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American Midstream Reports Third Quarter 2014 Financial Results

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American Midstream Partners, LP (NYSE:AMID) (“Partnership”) today reported financial results for the three and nine months ended September 30, 2014.

Gross margin (a non-GAAP financial measure) for the third quarter of 2014 was $21.3 million, an increase of $0.4 million, or 1.9 percent, compared to $20.9 million in the prior year period. For the nine months ended September 30, 2014, gross margin was $66.6 million compared to $51.9 million in the prior year period, an increase of $14.7 million, or 28.3 percent. The increase in gross margin for the three and nine months ended September 30, 2014 was primarily due to higher gross margin in the Partnership’s Transmission segment as a result of increased throughput from the April 2013 acquisition of the High Point System, incremental gross margin from the Terminals segment associated with the December 2013 acquisition of Blackwater Midstream, and incremental gross margin from the January 2014 acquisition of the Lavaca System, offset by lower gross margin in the Partnership’s Gathering and Processing segment attributable primarily to a decrease in throughput volumes on certain systems.

The Partnership reported Adjusted EBITDA (a non-GAAP financial measure) for the three and nine months ended September 30, 2014 of $9.0 million and $26.4 million, respectively, compared to $8.8 million and $21.4 million for the same periods in 2013. The increase in Adjusted EBITDA for the three and nine months ended September 30, 2014 was primarily attributable to the above-mentioned acquisitions, the acquisition of the Main Pass Oil Gathering system in August 2014, and the benefit of an adjustment related to debt issuance costs incurred in conjunction with amending the Partnership’s revolving credit facility in August 2014. The increase was partially offset by increased direct operating expenses associated with growth projects, higher integrity management costs within the transmission segment, and increased selling, general, and administrative expenses to support the Partnership’s current and anticipated growth.

Distributable cash flow (“DCF”) (a non-GAAP financial measure) for the three and nine months ended September 30, 2014 was $6.5 million and $17.2 million, respectively, representing a distribution coverage ratio of 0.77 and 0.86, respectively, including the impact of approximately 4.6 million common units issued in a private placement during the third quarter of 2014 in anticipation of future growth. The distribution coverage ratio excluding the private placement units would have been 1.04 and 0.97 for the three and nine months ended September 30, 2014, respectively. The third quarter 2014 distribution of $8.5 million, or $0.4725 per common unit, an increase of 4.4 percent per unit over the third quarter 2013 distribution, will be paid on November 14, 2014 to unitholders of record as of November 7, 2014.

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 nine months ended September 30, 2014 was $2.5 million and $3.7 million, respectively, compared to net loss of $2.7 million and $28.4 million for the same periods in 2013. The net loss attributable to the Partnership for the nine months ended September 30, 2013 was primarily a result of non-cash impairment charges on certain non-strategic gathering assets of $15.2 million in the second quarter of 2013. Excluding the impact of these impairments, the increase in net income for the three and nine months ended September 30, 2014 was primarily attributable to the same reasons for the increase in Adjusted EBITDA discussed above.

BUSINESS HIGHLIGHTS

Acquisition of Costar Midstream

On October 13, 2014, the Partnership acquired Costar Midstream LLC from Energy Spectrum Partners VI LP and Costar management for approximately $470 million. Costar is an onshore gathering and processing company with its primary gathering, processing, fractionation, and off-spec condensate treating and stabilization assets in East Texas and the Permian basin, with a significant crude oil gathering system project under way in the Bakken in North Dakota.

The acquisition was funded with approximately 6.9 million Partnership common units issued directly to Energy Spectrum and Costar management, and approximately $270 million of cash from borrowings under the Partnership’s revolving credit facility and proceeds from the August 2014 private placement.

Midla Natchez Line

On October 8, 2014, American Midstream Midla, LLC (“Midla”), a subsidiary of the Partnership, announced an agreement in principle to retire the existing 1920s vintage Midla pipeline that traverses Louisiana and Mississippi and replace the existing natural gas service with a new 12-inch pipeline from Winnsboro, Louisiana to Natchez Mississippi (the “Natchez Line”) to serve existing residential, commercial, and industrial customers. The agreement is subject to final agreements and ongoing proceedings at the Federal Energy Regulatory Commission.

Revolving Credit Facility Amendment

On September 8, 2014, the Partnership announced the execution of an amended and restated credit facility to extend the maturity to September 2019 and to increase the Partnership’s borrowing capacity from $200 million to $500 million, with the option to further increase the borrowing capacity to $700 million (subject to lender approval). The Partnership expects to utilize the credit facility to fund future growth and for other general Partnership purposes.

Private Placement of Common Units

On August 20, 2014, the Partnership issued approximately 4.6 million common units in a private placement for net proceeds of approximately $120 million.

Acquisition of Main Pass Oil Gathering System

On August 11, 2014, the Partnership acquired a 66.7 percent non-operated interest in the Main Pass Oil Gathering system (“MPOG”) from an affiliate of DCP Midstream, LLC for $13.5 million. The acquisition was funded through borrowings on the Partnership’s revolving credit facility.

Republic Midstream Crude Oil System

On August 5, 2014, the Partnership executed an option agreement providing the Partnership with the right to acquire a 50 percent interest in Republic Midstream, LLC (“Republic Midstream”) from an affiliate of ArcLight Capital Partners, LLC (“ArcLight”), which controls the General Partner of the Partnership. Republic Midstream executed an agreement with Penn Virginia Corporation (“Penn Virginia”) in July 2014 to construct a 170-mile crude oil gathering system, a 144-acre storage and blending crude oil terminal, and a 25-mile intermediate takeaway pipeline with initial capacity of 80,000 barrels per day to serve Penn Virginia’s acreage position in the Eagle Ford Shale. ArcLight has committed $400 million for development of the system and the Partnership will have the option to purchase a 50 percent interest at the commencement of operations in mid-2015 for total consideration of approximately $200 million. Midstream services will be provided to Penn Virginia under a long-term, fee-based transportation agreement, supported by minimum volume commitments and dedicated acreage in the area served by the gathering system.

Gonzales County Full-Well-Stream Gathering System

On August 4, 2014, the Board of Directors of the General Partner of the Partnership approved the Partnership’s right-of-first-offer to acquire the Gonzales County full-well-stream gathering and treating and saltwater disposal system in the Eagle Ford Shale. Following acquisition of the system, the Partnership will provide midstream services under a long-term, fee-based agreement. Construction of the system is under way, and the producer customer recently notified the Partnership of a change to their drilling program that will require modifications to the system and will delay commencement of operations until mid-2015. As such, the Partnership anticipates the drop-down of the system to be completed in mid-2015.

Series A Unit Distributions Amendment

The Partnership executed an amendment to the Partnership agreement related to its Series A Units, which became effective July 24, 2014. As a result of the Amendment, distributions on Series A Units will be made with paid-in-kind Series A Units, cash, or a combination thereof, at the discretion of the Board of Directors of the Partnership’s general partner, which began with the distribution for the three months ended June 30, 2014 and will continue for the subsequent three fiscal quarters. Prior to the Amendment, the Partnership was required to pay distributions on the Series A Units with a combination of paid-in-kind units and cash. The Board of Directors approved a distribution of paid-in-kind Series A Units for the three months ended June 30, 2014, which was made on August 14, 2014.

Harvey Terminal

Terminal storage operations at Harvey commenced in July 2014, adding approximately 250,000 barrels in incremental storage capacity and increasing the Partnership’s total storage capacity to approximately 1.7 million barrels. Construction of a deep-water ship dock is currently under way with completion expected in the first quarter of 2015. Upon completion, Harvey is expected to be a full-service storage site, providing rail, truck, barge, and deep-water service. Harvey has the potential for more than two million barrels of capacity when fully developed, which would increase the Partnership’s total storage capacity by more than 100 percent.

2014 ADJUSTED EBITDA, DCF, AND GROWTH CAPITAL EXPENDITURE FORECAST

The Partnership’s forecast for 2014 adjusted EBITDA and DCF remains unchanged in a range of $46 million to $48 million and $30 million to $32 million, respectively, based on its current forecast of operational volumes and prices for crude oil, natural gas, natural gas liquids, and derivative instruments currently outstanding. Growth capital expenditures in 2014, which exclude maintenance capital, continue to be forecasted in a range of $75 million to $80 million, which primarily includes capital expenditures associated with the Lavaca System, the development of the Harvey terminal, and the Bakken, Longview rail, and Permian development projects associated with the Costar acquisition.

2015 ADJUSTED EBITDA, DCF, AND GROWTH CAPITAL EXPENDITURE FORECAST

The Partnership forecasts 2015 Adjusted EBITDA in a range of $110 million to $120 million and DCF, in a range of $90 million to $100 million, based on its current forecast of operational volumes and prices for crude oil, natural gas, natural gas liquids, and derivative instruments currently outstanding. 2015 forecasted Adjusted EBITDA and DCF include the benefit of the anticipated acquisitions of Republic Midstream and the Gonzales County system. The Partnership’s guidance does not include the benefit of additional acquisitions, drop downs, or asset development projects the Partnership may pursue. Growth capital expenditures in 2015, which exclude capital for maintenance, are forecasted to be in a range of $140 million to $150 million and primarily include the Bakken, Longview rail, and Permian development projects associated with the Costar acquisition; capital costs to further expand the Lavaca System; development of the Natchez Line on the Midla system; and the ongoing build out of the Harvey terminal.

2014 Forecast 2015 Guidance % Change
(millions)
Adjusted EBITDA $46 – $48 $110 – $120 144.7%
Distributable Cash Flow $30 – $32 $90 – $100 206.5%
Growth Capital Expenditures $75 – $80 $140 – $150 87.1%

EXECUTIVE COMMENTARY

“Our strong year-to-date financial and operating results reflect continued success in executing our growth strategy,” stated Steve Bergstrom, Executive Chairman, President and Chief Executive Officer. “During the third quarter we further positioned the Partnership for long-term growth with the MPOG acquisition, commencement of operations at the Harvey terminal, execution of a successful private placement of common units, and significantly upsizing our credit facility. We also recently closed the acquisition of Costar Midstream, a transformative transaction that positions American Midstream as a growth-oriented, primarily fee-based MLP with asset platforms in the majority of the significant U.S. resource plays.”

“In addition, we remain focused on constructing more than $500 million in asset development projects, including in the prolific Eagle Ford with the ongoing expansion of the Lavaca System for the anchor producer customer and third-party producers, as well as significant progress on Republic Midstream and the Gonzales County full-well-stream gathering system. We also continue to expand Blackwater’s Harvey terminal and we are in the engineering and construction phase for development projects in East Texas as well as the Bakken and Permian basins resulting from the Costar acquisition.”

“Looking ahead, our 2015 guidance reflects a step-change in financial and operating results with 2015 Adjusted EBITDA and DCF forecasted at approximately 2.5 times and 3.0 times higher than our 2014 forecasts, respectively. Further, as a result of the successful execution of our growth strategy, we intend to recommend to our board of directors a distribution increase of approximately three percent for the fourth quarter 2014 distribution and an increase of between three and five percent for the first quarter 2015 distribution. Going forward, we anticipate recommending distribution increases of eight to ten percent annually. We are excited about our success to-date and remain committed to providing long-term, sustainable distribution growth.”

SEGMENT PERFORMANCE

Gross Margin Three months ended September 30, Nine months ended September 30, % Change
(thousands)
2014 2013 2014 2013 QTD YTD
Gathering and Processing $10,513 $10,879 $31,122 $28,812 (3.4 )% 8.0 %
Transmission $8,619 $7,864 $28,983 $19,296 9.6 % 50.2 %
Terminals $2,200 $2,165 $6,475 $3,824 1.6 % 69.3 %

Gathering and Processing – The Gathering and Processing segment includes natural gas transportation, gathering, treating, processing, fractionation, and selling or delivering natural gas and natural gas liquids (“NGLs”) to various markets and pipeline systems.

Segment gross margin for the Gathering and Processing segment was $10.5 million and $31.1 million for the three and nine months ended September 30, 2014, respectively, compared to $10.9 million and $28.8 million for the same periods in 2013. The decrease in gross margin for the three months ended September 30, 2014 was attributable primarily to lower throughput volumes on certain of the Partnership’s legacy gathering and processing systems, partially offset by incremental gross margin from the Lavaca System acquisition. The increase for the nine months ended September 30, 2014 was due to incremental gross margin associated with the Lavaca System acquisition, partially offset by lower throughput volumes on the Partnership’s legacy gathering and processing systems.

Natural gas throughput volumes averaged 229.8 million cubic feet per day (“MMcf/d”) and 259.9 MMcf/d for the three and nine months ended September 30, 2014, respectively, compared to 303.9 MMcf/d and 270.1 MMcf/d for the same periods in 2013. Processed NGLs averaged 39.1 thousand gallons per day (“Mgal/d”) and 39.5 Mgal/d for the three and nine months ended September 30, 2014, respectively, compared to 54.3 Mgal/d and 52.8 Mgal/d for the same periods in 2013. The decrease in throughput was attributable to lower throughput on certain of the Partnership’s legacy gathering and processing systems, partially offset by incremental throughput volumes on the Lavaca System. Processed NGLs decreased primarily as a result of lower production at the Bazor Ridge, Chatom, and Burns Point systems due to lower throughput.

Transmission – The Transmission segment transports and delivers natural gas from producing wells, receipt points, or pipeline interconnects to pipeline or end-use markets.

Segment gross margin for the Transmission segment was $8.6 million and $29.0 million for the three and nine months ended September 30, 2014, respectively, compared to $7.9 million and $19.3 million for the same periods in 2013. The increase in gross margin was attributable to the High Point System acquired in April 2013.

Total natural gas throughput volumes averaged 683.8 MMcf/d and 770.6 MMcf/d for the three and nine months ended September 30, 2014, respectively, compared to 698.6 MMcf/d and 611.3 MMcf/d for the same periods in 2013. The increase in throughput volume for the nine months ended September 30, 2014 was primarily due to the additional volumes contributed by the High Point System.

Terminals - The Terminals segment provides above-ground storage services at the Partnership’s marine terminals that 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 $2.2 million and $6.5 million for the three and nine months ended September 30, 2014, respectively, compared to $2.2 million and $3.8 million for the three and nine months ended September 30, 2013. The increase in gross margin is primarily attributable to nine months of activity in 2014 compared to less than six months in 2013 as the Partnership did not have a Terminals segment for the three months ended March 31, 2013.

BALANCE SHEET

As of September 30, 2014, the Partnership had $0.5 million of cash on hand, and $61.9 million outstanding under its senior secured revolving credit facility with $135.2 million of available borrowing capacity. For the three months ended September 30, 2014, capital expenditures totaled $28.1 million, which included $1.4 million for maintenance capital.

DERIVATIVES

The Partnership enters into derivative agreements to hedge exposure to commodity prices associated with natural gas, NGLs, and crude oil. As of September 30, 2014, approximately 7 percent of the Partnership’s exposure to NGL prices and approximately 80 percent of the Partnership’s exposure to oil prices are hedged through the end of 2014. In addition, approximately 3 percent of the Partnership’s expected exposure to NGL prices and 80 percent of expected exposure to oil prices are hedged for the first six months of 2015. The hedge percentages for 2014 and 2015 include commodity exposure associated with the Costar acquisition. Details regarding the Partnership’s hedge program are found in its quarterly report on Form 10-Q for the quarter ended September 30, 2014.

CONFERENCE CALL INFORMATION

The Partnership will host a conference call at 10:00 a.m. ET on Tuesday, November 11, 2014 to discuss results. The call will be webcast and archived on the Partnership’s website for a limited time.

Dial-In Numbers: (866) 318-8612 (Domestic toll free)
(617) 399-5131 (International)
Passcode: 93591748
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 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 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 assets from DCP and the acquisition of Costar Midstream 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 Reports on Form 10-Q for the quarters ended June 30, 2014 and September 30, 2014, filed on August 11, 2014 and November 10, 2014, respectively. 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

Condensed Consolidated Balance Sheets

(Unaudited, in thousands)

September 30,
2014
December 31,
2013
Assets
Current assets
Cash and cash equivalents $ 459 $ 393
Accounts receivable 7,430 6,822
Unbilled revenue 21,271 23,001
Risk management assets 1,047 473
Other current assets 4,715 7,497
Current assets held for sale 29 272
Total current assets 34,951 38,458
Property, plant and equipment, net 415,799 312,701
Goodwill 16,253 16,447
Intangible assets, net 45,585 3,682
Investment in unconsolidated affiliate 11,017
Other assets, net 11,195 9,064
Noncurrent assets held for sale, net 1,164 1,723
Total assets $ 535,964 $ 382,075
Liabilities, Equity and Partners’ Capital
Current liabilities
Accounts payable $ 12,426 $ 3,261
Accrued gas purchases 14,762 17,386
Accrued expenses and other current liabilities 21,425 15,058
Current portion of long-term debt 1 2,048
Risk management liabilities 335 423
Current liabilities held for sale 1 114
Total current liabilities 48,950 38,290
Risk management liabilities 101
Asset retirement obligations 34,782 34,636
Other liabilities 161 191
Long-term debt 57,700 130,735
Deferred tax liability 4,816 4,749
Noncurrent liabilities held for sale, net 95
Total liabilities 146,409 208,797
Commitments and contingencies
Convertible preferred units

Series A convertible preferred units (5,586 thousand and 5,279 thousand units
issued and outstanding as of September 30, 2014, and December 31, 2013,
respectively)

104,736 94,811

Equity and partners’ capital

General partner interest (299 thousand and 185 thousand units issued and
outstanding as of September 30, 2014, and December 31, 2013, respectively)

(3,106 ) 2,696

Limited partner interest (15,771 thousand and 7,414 thousand units issued and
outstanding as of September 30, 2014, and December 31, 2013, respectively)

251,564 71,039

Series B convertible units (1,232 thousand and zero units issued and outstanding as
of September 30, 2014, and December 31, 2013, respectively)

31,671
Accumulated other comprehensive income 157 104
Total partners’ capital 280,286 73,839
Noncontrolling interests 4,533 4,628
Total equity and partners’ capital 284,819 78,467
Total liabilities, equity and partners’ capital $ 535,964 $ 382,075

American Midstream Partners, LP and Subsidiaries

Condensed Consolidated Statements of Operations

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

Three months ended September 30, Nine months ended September 30,
2014 2013 2014 2013
Revenue $ 69,699 $ 78,018 $ 227,940 $ 217,201
(Loss) gain on commodity derivatives, net 606 (499 ) 283 110
Total revenue 70,305 77,519 228,223 217,311
Operating expenses:
Purchases of natural gas, NGLs and condensate 46,690 55,765 155,729 162,998
Direct operating expenses 11,884 9,092 31,889 22,369
Selling, general and administrative expenses 5,875 4,494 17,105 12,507
Equity compensation expense 337 392 1,132 1,877
Depreciation, amortization and accretion expense 5,706 7,880 19,350 22,274
Total operating expenses 70,492 77,623 225,205 222,025
Gain on involuntary conversion of property, plant and equipment 343
Loss on sale of assets, net (103 ) (124 )
Loss on impairment of property, plant and equipment (15,232 )
Operating income (loss) (290 ) (104 ) 2,894 (19,603 )
Other income (expense):

Interest expense

(1,430 ) (2,636 ) (5,013 ) (6,958 )
Other expense (672 ) (672 )
Earnings in unconsolidated affiliate 117 117
Net loss before income tax (expense) benefit (2,275 ) (2,740 ) (2,674 ) (26,561 )
Income tax (expense) benefit (122 ) 214 (260 ) 589
Net loss from continuing operations (2,397 ) (2,526 ) (2,934 ) (25,972 )
Discontinued operations:
Loss from operations of disposal groups, net of tax (26 ) (15 ) (582 ) (1,891 )
Net loss (2,423 ) (2,541 ) (3,516 ) (27,863 )
Net income attributable to noncontrolling interests 33 190 207 533
Net loss attributable to the Partnership $ (2,456 ) $ (2,731 ) $ (3,723 ) $ (28,396 )
General partner’s interest in net loss $ (32 ) $ (221 ) $ (48 ) $ (1,194 )
Limited partners’ interest in net loss $ (2,424 ) $ (2,510 ) $ (3,675 ) $ (27,202 )
Distribution declared per common unit (a) $ 0.4625 $ 0.4325 $ 1.3775 $ 0.8650
Limited partners’ net loss per common unit:
Basic and diluted:
Loss from continuing operations $ (0.58 ) $ (0.81 ) $ (1.52 ) $ (5.52 )
Loss from discontinued operations 0.01 (0.05 ) (0.21 )
Net loss $ (0.58 ) $ (0.80 ) $ (1.57 ) $ (5.73 )
Weighted average number of common units outstanding:
Basic and diluted 13,204 6,663 11,409 8,334

(a) Declared and paid in the quarter(s) during the three and nine months ended September 30, 2014 and 2013 related to prior quarter earnings.

American Midstream Partners, LP and Subsidiaries

Condensed Consolidated Statements of Cash Flows

(Unaudited, in thousands)

Nine months ended September 30,
2014 2013
Cash flows from operating activities
Net loss $ (3,516 ) $ (27,863 )
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, amortization and accretion expense 19,350 22,355
Amortization of deferred financing costs 1,894 975
Amortization of weather derivative premium 794 378
Unrealized (gain) loss on commodity derivatives, net (592 ) 1,159
Non-cash compensation expense 1,200 1,824
OPEB plan net periodic benefit (35 ) (55 )
Gain on involuntary conversion of property, plant and equipment (343 )
Loss on sale of assets 209
Loss on impairment of property, plant and equipment 15,232
Loss on impairment of noncurrent assets held for sale 673 1,807
Deferred tax benefit (58 ) (662 )
Changes in operating assets and liabilities, net:
Accounts receivable (599 ) 397
Unbilled revenue 1,913 (1,970 )
Risk management assets and liabilities (965 ) (1,147 )
Other current assets 2,858 602
Other assets, net (608 ) (67 )
Accounts payable 624 121
Accrued gas purchases (2,734 ) 273
Accrued expenses and other current liabilities (1,446 ) 2,685
Asset retirement obligations (690 )
Other liabilities (32 ) (114 )
Net cash provided by operating activities 18,240 15,587
Cash flows from investing activities
Cost of acquisitions (110,909 )
Additions to property, plant and equipment (41,257 ) (22,842 )
Proceeds from disposals of property, plant and equipment 6,323
Insurance proceeds from involuntary conversion of property, plant and equipment 482
Equity method investment (12,000 )
Proceeds from equity method investment, return of capital 983
Net cash used in investing activities (156,860 ) (22,360 )
Cash flows from financing activities
Proceeds from issuance of common units, net of offering costs 204,335
Unitholder contributions 2,896 13,075
Unitholder distributions (19,549 ) (12,458 )
Issuance of Series A convertible preferred units, net 14,393
Issuance of Series B Units 30,000
Acquisition of noncontrolling interest (8 )
Net distributions to noncontrolling interest owners (273 ) (571 )
LTIP tax netting unit repurchase (253 ) (400 )
Payments of deferred debt issuance costs (3,380 ) (1,509 )
Payments on other debt (2,217 ) (2,231 )
Borrowings on other debt 170 1,495
Payments on loan to affiliate (1,072 )
Payments on bank loans 6,200
Payments on long-term debt (212,670 ) (99,821 )
Borrowings on long-term debt 139,635 92,571
Net cash provided by financing activities 138,686 9,672
Net increase in cash and cash equivalents 66 2,899
Cash and cash equivalents
Beginning of period 393 576
End of period $ 459 $ 3,475
Supplemental cash flow information
Interest payments, net $ 4,064 $ 5,051
Supplemental non-cash information
Increase (decrease) in accrued property, plant and equipment $ 17,746 $ (6,080 )
Net assets contributed in the Blackwater Acquisition 22,129
Net assets contributed in exchange for the issuance of Series A convertible preferred units 59,994
Fair value of Series A Units in excess of net assets received 15,612
Accrued and in-kind unitholder distribution for Series A Units 9,925 2,912
In-kind unitholder distribution for Series B Units 1,671

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 September 30, Nine months ended September 30,
2014 2013 2014 2013

Reconciliation of Net loss attributable to the
Partnership to Adjusted EBITDA

Net loss attributable to the Partnership $ (2,456 ) $ (2,731 ) $ (3,723 ) $ (28,396 )
Add:
Depreciation, amortization and accretion expense 5,706 7,880 19,350 22,271
Interest expense 1,184 2,192 4,028 5,701
Debt issuance costs 3,226 280 3,380 1,595
Unrealized loss (gain) on derivatives, net (706 ) 913 (592 ) 1,158
Non-cash compensation expense 405 392 1,200 1,877
Transaction expenses 521 426 1,559 1,848
Income tax benefit (expense) 103 (248 ) (58 ) (662 )
Impairment of property, plant and equipment 15,232
Impairment of noncurrent assets held for sale 673 1,807

Proceeds from equity method investment, return
of capital

983 983
Deduct:
COMA income 66 292 601 544
Straight-line amortization of put costs (a) 32 89
OPEB plan net periodic benefit 12 18 36 54

Gain on involuntary conversion of property,
plant and equipment

343
Loss on sale of assets, net (103 ) (209 )
Adjusted EBITDA $ 8,991 $ 8,762 $ 26,372 $ 21,401
Deduct:
Cash interest expense (b) 1,146 1,557 3,909 3,039
Normalized maintenance capital (c) 1,300 1,104 3,900 2,145
Normalized integrity management (d) 370 544
Series A Convertible Preferred Payment (e) 1,074 1,338 1,074
Distributable Cash Flow $ 6,545 $ 4,657 $ 17,225 $ 14,599

(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 estimated annual maintenance capital expenditures of $5.2 million, which is what the Partnership expects to be required to maintain assets over the long term.

(d) Represents estimated integrity management costs over the seven year mandatory testing cycle net of integrity management costs that are expensed in direct operating expenses.

(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 September 30, Nine months ended September 30,
2014 2013 2014 2013

Reconciliation of gross margin to Net loss
attributable to the Partnership:

Gathering and processing segment gross margin $ 10,513 $ 10,879 $ 31,122 $ 28,812
Transmission segment gross margin 8,619 7,864 28,983 19,296
Terminals segment gross margin 2,200 2,165 6,475 3,824
Total gross margin 21,332 20,908 66,580 51,932
Plus:
(Loss) gain on commodity derivatives, net 606 (499 ) 283 110
Less:
Direct operating expenses (a) 10,282 7,799 27,050 19,867
Selling, general and administrative expenses 5,875 4,494 17,105 12,507
Equity compensation expense 337 392 1,132 1,877
Depreciation, amortization and accretion expense 5,706 7,880 19,350 22,274

Gain on involuntary conversion of property, plant
and equipment

(343 )
Loss on sale of assets, net 103 124

Loss on impairment of property, plant
and equipment

15,232
Interest expense 1,430 2,636 5,013 6,958
Other expense 672 672
Earnings in unconsolidated affiliates (117 ) (117 )
Other, net (b) (75 ) (52 ) (792 ) 231
Income tax expense (benefit) 122 (214 ) 260 (589 )
Loss from operations of disposal groups, net of tax 26 15 582 1,891
Net income attributable to noncontrolling interest 33 190 207 533
Net loss attributable to the Partnership $ (2,456 ) $ (2,731 ) $ (3,723 ) $ (28,396 )
(a) Direct operating expenses includes Gathering and Processing segment direct operating expenses of $5.2 million and $3.8 million, respectively, and Transmission segment direct operating expenses of $5.0 million and $4.0 million, respectively, for the three months ended September 30, 2014 and 2013. Direct operating expenses related to our Terminals segment of $1.6 million and $1.3 million, respectively, for the three months ended September 30, 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 $15.2 million and $10.9 million, respectively, and Transmission segment direct operating expenses of $11.9 million and $8.9 million, respectively, for the nine months ended September 30, 2014 and 2013. Direct operating expenses related to our Terminals segment of $4.8 million and $2.5 million, respectively, for the nine months ended September 30, 2014 and 2013 are included within the calculation of Terminals segment gross margin.
(b) Other, net includes realized (loss) gain on commodity derivatives of less than $0.1 million and $0.3 million and COMA income of $0.1 million and $0.3 million for the three months ended September 30, 2014 and 2013, respectively. Other, net includes realized (loss) gain on commodity derivatives of $(0.2) million and $0.8 million and COMA income of $0.6 million and $0.5 million for the nine months ended September 30, 2014 and 2013, respectively.

American Midstream Partners, LP and Subsidiaries

Segment Operating Data

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

Three months ended September 30, Nine months ended September 30,
2014 2013 2014 2013
Segment Financial and Operating Data:
Gathering and Processing segment
Financial data:
Revenue $ 45,569 $ 52,082 $ 147,209 $ 154,336
Loss on commodity derivatives 606 (499

)

283 110
Total revenue 46,175 51,583 147,492 154,446
Purchases of natural gas, NGLs and condensate 35,024 41,180 115,383 125,888
Direct operating expenses 5,249 3,805 15,163 10,924
Other financial data:
Segment gross margin $ 10,513 $ 10,879 $ 31,122 $ 28,812
Operating data:
Average throughput (MMcf/d) 229.8 303.9 259.9 270.1
Average plant inlet volume (MMcf/d) (a) (b) 62.1 134.4 78.6 114.5
Average gross NGL production (Mgal/d) (a) (c) 39.1 54.3 39.5 52.8
Average gross condensate production (Mgal/d) (a) 38.7 48.1 40.9 45.9
Average realized prices:
Natural gas ($/Mcf) $ 4.60 $ 3.80 $ 5.14 $ 3.96
NGLs ($/gal) $ 0.97 $ 0.91 $ 1.02 $ 0.86
Condensate ($/gal) $ 2.17 $ 2.40 $ 2.21 $ 2.35
Transmission segment
Financial data:
Total revenue $ 20,328 $ 22,478 $ 69,417 $ 56,539
Purchases of natural gas, NGLs and condensate 11,666 14,585 40,346 37,110
Direct operating expenses 5,033 3,994 11,887 8,943
Other financial data:
Segment gross margin $ 8,619 $ 7,864 $ 28,983 $ 19,296
Operating data:
Average throughput (MMcf/d) 683.8 698.6 770.6 611.3
Average firm transportation – capacity reservation (MMcf/d) 534.2 525.7 568.8 658.3
Average interruptible transportation – throughput (MMcf/d) 393.4 460.3 463.9 352.9
Terminals segment
Financial data:
Total revenue $ 3,802

$

3,458

$

11,314

$

6,326

Direct operating expenses 1,602

1,293

4,839

2,502

Other financial data:
Segment gross margin $ 2,200

$

2,165

$

6,475

$

3,824

Operating data:
Storage Utilization 82 %

100

%

93

%

100

%

(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.

Appendix A

Note About Non-GAAP Financial Measures

Gross margin, adjusted EBITDA and distributable cash flows 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 analysis of the Partnership’s results as reported under GAAP. Gross margin, adjusted EBITDA and distributable cash flow may be defined differently by other companies in the Partnership’s industry. The Partnership’s 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 affiliate 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 financial measure most directly comparable to adjusted EBITDA is net income.

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.

Gross margin and segment gross margin are metrics that we use to evaluate the Partnership’s performance. We define segment gross margin in the Partnership’s Gathering and Processing segment as revenue generated from gathering and processing operations less the cost of natural gas, NGLs and condensate purchased. 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 the Partnership’s own account, including pursuant to fixed-margin arrangements.

We define segment gross margin in the Partnership’s 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.

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

We define gross margin as the sum of the Partnership’s segment gross margin for the Partnership’s Gathering and Processing, Transmission and Terminals segments. The GAAP financial measure most comparable to gross margin is net income.

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