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American Midstream Reports Record Fourth Quarter and Full Year 2014 Financial Results

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American Midstream Partners LP (NYSE:AMID) (“Partnership”) today reported financial results for the three and twelve months ended December 31, 2014.

Fourth quarter and full-year highlights include:

  • Executed and integrated acquisitions totaling approximately $600 million to further expand the Partnership’s midstream platform in prolific U.S. resource plays, including the Eagle Ford, Permian, and Bakken;
  • Expanded assets in core operating areas, including the Lavaca System in the Eagle Ford, which is currently flowing 115 million cubic feet per day (“MMcf/d”), nearly tripling since the acquisition in January 2014;
  • Developed additional fee-based margin with the build-out of the Harvey Terminal, which increased the Partnership’s total storage capacity by approximately 30 percent year-over-year;
  • Generated record fourth quarter and full-year Adjusted EBITDA of $19.2 million and $45.6 million, respectively; and
  • Increased year-over-year distributions by approximately six percent with fourth quarter and full-year distribution coverage ratios of 1.28 and 1.02, respectively.

Gross margin (a non-GAAP financial measure) for the fourth quarter of 2014 was $36.2 million, an increase of $13.3 million, or 58.1 percent, compared to $22.9 million in the prior year period. For the twelve months ended December 31, 2014, gross margin was $102.8 million compared to $74.8 million in the prior year, an increase of $28.0 million, or 37.4 percent. The increase in gross margin for the three and twelve months ended December 31, 2014 was primarily due to higher gross margin in the Partnership’s Gathering and Processing segment from the January 2014 acquisition of the Lavaca System and the October 2014 acquisition of Costar Midstream, higher gross margin in the Partnership’s Transmission segment as a result of the full-year benefit of the April 2013 acquisition of the High Point System, and an increase in gross margin in the Terminals segment due to the ongoing expansion of the Harvey terminal.

Adjusted EBITDA (a non-GAAP financial measure) for the three and twelve months ended December 31, 2014 was $19.2 million and $45.6 million, respectively, compared to $10.5 million and $31.9 million for same periods in 2013, increases of 82.6 percent and 42.8 percent, respectively. The fourth quarter and full year increase in Adjusted EBITDA was primarily related to the above-mentioned acquisitions as well as the benefit of the August 2014 acquisition of the Main Pass Oil Gathering system (“MPOG”).

Distributable cash flow (“DCF”) (a non-GAAP financial measure) for the three and twelve months ended December 31, 2014 was $15.5 million and $32.7 million, respectively, representing a distribution coverage ratio of 1.28 and 1.02, respectively. The fourth quarter 2014 distribution of $12.2 million, or $0.4725 per common unit, an increase of 4.4 percent per unit over the fourth quarter 2013 distribution, was paid February 13, 2015 to unitholders of record as of February 6, 2015.

Reconciliations of the non-GAAP financial measures gross margin, Adjusted EBITDA, and DCF to net income (loss) attributable to the Partnership, the most directly comparable GAAP financial measure, are provided at the end of this press release.

Net loss attributable to the Partnership for the three and twelve months ended December 31, 2014 was $94.3 million and $98.0 million respectively, compared to net loss of $5.6 million and $34.0 million for the fourth quarter and full year 2013. The net loss attributable to the Partnership for the three and twelve months ended December 31, 2014 included a $99.9 million asset impairment charge, partially offset by the items that increased Adjusted EBITDA described above. During the fourth quarter, the decline in commodity prices negatively impacted certain producers and shippers to whom the Partnership provides gathering and processing services. As such, impairment charges of $99.9 million were recorded on certain non-core, legacy gathering and processing assets where the Partnership anticipates limited volume growth, volume reductions as a result of the decline in commodity prices, or a decrease in gross margin attributable to the significant decrease in forecast commodity prices.

2014 BUSINESS HIGHLIGHTS

Acquisitions

The Partnership executed and integrated approximately $600 million of acquisitions during 2014 to diversify its asset base in prolific U.S. resource plays, including:

  • October 2014 acquisition of Costar Midstream to expand the Partnership’s operations to East Texas, the Permian, and the Bakken, funded with a combination of cash and common units issued directly to the sellers;
  • August 2014 acquisition of the Main Pass Oil Gathering system to provide oil gathering services to offshore producers in the Gulf of Mexico;
  • January 2014 acquisition of the Lavaca natural gas gathering system in the prolific Eagle Ford; and
  • Execution of an option agreement to acquire a 50 percent interest in Republic Midstream, LLC (“Republic Midstream”) at the commencement of operations, currently expected in the second half of 2015. Republic Midstream is a crude oil gathering, storage, blending, and intermediate takeaway system in the Eagle Ford being developed by an affiliate of ArcLight Capital Partners, which controls the General Partner of the Partnership.

In addition, during 2014 the Partnership received approval of a right-of-first-offer from the Board of Directors of its General Partner to acquire the Gonzales County full-well-stream gathering system (“Gonzales County”) in the Eagle Ford that is being developed by the General Partner. The producer customer on the system recently announced its intention to cease drilling activities in areas served by the system. As such, the Partnership does not anticipate drop-down of the system in 2015 and will continue to evaluate timing of drop-down with the General Partner.

Organic Growth and Asset Restructuring

During 2014 the Partnership added incremental fee-based gross margin through the execution of organic growth projects and optimization of legacy assets, including:

  • Significant expansion of the Lavaca System located in the prolific Eagle Ford, nearly tripling volumes to 115 MMcf/d currently since acquisition of the system in January 2014;
  • Commencement of operations at the Harvey Terminal in July 2014, adding approximately 238,000 barrels in incremental storage capacity and increasing the Partnership’s total storage capacity to approximately 1.7 million barrels;
  • Secured significant additional fee-based firm transportation agreements on the AlaTenn system and Magnolia gathering assets, increasing contracted volumes by approximately 50 percent on AlaTenn and more than 100 percent on Magnolia;
  • Execution of an agreement in principle to retire the Midla pipeline and replace with a new 12-inch pipeline from Winnsboro, Louisiana to Natchez, Mississippi (“Natchez Line”) to serve existing residential, commercial, and industrial customers. The restructuring is anticipated to result in Midla generating a reasonable return on invested capital. The agreement is subject to final agreements and ongoing proceedings at the Federal Energy Regulatory Commission; and
  • Execution of a long-term, fee-based agreement in early 2015 to construct a 15-mile extension of the High Point system to serve an existing refinery customer in southeast Louisiana, which is expected to be placed into service later this year.

Capital Markets

During 2014, the Partnership executed capital markets transactions to support organic growth and acquisitions, including:

  • Increased borrowing capacity on the Partnership’s revolving credit facility from $200 million to $500 million with the option to further increase borrowing capacity to $700 million;
  • Generated approximately $240 million of total proceeds, net of offering costs, through the issuance of common units in a public offering and private placement, as well as through the issuance of Series B Convertible Units to the Partnership’s General Partner; and
  • Executed an amendment related to the outstanding Series A Units whereby distributions on Series A Units will be made with paid-in-kind Series A Units, cash, or a combination thereof, which began with the distribution for the three months ended June 30, 2014 and will continue through the distribution for the three months ended March 31, 2015.

2015 ADJUSTED EBITDA, DCF, AND GROWTH CAPITAL EXPENDITURE FORECAST

The Partnership updated its 2015 forecast and now expects 2015 Adjusted EBITDA to be in a range of $85 million to $95 million and DCF in a range of $65 million to $75 million. The change to the 2015 forecast is primarily a result of significantly lower forecasted commodity prices in 2015 and the anticipated delay in the drop-down of the Gonzales County system from the Partnership’s General Partner. The forecast includes the benefit of the anticipated acquisition of a 50 percent interest in Republic Midstream, and does not include the benefit of additional acquisitions, drop downs, or asset development projects the Partnership may pursue. The 2015 forecast also reflects current expectations of operational volumes and derivative instruments outstanding.

2015 growth capital expenditures, which exclude capital for maintenance and acquisition capital expenditures, are anticipated to be in a range of $125 million to $135 million. Forecasted growth capital expenditures include construction of midstream infrastructure for the Lavaca and Bakken systems, completion of the Longview rail facility, construction of the Natchez Line on the Midla system, the continued build-out of the Harvey Terminal, construction of the High Point extension, and other organic growth projects.

2014 Actual 2015 Guidance Percent change
(millions) (from the midpoint)
Adjusted EBITDA $45.6 $85 – $95 97%
Distributable Cash Flow $32.7 $65 – $75 114%
Growth Capital Expenditures $90.3 $125 – $135 44%

EXECUTIVE COMMENTARY

“Our record fourth quarter and full year results reflect the successful execution of our growth strategy in 2014,” stated Steve Bergstrom, Executive Chairman, President and Chief Executive Officer. “During 2014 we significantly diversified the Partnership’s asset platform with the acquisitions of the Lavaca System in January, MPOG in August, and Costar Midstream in October. We now operate assets in the majority of U.S. resource plays including the Eagle Ford, East Texas, Bakken and Permian.”

“The Lavaca and Costar assets contributed significant gross margin in the gathering and processing segment, and throughputs in the transmission segment increased approximately 20 percent over 2013, primarily attributable to High Point. Our Terminals segment delivered significant year-over-year fee-based growth, expanding total storage capacity by approximately 30 percent with the successful initial build-out of the Harvey Terminal. Harvey is adding approximately 300,000 barrels of additional storage capacity in the first half of 2015 and has the potential to more than double the Partnership’s existing capacity of 1.7 million barrels.”

“We remain focused on executing asset development projects in 2015 that will contribute incremental, fee-based cash flow to our portfolio. We expect the Bakken crude oil gathering project to begin operations in the next few weeks and anticipate acquiring a 50 percent interest in Republic Midstream in the second half of the year. The Lavaca System located in the prolific Eagle Ford Shale is currently flowing approximately 115 MMcf/d, which is above our expectations. Construction of the Longview rail facility, which complements our existing off-spec treatment operations in East Texas, is currently underway with operations expected to commence in the second half of 2015. The facility will significantly increase the inbound supply of off-spec condensate and the outbound sales margins of marketable NGLs and blendable condensate.”

“In light of the dynamic commodity price environment, we updated our 2015 forecast and currently expect Adjusted EBITDA of approximately $90 million at the midpoint of our guidance range, approximately double our 2014 Adjusted EBITDA, and the expectation to hold our current distribution flat in 2015 in order to maintain distribution coverage at approximately one times. In addition, we lowered our growth capital expenditure forecast to reflect updated timing of capital expenditures and ongoing efforts to operate prudently in the current price environment.”

“In 2014 we delivered on our strategy by diversifying the Partnership in major U.S. resource plays and executing significant asset development projects. Looking ahead, we are actively engaged in expanding our asset base through organic expansion projects as well as third-party and drop-down acquisitions. We remain committed to delivering long-term, sustainable distribution growth to our unitholders, and ArcLight Capital, which controls our General Partner, remains strongly supportive of our long-term growth strategy.”

SEGMENT PERFORMANCE

Gross Margin

Three months ended
December 31,

Twelve months ended
December 31,

Percent change
(millions)
2014 2013 2014 2013 Quarter-over-quarter Year-over-year
Gathering and Processing $19.7 $8.2 $50.8 $37.0 140.2% 37.3%
Transmission $13.8 $13.1 $42.8 $32.4 5.3% 32.1%
Terminals $2.7 $1.6 $9.2 $5.4 68.8% 70.4%

Gathering and Processing – The Gathering and Processing segment includes natural gas transportation, gathering, treating, processing, fractionation, and marketing or re-delivery of natural gas and NGLs to various markets and pipeline systems.

Segment gross margin for the Gathering and Processing segment was $19.7 million and $50.8 million for the three and twelve months ended December 31, 2014, respectively, compared to $8.2 million and $37.0 million for the three and twelve months ended December 31, 2013. The increase in gross margin for the fourth quarter and full-year was primarily attributable to the incremental gross margin from the Lavaca System as well as the Longview, Chapel Hill, and Yellow Rose assets acquired with the Costar Midstream acquisition, partially offset by lower throughput volumes on the Partnership’s legacy assets.

Natural gas throughput volumes averaged 320.3 MMcf/d and 274.8 MMcf/d for the three and twelve months ended December 31, 2014, respectively, compared to 298.2 MMcf/d and 277.2 MMcf/d for the fourth quarter and full year 2013. Processed NGLs averaged 138.4 thousand gallons per day (“Mgal/d”) and 64.2 Mgal/d for the three and twelve months ended December 31, 2014, respectively, compared to 49.6 Mgal/d and 52.0 Mgal/d for the same periods in 2013. The increase in natural gas throughput volumes for the fourth quarter was primarily attributable to the addition of the Lavaca System as well as the Costar Midstream assets, partially offset by lower throughputs from the Partnership’s legacy assets. The decrease in natural gas throughput for the full year 2014 was primarily attributable to lower throughputs from the Partnership’s legacy assets, partially offset by increased throughput from the Lavaca System and the Costar Midstream assets. The increase in processed NGLs for the three and twelve months ended December 31, 2014, was attributable to the addition of the Costar Midstream assets in the fourth quarter, partially offset by lower processed NGLs from the Partnership’s legacy assets.

Transmission – The Transmission segment transports and delivers natural gas from producing wells, receipt points, or pipeline interconnects to pipeline or end-use markets primarily under fee-based and firm transportation agreements.

Segment gross margin for the Transmission segment was $13.8 million and $42.8 million for the three and twelve months ended December 31, 2014, respectively, compared to $13.1 million and $32.4 million for the three and twelve months ended December 31, 2013. The increase in gross margin for the fourth quarter and full year was attributable to the full-year benefit of the April 2013 acquisition of the High Point System.

Total natural gas throughput volumes averaged 803.4 MMcf/d and 778.9 MMcf/d for the three and twelve months ended December 31, 2014, respectively, compared to 743.8 MMcf/d and 644.7 MMcf/d for the three and twelve months ended December 31, 2013. The increase in throughput volume for the three and twelve months ended December 31, 2014 was primarily due to the additional volumes on the High Point System.

Terminals - The Terminals segment provides above-ground, fee-based storage services at the Partnership’s marine terminals to support various commercial customers, including commodity brokers, refiners and chemical manufacturers to store a range of products, including chemicals, distillates, and agricultural products.

Segment gross margin for the Terminals segment was $2.7 million and $9.2 million for the three and twelve months ended December 31, 2014, respectively, compared to $1.6 million and $5.4 million for the three and twelve months ended December 31, 2013. The increase in gross margin was attributable to an approximate 30 percent increase in storage capacity in 2014 compared to 2013 as a result of incremental capacity constructed in 2014, as well as full-year results in 2014 compared to less than nine months in 2013 as the Partnership did not have a Terminals segment for the three months ended March 31, 2013.

BALANCE SHEET

As of December 31, 2014, the Partnership had $0.5 million of cash on hand, and $374.6 million outstanding under its senior secured revolving credit facility. For the three and twelve months ended December 31, 2014, capital expenditures totaled $55.8 million and $97.0 million, respectively, which included $2.1 million and $6.2 million for maintenance capital, respectively. 2014 capital expenditures were primarily attributable to expansion of the Lavaca System, construction of the Bakken and Longview systems, completion of the Yellow Rose plant, and the ongoing build-out of the Harvey Terminal.

DERIVATIVES

The Partnership enters into derivative agreements to hedge exposure to commodity prices associated with natural gas, NGLs, and crude oil. As of December 31, 2014, approximately four percent of the Partnership’s exposure to NGL prices is hedged through the first half of 2015. Details regarding the Partnership’s hedge program are found in its Annual Report on Form 10-K for the quarter ended December 31, 2014.

CONFERENCE CALL INFORMATION

The Partnership will host a conference call at 10:00 a.m. Eastern Time on Tuesday, March 10, 2015 to discuss results. The call will be webcast and archived on the Partnership’s website for a limited time.

Dial-In Numbers: (877) 201-0168 (Domestic toll-free)
(647) 788-4901 (International)
Conference ID:

68129339

Webcast URL:

www.AmericanMidstream.com under Investor Relations

Non-GAAP Financial Measures

This press release and the accompanying tables, include financial measures in accordance with U.S. generally accepted accounting principles, or GAAP, as well as non-GAAP financial measures, including “Adjusted EBITDA,” “Gross Margin,” and “Distributable Cash Flow.” The tables included in this press release include reconciliations of these non-GAAP financial measures to the nearest GAAP financial measures. In addition, an “Explanation of Non-GAAP Financial Measures” is set forth in Appendix A attached to this press release.

About American Midstream Partners, LP

Denver-based American Midstream Partners, LP is a growth-oriented limited partnership formed to own, operate, develop and acquire a diversified portfolio of midstream energy assets. The Partnership provides midstream services in the Texas, North Dakota, and the Gulf Coast and Southeast regions of the United States. For more information about American Midstream Partners, LP, visit www.AmericanMidstream.com.

Forward-Looking Statements

This press release includes forward-looking statements. These statements relate to, among other things, projections of operational volumetrics and improvements, growth projects, cash flows and capital expenditures. We have used the words “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “plan,” “predict,” “project,” “should,” “will,” “potential,” and similar terms and phrases to identify forward-looking statements in this press release. Although we believe the assumptions upon which these forward-looking statements are based are reasonable, any of these assumptions could prove to be inaccurate and the forward-looking statements based on these assumptions could be incorrect. Our operations and future growth involve risks and uncertainties, many of which are outside our control, and any one of which, or a combination of which, could materially affect our results of operations and whether the forward-looking statements ultimately prove to be correct. Actual results and trends in the future may differ materially from those suggested or implied by the forward-looking statements depending on a variety of factors which are described in greater detail in our filings with the SEC. The closing of the Republic Midstream and Gonzales County acquisitions discussed in this press release are subject to negotiation of definitive acquisition agreements and other conditions beyond our control. Construction of the projects described in this press release is subject to risks beyond our control including cost overruns and delays resulting from numerous factors. In addition, we face risks associated with the integration of acquired businesses, decreased liquidity, increased interest and other expenses, assumption of potential liabilities, diversion of management’s attention, and other risks associated with acquisitions and growth, including the acquisition of the Main Pass Oil Gathering system and the acquisition of Costar Midstream, LLC described in this press release and either or both of the Republic Midstream and Gonzales County acquisitions, if consummated. Please see our Risk Factor disclosures included in our Annual Report on Form 10-K for the year ended December 31, 2013 filed on March 11, 2014, and our Quarterly Report on Form 10-Q for the quarter ended September 30, 2014 filed on November 10, 2014. On December 23, 2014, we filed Amendment No. 1 on Form 10-Q/A to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2014. All future written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the previous statements. The forward-looking statements herein speak as of the date of this press release. We undertake no obligation to update any information contained herein or to publicly release the results of any revisions to any forward-looking statements that may be made to reflect events or circumstances that occur, or that we become aware of, after the date of this press release.

American Midstream Partners, LP and Subsidiaries

Consolidated Balance Sheets
(Unaudited, in thousands)

December 31,
2014 2013
Assets
Current assets
Cash and cash equivalents $ 499 $ 393
Accounts receivable 4,924 6,822
Unbilled revenue 24,619 23,001
Risk management assets 688 473
Other current assets 15,502 7,497
Current deferred tax asset 3,086
Current assets held for sale 52 272
Total current assets 49,370 38,458
Property, plant and equipment, net 582,182 312,701
Goodwill 142,236 16,447
Intangible assets, net 106,306 3,682
Investment in unconsolidated affiliates 22,252
Other assets, net 13,117 9,064
Noncurrent assets held for sale, net 1,181 1,723
Total assets $ 916,644 $ 382,075
Liabilities and Partners’ Capital
Current liabilities
Accounts payable $ 20,326 $ 3,261
Accrued gas purchases 14,326 17,386
Accrued expenses and other current liabilities 25,788 15,058
Current portion of long-term debt 2,908 2,048
Risk management liabilities 215 423
Current liabilities held for sale 12 114
Total current liabilities 63,575 38,290
Risk management liabilities 101
Asset retirement obligations 34,645 34,636
Other liabilities 126 191
Long-term debt 372,950 130,735
Deferred tax liability 8,199 4,749
Noncurrent liabilities held for sale, net 95
Total liabilities 479,495 208,797
Commitments and contingencies
Convertible preferred units
Series A convertible preferred units (5,745 thousand and 5,279 thousand units issued and outstanding as of December 31, 2014 and 2013, respectively) 107,965 94,811
Equity and partners’ capital
General Partner Interests (392 thousand and 185 thousand units issued and outstanding as of December 31, 2014 and 2013, respectively) (2,450 ) 2,696
Limited Partner Interests (22,670 thousand and 7,414 thousand units issued and outstanding as of December 31, 2014 and 2013, respectively) 294,695 71,039
Series B convertible units (1,255 thousand and zero units issued and outstanding as of December 31, 2014 and 2013, respectively) 32,220
Accumulated other comprehensive income (loss) 2 104
Total partners’ capital 324,467 73,839
Noncontrolling interests 4,717 4,628
Total equity and partners’ capital 329,184 78,467
Total liabilities, equity and partners’ capital $ 916,644 $ 382,075

American Midstream Partners, LP and Subsidiaries

Consolidated Statements of Operations

(Unaudited, in thousands, except for per unit amounts)

Three months ended December 31, Twelve months ended December 31,
2014 2013 2014 2013 2012
Revenue $ 79,369 $ 76,852 $ 307,309 $ 294,051 $ 204,868
Gain (loss) on commodity derivatives, net 808 (82 ) 1,091 28 3,400
Total revenue 80,177 76,770 308,400 294,079 208,268
Operating expenses:
Purchases of natural gas, NGLs and condensate 42,223 52,055 197,952 215,053 154,472
Direct operating expenses 13,813 9,867 45,702 32,236 17,183
Selling, general and administrative expenses 5,998 6,572 23,103 19,079 14,309
Equity compensation expense 404 217 1,536 2,094 1,783
Depreciation, amortization and accretion expense 9,482 7,728 28,832 30,002 21,287
Total operating expenses 71,920 76,439 297,125 298,464 209,034
Gain (loss) on involuntary conversion of property, plant and equipment 343 (1,021

)

Gain (loss) on sale of assets, net 2 (122 ) 123
Loss on impairment of property, plant and equipment (99,892 ) (2,923 ) (99,892 ) (18,155 )
Operating income (loss) (91,633 ) (2,592 ) (88,739 ) (22,197 ) (1,664 )
Other income (expense):
Interest expense (2,564 ) (2,333 ) (7,577 ) (9,291 ) (4,570 )
Other expense 2 (670

)

Earnings in unconsolidated affiliates 231 348
Net income (loss) before income tax benefit (93,964 ) (4,925 ) (96,638 ) (31,488 ) (6,234 )
Income tax (expense) benefit (297 ) (94 ) (557 ) 495
Net income (loss) from continuing operations (94,261 ) (5,019 ) (97,195 ) (30,993 ) (6,234 )
Discontinued operations
Gain (loss) from operations of disposal groups, net of tax (29 ) (522 ) (611 ) (2,413 ) (18 )
Net income (loss) (94,290 ) (5,541 ) (97,806 ) (33,406 ) (6,252 )
Net income (loss) attributable to noncontrolling interests 7 100 214 633 256
Net income (loss) attributable to the Partnership $ (94,297 ) $ (5,641 ) $ (98,020 ) $ (34,039 ) $ (6,508 )
General Partner’s Interest in net income (loss) $ (1,231 ) $ (209 ) $ (1,279 ) $ (1,405 ) $ (129 )
Limited Partners’ Interest in net income (loss) $ (93,066 ) $ (5,432 ) $ (96,741 ) $ (32,634 ) $ (6,379 )

Distribution declared per common unit (a)

$

0.4725

$

0.4525

$

1.8500

$

1.7500

$

1.7300

Limited partners’ net income (loss) per common unit:

Basic and diluted:

Income (loss) from continuing operations

$

(4.98

)

$

(1.43

)

$

(8.54

)

$

(7.15

)

$

(0.70

)

Income (loss) from operations of disposal groups

(0.04

)

(0.27

)

Net income (loss)

$

(4.98

)

$

(1.43

)

$

(8.58

)

$

(7.42

)

$

(0.70

)

Weighted average number of common units outstanding:

Basic and diluted

19,597

5,125

13,472

7,525

9,113

(a) Declared and paid during the quarters or years ended December 31, 2014, 2013, and 2012.

American Midstream Partners, LP and Subsidiaries

Consolidated Statements of Cash Flows

(Unaudited, in thousands)

Year Ended December 31,
2014 2013 2012
Cash flows from operating activities
Net income (loss) $ (97,806 ) $ (33,406 ) $ (6,252 )
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, amortization and accretion expense 28,832 29,999 21,414
Amortization of deferred financing costs 2,212 1,334 716
Amortization of weather derivative premium 1,035 662
Unrealized (gain) loss on derivative contracts, net (595 ) 1,505 (992 )
Non-cash compensation 1,626 2,094 1,783
Postretirement expense (benefit) (45 ) (73 ) (88 )
(Gain) loss on involuntary conversion of property, plant and equipment (343 ) 1,021
(Gain) loss on sale of assets, net 207 75 (128 )
Loss on impairment of property, plant and equipment 99,892 18,155
Loss on impairment of noncurrent assets held for sale 673 2,400
Deferred tax expense (benefit) 213 (847 )
Changes in operating assets and liabilities, net of effects of assets acquired and liabilities assumed:
Accounts receivable 13,067 (790 ) (740 )
Unbilled revenue 2,272 (226 ) 2,768
Risk management assets and liabilities (809 ) (1,147 ) (156 )
Other current assets (7,533 ) (1,614 ) 984
Other assets, net 6,049 (823 ) (57 )
Accounts payable (12,026 ) (845 ) 1,197
Accrued gas purchases (5,540 ) 462 (1,711 )
Accrued expenses and other current liabilities (9,149 ) 769 (943 )
Asset retirement obligations (1,030 )
Other liabilities (67 ) (118 ) (468 )
Net cash provided by operating activities 21,478 17,223 18,348
Cash flows from investing activities
Cost of acquisitions, net of cash acquired (362,316 ) (51,377 )
Additions to property, plant and equipment (96,998 ) (27,196 ) (11,705 )
Proceeds from disposal of property, plant and equipment 6,323 500 128
Insurance proceeds from involuntary conversion of property, plant and equipment 482 527
Investment in unconsolidated affiliate (12,000 )
Proceeds from equity method investment, return of capital 1,632
Restricted cash (8,511 ) (2,000 )
Net cash used in investing activities (471,870 ) (28,214 ) (62,427 )
Cash flows from financing activities
Proceeds from issuance of common units to public, net of offering costs 204,255 54,853
Unitholder contributions 5,588 13,075 13
Unitholder distributions (28,009 ) (16,120 ) (16,070 )
Issuance of Series A Units 14,393
Issuance of Series B Units 30,000
Unitholder distributions for Blackwater Acquisition (27,650 )
Acquisition of noncontrolling interests (8 ) (752 )
Net distributions to noncontrolling interests (314 ) (661 ) (225 )
LTIP tax netting unit repurchase (256 ) (630 ) (385 )
Deferred financing costs (3,841 ) (2,113 ) (1,564 )
Payments on other debt (2,589 ) (2,640 )
Borrowings on other debt 3,449 3,795
Payments on loan to affiliate (20,000 )
Payments on bank loans (34,730 )
Borrowings on bank loans 27,546
Payments on long-term debt (250,870 ) (131,571 ) (59,230 )
Borrowings on long-term debt 493,085 134,021 121,245
Net cash provided by financing activities 450,490 10,816 43,784
Net increase (decrease) in cash and cash equivalents 98 (175 ) (295 )
Cash and cash equivalents
Beginning of period 401 576 871
End of period $ 499 $ 401 $ 576
Supplemental cash flow information
Interest payments, net $

6,726

$ 6,416 $ 3,185
Supplemental non-cash information
(Decrease) increase in accrued property, plant and equipment $ 31,390 $ (5,181 ) $ 6,968
Receivable for reimbursable construction in progress projects 141
Net assets contributed by General Partner in Blackwater acquisition 22,121
Net assets contributed by General Partner in exchange for the issuance of Series A Units 59,995
Fair value of Series A Units in excess of net assets received 15,612
Accrued and in-kind unitholder distribution for Series A Units 13,154 4,811
In-kind unitholder distribution for Series B Units 2,220
Common unit issuance related to Costar Acquisition 147,296

American Midstream Partners, LP and Subsidiaries

Reconciliation of Net income (loss) attributable to the Partnership

to Adjusted EBITDA to Distributable Cash Flow

(Unaudited, in thousands)

Three months ended December 31, Twelve months ended December 31,
2014 2013 2014 2013 2012
Reconciliation of Adjusted EBITDA and Distributable Cash Flow to Net income (loss) attributable to the Partnership
Net income (loss) attributable to the Partnership $ (94,297 ) $ (5,641 ) $ (98,020 ) $ (34,039 ) $ (6,508 )
Add:
Depreciation, amortization and accretion expense 9,482 7,728 28,832 30,002 21,287
Interest expense 2,405 2,149 6,433 7,850 4,570
Debt issuance costs 461 518 3,841 2,113 1,564
Unrealized (gain) loss on derivatives, net (2 ) 337

(595

) 1,495 (992 )
Non-cash equity compensation expense 427 217

1,626

2,094 1,783
Transaction expenses 234 2,139

1,794

3,987
Income tax expense (benefit) 282 (185 ) 224 (847 )
Impairment on property, plant and equipment 99,892 2,923 99,892 18,155
Loss on impairment of noncurrent assets held for sale 593 673 2,400
Proceeds from equity method investment, return of capital 649 1,632
Deduct:
COMA income 342 299 943 843 3,373
Straight-line amortization of put costs (a) 30 119 291
OPEB plan net periodic benefit 10 19

45

73 88
Gain (loss) on involuntary conversion of property, plant and equipment 343 (1,021 )
Gain (loss) on sale of assets, net 2 (75 ) (207 ) (75 ) 123
Adjusted EBITDA $ 19,179 $ 10,505 $ 45,551 $ 31,907 $ 18,850
Deduct:
Cash interest expense (b) 2,366 1,713 6,275 7,295 3,854
Normalized maintenance capital (c) 1,300 1,196 5,200 4,685 3,828
Normalized integrity management costs (d) 1,007
Series A convertible preferred payment (e) 1,321 1,338 3,696
Distributable Cash Flow $ 15,513 $ 6,275 $ 32,738 $ 16,231 $ 10,161
(a) Amounts noted represent the straight-line amortization of the cost of commodity put contracts over the life of the contract.
(b) Excludes amortization of debt issuance costs and mark-to-market adjustments related to interest rate derivatives.
(c) Represents annual maintenance capital expenditures in each given period, which is what the Partnership expects to be required to maintain assets over the long term.
(d)

Represents integrity management costs over the seven year mandatory testing cycle net of integrity management costs that are expensed in direct operating expenses. In 2013, integrity management costs were no longer normalized in the calculation of distributable cash flow.

(e) Calculated on a pro-rata basis for the number of days the Series A units were outstanding during the given periods.

American Midstream Partners, LP and Subsidiaries

Reconciliation of Gross Margin to Net income (loss) attributable to the Partnership

(Unaudited, in thousands)

Three months ended December 31, Twelve months ended December 31,
2014 2013 2014 2013 2012
Reconciliation of Gross Margin to Net income (loss) attributable to the Partnership
Gathering and processing segment gross margin $ 19,694 $ 8,175 $ 50,817 $ 36,985 $ 36,118
Transmission segment gross margin 13,846 13,112 42,828 32,408 13,313
Terminals segment gross margin (a) 2,687 1,604 9,162 5,428
Total gross margin 36,227 22,891 102,807 74,821 49,431
Plus:
Gain (loss) on commodity derivatives 808 (82 ) 1,091 28 3,400
Less:
Direct operating expenses (b) 12,310 7,966 39,360 27,833 17,183
Selling, general and administrative expenses 5,998 6,572 23,103 19,079 14,309
Equity compensation expense 404 217 1,536 2,094 1,783
Depreciation, amortization and accretion expense 9,482 7,728 28,832 30,002 21,287
(Gain) loss on involuntary conversion of property, plant and equipment (343 ) 1,021
(Gain) loss on sale of assets (2 ) 122 (123 )
Loss on impairment of property, plant and equipment 99,892 2,923 99,892 18,155
Interest expense 2,564 2,333 7,577 9,291 4,570
Other expense (2 ) 670
Earnings in unconsolidated affiliates (231 ) (348 )
Other, net (c) 584 (5 ) (208 ) 226 (965 )
Income tax expense (benefit) 297 94 557 (495 )
Income (loss) from operations of disposal groups, net of tax 29 522 611 2,413 18
Net income (loss) attributable to noncontrolling interest 7 100 214 633 256
Net income (loss) attributable to the Partnership $ (94,297 ) $ (5,641 ) $ (98,020 ) $ (34,039 ) $ (6,508 )
(a)

Terminals segment amounts are for the period from April 15, 2013 to December 31, 2013 for the year ended December 31, 2013

(b) Direct operating expenses includes Gathering and Processing segment direct operating expenses of $8.6 million and $3.7 million, respectively, and Transmission segment direct operating expenses of $3.7 million and $4.3 million, respectively, for the three months ended December 31, 2014 and 2013. Direct operating expenses related to our Terminals segment of $1.5 million and $1.9 million, respectively, for the three months ended December 31, 2014 and 2013 are included within the calculation of Terminals segment gross margin. Direct operating expenses includes Gathering and Processing segment direct operating expenses of $23.8 million, $14.6 million, and $12.2 million, respectively, and Transmission segment direct operating expenses of $15.6 million, $13.3 million, and $5.0 million, respectively, for the twelve months ended December 31, 2014, 2013, and 2012. Direct operating expenses related to our Terminals segment of $6.3 million, $4.4 million, and $0.0 million respectively, for the twelve months ended December 31, 2014, 2013, and 2012 are included within the calculation of Terminals segment gross margin.
(c)

Other, net includes realized (loss) gain on commodity derivatives of $0.9 million and $0.3 million and COMA income of $0.3 million and $0.3 million for the three months ended December 31, 2014 and 2013, respectively. Other, net includes realized gain on commodity derivatives of $0.7 million, $1.1 million and $2.4 million and COMA income of $0.9 million, $0.8 million and $3.4 million for the twelve months ended December 31, 2014, 2013 and 2012, respectively.

American Midstream Partners, LP and Subsidiaries

Segment Operating Data

(Unaudited, in thousands, except for operating and pricing data)

Three months ended December 31, Twelve months ended December 31,
2014 2013 2014 2013 2012
Segment Financial and Operating Data:
Gathering and Processing segment
Financial data:
Revenue

$

56,406

$ 50,845 $ 203,616 $ 205,179 $ 152,339
Gain (loss) on commodity derivatives, net 808 (82

)

1,091 28 3,400
Total revenue 57,214 50,763 204,707 205,207 155,739
Purchases of natural gas, NGLs and condensate 37,307 42,686 152,690 168,574 117,956
Direct operating expenses 8,620 3,650 23,783 14,574 12,152
Other financial data:
Segment gross margin $ 19,694 $ 8,175 $ 50,817 $ 36,985 $ 36,118
Operating data:
Average throughput (MMcf/d) 320.3 298.2 274.8 277.2 291.2
Average plant inlet volume (MMcf/d) (a) (b) 120.2 125.8 89.1 117.3 116.1
Average gross NGL production (Mgal/d) (a) (c) 138.4 49.6 64.2 52.0 49.9
Average gross condensate production (Mgal/d) (a) 167.1 47.2 75.2 46.2 22.6
Average realized prices:
Natural gas ($/MMcf) $ 4.27 $ 4.24 $ 4.92 $ 4.03 $ 2.98
NGLs ($/gal) $ 0.76 $ 1.01 $ 0.91 $ 0.90 $ 1.08
Condensate ($/gal) $ 1.15 $ 2.14 $ 1.62 $ 2.29 $ 2.30
Transmission segment
Financial data:
Revenue $ 18,773 $ 22,502 $ 88,189 $ 79,041 $ 52,529
Purchases of natural gas, NGLs and condensate 4,916 9,369 45,262 46,479 36,516
Direct operating expenses 3,690 4,316 15,577 13,259 5,031
Other financial data:
Segment gross margin $ 13,846 $ 13,112 $ 42,828 $ 32,408 $ 13,313
Operating data:
Average throughput (MMcf/d) 803.4 743.8 778.9 644.7 398.5
Average firm transportation – capacity reservation (MMcf/d) 605.3 587.6 577.9 640.7 703.6
Average interruptible transportation – throughput (MMcf/d) 483.8 497.0 468.9 389.2 86.6
Terminal Segment (d)
Financial data:
Total revenue $ 4,190 $ 3,505 $ 15,504 $ 9,831 $
Direct operating expenses 1,503 1,901

6,342

4,403

Other financial data:
Segment gross margin $ 2,687 $ 1,604 $ 9,162 $ 5,428 $
Operating data:
Storage utilization 82.9

%

96.0

%

82.9

%

96.2

%

%

(a) Excludes volumes and gross production under our elective processing arrangements.
(b) Includes gross plant inlet volume associated with our interest in the Burns Point processing plant.
(c) Includes net NGL production associated with our interest in the Burns Point processing plant.
(d) Terminals segment amounts are for the period from April 15, 2013 to December 31, 2013.

Appendix A

Note About Non-GAAP Financial Measures

Gross margin, adjusted EBITDA and distributable cash flow are all non-GAAP financial measures. Each has important limitations as an analytical tool because it excludes some, but not all, items that affect the most directly comparable GAAP financial measures. Management compensates for the limitations of these non-GAAP financial measures as analytical tools by reviewing the comparable GAAP financial measures, understanding the differences between the measures and incorporating these data points into management’s decision-making process.

You should not consider any of gross margin, adjusted EBITDA or distributable cash flow in isolation or as a substitute for or more meaningful than our results as reported under GAAP. Gross margin, adjusted EBITDA and distributable cash flow may be defined differently by other companies in our industry. Our definitions of these non-GAAP financial measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.

We define adjusted EBITDA as net income, plus interest expense, income tax expense, depreciation expense, certain non-cash charges such as non-cash equity compensation, unrealized losses on commodity derivative contracts, cash distributions in excess of earnings from unconsolidated affiliates and selected charges that are unusual or nonrecurring, less interest income, income tax benefit, unrealized gains on commodity derivative contracts, amortization of commodity put purchase costs, and selected gains that are unusual or nonrecurring. The GAAP measure most directly comparable to adjusted EBITDA is net income (loss) attributable to the Partnership.

Distributable cash flow is a significant performance metric used by us and by external users of the Partnership’s 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 the Partnership’s unitholders. Using this metric, management and external users of the Partnership’s financial statements can quickly compute the coverage ratio of estimated cash flows to planned cash distributions. Distributable cash flow is also an important financial measure for the Partnership’s unitholders since it serves as an indicator of the Partnership’s success in providing a cash return on investment. Specifically, this financial measure may indicate to investors whether we are generating cash flow at a level that can sustain or support an increase in the Partnership’s quarterly distribution rates. Distributable cash flow is also a quantitative standard used throughout the investment community with respect to publicly traded partnerships and limited liability companies 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). Distributable cash flow will not reflect changes in working capital balances.

We define distributable cash flow as adjusted EBITDA plus interest income, less cash paid for interest expense, normalized maintenance capital expenditures, and dividends related to the Series A convertible preferred units. The GAAP financial measure most comparable to distributable cash flow is net income (loss) attributable to the Partnership.

The GAAP measure most directly comparable to forecasted adjusted EBITDA and distributable cash flow is net income (loss) attributable to the Partnership. Net income attributable to the Partnership is forecasted to be approximately $35 million to $45 million in 2015.

Gross margin and segment gross margin are metrics that we use to evaluate our performance. We define segment gross margin in our Gathering and Processing segment as revenue generated from gathering and processing operations less the cost of natural gas, NGLs and condensate purchased and revenue from construction, operating and maintenance agreements (“COMA”). Revenue includes revenue generated from fixed fees associated with the gathering and treating of natural gas and from the sale of natural gas, NGLs and condensate resulting from gathering and processing activities under fixed-margin and percent-of-proceeds arrangements. The cost of natural gas, NGLs and condensate includes volumes of natural gas, NGLs and condensate remitted back to producers pursuant to percent-of-proceeds arrangements and the cost of natural gas purchased for our own account, including pursuant to fixed-margin arrangements.

We define segment gross margin in our Transmission segment as revenue generated from firm and interruptible transportation agreements and fixed-margin arrangements, plus other related fees, less the cost of natural gas purchased in connection with fixed-margin arrangements. Substantially all of our gross margin in this segment is fee-based or fixed-margin, with little to no direct commodity price risk.

We define segment gross margin in our Terminals segment as revenue generated from fee-based compensation on guaranteed firm storage contracts and throughput fees charged to our customers less direct operating expense which includes direct labor, general materials and supplies and direct overhead.

We define gross margin as the sum of our segment gross margin for our Gathering and Processing, Transmission and Terminals segments. The GAAP measure most comparable to gross margin is net income (loss) attributable to the Partnership.

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