legal, billing, information technology, administration of insurance, general office expenses and employee benefit plans and other general corporate overhead functions we share with Martin Resource Management’s retained businesses.  The Omnibus Agreement also contains significant non-compete provisions and indemnity obligations.  Martin Resource Management also licenses certain of its trademarks and trade names to us under the Omnibus Agreement.

The agreements include, but are not limited to, motor carrier agreements, marine transportation agreements, terminal services agreements, a tolling agreement, a sulfuric acid agreement, and various other miscellaneous agreements. Pursuant to

35

the terms of the Omnibus Agreement, we are prohibited from entering into certain material agreements with Martin Resource Management without the approval of the Conflicts Committee.

For a more comprehensive discussion concerning the Omnibus Agreement and the other agreements that we have entered into with Martin Resource Management, please refer to "Item 13. Certain Relationships and Related Transactions, and Director Independence" set forth in our Annual Report on Form 10-K for the year ended December 31, 2014, filed with the SEC on March 2, 2015, as amended by Amendment No. 1 on Form 10-K/A filed on March 5, 2015.

Commercial

We have been and anticipate that we will continue to be both a significant customer and supplier of products and services offered by Martin Resource Management. Our motor carrier agreement with Martin Resource Management provides us with access to Martin Resource Management’s fleet of road vehicles and road trailers to provide land transportation in the areas served by Martin Resource Management. Our ability to utilize Martin Resource Management’s land transportation operations is currently a key component of our integrated distribution network.

In the aggregate, the impact of related party transactions included in cost of products sold accounted for approximately 10% and 8% of our total cost of products sold during the three months ended September 30, 2015 and 2014, respectively. In the aggregate, the impact of related party transactions included in cost of products sold accounted for approximately 9% and 7% of our total cost of products sold during the nine months ended September 30, 2015 and 2014, respectively. We also purchase marine fuel from Martin Resource Management, which we account for as an operating expense.

Correspondingly, Martin Resource Management is one of our significant customers. Our sales to Martin Resource Management accounted for approximately 10% and 7% of our total revenues for the three months ended September 30, 2015 and 2014, respectively.  Our sales to Martin Resource Management accounted for approximately 11% and 6% of our total revenues for the nine months ended September 30, 2015 and 2014, respectively.  We have entered into certain agreements with Martin Resource Management pursuant to which we provide terminalling and storage and marine transportation services to its subsidiary, Martin Energy Services, LLC ("MES"), and MES provides terminal services to us to handle lubricants, greases and drilling fluids.  Additionally, we have entered into a long-term, fee for services-based tolling agreement with Martin Resource Management where Martin Resource Management agrees to pay us for the processing of its crude oil into finished products, including naphthenic lubricants, distillates, asphalt and other intermediate cuts.

For a more comprehensive discussion concerning the agreements that we have entered into with Martin Resource Management, please refer to "Item 13. Certain Relationships and Related Transactions, and Director Independence" set forth in our Annual Report on Form 10-K for the year ended December 31, 2014, filed with the SEC on March 2, 2015, as amended by Amendment No. 1 on Form 10-K/A filed on March 5, 2015.

Approval and Review of Related Party Transactions

If we contemplate entering into a transaction, other than a routine or in the ordinary course of business transaction, in which a related person will have a direct or indirect material interest, the proposed transaction is submitted for consideration to the board of directors of our general partner or to our management, as appropriate. If the board of directors of our general partner is involved in the approval process, it determines whether to refer the matter to the Conflicts Committee of our general partner's board of directors, as constituted under our limited partnership agreement. If a matter is referred to the Conflicts Committee, it obtains information regarding the proposed transaction from management and determines whether to engage independent legal counsel or an independent financial advisor to advise the members of the committee regarding the transaction.  If the Conflicts Committee retains such counsel or financial advisor, it considers such advice and, in the case of a financial advisor, such advisor’s opinion as to whether the transaction is fair and reasonable to us and to our unitholders.

How We Evaluate Our Operations

Our management uses a variety of financial and operational measurements other than our financial statements prepared in accordance with U.S. GAAP to analyze our performance. These include: (1) net income before interest expense, income tax expense, and depreciation and amortization ("EBITDA"), (2) adjusted EBITDA and (3) distributable cash flow. Our management views these measures as important performance measures of core profitability for our operations and the ability to generate and distribute cash flow, and as key components of our internal financial reporting. We believe investors benefit from having access to the same financial measures that our management uses.


36

EBITDA and Adjusted EBITDA. Certain items excluded from EBITDA and adjusted EBITDA are significant components in understanding and assessing an entity's financial performance, such as cost of capital and historical costs of depreciable assets. We have included information concerning EBITDA and adjusted EBITDA because they provide investors and management with additional information to better understand the following: financial performance of our assets without regard to financing methods, capital structure or historical cost basis; our operating performance and return on capital as compared to those of other similarly situated entities; and the viability of acquisitions and capital expenditure projects. Our method of computing adjusted EBITDA may not be the same method used to compute similar measures reported by other entities. The economic substance behind our use of adjusted EBITDA is to measure the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness and make distributions to our unit holders.

Distributable Cash Flow. Distributable cash flow is a significant performance measure used by our management and by external users of our financial statements, such as investors, commercial banks and research analysts, to compare basic cash flows generated by us to the cash distributions we expect to pay our unitholders. Distributable cash flow is also an important financial measure for our unitholders since it serves as an indicator of our success in providing a cash return on investment. Specifically, this financial measure indicates to investors whether or not we are generating cash flow at a level that can sustain or support an increase in our quarterly distribution rates. Distributable cash flow is also a quantitative standard used throughout the investment community with respect to publicly-traded partnerships because the value of a unit of such an entity is generally determined by the unit's yield, which in turn is based on the amount of cash distributions the entity pays to a unitholder.

EBITDA, adjusted EBITDA and distributable cash flow should not be considered alternatives to, or more meaningful than, net income, cash flows from operating activities, or any other measure presented in accordance with U.S. GAAP. Our method of computing these measures may not be the same method used to compute similar measures reported by other entities.

Non-GAAP Financial Measures

The following table reconciles the non-GAAP financial measurements used by management to our most directly comparable GAAP measures for the three and nine months ended September 30, 2015 and 2014.


37

Reconciliation of EBITDA, Adjusted EBITDA, and Distributable Cash Flow
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2015
 
2014
 
2015
 
2014
 
(in thousands)
Net income (loss)
$
3,330

 
$
(26,905
)
 
$
31,539

 
$
(16,078
)
Less: (Income) loss from discontinued operations, net of income taxes
—

 
1,167

 
(1,215
)
 
3,048

Income (loss) from continuing operations
3,330

 
(25,738
)
 
30,324

 
(13,030
)
Adjustments:
 
 
 
 
 
 
 
Interest expense
11,994

 
11,459

 
32,465

 
34,351

Income tax expense
200

 
300

 
814

 
954

Depreciation and amortization
23,335

 
16,457

 
68,737

 
44,277

EBITDA
38,859

 
2,478

 
132,340

 
66,552

Adjustments:
 
 
 
 
 
 
 
Equity in earnings of unconsolidated entities
(2,363
)
 
(2,655
)
 
(5,752
)
 
(4,297
)
(Gain) loss on sale of property, plant and equipment
1,586

 
—

 
1,751

 
(54
)
Impairment of long-lived assets
—

 
3,445

 
—

 
3,445

Unrealized mark to market on commodity derivatives
358

 
(21
)
 
358

 
(21
)
Reduction in carrying value of investment in Cardinal due to the purchase of the controlling interest
—

 
30,102

 
—

 
30,102

Debt prepayment premium
—

 
—

 
—

 
7,767

Gain on retirement of senior unsecured notes
(728
)
 
—

 
(728
)
 
—

Distributions from unconsolidated entities
3,400

 
982

 
7,800

 
2,323

Unit-based compensation
330

 
201

 
1,080

 
589

Adjusted EBITDA
41,442

 
34,532

 
136,849

 
106,406

Adjustments:
 
 
 
 
 
 
 
Interest expense
(11,994
)
 
(11,459
)
 
(32,465
)
 
(34,351
)
Income tax expense
(200
)
 
(300
)
 
(814
)
 
(954
)
Amortization of debt discount
—

 
—

 
—

 
1,305

Amortization of debt premium
(82
)
 
(82
)
 
(246
)
 
(164
)
Amortization of deferred debt issuance costs
2,400

 
827

 
4,142

 
5,415

Non-cash mark-to-market on derivatives
—

 
(58
)
 
—

 
489

Payments for plant turnaround costs
—

 
(90
)
 
(1,754
)
 
(4,000
)
Maintenance capital expenditures
(2,438
)
 
(4,306
)
 
(7,621
)
 
(13,260
)
Distributable Cash Flow
$
29,128

 
$
19,064

 
$
98,091

 
$
60,886


Results of Operations

The results of operations for the three and nine months ended September 30, 2015 and 2014 have been derived from our consolidated and condensed financial statements.

We evaluate segment performance on the basis of operating income, which is derived by subtracting cost of products sold, operating expenses, selling, general and administrative expenses, and depreciation and amortization expense from revenues.  The following table sets forth our operating revenues and operating income by segment for the three and nine months ended September 30, 2015 and 2014.  The results of operations for these interim periods are not necessarily indicative of the results of operations which might be expected for the entire year.

Our consolidated and condensed results of operations are presented on a comparative basis below.  There are certain items of income and expense which we do not allocate on a segment basis.  These items, including equity in earnings (loss) of

38

unconsolidated entities, interest expense, and indirect selling, general and administrative expenses, are discussed following the comparative discussion of our results within each segment.

Three Months Ended September 30, 2015 Compared to the Three Months Ended September 30, 2014
 
Operating Revenues
 
Intersegment Revenues Eliminations
 
Operating Revenues
 after Eliminations
 
Operating Income (Loss)
 
Operating Income (Loss) Intersegment Eliminations
 
Operating
Income (Loss)
 after
Eliminations
Three Months Ended September 30, 2015
(in thousands)
Terminalling and storage
$
68,473

 
$
(1,566
)
 
$
66,907

 
$
8,823

 
$
(1,037
)
 
$
7,786

Natural gas services
103,834

 
—

 
103,834

 
5,503

 
762

 
6,265

Sulfur services
36,303

 
—

 
36,303

 
3,573

 
(665
)
 
2,908

Marine transportation
19,522

 
(545
)
 
18,977

 
(917
)
 
940

 
23

Indirect selling, general and administrative
—

 
—

 
—

 
(4,948
)
 
—

 
(4,948
)
Total
$
228,132

 
$
(2,111
)
 
$
226,021

 
$
12,034

 
$
—

 
$
12,034

Three Months Ended September 30, 2014
 
 
 
 
 
 
 
 
 
 
 
Terminalling and storage
$
80,948

 
$
(1,333
)
 
$
79,615

 
$
6,298

 
$
(378
)
 
$
5,920

Natural gas services
223,162

 
—

 
223,162

 
7,606

 
1,045

 
8,651

Sulfur services
50,030

 
—

 
50,030

 
3,357

 
(1,722
)
 
1,635

Marine transportation
25,858

 
(1,577
)
 
24,281

 
399

 
1,055

 
1,454

Indirect selling, general and administrative
—

 
—

 
—

 
(4,479
)
 
—

 
(4,479
)
Total
$
379,998

 
$
(2,910
)
 
$
377,088

 
$
13,181

 
$
—

 
$
13,181



Nine Months Ended September 30, 2015 Compared to the Nine Months Ended September 30, 2014
 
Operating Revenues
 
Intersegment Revenues Eliminations
 
Operating Revenues
 after Eliminations
 
Operating Income (Loss)
 
Operating Income (Loss) Intersegment Eliminations
 
Operating
Income (Loss)
 after
Eliminations
Nine Months Ended September 30, 2015
(in thousands)
Terminalling and storage
$
207,794

 
$
(4,065
)
 
$
203,729

 
$
22,736

 
$
(1,965
)
 
$
20,771

Natural gas services
380,974

 
—

 
380,974

 
22,739

 
1,673

 
24,412

Sulfur services
137,814

 
—

 
137,814

 
20,932

 
(2,758
)
 
18,174

Marine transportation
62,354

 
(2,398
)
 
59,956

 
4,217

 
3,050

 
7,267

Indirect selling, general and administrative
—

 
—

 
—

 
(14,258
)
 
—

 
(14,258
)
Total
$
788,936

 
$
(6,463
)
 
$
782,473

 
$
56,366

 
$
—

 
$
56,366



39

 
Operating Revenues
 
Intersegment Revenues Eliminations
 
Operating Revenues
 after Eliminations
 
Operating Income (Loss)
 
Operating Income (Loss) Intersegment Eliminations
 
Operating
Income (Loss)
 after
Eliminations
Nine Months Ended September 30, 2014
(in thousands)
Terminalling and storage
$
255,162

 
$
(3,863
)
 
$
251,299

 
$
24,505

 
$
(1,909
)
 
$
22,596

Natural gas services
777,562

 
—

 
777,562

 
22,947

 
2,865

 
25,812

Sulfur services
166,818

 
—

 
166,818

 
21,758

 
(4,169
)
 
17,589

Marine transportation
73,254

 
(3,775
)
 
69,479

 
681

 
3,213

 
3,894

Indirect selling, general and administrative
—

 
—

 
—

 
(14,214
)
 
—

 
(14,214
)
Total
$
1,272,796

 
$
(7,638
)
 
$
1,265,158

 
$
55,677

 
$
—

 
$
55,677

 
Terminalling and Storage Segment

Comparative Results of Operations for the Three Months Ended September 30, 2015 and 2014
 
Three Months Ended September 30,
 
Variance
 
Percent Change
 
2015
 
2014
 
 
 
(In thousands, except BBL per day)
 
 
Revenues:
 
 
 
 
 
 
 
Services
$
35,144

 
$
33,213

 
$
1,931

 
6%
Products
33,329

 
47,735

 
(14,406
)
 
(30)%
Total revenues
68,473

 
80,948

 
(12,475
)
 
(15)%
 
 
 
 
 
 
 
 
Cost of products sold
28,765

 
43,193

 
(14,428
)
 
(33)%
Operating expenses
20,268

 
21,506

 
(1,238
)
 
(6)%
Selling, general and administrative expenses
995

 
786

 
209

 
27%
Depreciation and amortization
9,624

 
9,512

 
112

 
1%
 
8,821

 
5,951

 
2,870

 
48%
Other operating income
2

 
347

 
(345
)
 
(99)%
Operating income
$
8,823

 
$
6,298

 
$
2,525

 
40%
 
 
 
 
 
 
 
 
Lubricant sales volumes (gallons)
5,974

 
8,193

 
(2,219
)
 
(27)%
Shore-based throughput volumes (gallons)
36,383

 
64,338

 
(27,955
)
 
(43)%
Smackover refinery throughput volumes (BBL per day)
6,205

 
7,123

 
(918
)
 
(13)%
Corpus Christi crude terminal (BBL per day)
148,377

 
173,315

 
(24,938
)
 
(14)%

Services revenues.  Services revenue increased $1.9 million, which includes increases of $0.8 million at our specialty terminals due to increased through-put and pass-through revenue, an increase of $0.5 million at our shore based terminals primarily due to increased consigned lube revenue, and an increase of $0.6 million at the Smackover refinery primarily due to an increase in reservation fee revenue and minimum through-put revenue. Throughput volumes at our Smackover refinery decreased compared to the third quarter of 2014 as a result of downtime experienced in the third quarter of 2015 related to operational repairs and maintenance.

Products revenues. A 44% decrease in sales volumes at our blending and packaging facilities resulted in a $14.5 million decrease to products revenues. The decline in volumes resulted primarily from increased price competition. The average sales price from our blending and packaging assets increased 2%, resulting in a $0.7 million increase in products revenues. The average sales price at our shore based terminals decreased 14%, resulting in a $2.1 million decrease in products revenues. An 11% increase in sales volumes at our shore based terminal resulted in a $1.5 million increase to products revenues.


40

Cost of products sold.  A 44% decrease in sales volumes at our blending and packaging facilities resulted in an $11.7 million decrease in cost of products sold. The average price per gallon decreased 7%, resulting in a $1.9 million decrease in cost of products sold. The average price per gallon decreased 15%, resulting in a $2.2 million decrease in cost of products sold at our shore based terminals. An 11% increase in sales volumes at our shore based terminals resulted in a $1.4 million increase to cost of products sold.

Operating expenses. Operating expenses at our Smackover refinery decreased $1.2 million, primarily due to decreases in outside services of $0.4 million, utilities of $0.3 million, and taxes of $0.3 million.

Selling, general and administrative expenses.  Selling, general and administrative expenses increased in our blending and packaging operations related to increased bad debt expense of $0.1 million and compensation expense of $0.1 million.

Depreciation and amortization.  The increase in depreciation and amortization is due to the impact of recent capital expenditures.

Other operating income.  Other operating income represents gains from the disposition of property, plant and equipment.

Comparative Results of Operations for the Nine Months Ended September 30, 2015 and 2014
 
Nine Months Ended September 30,
 
Variance
 
Percent Change
 
2015
 
2014
 
 
 
(In thousands, except BBL per day)
 
 
Revenues:
 
 
 
 
 
 
 
Services
$
104,893

 
$
101,711

 
$
3,182

 
3%
Products
102,901

 
153,451

 
(50,550
)
 
(33)%
Total revenues
207,794

 
255,162

 
(47,368
)
 
(19)%
 
 
 
 
 
 
 
 
Cost of products sold
90,076

 
139,028

 
(48,952
)
 
(35)%
Operating expenses
62,947

 
61,628

 
1,319

 
2%
Selling, general and administrative expenses
2,806

 
2,484

 
322

 
13%
Depreciation and amortization
29,030

 
27,902

 
1,128

 
4%
 
22,935

 
24,120

 
(1,185
)
 
(5)%
Other operating income (loss)
(199
)
 
385

 
(584
)
 
(152)%
Operating income
$
22,736

 
$
24,505

 
$
(1,769
)
 
(7)%
 
 
 
 
 
 
 
 
Lubricant sales volumes (gallons)
18,007

 
26,170

 
(8,163
)
 
(31)%
Shore-based throughput volumes (gallons)
122,743

 
186,956

 
(64,213
)
 
(34)%
Smackover refinery throughput volumes (BBL per day)
6,091

 
5,803

 
288

 
5%
Corpus Christi crude terminal (BBL per day)
166,129

 
160,332

 
5,797

 
4%

Services revenues. Services revenue increased $3.2 million, including $2.0 million at our Smackover refinery related to increased reservation fees and tolling fees and $1.3 million at our shore based terminals related to an increase in through-put rate and increased consigned lubricants revenue. Historical throughput volumes at our Smackover refinery are down for each nine month period presented as a result of a significant turnaround experienced during the first quarter of 2014 and downtime experienced in the third quarter of 2015 related to operational repairs and maintenance.

Products revenues. A 46% decrease in sales volumes at our blending and packaging facilities resulted in a $47.2 million decrease to products revenues. The decline in volumes resulted primarily from increased price competition. The average sales price from our blending and packaging assets increased 2%, resulting in a $1.6 million offsetting increase in products revenues. The average sales price at our shore based terminals decreased 13%, resulting in a $6.6 million decrease in products revenues. A 4% increase in sales volumes at our shore based terminals resulted in a $1.7 million increase to products revenues.

Cost of products sold.  A 46% decrease in sales volumes at our blending and packaging facilities resulted in a $39.3 million decrease in cost of products sold. Average price per gallon decreased 5%, resulting in a $4.8 million decrease in cost of

41

products sold. The average price per gallon decreased 13%, resulting in a $6.4 million decrease in cost of products sold at our shore based terminals. A 4% increase in sales volumes at our shore based terminals resulted in a $1.6 million increase to products revenue.

Operating expenses. Operating expenses at our specialty terminals increased $2.0 million, primarily as a result of $2.3 million in increased repairs and maintenance, offset by a $0.4 million decrease related to property taxes. Operating expenses at our Smackover refinery decreased $0.9 million related to a decrease in outside services.

Selling, general and administrative expenses.   Selling, general and administrative expenses increased $0.3 million in our blending and packaging operations as a result of the revision of the classification of certain employees' labor costs from cost of products sold in the 2014 period.

Depreciation and amortization.  The increase in depreciation and amortization is due to the impact of recent capital expenditures.

Other operating income (loss).  Other operating income (loss) represents gains and losses from the disposition of property, plant and equipment.

Natural Gas Services Segment

Comparative Results of Operations for the Three Months Ended September 30, 2015 and 2014
 
Three Months Ended September 30,
 
Variance
 
Percent Change
 
2015
 
2014
 
 
 
(In thousands)
 
 
Revenues:
 
 
 
 
 
 
 
Services
$
17,120

 
$
5,764

 
$
11,356

 
197%
Products
86,714

 
217,398

 
(130,684
)
 
(60)%
Total revenues
103,834

 
223,162

 
(119,328
)
 
(53)%
 
 
 
 
 
 
 
 
Cost of products sold
81,472

 
206,354

 
(124,882
)
 
(61)%
Operating expenses
6,489

 
3,438

 
3,051

 
89%
Selling, general and administrative expenses
1,848

 
3,366

 
(1,518
)
 
(45)%
Depreciation and amortization
8,522

 
2,398

 
6,124

 
255%
Operating income
$
5,503

 
$
7,606

 
$
(2,103
)
 
(28)%
 
 
 
 
 
 
 
 
NGL sales volumes (Bbls)
3,138

 
3,511

 
(373
)
 
(11)%
 
Services Revenues. The increase in services revenue is a result of the 2015 period including a full quarter of natural gas storage revenue related to the acquisition of Cardinal, which occurred August 29, 2014.

Products Revenues. Our NGL average sales price per barrel decreased $34.29, or 55%, resulting in a decrease to products revenues of $120.4 million. The decrease in average sales price per barrel was a result of a decline in market prices.
Product sales volumes decreased 11%, decreasing products revenues $10.3 million.  

Cost of products sold.  Our average cost per barrel decreased $32.81, or 56%, decreasing cost of products sold by $115.2 million. The decrease in average cost per barrel was a result of a decline in market prices.  The decrease in sales volume of 11% resulted in a $9.7 million decrease to cost of products sold. Our margins decreased $1.48 per barrel, or 47% during the period.

Operating expenses.  Operating expenses increased $3.1 million, $2.2 million of which is related to the acquisition of Cardinal, $0.5 million is a result of the expenses associated with hydrotesting our 200 mile NGL pipeline, and $0.3 million is related to the rail operations at our Arcadia facility which was placed in service in June 2015.


42

Selling, general and administrative expenses.  Selling, general and administrative expenses decreased $1.5 million, $0.9 million of which is due to employee severance costs experienced in the 2014 period as a result of the acquisition of Cardinal, $0.4 million is related to decreased compensation expense, and $0.2 million is related to decreased property taxes.

Depreciation and amortization. The increase in depreciation and amortization is primarily due to the acquisition of Cardinal as well as the addition of recent capital expenditures.

Comparative Results of Operations for the Nine Months Ended September 30, 2015 and 2014
 
Nine Months Ended September 30,
 
Variance
 
Percent Change
 
2015
 
2014
 
 
 
(In thousands)
 
 
Revenues:
 
 
 
 
 
 
 
Services
$
50,171

 
$
5,764

 
$
44,407

 
770%
Products
330,803

 
771,798

 
(440,995
)
 
(57)%
Total revenues
380,974

 
777,562

 
(396,588
)
 
(51)%
 
 
 
 
 
 
 
 
Cost of products sold
308,713

 
740,021

 
(431,308
)
 
(58)%
Operating expenses
17,905

 
5,530

 
12,375

 
224%
Selling, general and administrative expenses
6,313

 
6,253

 
60

 
1%
Depreciation and amortization
25,297

 
2,811

 
22,486

 
800%
 
22,746

 
22,947

 
(201
)
 
(1)%
Other operating income loss
(7
)
 
—

 
(7
)
 
 
Operating income
$
22,739

 
$
22,947

 
$
(208
)
 
(1)%
 
 
 
 
 
 
 
 
NGL sales volumes (Bbls)
10,227

 
12,027

 
(1,800
)
 
(15)%

Services Revenues. The increase in services revenue is a result of the 2015 period including a full nine months of natural gas storage revenue related to the acquisition of Cardinal, which occurred August 29, 2014.

Products Revenues. Our NGL average sales price per barrel decreased $31.83, or 50%, resulting in a decrease to products revenues of $382.8 million. The decrease in average sales price per barrel was a result of a decline in market prices.
Product sales volumes decreased 15%, decreasing products revenues $58.2 million.  

Cost of products sold.  Our average cost per barrel decreased $31.34, or 51%, decreasing cost of products sold by $377.0 million.  The decrease in average cost per barrel was a result of a decline in market prices.  The decrease in sales volume of 15% resulted in a $54.3 million decrease to cost of products sold. Our margins decreased $0.48 per barrel, or 18% during the period.

Operating expenses.  Operating expenses increased $12.4 million, $10.4 million of which is related to the acquisition of Cardinal, $1.1 million is a result of the acquisition of NGL storage assets from Martin Resource Management in May 2014, $0.3 million is related to the rail operations at our Arcadia facility which was placed in service in June of 2015, and $0.5 million is a result of the expenses associated with hydrotesting our 200 mile NGL pipeline.

Selling, general and administrative expenses.  Selling, general and administrative expenses increased $1.3 million as a result of the acquisition of Cardinal on August 29, 2014. Offsetting this increase was a decrease to compensation expense of $1.1 million and property taxes of $0.1 million.
  
Depreciation and amortization. The increase in depreciation and amortization is primarily due to the acquisition of Cardinal as well as the addition of recent capital expenditures.


43

Sulfur Services Segment

Comparative Results of Operations for the Three Months Ended September 30, 2015 and 2014
 
Three Months Ended September 30,
 
Variance
 
Percent Change
 
2015
 
2014
 
 
 
(In thousands)
 
 
Revenues:
 
 
 
 
 
 
 
Services
$
3,090

 
$
3,037

 
$
53

 
2%
Products
33,213

 
46,993

 
(13,780
)
 
(29)%
Total revenues
36,303

 
50,030

 
(13,727
)
 
(27)%
 
 
 
 
 
 
 
 
Cost of products sold
26,235

 
38,932

 
(12,697
)
 
(33)%
Operating expenses
3,427

 
4,497

 
(1,070
)
 
(24)%
Selling, general and administrative expenses
934

 
1,166

 
(232
)
 
(20)%
Depreciation and amortization
2,129

 
2,078

 
51

 
2%
 
3,578

 
3,357

 
221

 
7%
Other operating loss
(5
)
 
—

 
(5
)
 
 
Operating income
$
3,573

 
$
3,357

 
$
216

 
6%
 
 
 
 
 
 
 
 
Sulfur (long tons)
203

 
251

 
(48
)
 
(19)%
Fertilizer (long tons)
51

 
52

 
(1
)
 
(2)%
Total sulfur services volumes (long tons)
254

 
303

 
(49
)
 
(16)%
 
Revenues.  Products revenue decreased $7.4 million as a result of a 16% decrease in average sales price due to a decline in commodity prices. A 16% decrease in sales volumes resulted in a decrease in products revenue of $6.4 million.

Cost of products sold.  A 20% decrease in prices reduced cost of products sold by $7.6 million, resulting from a decline in commodity prices. A 16% decrease in volumes resulted in a decrease in cost of products sold of $5.1 million.

Operating expenses.  Our operating expenses decreased as a result of lower towing expenses of $0.5 million and reduced fuel expense of $0.4 million.

Selling, general and administrative expenses.  Selling, general and administrative expenses decreased as a result of decreased compensation expense.

Depreciation and amortization.  The slight increase in depreciation and amortization is due to the impact of recent capital expenditures.


44

    

Comparative Results of Operations for the Nine Months Ended September 30, 2015 and 2014    
 
Nine Months Ended September 30,
 
Variance
 
Percent Change
 
2015
 
2014
 
 
 
(In thousands)
 
 
Revenues:
 
 
 
 
 
 
 
Services
$
9,270

 
$
9,112

 
$
158

 
2%
Products
128,544

 
157,706

 
(29,162
)
 
(18)%
Total revenues
137,814

 
166,818

 
(29,004
)
 
(17)%
 
 
 
 
 
 
 
 
Cost of products sold
95,961

 
122,281

 
(26,320
)
 
(22)%
Operating expenses
11,697

 
13,283

 
(1,586
)
 
(12)%
Selling, general and administrative expenses
2,859

 
3,404

 
(545
)
 
(16)%
Depreciation and amortization
6,360

 
6,092

 
268

 
4%
 
20,937

 
21,758

 
(821
)
 
(4)%
Other operating loss
(5
)
 
—

 
(5
)
 

Operating income
$
20,932

 
$
21,758

 
$
(826
)
 
(4)%
 
 
 
 
 
 
 
 
Sulfur (long tons)
641

 
646

 
(5
)
 
(1)%
Fertilizer (long tons)
229

 
233

 
(4
)
 
(2)%
Total sulfur services volumes (long tons)
870

 
879

 
(9
)
 
(1)%

Revenues.  Products revenue decreased $27.8 million as a result of a 18% decrease in average sales price due to a decline in commodity prices. A 1% decrease in sales volumes resulted in a decrease in products revenue of $1.3 million.

Cost of products sold.  Cost of products sold decreased $25.3 million due to a 21% reduction in prices, resulting from a decline in commodity prices. A volume decrease of 1% resulted in a $1.0 million decrease in cost of products sold.

Operating expenses.  Our operating expenses decreased primarily as a result of lower towing expenses of $1.3 million and reduced fuel expense of $0.3 million.

Selling, general and administrative expenses.  Selling, general and administrative expenses decreased as a result of decreased compensation expense.

Depreciation and amortization.  The slight increase in depreciation and amortization is due to the impact of recent capital expenditures.


45

Marine Transportation Segment

Comparative Results of Operations for the Three Months Ended September 30, 2015 and 2014
 
Three Months Ended September 30,
 
Variance
 
Percent Change
 
2015
 
2014
 
 
 
(In thousands)
 
 
Revenues
$
19,522

 
$
25,858

 
$
(6,336
)
 
(25)%
Operating expenses
15,855

 
19,181

 
(3,326
)
 
(17)%
Selling, general and administrative expenses
(59
)
 
364

 
(423
)
 
(116)%
Depreciation and amortization
3,060

 
2,469

 
591

 
24%
 
666

 
3,844

 
(3,178
)
 
(83)%
Impairment of long-lived assets
—

 
(3,445
)
 
3,445

 
100%
Other operating loss
(1,583
)
 
—

 
(1,583
)
 

Operating income (loss)
$
(917
)
 
$
399

 
$
(1,316
)
 
(330)%

Inland revenues.  A $2.2 million decrease in inland revenues is primarily attributable to decreased utilization of the inland fleet and downtime experienced for regulatory maintenance.

Offshore revenues.  A $1.4 million decrease in offshore revenue is the result of decreased utilization of the offshore fleet and downtime experienced for regulatory maintenance.

Pass-through revenues.  A $2.4 million decrease in pass-through revenues was primarily related to fuel.

Operating expenses.  Operating expenses decreased as a result of decreased pass-through expenses (primarily fuel) of $2.5 million, compensation expense of $0.6 million, property and liability premiums of $0.3 million, fuel expense of $0.2 million, and tankerman fees of $0.2 million. These decreases were offset by increased repairs and maintenance of $0.5 million.

Selling, general and administrative expenses. Selling, general and administrative expenses decreased $0.4 million as a result of the revision of the classification of property taxes to operating expenses in the three month period ending September 30, 2015.

Depreciation and amortization.  Depreciation and amortization increased as a result of recent capital expenditures offset by the disposal of property, plant and equipment.

Impairment of long-lived assets. Impairment of long-lived assets represents the write-down of one offshore tow.

Other operating loss.  Other operating loss represents losses from the disposition of property, plant and equipment.

Comparative Results of Operations for the Nine Months Ended September 30, 2015 and 2014
 
Nine Months Ended September 30,
 
Variance
 
Percent Change
 
2015
 
2014
 
 
 
(In thousands)
 
 
Revenues
$
62,354

 
$
73,254

 
$
(10,900
)
 
(15)%
Operating expenses
48,284

 
60,805

 
(12,521
)
 
(21)%
Selling, general and administrative expenses
251

 
867

 
(616
)
 
(71)%
Depreciation and amortization
8,050

 
7,472

 
578

 
8%
  Operating income  
$
5,769

 
$
4,110

 
$
1,659

 
40%
Impairment of long-lived assets
—

 
(3,445
)
 
3,445

 
100%
Other operating income (loss)
(1,552
)
 
16

 
(1,568
)
 
(9,800)%
Operating income
$
4,217

 
$
681

 
$
3,536

 
519%
 


46

Inland revenues.  A $4.4 million decrease in inland revenues is primarily attributable to decreased utilization of the inland fleet and downtime experienced for regulatory maintenance.

Offshore revenues.  A $0.6 million decrease in offshore revenue is the result of decreased utilization of the offshore fleet.

Pass-through revenues.  A $5.3 million decrease in pass-through revenues was primarily related to fuel.

Tankerman revenues. A $0.6 million decrease in tankerman revenues is a result of a reduction in services provided to maintain shore-side operations for the disposition of the floating storage assets, which were disposed of in February of 2015.

Operating expenses.  The decrease in operating expenses is a result of decreased pass-through expenses (primarily fuel) of $5.5 million, lower repairs and maintenance of $4.4 million, property and liability insurance premiums of $0.6 million, tankerman fees of $0.5 million, compensation expense of $0.5 million, Jones Act claims of $0.3 million, property taxes of $0.3 million, and operating supplies of $0.3 million.
 
Selling, general and administrative expenses.  Selling, general and administrative expenses decreased as a result of a $1.4 million decrease during the quarter in a legal reserve established during the purchase of Talen's Marine & Fuel, LLC, offset by an increase in the reserve for an uncollectible customer receivable of $0.8 million.

Depreciation and amortization.  Depreciation and amortization increased as a result of recent capital expenditures offset by the disposal of property, plant and equipment.

Impairment of long-lived assets. Impairment of long-lived assets represents the write-down of one offshore tow.

Other operating loss.  Other operating loss represents losses from the disposition of property, plant and equipment.

Equity in Earnings in and Distributions from Unconsolidated Entities for the Three Months Ended September 30, 2015 and 2014
 
Three Months Ended September 30,
 
Variance
 
Percent Change
 
2015
 
2014
 
 
 
(In thousands)
 
 
Equity in earnings of WTLPG
$
2,363

 
$
1,138

 
$
1,225

 
108%
Equity in earnings of Cardinal
—

 
1,135

 
(1,135
)
 
(100)%
Equity in earnings of MET
—

 
382

 
(382
)
 
(100)%
    Equity in earnings of unconsolidated entities
$
2,363

 
$
2,655

 
$
(292
)
 
(11)%

 
Three Months Ended September 30,
 
Variance
 
Percent Change
 
2015
 
2014
 
 
 
(In thousands)
 
 
Distributions from WTLPG
$
3,400

 
$
600

 
$
2,800

 
467%
Distributions from Cardinal
—

 
—

 
—

 

Distributions from MET
—

 
382

 
(382
)
 
(100)%
Distributions from unconsolidated entities
$
3,400

 
$
982

 
$
2,418

 
246%

The increase in equity in earnings from West Texas LPG Pipeline L.P. ("WTLPG") is attributable to improved operating results of the asset.    

On August 29, 2014, the Partnership acquired the approximate 57.8% Category A membership interest in Cardinal it did not previously own. Cardinal results of operations are included in the Natural Gas Services segment subsequent to that date.
    
Equity in earnings of Martin Energy Trading LLC ("MET"), recorded initially in April 2013, represented dividends on our 100% investment in its preferred interests. During March 2013, the Partnership acquired 100% of the preferred interests in MET, a

47

subsidiary of Martin Resource Management, for $15,000. In August, 2014, MET converted its preferred equity to subordinated debt, resulting in a note receivable from MET.

Distributions from unconsolidated entities for the three months ended September 30, 2015, represents the quarterly distribution from our interests in WTLPG of $3.4 million. The 2014 period includes a $0.6 million distribution from WTLPG and a $0.4 million distribution from MET.

Equity in Earnings in and Distributions from Unconsolidated Entities for the Nine Months Ended September 30, 2015 and 2014    
 
Nine Months Ended September 30,
 
Variance
 
Percent Change
 
2015
 
2014
 
 
 
(In thousands)
 
 
Equity in earnings of WTLPG
$
5,752

 
$
1,907

 
$
3,845

 
202%
Equity in earnings of Cardinal
—

 
892

 
(892
)
 
100%
Equity in earnings of MET
—

 
1,498

 
(1,498
)
 
(100)%
    Equity in earnings of unconsolidated entities
$
5,752

 
$
4,297

 
$
1,455

 
34%

 
Nine Months Ended September 30,
 
Variance
 
Percent Change
 
2015
 
2014
 
 
 
(In thousands)
 
 
Distributions from WTLPG
$
7,800

 
$
600

 
$
7,200

 
1,200%
Distributions from Cardinal
—

 
225

 
(225
)
 
100%
Distributions from MET
—

 
1,498

 
(1,498
)
 
(100)%
Distributions from unconsolidated entities
$
7,800

 
$
2,323

 
$
5,477

 
236%

The nine month period ended September 30, 2014 includes equity in earnings of WTLPG from the acquisition in May 2014. The investment was owned for the entire 2015 period.    

On August 29, 2014, the Partnership acquired the approximate 57.8% Category A membership interest in Cardinal it did not previously own. Cardinal results of operations are included in the Natural Gas Services segment subsequent to that date.
    
Equity in earnings of MET, recorded initially in April 2013, represented dividends on our 100% investment in its preferred interests. During March 2013, the Partnership acquired 100% of the preferred interests in MET, a subsidiary of Martin Resource Management, for $15,000. In August, 2014, MET converted its preferred equity to subordinated debt, resulting in a note receivable from MET.

Distributions from unconsolidated entities for the nine months ended September 30, 2015 represents three quarterly distributions from our interests in WTLPG of $7.8 million. The 2014 period includes a $0.6 million distribution from WTLPG, a $0.2 million distribution from Cardinal, and a $1.5 million distribution from MET.


48

Interest Expense, Net

Comparative Components of Interest Expense, Net for the Three Months Ended September 30, 2015 and 2014
 
Three Months Ended September 30,
 
Variance
 
Percent Change
 
2015
 
2014
 
 
 
(In thousands)
 
 
Revolving loan facility
$
4,043

 
$
3,719

 
$
324

 
9%
7.25% Senior notes
7,253

 
7,251

 
2

 
—%
Amortization of deferred debt issuance costs
2,400

 
827

 
1,573

 
190%
Amortization of debt discount and premium
(82
)
 
(82
)
 
—

 
—%
Impact of interest rate derivative activity, including cash settlements
(750
)
 
63

 
(813
)
 
1,290%
Other
124

 
100

 
24

 
(24)%
Capitalized interest
(427
)
 
(234
)
 
(193
)
 
(82)%
Interest income
(567
)
 
(185
)
 
(382
)
 

Total interest expense, net
$
11,994

 
$
11,459

 
$
535

 
5%

Comparative Components of Interest Expense, Net for the Nine Months Ended September 30, 2015 and 2014
 
Nine Months Ended September 30,
 
Variance
 
Percent Change
 
2015
 
2014
 
 
 
(In thousands)
 
 
Revolving loan facility
$
12,173

 
$
8,325

 
$
3,848

 
46%
8.875% Senior notes
—

 
3,882

 
(3,882
)
 
(100)%
7.25% Senior notes
21,753

 
19,002

 
2,751

 
14%
Amortization of deferred debt issuance costs
4,142

 
5,415

 
(1,273
)
 
(24)%
Amortization of debt discount and premium
(246
)
 
1,141

 
(1,387
)
 
(122)%
Impact of interest rate derivative activity, including cash settlements
(2,495
)
 
(2,864
)
 
369

 
13%
Other
343

 
592

 
(249
)
 
(42)%
Capitalized interest
(1,522
)
 
(957
)
 
(565
)
 
(59)%
Interest income
(1,683
)
 
(185
)
 
(1,498
)
 
 
Total interest expense, net
$
32,465

 
$
34,351

 
$
(1,886
)
 
(5)%

Indirect Selling, General and Administrative Expenses
 
Three Months Ended September 30,
 
Variance
 
Percent Change
 
Nine Months Ended September 30,
 
Variance
 
Percent Change
 
2015
 
2014
 
 
 
2015
 
2014
 
 
 
(In thousands)
 
 
 
(In thousands)
 
 
Indirect selling, general and administrative expenses
$
4,948

 
$
4,479

 
$
469

 
10%
 
$
14,258

 
$
14,214

 
$
44

 
—%

Indirect selling, general and administrative expenses increased for the three months ended September 30, 2015 due principally to a $0.4 million increase in acquisition due diligence costs.

Martin Resource Management allocates to us a portion of its indirect selling, general and administrative expenses for services such as accounting, legal, treasury, clerical, billing, information technology, administration of insurance, engineering, general office expense and employee benefit plans and other general corporate overhead functions we share with Martin Resource Management retained businesses. This allocation is based on the percentage of time spent by Martin Resource Management personnel that provide such centralized services. GAAP also permits other methods for allocation of these expenses, such as basing the allocation on the percentage of revenues contributed by a segment. The allocation of these expenses between Martin Resource Management and us is subject to a number of judgments and estimates, regardless of the method used. We can provide

49

no assurances that our method of allocation, in the past or in the future, is or will be the most accurate or appropriate method of allocation for these expenses. Other methods could result in a higher allocation of selling, general and administrative expense to us, which would reduce our net income.

Under the Omnibus Agreement, we are required to reimburse Martin Resource Management for indirect general and administrative and corporate overhead expenses. The Conflicts Committee of our general partner approved the following reimbursement amounts during the three and nine months ended September 30, 2015 and 2014:
 
Three Months Ended September 30,
 
Variance
 
Percent Change
 
Nine Months Ended September 30,
 
Variance
 
Percent Change
 
2015
 
2014
 
 
 
2015
 
2014
 
 
 
(In thousands)
 
 
 
(In thousands)
 
 
Conflicts Committee approved reimbursement amount
$
3,420

 
$
3,134

 
$
286

 
9%
 
$
10,259

 
$
9,401

 
$
858

 
9%

The amounts reflected above represent our allocable share of such expenses. The Conflicts Committee will review and approve future adjustments in the reimbursement amount for indirect expenses, if any, annually.

Liquidity and Capital Resources
 
General

Our primary sources of liquidity to meet operating expenses, pay distributions to our unitholders and fund capital expenditures are cash flows generated by our operations and access to debt and equity markets, both public and private.  We have recently completed several transactions that have improved our liquidity position, helping fund our acquisitions and organic growth projects.  

As a result of these financing activities, discussed in further detail below, management believes that expenditures for our current capital projects will be funded with cash flows from operations, current cash balances and our current borrowing capacity under the expanded revolving credit facility. However, it may be necessary to raise additional funds to finance our future capital requirements.

Our ability to satisfy our working capital requirements, to fund planned capital expenditures and to satisfy our debt service obligations will also depend upon our future operating performance, which is subject to certain risks. Please read "Item 1A. Risk Factors" of our Form 10-K for the year ended December 31, 2014, filed with the SEC on March 2, 2015, as amended by Amendment No. 1 on Form 10-K/A filed on March 5, 2015, for a discussion of such risks.

Recent Debt Financing Activity
 
In September 2015, we repurchased on the open market an aggregate $16.1 million of our outstanding 7.25% senior unsecured notes. These transactions resulted in a gain on retirement of $0.7 million.

On August 14, 2015, we notified the Royal Bank of Canada, the administrative agent of our revolving credit facility, that we were reducing the aggregate committed sum (as defined in the underlying credit agreement) from $900.0 million to $700.0 million. We have the ability to exercise the accordion feature of our revolving credit facility at any time and expand the facility up to an aggregate committed sum of $1.0 billion. As a result of the decreased capacity, we expect to reduce the amount of commitment fees under our revolving credit facility by approximately $1.0 million on an annual basis.

On June 23, 2015, we amended the definition of Consolidated EBITDA (as defined in the credit facility agreement) to include cash interest payments received by the Partnership in respect of subordinated debt owed to the Partnership by MET. Additionally, the amendment permits us to purchase, redeem or otherwise acquire up to $25.0 million of our common units and/or senior unsecured notes, subject to compliance with certain minimum liquidity, maximum leverage and other conditions set forth in the amendment.

50


Recent Equity Markets Activity

On September 29, 2014, we completed a public offering of 3,450,000 common units at a price of $36.91 per common unit, before the payment of underwriters' discounts, commissions and offering expenses.  Total proceeds from the sale of the 3,450,000 common units, net of underwriters' discounts, commissions and offering expenses, were $122.2 million.  Our general partner contributed $2.6 million in cash to us in conjunction with the issuance in order to maintain its 2.0% general partner interest in us.  The net proceeds from the common unit issuance were used to pay down outstanding amounts under our revolving credit facility.

On August 29, 2014, we closed a private equity sale with Martin Resource Management, under which Martin Resource Management invested $45.0 million in cash in exchange for 1,171,265 common units. The pricing of $38.42 per common unit was based on the 10-day weighted average price of our common units for the 10 trading days ending August 8, 2014. In connection with the issuance of these common units, our general partner contributed $0.9 million in order to maintain its 2.0% general partner interest in us. The proceeds from the common unit issuance were used to pay down outstanding amounts under our revolving credit facility.

Due to the foregoing, we believe that cash generated from operations and our borrowing capacity under our credit facility will be sufficient to meet our working capital requirements, anticipated maintenance capital expenditures and scheduled debt payments in 2015.

Finally, our ability to satisfy our working capital requirements, to fund planned capital expenditures and to satisfy our debt service obligations will depend upon our future operating performance, which is subject to certain risks.  Please read "Item 1A. Risk Factors" of our Form 10-K for the year ended December 31, 2014, filed with the SEC on March 2, 2015, as amended by Amendment No. 1 on Form 10-K/A filed on March 5, 2015, for a discussion of such risks.

Cash Flows - Nine Months Ended September 30, 2015 Compared to Nine Months Ended September 30, 2014

The following table details the cash flow changes between the nine months ended September 30, 2015 and 2014:
 
Nine Months Ended September 30,
 
Variance
 
Percent Change
 
2015
 
2014
 
 
 
(In thousands)
 
 
 
 
Net cash provided by (used in):
 
 
 
 
 
 
 
Operating activities
$
112,984

 
$
53,001

 
$
59,983

 
113%
Investing activities
1,358

 
(296,464
)
 
297,822

 
100%
Financing activities
(114,371
)
 
229,927

 
(344,298
)
 
(150)%
Net decrease in cash and cash equivalents
$
(29
)
 
$
(13,536
)
 
$
13,507

 
100%

The change in net cash provided by operating activities for the nine months ended September 30, 2015 includes an increase in operating results plus other non-cash items of $31.6 million, a $17.6 million favorable variance in working capital, and an increase in distributions from equity method investees of $7.2 million. Net cash used in discontinued operating activities decreased $5.1 million in 2015. Preferred dividends decreased $1.5 million in 2015.
    
Net cash provided by investing activities for the nine months ended September 30, 2015 increased due to no acquisition expenditures in 2015 compared to $100.0 million in 2014. Additionally, there were no investments or contributions to unconsolidated entities in 2015 while 2014 included $137.8 million of these expenditures. Payments for capital expenditures and plant turnaround costs decreased $20.6 million in 2015. Finally, 2015 includes $41.3 million in cash proceeds from the disposition of the Floating Storage Assets.

The change in net cash provided by (used in) financing activities for the nine months ended September 30, 2015 is due to a decrease in equity offering proceeds of $331.9 million and increased cash distributions of $32.0 million. Net repayments of long-term borrowings decreased $16.5 million in 2015.


51

Capital Expenditures and Plant Turnaround Costs

Our operations require continual investment to upgrade or enhance operations and to ensure compliance with safety, operational, and environmental regulations. Our capital expenditures consist primarily of:

•expansion capital expenditures to acquire assets to grow our business, to expand existing facilities, such as projects that increase operating capacity, or to reduce operating costs;
    
•maintenance capital expenditures made to maintain existing assets and operations; and

•plant turnaround costs made at our refinery to perform maintenance, overhaul and repair operations and to inspect, test and replace process materials and equipment.

The following table summarizes our capital expenditure activity, excluding amounts paid for acquisitions, for the periods presented:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2015
 
2014
 
2015
 
2014
 
(In thousands)
Expansion capital expenditures
$
10,280

 
$
12,979

 
$
36,891

 
$
45,262

Maintenance capital expenditures
2,438

 
4,306

 
7,621

 
13,260

Plant turnaround costs
—

 
90

 
1,754

 
4,000

    Total
$
12,718

 
$
17,375

 
$
46,266

 
$
62,522


Expansion capital expenditures were made primarily in our Terminalling and Storage and Natural Gas Services segments during the three and nine months ended September 30, 2015. Within our Terminalling and Storage segment, expenditures were made primarily at our Smackover refinery and on certain organic growth projects ongoing in our specialty terminalling operations. Within our Natural Gas Services segment, expenditures were made on ongoing organic growth projects. Maintenance capital expenditures were made primarily in our Terminalling and Storage segment to maintain our existing assets and operations during the three and nine months ended September 30, 2015. For the three and nine months ended September 30, 2015, plant turnaround costs relate to our Smackover refinery.

Expansion capital expenditures were made primarily in our Terminalling and Storage, Marine Transportation, and Natural Gas Services segments during the three and nine months ended September 30, 2014 . Within our Terminalling and Storage segment, expenditures were made primarily at our Corpus Christi crude terminal, Smackover refinery, and certain smaller organic growth projects ongoing in our specialty terminalling operations. Within our Marine Transportation segment, expenditures were made related to the construction of new barges. Within our Natural Gas Services segment, expenditures were made on ongoing organic growth projects. Maintenance capital expenditures were made primarily in our Marine Transportation, Terminalling and Storage, and Sulfur Services segments to maintain our existing assets and operations during the three and nine months ended September 30, 2014 . For the three and nine months ended September 30, 2014 , plant turnaround costs relate to our Smackover refinery.

Capital Resources

Historically, we have generally satisfied our working capital requirements and funded our capital expenditures with cash generated from operations and borrowings. We expect our primary sources of funds for short-term liquidity will be cash flows from operations and borrowings under our credit facility.
     

52

Total Contractual Cash Obligations.  A summary of our total contractual cash obligations as of September 30, 2015, is as follows: 
 
Payments due by period
Type of Obligation
Total
Obligation
 
Less than
One Year
 
1-3
Years
 
3-5
Years
 
Due
Thereafter
Revolving credit facility
$
500,000

 
$
—

 
$
500,000

 
$
—

 
$
—

2021 Senior unsecured notes
383,875

 
—

 
—

 
—

 
383,875

Throughput commitment
35,573

 
5,232

 
10,974

 
11,692

 
7,675

Operating leases
36,177

 
12,011

 
13,823

 
5,745

 
4,598

Interest expense: ¹
 

 
 

 
 

 
 

 
 

Revolving credit facility
36,716

 
14,743

 
21,973

 
—

 
—

2021 Senior unsecured notes
157,709

 
27,831

 
55,662

 
55,662

 
18,554

Total contractual cash obligations
$
1,150,050

 
$
59,817

 
$
602,432

 
$
73,099

 
$
414,702


¹Interest commitments are estimated using our current interest rates for the respective credit agreements over their remaining terms.

Letters of Credit.  At September 30, 2015, we had outstanding irrevocable letters of credit in the amount of $1.6 million, which were issued under our revolving credit facility.

Off Balance Sheet Arrangements.  We do not have any off-balance sheet financing arrangements.
 
Description of Our Long-Term Debt

2021 Senior Notes

For a description of our 7.25% senior unsecured notes due 2021, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Description of Our Long-Term Debt" in our Annual Report on Form 10-K for the year ended December 31, 2014, as amended.

Revolving Credit Facility

We maintain a $700.0 million credit facility, which was reduced from $900.0 million on August 14, 2015 through notification to our credit facility's administrative agent. On June 23, 2015, we amended the facility to change the definition of Consolidated EBITDA (as defined in the credit facility agreement) to include cash interest payments received by the Partnership in respect of subordinated debt owed to the Partnership by MET. Additionally, the amendment permits us to purchase, redeem or otherwise acquire up to $25.0 million of our common units and/or senior unsecured notes, subject to compliance with certain minimum liquidity, maximum leverage and other conditions set forth in the amendment.

As of September 30, 2015, the capacity of our revolving credit facility was $700.0 million. We had $500.0 million outstanding under the revolving credit facility and $1.6 million of letters of credit issued, leaving a maximum available to be borrowed under our credit facility for future revolving credit borrowings and letters of credit of $198.4 million. Subject to the financial covenants contained in our credit facility and based on our existing EBITDA (as defined in our credit facility) calculations, as of September 30, 2015, we have the ability to borrow approximately $70.7 million of that amount.

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 nine months ended September 30, 2015, the level of outstanding draws on our credit facility has ranged from a low of $450.0 million to a high of $515.0 million.

The credit facility is guaranteed by substantially all of our subsidiaries. Obligations under the credit facility are secured by first priority liens on substantially all of our assets and those of the guarantors, including, without limitation, inventory, accounts receivable, bank accounts, marine vessels, equipment, fixed assets and the interests in our subsidiaries and certain of our equity method investees.


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We may prepay all amounts outstanding under the credit facility at any time without premium or penalty (other than customary LIBOR breakage costs), subject to certain notice requirements. The credit facility requires mandatory prepayments of amounts outstanding thereunder with the net proceeds of certain asset sales, equity issuances and debt incurrences.

Indebtedness under the credit facility bears interest at our option at the Eurodollar Rate (the British Bankers Association LIBOR Rate) plus an applicable margin or the Base Rate (the highest of the Federal Funds Rate plus 0.50%, the 30-day Eurodollar Rate plus 1.0%, or the administrative agent’s prime rate) plus an applicable margin. We pay a per annum fee on all letters of credit issued under the credit facility, and we pay a commitment fee per annum on the unused revolving credit availability under the credit facility. The letter of credit fee, the commitment fee and the applicable margins for our interest rate vary quarterly based on our leverage ratio (as defined in the credit facility, being generally computed as the ratio of total funded debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges) and are as follows:
 
Leverage Ratio
Base Rate Loans
 
Eurodollar
Rate
Loans
 
Letters of Credit
Less than 3.00 to 1.00
0.75
%
 
1.75
%
 
1.75
%
Greater than or equal to 3.00 to 1.00 and less than 3.50 to 1.00
1.00
%
 
2.00
%
 
2.00
%
Greater than or equal to 3.50 to 1.00 and less than 4.00 to 1.00
1.25
%
 
2.25
%
 
2.25
%
Greater than or equal to 4.00 to 1.00 and less than 4.50 to 1.00
1.50
%
 
2.50
%
 
2.50
%
Greater than or equal to 4.50 to 1.00
1.75
%
 
2.75
%
 
2.75
%
    
The applicable margin for revolving loans that are LIBOR loans ranges from 1.75% to 2.75% and the applicable margin for revolving loans that are base prime rate loans ranges from 0.75% to 1.75%. The applicable margin for LIBOR borrowings at September 30, 2015 is 2.75%.  

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 5.25 to 1.00 with a temporary springing provision to 5.50 to 1.00 under certain scenarios. The maximum permitted senior leverage ratio (as defined in the 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 3.50 to 1.00. The minimum interest coverage ratio (as defined in the 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 2.50 to 1.00.

In addition, the credit facility contains various covenants, which, among other things, limit our and our subsidiaries’ ability to: (i) grant or assume liens; (ii) make investments (including investments in our joint ventures) and acquisitions; (iii) enter into certain types of hedging agreements; (iv) incur or assume indebtedness; (v) sell, transfer, assign or convey assets; (vi) 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; (vii) change the nature of our business; (viii) engage in transactions with affiliates; (ix) enter into certain burdensome agreements; (x) make certain amendments to the Omnibus Agreement and our material agreements; (xi) make capital expenditures; and (xii) permit our joint ventures to incur indebtedness or grant certain liens.

The credit facility contains customary events of default, including, without limitation: (i) failure to pay any principal, interest, fees, expenses or other amounts when due; (ii) failure to meet the quarterly financial covenants; (iii) 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; (iv) the failure of any representation or warranty to be materially true and correct when made; (v) our, or any of our subsidiaries’ default under other indebtedness that exceeds a threshold amount; (vi) bankruptcy or other insolvency events involving us or any of our subsidiaries; (vii) judgments against us or any of our subsidiaries, in excess of a threshold amount; (viii) certain ERISA events involving us or any of our subsidiaries, in excess of a threshold amount; (ix) a change in control (as defined in the credit facility); and (x) the invalidity of any of the loan documents or the failure of any of the collateral documents to create a lien on the collateral.

The credit facility also contains certain default provisions relating to Martin Resource Management. If Martin Resource Management no longer controls our general partner, the lenders under the 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 our credit facility if it is deemed to have a material adverse effect on us.

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If an event of default relating to bankruptcy or other insolvency events occurs with respect to us or any of our subsidiaries, all indebtedness under our credit facility will immediately become due and payable. If any other event of default exists under our credit facility, the lenders may terminate their commitments to lend us money, accelerate the maturity of the indebtedness outstanding under the credit facility and exercise other rights and remedies. In addition, if any event of default exists under our credit facility, the lenders may commence foreclosure or other actions against the collateral.
 
As of October 28, 2015, our outstanding indebtedness includes $490.0 million under our credit facility.
 
We are subject to interest rate risk on our credit facility due to the variable interest rate and may enter into interest rate swaps to reduce this variable rate risk.

The Partnership is in compliance with all debt covenants as of September 30, 2015 and expects to be in compliance for the next twelve months.

Seasonality

A substantial portion of our revenues are dependent on sales prices of products, particularly NGLs and fertilizers, which fluctuate in part based on winter and spring weather conditions. The demand for NGLs is strongest during the winter heating season and the refinery blending season. The demand for fertilizers is strongest during the early spring planting season. However, our WTLPG and natural gas storage divisions of the Natural Gas Services segment each provide stable cash flows and are not generally subject to seasonal demand factors. Additionally, our Terminalling and Storage and Marine Transportation segments and the molten sulfur business are typically not impacted by seasonal fluctuations and a significant portion of our net income is derived from our terminalling and storage, sulfur and marine transportation businesses. Therefore, we do not expect that our overall net income will be impacted by seasonality factors.  However, extraordinary weather events, such as hurricanes, have in the past, and could in the future, impact our Terminalling and Storage and Marine Transportation segments.

Impact of Inflation

Inflation did not have a material impact on our results of operations for the nine months ended September 30, 2015 or 2014.  Although the impact of inflation has been insignificant in recent years, it is still a factor in the U.S. economy and may increase the cost to acquire or replace property, plant and equipment. It may also increase the costs of labor and supplies.  In the future, increasing energy prices could adversely affect our results of operations. Diesel fuel, natural gas, chemicals and other supplies are recorded in operating expenses.  An increase in price of these products would increase our operating expenses which could adversely affect net income. We cannot provide assurance that we will be able to pass along increased operating expenses to our customers.

Environmental Matters

Our operations are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. We incurred no material environmental costs, liabilities or expenditures to mitigate or eliminate environmental contamination during the nine months ended September 30, 2015 or 2014.

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Item 3.
Quantitative and Qualitative Disclosures about Market Risk

Commodity Risk. The Partnership from time to time uses derivatives to manage the risk of commodity price fluctuation. Commodity risk is the adverse effect on the value of a liability or future purchase that results from a change in commodity price.  We have established a hedging policy and monitor and manage the commodity market risk associated with potential commodity risk exposure.  In addition, we focus on utilizing counterparties for these transactions whose financial condition is appropriate for the credit risk involved in each specific transaction.     

We have entered into hedging transactions through March 31, 2016 to protect a portion of our commodity price risk exposure. These hedging arrangements are in the form of swaps for NGLs. We have arrangements totaling a notional quantity of 0.3 million barrels settling during the period from October 31, 2015 through March 31, 2016. These instruments settle against OPIS Mont Belvieu (non-TET) monthly average price. These instruments are recorded on our Consolidated and Condensed Balance Sheets at September 30, 2015 in "Fair value of derivatives" as a currently liability of $0.4 million. Based on the current notional volume hedged as of September 30, 2015, a $0.10 change in the expected settlement price of these contracts would result in an impact to the Partnership's net income of approximately $1.3 million.

Interest Rate Risk. We are exposed to changes in interest rates as a result of our credit facility, which had a weighted-average interest rate of 2.95% as of September 30, 2015.  Based on the amount of unhedged floating rate debt owed by us on September 30, 2015, the impact of a 1% increase in interest rates on this amount of debt would result in an increase in interest expense and a corresponding decrease in net income of approximately $5.0 million annually.

We are not exposed to changes in interest rates with respect to our senior unsecured notes as these obligations are fixed rate.  The estimated fair value of the senior unsecured notes was approximately $361.0 million as of September 30, 2015, based on market prices of similar debt at September 30, 2015.   Market risk is estimated as the potential decrease in fair value of our long-term debt resulting from a hypothetical increase of 1% in interest rates. Such an increase in interest rates would result in approximately a $15.4 million decrease in fair value of our long-term debt at September 30, 2015.



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Item 4.
Controls and Procedures

Evaluation of disclosure controls and procedures. In accordance with Rules 13a-15 and 15d-15 of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), we, under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer of our general partner, carried out an evaluation of the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) and 15d-15(e) of the Exchange Act) as of the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer of our general partner concluded that our disclosure controls and procedures were effective, as of the end of the period covered by this report, to ensure that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

There were no changes in our internal controls over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) that occurred during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

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PART II - OTHER INFORMATION

Item 1.
Legal Proceedings

From time to time, we are subject to certain legal proceedings claims and disputes that arise in the ordinary course of our business. Although we cannot predict the outcomes of these legal proceedings, we do not believe these actions, in the aggregate, will have a material adverse impact on our financial position, results of operations or liquidity. Information regarding legal proceedings is set forth in Note 17 in Part I of this Form 10-Q.

Item 1A.
Risk Factors

There have been no material changes to the risk factors disclosed in our annual report on Form 10-K filed with the SEC on March 2, 2015, as amended by Amendment No. 1 on Form 10-K/A filed on March 5, 2015.

Item 6.
Exhibits

The information required by this Item 6 is set forth in the Index to Exhibits accompanying this quarterly report and is incorporated herein by reference.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this Report to be signed on its behalf by the undersigned thereunto duly authorized.
 
 
Martin Midstream Partners L.P.
 
 
 
 
 
 
By:
Martin Midstream GP LLC
 
 
 
Its General Partner
 
 
 
 
 
Date: 10/28/2015
By:
/s/ Robert D. Bondurant
 
 
 
Robert D. Bondurant
 
 
 
Executive Vice President, Treasurer, Chief Financial Officer, and Principal Accounting Officer
 

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INDEX TO EXHIBITS
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 November 25, 2009 (filed as Exhibit 10.1 to the Partnership's Amendment to Current Report on Form 8-K/A (SEC File No. 000-50056), filed January 19, 2010, and incorporated herein by reference).
3.3
Amendment No. 2 to the Second Amended and Restated Agreement of Limited Partnership of the Partnership dated January 31, 2011 (filed as Exhibit 3.1 to the Partnership's Current Report on Form 8-K (SEC File No. 000-50056), filed February 1, 2011, and incorporated herein by reference).
3.4
Amendment No. 3 to the Second Amended and Restated Agreement of Limited Partnership of the Partnership dated October 2, 2012 (filed as Exhibit 10.5 to the Partnership's Current Report on Form 8-K (SEC File No. 000-50056), filed October 9, 2012, and incorporated herein by reference).
3.5
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).
3.6
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 (SEC File No. 000-50056), filed November 19, 2002, and incorporated herein by reference).
3.7
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).
3.8
Amended and Restated Limited Liability Company Agreement of the General Partner, dated August 30, 2013 (filed as Exhibit 3.1 to the Partnership's Current Report on Form 8-K (Reg. No. 000-50056), filed September 3, 2013, and incorporated herein by reference).
3.9
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).
3.10
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).
3.11
Certificate of Formation of Arcadia Gas Storage, LLC, dated June 26, 2006 (filed as Exhibit 3.11 to the Partnership's Quarterly Report on Form 10-Q (SEC File No. 000-50056, filed October 29, 2014, and incorporated herein by reference).
3.12
Company Agreement of Arcadia Gas Storage, LLC, dated December 27, 2006 (filed as Exhibit 3.12 to the Partnership's Quarterly Report on Form 10-Q (SEC File No. 000-50056, filed October 29, 2014, and incorporated herein by reference).
3.13
Amendment to the Company Agreement of Arcadia Gas Storage, LLC, dated September 5, 2014 (filed as Exhibit 3.13 to the Partnership's Quarterly Report on Form 10-Q (SEC File No. 000-50056, filed October 29, 2014, and incorporated herein by reference).
3.14
Certificate of Formation of Cadeville Gas Storage LLC, dated May 23, 2008 (filed as Exhibit 3.14 to the Partnership's Quarterly Report on Form 10-Q (SEC File No. 000-50056, filed October 29, 2014, and incorporated herein by reference).
3.15
Limited Liability Company Agreement of Cadeville Gas Storage LLC, dated May 23, 2008 (filed as Exhibit 3.15 to the Partnership's Quarterly Report on Form 10-Q (SEC File No. 000-50056, filed October 29, 2014, and incorporated herein by reference).
3.16
First Amendment to the Limited Liability Company Agreement of Cadeville Gas Storage LLC, dated April 16, 2012 (filed as Exhibit 3.16 to the Partnership's Quarterly Report on Form 10-Q (SEC File No. 000-50056, filed October 29, 2014, and incorporated herein by reference).
3.17
Second Amendment to the Limited Liability Company Agreement of Cadeville Gas Storage LLC, dated September 5, 2014 (filed as Exhibit 3.17 to the Partnership's Quarterly Report on Form 10-Q (SEC File No. 000-50056, filed October 29, 2014, and incorporated herein by reference).
3.18
Certificate of Formation of Monroe Gas Storage Company, LLC, dated June 14, 2006 (filed as Exhibit 3.18 to the Partnership's Quarterly Report on Form 10-Q (SEC File No. 000-50056, filed October 29, 2014, and incorporated herein by reference).

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3.19
Amended and Restated Limited Liability Company Agreement of Monroe Gas Storage Company, LLC, dated May 31, 2011 (filed as Exhibit 3.19 to the Partnership's Quarterly Report on Form 10-Q (SEC File No. 000-50056, filed October 29, 2014, and incorporated herein by reference).
3.20
First Amendment to the Amended and Restated Limited Liability Company Agreement of Monroe Gas Storage Company, LLC, dated September 5, 2014 (filed as Exhibit 3.20 to the Partnership's Quarterly Report on Form 10-Q (SEC File No. 000-50056, filed October 29, 2014, and incorporated herein by reference).
3.21
Certificate of Formation of Perryville Gas Storage LLC, dated May 23, 2008 (filed as Exhibit 3.21 to the Partnership's Quarterly Report on Form 10-Q (SEC File No. 000-50056, filed October 29, 2014, and incorporated herein by reference).
3.22
Limited Liability Company Agreement of Perryville Gas Storage LLC, dated June 16, 2008 (filed as Exhibit 3.22 to the Partnership's Quarterly Report on Form 10-Q (SEC File No. 000-50056, filed October 29, 2014, and incorporated herein by reference).
3.23
First Amendment to the Limited Liability Company Agreement of Perryville Gas Storage LLC, dated April 14, 2010 (filed as Exhibit 3.23 to the Partnership's Quarterly Report on Form 10-Q (SEC File No. 000-50056, filed October 29, 2014, and incorporated herein by reference).
3.24
Second Amendment to the Limited Liability Company Agreement of Perryville Gas Storage LLC, dated September 5, 2014 (filed as Exhibit 3.24 to the Partnership's Quarterly Report on Form 10-Q (SEC File No. 000-50056, filed October 29, 2014, and incorporated herein by reference).
3.25
Certificate of Formation of Cardinal Gas Storage Partners LLC, dated April 2, 2008 (filed as Exhibit 3.25 to the Partnership's Quarterly Report on Form 10-Q (SEC File No. 000-50056, filed October 29, 2014, and incorporated herein by reference).
3.26
Third Amended and Restated Limited Liability Company Agreement of Cardinal Gas Storage Partners LLC (F/K/A Redbird Gas Storage LLC) dated October 27, 2014 (filed as Exhibit 3.26 to the Partnership's Quarterly Report on Form 10-Q (SEC File No. 000-50056, filed October 29, 2014, and incorporated herein by reference).
3.27
Certificate of Formation of Redbird Gas Storage LLC, dated May 24, 2011 (filed as Exhibit 3.27 to the Partnership’s Annual Report on Form 10-K (SEC File No 000-50056), filed March 2, 2015, and incorporated herein by reference).
3.28
Certificate of Merger of Cardinal Gas Storage Partners LLC with and into Redbird Gas Storage LLC, dated October 27, 2014 (filed as Exhibit 3.27 to the Partnership's Quarterly Report on Form 10-Q (SEC File No. 000-50056, filed October 29, 2014, and incorporated herein by reference).
3.29
Certificate of Formation of Martin Midstream NGL Holdings, LLC, dated April 21, 2011, as amended (filed as Exhibit 3.11 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed July 31, 2014, and incorporated herein by reference).
3.30
Limited Liability Company Agreement of Martin Midstream NGL Holdings, LLC, dated May 15, 2014 (filed as Exhibit 3.12 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed July 31, 2014, and incorporated herein by reference).
3.31
Certificate of Formation of Martin Midstream NGL Holdings II, LLC, dated April 21, 2011, as amended (filed as Exhibit 3.13 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed July 31, 2014, and incorporated herein by reference).
3.32
Limited Liability Company Agreement of Martin Midstream NGL Holdings II, LLC, dated May 15, 2014 (filed as Exhibit 3.14 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed July 31, 2014, and incorporated herein by reference).
3.33
Certificate of Formation of MOP Midstream Holdings, LLC, dated March 20, 2012 (filed as Exhibit 3.16 to the Partnership’s Registration Statement on Form S-4 (SEC File No. 333-187825), filed on April 10, 2013, and incorporated herein by reference).
3.34
Limited Liability Company Agreement of MOP Midstream Holdings, LLC, dated March 26, 2012 (filed as Exhibit 3.17 to the Partnership’s Registration Statement on Form S-4 (SEC File No. 333-187825), filed on April 10, 2013, and incorporated herein by reference).
3.35
Certificate of Incorporation of Martin Midstream Finance Corporation, dated March 15, 2010 (filed as Exhibit 3.12 to the Partnership’s Registration Statement on Form S-4 (SEC File No. 333-169408), filed September 16, 2010, and incorporated herein by reference).
3.36
Bylaws of Martin Midstream Finance Corporation, dated March 16, 2010 (filed as Exhibit 3.13 to the Partnership’s Registration Statement on Form S-4 (SEC File No. 333-169408), filed September 16, 2010, 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).

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4.3
Indenture (including form of 7.250% Senior Notes due 2021), dated February 11, 2013, 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 (SEC File No. 000-50056), filed February 12, 2013, and incorporated herein by reference).
4.4
First Supplemental Indenture, to the Indenture dated February 11, 2013, dated July 21, 2014, by and among the Partnership, Martin Midstream Finance Corp., the Guarantors named therein and Wells Fargo Bank National Association, as trustee (filed as Exhibit 4.4 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed July 31, 2014, and incorporated herein by reference).
4.4
Second Supplemental Indenture, to the Indenture dated February 11, 2013 dated September 30, 2014, by and among the Partnership, Martin Midstream Finance Corp., the Guarantors named therein and Wells Fargo Bank National Association, as trustee.
4.5
Third Supplemental Indenture, to the Indenture dated February 11, 2013 dated October 27, 2014, by and among the Partnership, Martin Midstream Finance Corp., the Guarantors named therein and Wells Fargo Bank National Association, as trustee (filed as Exhibit 4.4 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed October 29, 2014 and incorporated herein by reference).
31.1*
Certifications of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*
Certifications of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*
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."
32.2*
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."
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Interactive Data: the following financial information from Martin Midstream Partners L.P.’s Quarterly Report on Form 10-Q for the fiscal quarter ended March, 2015, formatted in Extensible Business Reporting Language: (1) the Consolidated and Condensed Balance Sheets; (2) the Consolidated and Condensed Statements of Income; (3) the Consolidated and Condensed Statements of Cash Flows; (4) the Consolidated and Condensed Statements of Capital; and (5) the Notes to Consolidated and Condensed Financial Statements.
* Filed or furnished herewith


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