Attached files
| file | filename |
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| EX-31.2 - EXHIBIT 31.2 - American Midstream Partners, LP | a2017q310-qaexhibit312302c.htm |
| EX-31.1 - EXHIBIT 31.1 - American Midstream Partners, LP | a2017q310-qaexhibit311302c.htm |
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q/A
Amendment No.1
x | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
or
¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission File Number: 001-35257
AMERICAN MIDSTREAM PARTNERS, LP
(Exact name of registrant as specified in its charter)
Delaware | 27-0855785 |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) |
2103 CityWest Boulevard | |
Building #4, Suite 800 | |
Houston, TX | 77042 |
(Address of principal executive offices) | (Zip code) |
(Registrant’s telephone number, including area code)
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. ý Yes ¨ No
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). ý Yes ¨ No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” or an “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer | ¨ | Accelerated filer | ý |
Non-accelerated filer | ¨ (Do not check if a smaller reporting company) | Smaller reporting company | ¨ |
Emerging growth company | ¨ | ||
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. | ¨ | ||
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ¨ Yes ý No
There were 52,684,359 common units, 10,536,915 Series A Units, and 8,792,205 Series C Units of American Midstream Partners, LP outstanding as of October 27, 2017. Our common units trade on the New York Stock Exchange under the ticker symbol “AMID.”
TABLE OF CONTENTS
Page | ||
EXPLANATORY NOTE | ||
Item 2. | ||
Item 6. | ||
SIGNATURES | ||
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EXPLANATORY NOTE
American Midstream Partners, LP (“AMID”) is filing this Amendment No. 1 (this “Amendment”) to its Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2017, which was filed with the Securities and Exchange Commission (the “SEC”) on November 9, 2017 (the “Original Form 10-Q”). This Amendment is being filed to amend and restate in its entirety Part I. Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the Original Form 10-Q. The Original Form 10-Q contained an inadvertent error in the calculation of the non-GAAP supplemental financial measure Adjusted EBITDA, which requires revisions to such measure and the reconciliation to the most directly comparable GAAP measure included in Part I. Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations. The consolidated financial statements of AMID included in Part I. Item 1. Financial Statements of the Original Form 10-Q were not impacted. No other changes have been made to the Original Form 10-Q. This Amendment speaks as of the filing date of the Original Form 10-Q, does not reflect events that may have occurred subsequent to the original filing date, and does not modify or update in any way disclosures made in the Original Form 10-Q other than to correct the error described above. Accordingly, this Amendment should be read in conjunction with the Original Form 10-Q and AMID’s other filings with the SEC.
PART I. FINANCIAL INFORMATION
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following management’s discussion and analysis of our financial condition and results of operations should be read in conjunction with the unaudited condensed consolidated financial statements and the related notes thereto filed in AMID's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2017, which was filed with the Securities and Exchange Commission ("SEC") on November 9, 2017 (the "Original Form 10-Q" or "Quarterly Report") and the audited consolidated financial statements and notes thereto included in our Current Report on Form 8-K dated December 6, 2017 (the "Recast Form 8-K”). This discussion contains forward-looking statements that reflect management’s current views with respect to future events and financial performance. Our actual results may differ materially from those anticipated in these forward-looking statements or as a result of certain factors such as those set forth below under the caption “Forward-Looking Statements.”
Forward-Looking Statements
Our reports, filings and other public announcements may from time to time contain statements that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements”. You can typically identify forward-looking statements by the use of forward-looking words, such as “may,” “could,” “project,” “believe,” “anticipate,” “expect,” “estimate,” “potential,” “plan,” “forecast,” and other similar words.
All statements that are not statements of historical facts, including statements regarding our future financial position, business strategy, budgets, projected costs and plans and objectives of management for future operations, are forward-looking statements.
These forward-looking statements reflect our intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties and other factors, many of which are outside our control. Important factors that could cause actual results to differ materially from the expectations expressed or implied in the forward-looking statements include known and unknown risks. Examples of these risks and uncertainties, many of which are beyond our control, include, but are not limited to, the following:
• | our ability to generate sufficient cash from operations to pay distributions to unitholders; |
• | our ability to maintain compliance with financial covenants and ratios in our Credit Agreement (as defined below); |
• | our ability to timely and successfully identify, consummate and integrate our recent, pending and future acquisitions (including the merger with Southcross, Energy Partner, L.P.) and complete strategic dispositions, including the realization of all anticipated benefits of any such transaction, which otherwise could negatively impact our future financial performance; |
• | the timing and extent of changes in natural gas, crude oil, NGLs, refined products and other commodity prices, interest rates and demand for our services; |
• | our ability to access capital to fund growth, including new and amended credit facilities and access to the debt and equity markets, which will depend on general market conditions; |
• | severe weather and other natural phenomena, including their potential impact on demand for the commodities we sell and the operation of company-owned and third party-owned infrastructure; |
• | the level of creditworthiness of counterparties to transactions; |
• | the level and success of natural gas and crude oil drilling around our assets and our success in connecting natural gas and crude oil supplies to our gathering and processing systems; |
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• | the volumes of natural gas and crude oil that we gather, process, transport and store, the throughput volume at our refined products terminals and our NGL sales volumes; |
• | the fees that we receive for the natural gas, crude oil, refined products and NGL volumes we handle; |
• | our success in risk management activities, including the use of derivative financial instruments to hedge commodity and interest rate risks; |
• | changes in laws and regulations, particularly with regard to taxes, safety, regulation of over-the-counter derivatives market and entities, and protection of the environment; |
• | our failure or our counterparties’ failure to perform on obligations under commodity derivative and financial derivative contracts; |
• | the performance of certain of our current and future projects and unconsolidated affiliates that we do not control; |
• | the demand for natural gas, crude oil, NGL and refined products by the petrochemical, refining or other industries; |
• | our dependence on a relatively small number of customers for a significant portion of our gross margin; |
• | general economic, market and business conditions, including industry changes and the impact of consolidations and changes in competition; |
• | our ability to renew our gathering, processing, transportation and terminal contracts; |
• | our ability to successfully balance our purchases and sales of natural gas; |
• | leaks or releases of hydrocarbons into the environment that result in significant costs and liabilities; |
• | the adequacy of insurance to cover our losses; |
• | our ability to grow through contributions from affiliates, acquisitions or internal growth projects; |
• | our management's history and experience with certain aspects of our business and our ability to hire as well as retain qualified personnel to execute our business strategy; |
• | the cost and effectiveness of our remediation efforts with respect to the material weakness discussed in "Part II. Item 9A. Controls and Procedures" of our Annual Report; |
• | volatility in the price of our common units; |
• | security threats such as military campaigns, terrorist attacks, and cybersecurity breaches, against, or otherwise impacting, our facilities and systems; and |
• | the amount of collateral required to be posted from time to time in our transactions. |
Although we believe that the assumptions underlying our forward-looking statements are reasonable, any of the assumptions could be inaccurate, and, therefore, we cannot assure you that the forward-looking statements included in this Quarterly Report will prove to be accurate. Some of these and additional risks and uncertainties that could cause actual results to differ materially from such forward-looking statements are more fully described in Part II, Item 1A of this Quarterly Report under the caption “Risk Factors”, Part I, Item 1A of our Annual Report, as filed with the SEC on March 28, 2017, under the caption “Risk Factors” and elsewhere in the Quarterly Report. The forward-looking statements in this report speak as of the filing date of this report. Except as may be required by applicable securities laws, we undertake no obligation to publicly update or advise of any change in any forward-looking statement, whether as a result of new information, future events or otherwise.
Overview
We are a growth-oriented Delaware limited partnership that was formed in August 2009 to own, operate, develop and acquire a diversified portfolio of midstream energy assets. We provide critical midstream infrastructure that links producers of natural gas, crude oil, NGLs, condensate and specialty chemicals to numerous intermediate and end-use markets. Through our five financial reporting segments, (i) gas gathering and processing services, (ii) liquid pipelines and services, (iii) natural gas transportation services, (iv) offshore pipelines and services and (v) terminalling services, we engage in the business of gathering, treating, processing, and transporting natural gas; gathering, transporting, storing, treating and fractionating NGLs; gathering, storing and transporting crude oil and condensates; storing specialty chemical products and selling refined products. As of September 1, 2017, as a result of the disposition of the Propane Business described in in Note 4 - Discontinued Operations, we have eliminated the Propane Marketing Services segment.
Our primary assets are strategically located in some of the most prolific onshore and offshore producing regions and key demand markets in the United States. Our gathering and processing assets are primarily located in (i) the Permian Basin of West Texas, (ii) the Cotton Valley/Haynesville Shale of East Texas, (iii) the Eagle Ford Shale of South Texas, and (iv) offshore in the Gulf of Mexico. Our liquid pipelines, natural gas transportation and offshore pipelines and terminal assets are located in prolific producing regions and key demand markets in Alabama, Louisiana, Mississippi, North Dakota, Texas, Tennessee and in the Port of New Orleans in Louisiana and the Port of Brunswick in Georgia. Additionally, we operate a fleet of NGL gathering and transportation trucks in the Eagle Ford shale and the Permian Basin. See Recent Developments regarding the recent acquisitions and dispositions in the third quarter of 2017.
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We own or have ownership interests in more than 5,100 miles of onshore and offshore natural gas, crude oil, NGL and saltwater pipelines across 17 gathering systems, six interstate pipelines and nine intrastate pipelines; eight natural gas processing plants; four fractionation facilities; an offshore semisubmersible floating production system with nameplate processing capacity of 90 MBbl/d of crude oil and 220 MMcf/d of natural gas; six marine terminal sites with approximately 6.7 MMBbls of above-ground aggregate storage capacity for petroleum products, distillates, chemicals and agricultural products; and 90 transportation trucks and a total trailer fleet of 130, of which 35 are LPG trailers and 95 are crude oil trailers.
A portion of our cash flow is derived from our investments in unconsolidated affiliates, including a 49.7% operated interest in Destin, a natural gas pipeline; a 35.7% non-operated interest in the Class A Units and common units of Delta House, which is a floating production system platform and related pipeline infrastructure; a 16.7% non-operated interest in Tri-States, an NGL pipeline; a 66.7% operated interest in Okeanos, a natural gas pipeline; and a 25.3% non-operated interest in Wilprise, a NGL pipeline.
Recent Developments
Our business objectives continue to focus on maintaining stable cash flows from our existing assets and executing on growth opportunities to increase our long-term cash flows. We believe the key elements to stable cash flows are the diversity of our asset portfolio and our fee-based business which represents a significant portion of our estimated margins, the objective of which is to protect against downside risk in our cash flows.
Strategic acquisitions and disposition
During the third quarter of 2017, we divested 100% of our Propane Business to SHV Energy N.V., received $162.7 million, net of $2.5 million of transaction cost and cash on hand, from proceeds of the sale and recognized a net gain of $46.5 million from the sale, as part of our efforts to re-focus on our core competencies. See Note 4 - Discontinued Operations. As part of our growth strategy, we also made a series of acquisitions in the second and third quarters of 2017 to enhance our Offshore pipeline and services segment and Gas gathering and processing segment with the purchase of Viosca Knoll, Panther and an additional ownership percentage of Delta House. We also formed the Cayenne JV with Targa. See Note 3 - Acquisitions and Note 10 - Investments in unconsolidated affiliates.
Southcross Energy Partners, L.P. Merger
On October 31, 2017, we, our General Partner, our wholly owned subsidiary Cherokee Merger Sub LLC (“Merger Sub”), Southcross Energy Partners, L.P. (“SXE”), and Southcross Energy Partners GP, LLC (“SXE GP”), entered into an Agreement and Plan of Merger (the “SXE Merger Agreement”). Upon the terms and subject to the conditions set forth in the SXE Merger Agreement, SXE will merge with Merger Sub (the “SXE Merger”), with SXE continuing its existence under Delaware law as the surviving entity in the SXE Merger and wholly owned subsidiary of us. The acquisition is valued at approximately $815 million, including the repayment of estimated net debt of $139 million.
At the effective time of the SXE Merger (the “Effective Time”), each common unit of SXE (each, an “SXE Common Unit”) issued and outstanding or deemed issued and outstanding as of immediately prior to the Effective Time will be converted into the right to receive 0.160 (the “Exchange Ratio”) of a common unit (each, an “AMID Common Unit”) representing limited partner interests in us (the “Merger Consideration”), except for those SXE Common Units held by affiliates of SXE and SXE GP, which will be cancelled for no consideration. Each SXE Common Unit, Subordinated Unit (as defined in the SXE Merger Agreement) and Class B Convertible Unit (as defined in the SXE Merger Agreement) held by Southcross Holdings LP (“Holdings LP”) or any of its subsidiaries and the SXE Incentive Distribution Rights (as defined in the SXE Merger Agreement) outstanding immediately prior to the Effective Time will be cancelled in connection with the closing of the SXE Merger.
In connection with the SXE Merger Agreement, on October 31, 2017, we and our General Partner entered into a Contribution Agreement (the “SXE Contribution Agreement” and, together with the SXE Merger Agreement, the “SXE Transaction Agreements”) with Holdings LP. Upon the terms and subject to the conditions set forth in the SXE Contribution Agreement, Holdings LP will contribute its equity interests in its new wholly owned subsidiary (“SXH Holdings”), which will hold substantially all the current subsidiaries (Southcross Holdings Intermediary LLC, Southcross Holdings Guarantor GP LLC and Southcross Holdings Guarantor LP) and business of Holdings LP, to us and our General Partner in exchange for (i) the number of AMID Common Units with a value equal to $185,697,148, subject to certain adjustments for cash, indebtedness, working capital and transaction expenses contemplated by the SXE Contribution Agreement, divided by $13.69 per AMID Common Unit, (ii) 4,500,000 AMID Preferred Units (as defined in the SXE Contribution Agreement), (iii) options to purchase 4,500,000 AMID Common Units (the “Options”), and (iv) 3,000 AMID GP Class D Units (as defined in the SXE Contribution Agreement) (the transactions contemplated thereby and the agreements ancillary thereto, the “SXE Contribution”). A portion of the consideration will be
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deposited into escrow in order to secure certain post-closing obligations of Holdings LP. Concurrently with the closing of the transaction, our agreement of limited partnership will be amended to reflect the issuance of AMID Preferred Units, and the GP LLC Agreement will be amended to reflect the issuance of such AMID GP Class D Units.
Financial Highlights
Financial highlights for the three months ended September 30, 2017, include the following:
• | Net income attributable to the Partnership increased to $55.9 million, as compared to net loss of $9.0 million in the same period in 2016, primarily due to the net gain on disposition of the Propane Business of $46.5 million, the gain of $32.3 million related to the MPOG acquisition and the $4.0 million gain recognized on Cayenne, offset partially by an increase in operating loss of $10.9 million and interest expense of $11.9 million. |
• | Earnings in unconsolidated affiliates were $16.8 million, an increase of $6.4 million as compared to the same period in 2016, primarily due to the additional 6.2 % Delta House investments in the fourth quarter of 2016 which continues to perform near nameplate capacity as a result of the strong performance by producers. |
• | Segment gross margin amounted to $63.7 million, or a increase of $4.9 million as compared to the same period in 2016, primarily due to higher segment gross margin in our Offshore pipelines and services segment as a result of higher earnings in unconsolidated affiliates, offset by a decrease in the Terminalling services segment mainly due to lower contract rates at our North Little Rock facility; |
• | Adjusted EBITDA increased to $42.4 million, or an increase of 2.9% as compared to the same period in 2016, primarily due to support from our General Partner for cost reimbursement, partially offset by lower distributions from our unconsolidated affiliates; and |
• | We distributed $21.3 million to our common unitholders, or $0.4125 per common unit, with respect to the quarter, which was the 25th consecutive distribution since our initial public offering. |
Operational highlights for the three months ended September 30, 2017, include the following:
• | Contracted capacity for our Terminalling Services segment averaged 4,759,978 Bbls, representing an 8.8% decrease compared to the same period in 2016; |
• | Average condensate production totaled 57.5 Mgal/d, representing a 29.6 Mgal/d or 34% decrease compared to the same period in 2016; |
• | Average gross NGL production totaled 324.3 Mgal/d, representing a 142.6 Mgal/d or 78% increase compared to the same period in 2016; |
• | Throughput volumes attributable to the Natural gas transportation services and Offshore pipelines and services segments totaled 423 MMcf/d, representing a 94 MMcf/d or 18% decrease compared to the same period in 2016; |
• | Throughput volumes attributable to the Liquid pipelines and services segment totaled 35,403Bbls/d, representing a 5,032 Bbls/d or 16% increase compared to the same period in 2016; and |
• | The percentage of gross margin generated from fee based, fixed margin, firm and interruptible transportation contracts and firm storage contracts was 86.6%, representing a decrease of 4.5% as compared to the same period in 2016. |
Commodity Prices
Average daily prices for NYMEX West Texas Intermediate crude oil ranged from a high of $54.45 per barrel to a low of $42.53 per barrel from January 1, 2017 through October 27, 2017. Average daily prices for NYMEX Henry Hub natural gas ranged from a high of $3.71 per MMBtu to a low of $2.44 per MMBtu from January 1, 2017 through October 27, 2017.
Fluctuations in energy prices can greatly affect the development of new crude oil and natural gas reserves. Further declines in commodity prices of crude oil and natural gas could have a negative impact on exploration, development and production activity, and, if sustained, could lead to a material decrease in such activity. Sustained reductions in exploration or production activity in
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our areas of operation would lead to continued or further reduced utilization of our assets. We are unable to predict future potential movements in the market price for natural gas, crude oil and NGLs and thus, cannot predict the ultimate impact of commodity prices on our operations.
Capital Markets
Volatility in the capital markets continues to impact our operations in multiple ways, including limiting our producers’ ability to finance their drilling and workover programs and limiting our ability to fund drop downs, organic growth projects and acquisitions. We may opportunistically consider accessing the capital markets.
Our Operations
On September 1, 2017, we completed the disposition of our Propane Business. Prior to the classification as discontinued operations, we reported the Propane Business in our Propane Marketing Services segment, which was dissolved at the time of the Propane Business disposition. Accordingly, we have recast our financial statements to retrospectively reflect this change in classification for the Propane Business to discontinued operations for all periods presented. See Note 1 - Organization, Basis of Presentation and Summary of Significant Accounting Policies and Note 4 - Discontinued Operations.
We manage our business and analyze and report our results of operations through five reportable segments.
• | Gas Gathering and Processing Services. Our Gas Gathering and Processing Services segment provides “wellhead-to-market” services to producers of natural gas and natural gas liquids, which include transporting raw natural gas from various receipt points through gathering systems, treating the raw natural gas, processing raw natural gas to separate the NGLs from the natural gas, fractionating NGLs, and selling or delivering pipeline-quality natural gas and NGLs to various markets and pipeline systems. |
• | Liquid Pipelines and Services. Our Liquid Pipelines and Services segment provides transportation, purchase and sales of crude oil from various receipt points including lease automatic customer transfer (“LACT”) facilities and deliveries to various markets. |
• | Natural Gas Transportation Services. Our Natural Gas Transportation Services segment transports and delivers natural gas from producing wells, receipt points or pipeline interconnects for shippers and other customers, which include local distribution companies (“LDCs”), utilities and industrial, commercial and power generation customers. |
• | Offshore Pipelines and Services. Our Offshore Pipelines and Services segment gathers and transports natural gas and crude oil from various receipt points to other pipeline interconnects, onshore facilities and other delivery points. |
• | Terminalling Services. Our Terminalling Services segment provides above-ground leasable storage operations at our marine terminals that support various commercial customers, including commodity brokers, refiners and chemical manufacturers to store a range of products and also includes crude oil storage in Cushing, Oklahoma and refined products terminals in Texas and Arkansas. |
Gas Gathering and Processing Services Segment
Results of operations from the Gas Gathering and Processing Services segment are determined primarily by the volumes of natural gas we gather, process and fractionate, the commercial terms in our current contract portfolio and natural gas, crude oil, NGL and condensate prices. We gather and process natural gas primarily pursuant to the following arrangements:
• | Fee-Based Arrangements. Under these arrangements, we generally are paid a fixed fee for gathering, processing and transporting natural gas. |
• | Fixed-Margin Arrangements. Under these arrangements, we purchase natural gas and off-spec condensate from producers or suppliers at receipt points on our systems at an index price less a fixed transportation fee and simultaneously sell an identical volume of natural gas or off-spec condensate at delivery points on our systems at the same, undiscounted index price. By entering into back-to-back purchases and sales of natural gas or off-spec condensate, we are able to lock in a fixed margin on these transactions. We view the segment gross margin |
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earned under our fixed-margin arrangements to be economically equivalent to the fee earned in our fee-based arrangements.
• | Percent-of-Proceeds Arrangements (“POP”). Under these arrangements, we generally gather raw natural gas from producers at the wellhead or other supply points, transport it through our gathering system, process it and sell the residue natural gas, NGLs and condensate at market prices. Where we provide processing services at the processing plants that we own, or obtain processing services for our own account in connection with our elective processing arrangements, we generally retain and sell a percentage of the residue natural gas and resulting NGLs. However, we also have contracts under which we retain a percentage of the resulting NGLs and do not retain a percentage of residue natural gas. Our POP arrangements also often contain a fee-based component. |
Gross margin earned under fee-based and fixed-margin arrangements is directly related to the volume of natural gas that flows through our systems and is not directly dependent on commodity prices. However, a sustained decline in commodity prices could result in a decline in throughput volumes from producers and, thus, a decrease in our fee-based and fixed-margin gross margin. These arrangements provide stable cash flows, but upside in higher commodity-price environments is limited to an increase in throughput volumes from producers. Under our typical POP arrangement, our gross margin is directly impacted by the commodity prices we realize on our share of natural gas and NGLs received as compensation for processing raw natural gas. However, our POP arrangements often contain a fee-based component, which helps to mitigate the degree of commodity-price volatility we could experience under these arrangements. We further seek to mitigate our exposure to commodity price risk through our hedging program. See the information set forth in Part I, Item 3 of the Quarterly Report under the caption “ — Quantitative and Qualitative Disclosures about Market Risk — Commodity Price Risk.”
Liquid Pipelines and Services Segment
Results of operations from the Liquid Pipelines and Services segment are determined by the volumes of crude oil transported on the interstate and intrastate pipelines we own. Tariffs associated with our Bakken system are regulated by FERC for volumes gathered via pipeline and trucked to the AMID Truck facility in Watford City, North Dakota. Volumes transported on our Silver Dollar system are underpinned by long-term, fee-based contracts. Our transportation arrangements are further described below:
• | Firm Transportation Arrangements. Our obligation to provide firm transportation service means that we are obligated to transport crude oil nominated by the shipper up to the maximum daily quantity specified in the contract. In exchange for that obligation on our part, the shipper pays a specified reservation charge, whether or not the shipper utilizes the capacity. In most cases, the shipper also pays a variable-use charge with respect to quantities actually transported by us. |
• | Uncommitted Shipper Arrangements. Our obligation to provide interruptible transportation service means that we are only obligated to transport crude oil nominated by the shipper to the extent that we have available capacity. For this service the shipper pays no reservation charge but pays a variable-use charge for quantities actually shipped. |
• | Fee-Based Arrangements. Under these arrangements our operations are underpinned by long-term, fee-based contracts with leading producers in the Midland Basin. Some of these contracts also have minimum volume commitments as well as some have acreage dedications. |
• | Buy-Sell Arrangements. We enter into outright purchase and sales contracts as well as buy/sell contracts with counterparties, under which contracts we gather and transport different types of crude oil and eventually sell the crude oil to either the same counterparty or different counterparties. We account for such revenue arrangements on a gross basis. Occasionally, we enter into crude oil inventory exchange arrangements with the same counterparty which the purchase and sale of inventory are considered in contemplation of each other. Revenues from such inventory exchange arrangements are recorded on a net basis. |
Natural Gas Transportation Services Segment
Results of operations from the Natural Gas Transportation Services segment are determined by capacity reservation fees from firm and interruptible transportation contracts and the volumes of natural gas transported on the interstate and intrastate pipelines we own pursuant to interruptible transportation or fixed-margin contracts. Our transportation arrangements are further described below:
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• | Firm Transportation Arrangements. Our obligation to provide firm transportation service means that we are obligated to transport natural gas nominated by the shipper up to the maximum daily quantity specified in the contract. In exchange for that obligation on our part, the shipper pays a specified reservation charge, whether or not the shipper utilizes the capacity. In most cases, the shipper also pays a variable-use charge with respect to quantities actually transported by us. |
• | Interruptible Transportation Arrangements. Our obligation to provide interruptible transportation service means that we are only obligated to transport natural gas nominated by the shipper to the extent that we have available capacity. For this service the shipper pays no reservation charge but pays a variable-use charge for quantities actually shipped. |
• | Fixed-Margin Arrangements. Under these arrangements, we purchase natural gas from producers or suppliers at receipt points on our systems at an index price less a fixed transportation fee and simultaneously sell an identical volume of natural gas at delivery points on our systems at the same undiscounted index price. We view fixed-margin arrangements to be economically equivalent to our interruptible transportation arrangements. |
Offshore Pipelines and Services
Results of operations from the Offshore Pipelines and Services segment are determined by capacity reservation fees from firm and interruptible transportation contracts and the volumes of natural gas transported on the interstate and intrastate pipelines we own pursuant to interruptible transportation or fixed-margin contracts. Our transportation arrangements are further described below:
• | Firm Transportation Arrangements. Our obligation to provide firm transportation service means that we are obligated to transport natural gas nominated by the shipper up to the maximum daily quantity specified in the contract. In exchange for that obligation on our part, the shipper pays a specified reservation charge, whether or not the shipper utilizes the capacity. In most cases, the shipper also pays a variable-use charge with respect to quantities actually transported by us. |
• | Interruptible Transportation Arrangements. Our obligation to provide interruptible transportation service means that we are only obligated to transport natural gas nominated by the shipper to the extent that we have available capacity. For this service the shipper pays no reservation charge but pays a variable-use charge for quantities actually shipped. |
• | Fixed-Margin Arrangements. Under these arrangements, we purchase natural gas from producers or suppliers at receipt points on our systems at an index price less a fixed transportation fee and simultaneously sell an identical volume of natural gas at delivery points on our systems at the same undiscounted index price. We view fixed-margin arrangements to be economically equivalent to our interruptible transportation arrangements. |
Terminalling Services Segment
Our Terminalling Services segment provides above-ground leasable storage services at our marine terminals that support various commercial customers, including commodity brokers, refiners and chemical manufacturers to store a range of products, including petroleum products, distillates, chemicals and agricultural products. We generally receive fee-based compensation on guaranteed firm storage contracts, throughput fees charged to our customers when their products are either received or disbursed and other fee-based charges associated with ancillary services provided to our customers, such as excess throughput, truck weighing, etc. Our firm storage contracts are typically multi-year contracts with renewal options. Our refined products terminals have butane blending capabilities.
Contract Mix
For the three months ended September 30, 2017 and 2016, $38.6 million and $43.3 million, or 86.6% and 91.0%, respectively, of our gross margin (excluding our Investments in unconsolidated affiliates) was generated from fee-based, fixed margin, firm and interruptible transportation contracts and firm storage contracts.
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Cash distributions received from our unconsolidated affiliates amounted to $20.6 million and $22.7 million for the three months ended September 30, 2017 and 2016, respectively. Cash distributions derived from our unconsolidated affiliates are primarily generated from fee-based gathering and processing arrangements.
For the nine months ended September 30, 2017 and 2016, $115.3 million and $119.3 million, or 87.7% and 91.9%, respectively, of our gross margin (excluding our Investments in unconsolidated affiliates) was generated from fee-based, fixed margin, firm and interruptible transportation contracts and firm storage contracts.
Cash distributions received from our unconsolidated affiliates amounted to $59.0 million and $62.8 million for the nine months ended September 30, 2017 and 2016, respectively. Cash distributions derived from our unconsolidated affiliates are primarily generated from fee-based gathering and processing arrangements.
How We Evaluate Our Operations
Our management uses a variety of financial and operational metrics to analyze our performance. We view these metrics as important factors in evaluating our profitability and review these measurements on at least a monthly basis for consistency and trend analysis. These metrics include throughput volumes, storage utilization, segment gross margin, gross margin, operating margin, direct operating expenses on a segment basis, and Adjusted EBITDA on a company-wide basis.
Throughput Volumes
In our Gas Gathering and Processing Services segment, we must continually obtain new supplies of natural gas, NGLs and condensate to maintain or increase throughput volumes on our systems. Our ability to maintain or increase existing volumes of natural gas, NGLs and condensate is impacted by i) the level of work-overs or recompletions of existing connected wells and successful drilling activity of our significant producers in areas currently dedicated to or near our gathering systems, ii) our ability to compete for volumes from successful new wells in the areas in which we operate, iii) our ability to obtain natural gas, crude oil, NGLs and condensate that has been released from other commitments and iv) the volume of natural gas, NGLs and condensate that we purchase from connected systems. We actively monitor producer activity in the areas served by our gathering and processing systems to maintain current throughput volumes and pursue new supply opportunities.
In our Liquid Pipelines and Services segment, the amount of revenue we generate from our crude oil pipelines business depends primarily on throughput volumes. We generate a portion of our crude oil pipeline revenues through long-term contracts containing acreage dedications or minimum volume commitments. Throughput volumes on our pipeline system are affected primarily by the supply of crude oil in the market served by our assets. The revenue generated from our crude oil supply and logistics business depends on the volume of crude oil we purchase from producers, aggregators and traders and then sell to producers, traders and refiners as well as the volumes of crude oil that we gather and transport. The volume of our crude oil supply and logistics activities and the volumes transported by our crude oil gathering and transportation trucks are affected by the supply of crude oil in the markets served directly or indirectly by our assets. Accordingly, we actively monitor producer activity in the areas served by our crude oil supply and logistics business and other producing areas in the United States to compete for volumes from crude oil producers. Revenues in this business are also impacted by changes in the market price of commodities that we pass through to our customers.
In our Natural Gas Transportation Services and Offshore Pipelines and Services segments, the majority of our segment gross margin is generated by firm capacity reservation charges and interruptible transportation services from throughput volumes on our interstate and intrastate pipelines. Substantially all of the segment gross margin is generated under contracts with shippers, including producers, industrial companies, LDCs and marketers, for firm and interruptible natural gas transportation on our pipelines. We routinely monitor natural gas market activities in the areas served by our transmission systems to maintain current throughput volumes and pursue new shipper opportunities.
In our Terminalling Services segment, we receive fee-based compensation on guaranteed firm storage contracts, throughput fees charged to our customers when their products are either received or disbursed, and other operational charges associated with ancillary services provided to our customers, such as excess throughput, steam heating, and truck weighing at our marine terminals. The amount of revenue we generate from our refined products terminals depends primarily on the volume of refined products that we handle. These volumes are affected primarily by the supply of and demand for refined products in the markets served directly or indirectly by our refined products terminals. Our refined products terminals have butane blending capabilities. The volume of crude oil stored at our crude oil storage facility in Cushing, Oklahoma has no impact on the revenue generated by our crude oil storage business because we receive a fixed monthly fee per barrel of shell capacity that is not contingent on the usage of our storage tanks.
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Storage Utilization
Storage utilization is a metric that we use to evaluate the performance of our Terminalling Services segment. We define storage utilization as the percentage of the contracted capacity in barrels compared to the design capacity of the tank.
Segment Gross Margin and Total Segment Gross Margin
Segment gross margin and total segment gross margin are metrics that we use to evaluate our performance.
We define segment gross margin in our Gas Gathering and Processing Services segment as total revenue plus unconsolidated affiliate earnings less unrealized gains or plus unrealized losses on commodity derivatives, construction and operating management agreement income and the cost of natural gas, and NGLs and condensate purchased.
We define segment gross margin in our Liquid Pipelines and Services segment as total revenue plus unconsolidated affiliate earnings less unrealized gains or plus unrealized losses on commodity derivatives and the cost of crude oil 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 Natural Gas Transportation Services segment as total revenue plus unconsolidated affiliate earnings 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 Offshore Pipelines and Services segment as total revenue plus unconsolidated affiliate earnings 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 Terminalling Services segment as total revenue less direct operating expense which includes direct labor, general materials and supplies and direct overhead.
Total segment gross margin is a supplemental non-GAAP financial measure that we use to evaluate our performance. We define total segment gross margin as the sum of the segment gross margins for our Gas Gathering and Processing Services, Liquid Pipelines and Services, Natural Gas Transportation Services, Offshore Pipelines and Services, Terminalling Services segments. The GAAP measure most directly comparable to gross margin is Net income (loss) attributable to the Partnership. For a reconciliation of gross margin to net income (loss), see “Non-GAAP Financial Measures” below.
Operating Margin
We define operating margin as total segment gross margin less other direct operating expenses. The GAAP measure most directly comparable to operating margin is net income (loss) attributable to the Partnership. For a reconciliation of Operating Margin to net income (loss), see “- Non-GAAP Financial Measures.”
Direct Operating Expenses
Our management seeks to maximize the profitability of our operations in part by minimizing direct operating expenses without sacrificing safety or the environment. Direct labor costs, insurance costs, ad valorem and property taxes, repair and non-capitalized maintenance costs, integrity management costs, utilities, lost and unaccounted for gas, and contract services comprise the most significant portion of our operating expenses. These expenses are relatively stable and largely independent of throughput volumes through our systems but may fluctuate depending on the activities performed during a specific period.
Adjusted EBITDA
Adjusted EBITDA is a supplemental non-GAAP financial measure used by our management and external users of our financial statements, such as investors, commercial banks, research analysts and others, to assess: the financial performance of our assets without regard to financing methods, capital structure or historical cost basis; the ability of our assets to generate cash flow to make cash distributions to our unitholders and our General Partner; our operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing or capital structure; and the attractiveness of capital projects and acquisitions and the overall rates of return on alternative investment opportunities.
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We define Adjusted EBITDA as net income (loss) attributable to the Partnership, plus depreciation, amortization and accretion expense, interest expense, debt issuance costs, unrealized losses on derivatives, non-cash charges such as non-cash equity compensation expense, and charges that are unusual such as transaction expenses primarily associated with our acquisitions (such as JPE, Viosca Knoll, Delta House and Panther), income tax expense, distributions from unconsolidated affiliates and general partner’s contribution, less earnings in unconsolidated affiliates, gains (losses) that are unusual such as gain on revaluation of equity interest and gain on sale of the Propane Business, other, net, and gain on sale of assets, net.
We have changed our definition of Adjusted EBITDA to include the Adjusted EBITDA of our discontinued operations as we believe the impact to our operating results of our discontinued operations should be reflected in our Adjusted EBITDA for the historical periods we owned the businesses. We believe including the impact of our discontinued operations for the periods in which the businesses were owned is more meaningful to our investors and more reflective of the Partnership’s actual performance. In connection with filing our Report on Form 10-Q for the quarter ended September 30, 2017, we had reported our Adjusted EBITDA without the Adjusted EBITDA of our discontinued operations.
The GAAP measure most directly comparable to our performance measure Adjusted EBITDA is net income (loss) attributable to the Partnership. For a reconciliation of Adjusted EBITDA to net income (loss), see “Non-GAAP Financial Measures” below.
Non-GAAP Financial Measures
Total segment gross margin, operating margin and Adjusted EBITDA are performance measures that are non-GAAP financial measures. Each has important limitations as an analytical tool because they exclude some, but not all, items that affect the most directly comparable GAAP financial measures. Management compensates for the limitations of these non-GAAP measures as analytical tools by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these data points into management’s decision-making process.
You should not consider total segment gross margin, operating margin, or Adjusted EBITDA in isolation or as a substitute for, or more meaningful than analysis of, our results as reported under GAAP. Total segment gross margin, operating margin and Adjusted EBITDA 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.
The following tables reconcile the non-GAAP financial measures of total segment gross margin, operating margin and Adjusted EBITDA used by management to Net income (loss) attributable to the Partnership, their most directly comparable GAAP measure, for the three and nine months ended September 30, 2017 and 2016 (in thousands):
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Three months ended September 30, | Nine months ended September 30, | ||||||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||||||
Reconciliation of Segment Gross Margin to Net income (loss) attributable to the Partnership: | |||||||||||||||
Gas Gathering and Processing Services segment gross margin | $ | 12,761 | $ | 12,627 | $ | 36,663 | $ | 37,586 | |||||||
Liquid Pipelines and Services segment gross margin | 7,808 | 7,600 | 21,209 | 23,829 | |||||||||||
Natural Gas Transportation Services segment gross margin | 5,356 | 3,709 | 17,106 | 13,115 | |||||||||||
Offshore Pipelines and Services segment gross margin | 29,312 | 24,126 | 80,738 | 57,947 | |||||||||||
Terminalling Services segment gross margin (1) | 8,509 | 10,731 | 30,429 | 31,760 | |||||||||||
Total segment gross margin (non-GAAP) | 63,746 | 58,793 | 186,145 | 164,237 | |||||||||||
Less: | |||||||||||||||
Direct operating expenses (1) | 17,274 | 14,695 | 47,316 | 45,999 | |||||||||||
Plus: | |||||||||||||||
Gain (loss) on commodity derivatives, net | (597 | ) | 324 | (33 | ) | (1,929 | ) | ||||||||
Less: | |||||||||||||||
Corporate expenses | 27,083 | 22,103 | 84,570 | 60,945 | |||||||||||
Depreciation, amortization and accretion expense | 26,781 | 22,668 | 78,834 | 65,937 | |||||||||||
(Gain) loss on sale of assets, net | (4,061 | ) | 36 | (4,064 | ) | 297 | |||||||||
Interest expense | 17,759 | 5,830 | 51,037 | 24,723 | |||||||||||
Other (income) expense | (34,085 | ) | 1 | (32,248 | ) | (245 | ) | ||||||||
Other (income) expense, net | (139 | ) | (1,129 | ) | 322 | (1,773 | ) | ||||||||
Income tax expense | 731 | 401 | 2,611 | 1,839 | |||||||||||
(Income) loss from discontinued operations, net of tax | (44,696 | ) | 2,310 | (42,185 | ) | (7,532 | ) | ||||||||
Net income attributable to noncontrolling interests | 621 | 1,241 | 3,386 | 2,192 | |||||||||||
Net Income (loss) attributable to the Partnership | $ | 55,881 | $ | (9,039 | ) | $ | (3,467 | ) | $ | (30,074 | ) | ||||
_______________________
(1) Direct operating expenses include Gas Gathering and Processing Services segment direct operating expenses of $8.7 million and $7.9 million for the three months ended September 30, 2017 and 2016, respectively, and $24.8 million and $25.3 million, for the nine months ended September 30, 2017 and 2016, respectively, Liquid Pipelines and Services segment direct operating expenses of $2.4 million and $2.6 million for the three months ended September 30, 2017 and 2016, respectively, and $7.1 million and $8.2 million for the nine months ended September 30, 2017 and 2016, respectively, Natural Gas Transportation Services segment direct operating expenses of $2.2 million and $1.3 million for the three months ended September 30, 2017 and 2016, respectively, and $5.4 million and $4.5 million for the nine months ended September 30, 2017 and 2016, respectively, Offshore Pipelines and Services segment direct operating expenses of $3.9 million and $2.9 million for the three months ended September 30, 2017 and 2016, respectively, and $10.0 million and $8.0 million for the nine months ended September 30, 2017 and 2016, respectively, and Direct operating expenses related to our Terminalling Services segment of $3.4 million and $2.9 million for the three months ended September 30, 2017 and 2016, respectively, as well as $9.5 million and $7.9 million for the nine months ended September 30, 2017 and 2016, respectively, are included within the calculation of Terminalling Services segment gross margin.
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Three months ended September 30, | Nine months ended September 30, | ||||||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||||||
Reconciliation of Net income (loss) attributable to the Partnership to Adjusted EBITDA: | |||||||||||||||
Net income (loss) attributable to the Partnership | $ | 55,881 | $ | (9,039 | ) | $ | (3,467 | ) | $ | (30,074 | ) | ||||
Add: | |||||||||||||||
Depreciation, amortization and accretion expense | 26,685 | 22,668 | 78,173 | 65,937 | |||||||||||
Interest expense | 14,959 | 5,014 | 43,769 | 22,395 | |||||||||||
Debt issuance costs paid | 119 | 2,512 | 2,235 | 3,987 | |||||||||||
Unrealized losses (gains) on derivatives, net | 325 | (3,175 | ) | 2,288 | 2,431 | ||||||||||
Non-cash equity compensation expense | 835 | 1,234 | 6,067 | 4,285 | |||||||||||
Transaction expenses | 10,470 | 4,983 | 31,155 | 9,145 | |||||||||||
Income tax expense | 731 | 401 | 2,611 | 1,839 | |||||||||||
Distributions from unconsolidated affiliates | 20,582 | 22,720 | 58,976 | 62,797 | |||||||||||
General Partner contribution for cost reimbursement | 9,870 | — | 34,614 | 5,000 | |||||||||||
Deduct: | |||||||||||||||
Earnings in unconsolidated affiliates | 16,827 | 10,468 | 49,781 | 29,513 | |||||||||||
Gain on revaluation of equity interest | 32,383 | — | 32,383 | — | |||||||||||
Other income | 86 | 389 | 241 | 342 | |||||||||||
OPEB plan net periodic benefit | 5 | 20 | 16 | 13 | |||||||||||
Gain (loss) on sale of assets, net | 4,061 | (36 | ) | 4,064 | (297 | ) | |||||||||
Net impact of discontinued operations (1) | (44,745 | ) | 4,690 | (36,247 | ) | 13,660 | |||||||||
Adjusted EBITDA | $ | 42,350 | $ | 41,167 | $ | 133,689 | $ | 131,831 | |||||||
_______________________
(1) Amounts primarily represent adjustments related to depreciation, amortization and accretion, unrealized (gain) loss on derivatives, (gain) loss on asset sales, transaction expenses and gain on sale of Propane Business.
General Trends and Outlook
We expect our business to continue to be affected by the key trends discussed in the Recast Form 8-K/A, under the caption “Management’s Discussion and Analysis of Financial Condition and Results of Operations — General Trends and Outlook.”
Results of Operations — Consolidated
Net income attributable to the Partnership increased by $64.8 million to $55.9 million for the three months ended September 30, 2017, as compared to net loss of $9.0 million in the same period in 2016, which was primarily due to the net gain on disposition of the Propane Business of $46.5 million, the gain of $32.3 million related to the MPOG acquisition and the $4.0 million gain recognized on Cayenne, offset partially by an increase in operating loss of $10.9 million and interest expense of $11.9 million.
Net loss decreased by $26.6 million, to $3.5 million for the nine months ended September 30, 2017 as compared to the same period in 2016 primarily due to the net gain on disposition of the Propane Business, gain related to the MPOG acquisition, offset partially by an increase in operating loss of approximately $32.0 million and an increase in interest expense of $26.3 million due to higher average debt balances from our growth initiatives as well as higher average interest costs.
For the three months ended September 30, 2017, direct operating expenses increased by $3.1 million primarily due to the recent acquisitions of Viosca Knoll and Panther. Corporate expenses increased by $5.0 million, or 22.5%, due to an increase of $4.5 million of merger/disposition related costs which include legal, consulting services and employee severance costs. Interest expense increased by $12.0 million, or 206.9%, as a result of additional borrowings to fund capital growth and acquisitions. Earnings from unconsolidated affiliates increased by $6.4 million, or 60.7%, as result of our additional 6.6% investment in Delta House that occurred in the fourth quarter of 2016.
For the nine months ended September 30, 2017, direct operating expenses increased by $2.9 million primarily due to the recent acquisitions of Viosca Knoll and Panther partially offset by lower compressor rental costs. Corporate expenses increased by $23.7 million, or 38.9%, due to an increase of $18.6 million of merger-related costs which include legal, consulting services and employee
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severance costs; $3.0 million relating to a settlement of litigation claim; and $1.4 million of compensation relating to severance costs. Interest expense increased by $26.3 million, or 106.4%, as a result of a $25.0 million increase of interest expense due to additional borrowings to fund capital growth and acquisitions. Earnings from unconsolidated affiliates increased by $20.3 million, or 68.8%, as result of our additional 6.6% investment in Delta House that occurred in Q4 2016.
Segment gross margin was $63.7 million for the three months ended September 30, 2017 and $186.1 million for the nine months ended September 30, 2017 compared to $58.8 million for the three months ended September 30, 2016 and $164.2 million for the nine months ended September 30, 2016. The increase of $4.9 million for the three months ended September 30, 2017 was primarily due to our Offshore Pipelines and Services segment increase of $5.2 million as a result of higher earnings in unconsolidated affiliates. For the nine months ended September 30, 2017, the increase of $21.9 million was primarily due to our Offshore Pipelines and Services segment of $22.8 million as a result of increased earnings in unconsolidated affiliates and the American Panther system that was acquired in Q3 2016, and an increase in our Natural Gas Transportation Services segment of $4.0 million mostly due to higher throughput as a result of new firm transportation contracts on our Mid Louisiana Gas Transmission (MLGT), Midla and AlaTenn systems. These increases were partially offset by a decrease of $2.6 million related to our Liquids Pipeline and Services segment primarily attributable to higher average cost of crude barrels in 2017 compared to 2016 on Crude Oil Supply and Logistics (COSL) offset by higher sour crude marketing transactions that began in May 2017.
For the three and nine months ended September 30, 2017, Adjusted EBITDA increased $1.2 million, or 2.9%, and $1.9 million, or 1.4%, compared to the same periods in 2016, respectively. The increase is primarily related to support from our General Partner for cost reimbursement and partially offset by lower distributions from our unconsolidated affiliates.
We distributed $21.3 million to holders of our common units, or $0.4125 per common unit, during the three months ended September 30, 2017, and $67.6 million, or $1.2375 per common unit, during the nine months ended September 30, 2017.
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The results of operations by segment are discussed in further detail following this overview (in thousands):
Three months ended September 30, | Nine months ended September 30, | ||||||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||||||
Statement of Operations Data: | |||||||||||||||
Revenue: | |||||||||||||||
Commodity sales | $ | 124,052 | $ | 119,194 | $ | 372,049 | $ | 304,084 | |||||||
Services | 38,835 | 40,385 | 116,382 | 110,998 | |||||||||||
Gain (loss) on commodity derivatives, net | (597 | ) | 324 | (33 | ) | (1,929 | ) | ||||||||
Total revenue | 162,290 | 159,903 | 488,398 | 413,153 | |||||||||||
Operating expenses: | |||||||||||||||
Costs of sales | 112,398 | 107,249 | 342,886 | 270,712 | |||||||||||
Direct operating expenses | 20,705 | 17,571 | 56,819 | 53,872 | |||||||||||
Corporate expenses | 27,083 | 22,103 | 84,570 | 60,945 | |||||||||||
Depreciation, amortization and accretion | 26,781 | 22,668 | 78,834 | 65,937 | |||||||||||
Total operating expenses | 186,967 | 169,591 | 563,109 | 451,466 | |||||||||||
(Gain) loss on sale of assets, net | (4,061 | ) | 36 | (4,064 | ) | 297 | |||||||||
Operating loss | (20,616 | ) | (9,724 | ) | (70,647 | ) | (38,610 | ) | |||||||
Other income (expense), net | |||||||||||||||
Interest expense | (17,759 | ) | (5,830 | ) | (51,037 | ) | (24,723 | ) | |||||||
Other income (expense) | 34,085 | (1 | ) | 32,248 | 245 | ||||||||||
Earnings in unconsolidated affiliates | 16,827 | 10,468 | 49,781 | 29,513 | |||||||||||
Income (loss) from continuing operations before income taxes | 12,537 | (5,087 | ) | (39,655 | ) | (33,575 | ) | ||||||||
Income tax expense | (731 | ) | (401 | ) | (2,611 | ) | (1,839 | ) | |||||||
Income (loss) from continuing operations | 11,806 | (5,488 | ) | (42,266 | ) | (35,414 | ) | ||||||||
Income (loss) from discontinued operations, including net gain on disposition of $46.5 million (Note 4) | 44,696 | (2,310 | ) | 42,185 | 7,532 | ||||||||||
Net income (loss) | 56,502 | (7,798 | ) | (81 | ) | (27,882 | ) | ||||||||
Less: Net income attributable to noncontrolling interests | 621 | 1,241 | 3,386 | 2,192 | |||||||||||
Net income (loss) attributable to the Partnership | $ | 55,881 | $ | (9,039 | ) | $ | (3,467 | ) | $ | (30,074 | ) | ||||
Other Financial Data: | |||||||||||||||
Total segment gross margin (1) | $ | 63,746 | $ | 58,793 | $ | 186,145 | $ | 164,237 | |||||||
Adjusted EBITDA (1) | $ | 42,350 | $ | 41,167 | $ | 133,689 | $ | 131,831 | |||||||
______________________
(1) | For definitions of gross margin and Adjusted EBITDA and reconciliations to their most directly comparable financial measure calculated and presented in accordance with GAAP, and a discussion of how we use gross margin and Adjusted EBITDA to evaluate our operating performance, see the information in this Item under the caption “How We Evaluate Our Operations.” |
Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016
Total Revenue. Our total revenue for the three months ended September 30, 2017 was $162.3 million compared to $159.9 million for the three months ended September 30, 2016. This increase of $2.4 million was primarily due to the following:
• | an increase in our Gas Gathering and Processing segment revenue of $5.6 million primarily due to new contracts at our Longview plant for NGLs, natural gas and condensate for $12.9 million, partially offset by a decrease in natural gas and condensate volumes at Chatom/Bazor Ridge for $5.3 million due to lower system volumes, and due to marketing contracts that ended in Q4 of 2016 for $1.1 million; |
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• | a decrease in our Liquid Pipelines and Services revenue from operations of $0.9 million primarily due to the expiration of short-term marketing deals on COSL partially offset by sour crude marketing contracts that started in May 2017 for $0.7 million; and |
• | a decrease in our Terminalling Services segment revenue of $1.4 million primarily due to a $1.5 million reduction in storage and utilization at our Cushing terminal from a new contract with lower storage and rate terms. |
Cost of Sales. Our purchases of natural gas, NGLs, condensate and crude for the three months ended September 30, 2017 was $112.4 million compared to $107.2 million for the three months ended September 30, 2016. The increase of $5.2 million was mostly due to our Gas Gathering and Processing segment from higher NGL, natural gas and condensate purchases of $7.1 million due to an increase in throughput at the Longview Plant and an increase of $2.1 million primarily due to new sour crude marketing contracts partially offset by short-term marketing contracts on COSL that expired in 2016 in our Liquid Pipelines and Services segment, and the expiration of a marketing contract for $1.5 million in our Natural Gas Transportations Services segment.
Total Segment Gross Margin. Total segment gross margin for the three months ended September 30, 2017 was $63.7 million compared to $58.8 million for the three months ended September 30, 2016. The increase of $4.9 million was primarily due to our Offshore Pipelines and Services segment of $5.2 million as a result of increased earnings in unconsolidated affiliates mostly attributable to Delta House and Okeanos partially offset by a decrease in our Terminalling Services segment mainly due to lower contracted storage and rate terms at our Cushing terminal.
Direct Operating Expenses. Direct operating expenses for the three months ended September 30, 2017 were $20.7 million compared to $17.6 million for the three months ended September 30, 2016. This increase of $3.1 million was primarily due to an increase of $0.9 million related to the acquisitions of Viosca Knoll and Panther in 2017, an increase of $0.6 million due to fuel loss and recovery expense related to our Bamagas system, $0.7 million related to chemical purchases and $0.8 million in outside services and additional utilities charges.
Corporate Expenses. Corporate expenses for the three months ended September 30, 2017 were $27.1 million compared to $22.1 million for the three months ended September 30, 2016. This increase of $5.0 million was primarily due to an increase of $4.5 million of merger related costs which include legal, consulting services and employee severance costs. The remaining balance is primarily related to recruitment fees and higher employee costs due to increased headcount.
Depreciation, Amortization and Accretion Expense. Depreciation, amortization and accretion expense for the three months ended September 30, 2017 was $26.8 million compared to $22.7 million for the three months ended September 30, 2016. This increase of $4.1 million was primarily due to the decrease in useful life of certain intangible assets for $1.8 million and incremental depreciation of fixed assets primarily related to our recent acquisitions of Viosca Knoll and Panther.
Interest Expense. Interest expense for the three months ended September 30, 2017 was $17.8 million compared to $5.8 million for the three months ended September 30, 2016. The increase of $12.0 million was primarily due to interest charges on the 8.50% and 3.77% Senior Notes, which were issued in the fourth quarter of 2016, $6.4 million; unfavorable interest rate swaps contributed $2.2 million and the increased interest cost due to the borrowings on our revolving credit facility of $709.7 million.
Earnings in Unconsolidated Affiliates. Earnings in unconsolidated affiliates for the three months ended September 30, 2017 was $16.8 million compared to $10.5 million for the three months ended September 30, 2016. This increase of $6.3 million was primarily due to incremental earnings of $4.8 million related to our investment in Delta House and $0.9 million from Okeanos due to wells coming on line from the Thunderhorse expansion.
Income from discontinued operations. Income from discontinued operations is primarily associated with our Propane Business, including a net gain on disposition of $46.5 million for the three months ended September 30, 2017. The prior period’s results have been recast for comparative purposes.
Nine months ended September 30, 2017 Compared to Nine months ended September 30, 2016
Total Revenue. Our total revenue for the nine months ended September 30, 2017 was $488.4 million compared to $413.2 million for the nine months ended September 30, 2016. This increase of $75.2 million was primarily due to the following:
• | an increase in our Gas Gathering and Processing segment revenue of $25.3 million primarily due to increased revenue from sales of NGLs and condensate at the Longview Plant of $38.2 million due to three new contracts, two of which started in Q1 2017, partially offset by a decrease in NGL and condensate volumes at Chatom/Bazor Ridge of $6.4 million due to lower system volumes and due to marketing contracts that ended in fourth quarter of 2016 for $4.5 million; |
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• | an increase in our Liquid Pipelines and Services segment revenue of $31.7 million primarily due to an increase in revenue of $34.6 million due to sour crude marketing transactions that started in May 2017; |
• | an increase in our Natural Gas Transportation Services segment revenue of $6.6 million primarily due to an increase on the Magnolia system of $3.6 million due to favorable prices and $2.8 million of additional revenues on our MLGT, Midla and AlaTenn systems due to new firm transportation contracts; |
• | an increase in our Offshore Pipelines and Services segment revenue of $8.8 million due primarily to higher volumes and management fees from our American Panther system for $7.0 million, $2.5 million of platform fee and transportation revenues as a result of the acquisition of the VKGS system in June 2017, increased volumes sold to the Alliance Refinery and new wells on our Gloria system for $3.8 million, partially offset by our High Point Gas Transmission (HPGT) system as a result of contracts expiring contributing to lower volumes for $5.0 million; and |
• | an increase in our Terminalling Services segment revenue of $0.9 million primarily due to an expansion at our Harvey terminal for $1.9 million. |
Cost of Sales. Our purchases of natural gas, NGLs, condensate and crude for the nine months ended September 30, 2017 was $342.9 million compared to $270.7 million for the nine months ended September 30, 2016. The increase of $72.2 million was primarily due to the Gas Gathering and Processing segment and higher NGL, natural gas and condensate purchases of $28.0 million due to an increase in throughput at the Longview Plant and an increase of $37.8 million in our Liquid Pipelines and Services segment mostly driven by sour crude marketing transactions that began in May 2017, and an increase in the average purchase cost for crude barrels in 2017 compared to 2016.
Total Segment Gross Margin. Total segment gross margin for the nine months ended September 30, 2017 was $186.1 million compared to $164.2 million for the nine months ended September 30, 2016. This increase of $21.9 million was primarily due to higher segment gross margin in our Offshore Pipelines and Services segment of $22.8 million as a result of increased earnings in unconsolidated affiliates and the VKGS system and American Panther that were acquired in the second quarter and third quarter of 2017, respectively, and due to an increase in our Natural Gas Transportation Services segment of $4.0 million mostly due to an increase in throughput as a result of new firm transportation contracts on our MLGT, Midla and AlaTenn systems. These increases were partially offset by a decrease of $2.6 million related to our Liquid Pipelines and Services segment primarily attributable to items discussed above, partially offset by increased volumes on Tri-States.
Direct Operating Expenses. Direct operating expenses for the nine months ended September 30, 2017 were $56.8 million compared to $53.9 million for the nine months ended September 30, 2016. This increase of $2.9 million was primarily due to $0.8 million related to the newly acquired VKGS and Panther entities, $0.8 million related to chemical purchases, $0.7 million related to fuel loss and recovery at Bamagas and $0.3 million in repair and maintenance.
Corporate Expenses. Corporate expenses for the nine months ended September 30, 2017 were $84.6 million compared to $60.9 million for the nine months ended September 30, 2016. This increase of $23.7 million was primarily due to an increase of $18.6 million of merger related costs which include legal, consulting services and employee severance costs; $3.0 million relating to the settlement of a litigation claim and $0.6 million higher insurance premiums on offshore assets.
Depreciation, Amortization and Accretion Expense. Depreciation, amortization and accretion expense for the nine months ended September 30, 2017 was $78.8 million compared to $65.9 million for the nine months ended September 30, 2016. This increase of $12.9 million was primarily due to $7.0 million increase in amortization expense caused by the acceleration of customer list useful life and incremental depreciation of fixed assets acquired in the last 12 months mainly related to our Midla and Mesquite projects, as well as a increase in depreciation due to our recent acquisitions.
Interest Expense. Interest expense for the nine months ended September 30, 2017 was $51.0 million compared to $24.7 million for the nine months ended September 30, 2016. This increase of $26.3 million was primarily due to interest on the 8.50% and 3.77% Senior Notes issued in the fourth quarter of 2016 increasing interest expense $21.0 million, and increased interest expense associated with higher borrowings on the Credit agreement of $2.7 million and $1.3 million in amortization of financing costs.
Earnings in Unconsolidated Affiliates. Earnings in unconsolidated affiliates for the nine months ended September 30, 2017 was $49.8 million compared to $29.5 million for the nine months ended September 30, 2016. This increase of $20.3 million was primarily due to incremental earnings of $12.6 million related to our increased investment in Delta House, $6.2 million from our interests in the Destin and Okeanos systems and $2.2 million from our interests in Tri-States and Wilprise.
Income from discontinued operations. Income from discontinued operations is primarily associated with our Propane Business, including a net gain on disposition of $46.5 million for the nine months ended September 30, 2017. The prior period’s results have been recast for comparative purposes.
18
Results of Operations — Segment Results
Gas Gathering and Processing Services Segment
The table below contains key segment performance indicators related to our Gathering and Processing Services segment (in thousands except operating and pricing data).
Three months ended September 30, | Nine months ended September 30, | ||||||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||||||
Segment Financial and Operating Data: | |||||||||||||||
Gas Gathering and Processing Services segment | |||||||||||||||
Financial data: | |||||||||||||||
Commodity sales | $ | 31,651 | $ | 25,776 | $ | 94,074 | $ | 67,053 | |||||||
Services | 5,636 | 5,874 | 16,927 | 18,602 | |||||||||||
Revenue from operations | 37,287 | 31,650 | 111,001 | 85,655 | |||||||||||
Gain (loss) on commodity derivatives, net | (65 | ) | 149 | (170 | ) | (716 | ) | ||||||||
Segment revenue | 37,222 | 31,799 | 110,831 | 84,939 | |||||||||||
Cost of sales | 24,492 | 18,477 | 74,261 | 47,344 | |||||||||||
Direct operating expenses | 8,655 | 7,856 | 24,766 | 25,344 | |||||||||||
Other financial data: | |||||||||||||||
Segment gross margin (2) | $ | 12,761 | $ | 12,627 | $ | 36,663 | $ | 37,586 | |||||||
Operating data: | |||||||||||||||
Average throughput (MMcf/d) | 201.0 | 211.0 | 205.0 | 218.0 | |||||||||||
Average plant inlet volume (MMcf/d) (1) | 94.9 | 103.7 | 100.0 | 103.0 | |||||||||||
Average gross NGL production (Mgal/d) (1) | 324.3 | 181.7 | 340.0 | 240.0 | |||||||||||
Average gross condensate production (Mgal/d) (1) | 57.5 | 87.1 | 73.0 | 81.0 | |||||||||||
_______________________
(1) Excludes volumes and gross production under our elective processing arrangements.
(2) For the definition of segment gross margin and a discussion of how we use segment gross margin to evaluate our operating performance, see the information in this Item under the caption “How We Evaluate Our Operations.”
Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016
Commodity sales. Commodity sales revenue for the three months ended September 30, 2017 was $31.7 million compared to $25.8 million for the three months ended September 30, 2016. The increase of $5.9 million resulted from a combination of the following:
• | increased revenue from sales of NGLs, natural gas and condensate at the Longview Plant of $12.5 million due to three new contracts, two of which started in first quarter of 2017; |
• | offset by reduced NGL, natural gas and condensate volumes at Chatom/Bazor Ridge for $5.3 million due to lower system volumes (production declines and loss of Y-grade product); and |
• | also offset by marketing contracts that ended in fourth quarter of 2016 for $1.1 million. |
Services. Segment services revenue for the period ended September 30, 2017 was $5.6 million compared to $5.9 million for the three months ended September 30, 2016. The decrease is primarily due to a reduction in Construction, Operating and Management Agreement (COMA) fee revenue on Yellow Rose of $0.3 million and lower gathering charges of $0.1 million on our Lavaca system, offset by increased service fee revenue of $0.2 million at Chatom/Bazor Ridge for a pipeline connection recovery fee.
Cost of Sales. Purchases of natural gas, NGLs and condensate for the three months ended September 30, 2017 were $24.5 million compared to $18.5 million for the three months ended September 30, 2016. The increase of $6.0 million was primarily due to the increase of NGL, natural gas and condensate sales at the Longview Plant, as discussed above.
Segment Gross Margin. Segment gross margin for the three months ended September 30, 2017 was $12.8 million compared to $12.6 million for the three months ended September 30, 2016, for reasons discussed above.
19
Direct Operating Expenses. Direct operating expenses for three months ended September 30, 2017 was $8.7 million compared to $7.9 million for the three months ended September 30, 2016. The $0.8 million increase is mainly due to $0.4 million in environmental compliance and chemical purchases as well as additional repairs of $0.3 million related to right-of-way sinkage and other repair and maintenance.
Nine months ended September 30, 2017 Compared to Nine months ended September 30, 2016
Commodity sales. Commodity sales revenue for the nine months ended September 30, 2017 was $94.1 million compared to $67.1 million for the nine months ended September 30, 2016. The increase of $27.0 million was primarily due to the following:
• | increased revenue from sales of NGLs and condensate at the Longview Plant of $38.2 million due to three new contracts, two of which started in Q1 2017; |
• | offset by reduced NGL and condensate volumes at Chatom/Bazor Ridge for $6.4 million due to lower system volumes (production declines and loss of Y-grade product); and |
• | also offset by marketing contracts that ended in Q4 of 2016 for $4.5 million. |
Services. Segment services revenue for the six months ended September 30, 2017 was $16.9 million compared to $18.6 million for the nine months ended September 30, 2016. The decrease is primarily due to a decline in compression and gathering charges of $1.6 million on our Lavaca system, lower fractionation and transportation fees of $0.9 million on Longview, production ceasing at Southern Industrial Gas Corp. (SIGCO) for $0.4 million which was partially offset by increased service fee revenue of $1.2 million at Chatom/Bazor Ridge for a pipeline connection recovery fee.
Cost of Sales. Purchases of natural gas, NGLs and condensate for the nine months ended September 30, 2017 were $74.3 million compared to $47.3 million for the nine months ended September 30, 2016. This increase of $27.0 million was primarily due to the increase of NGL, natural gas and condensate sales at the Longview Plant, as discussed above.
Segment Gross Margin. Segment gross margin for the nine months ended September 30, 2017 was $36.7 million compared to $37.6 million for the nine months ended September 30, 2016, for reasons as discussed above.
Direct Operating Expenses. Direct operating expenses of $24.8 million for nine months ended September 30, 2017 declined from $25.3 million for the nine months ended September 30, 2016, mainly due to our ongoing cost savings initiatives reducing compressor rentals and labor costs by $0.3 million and $0.2 million in lower regulatory costs.
20
Liquid Pipelines and Services Segment
The table below contains key segment performance indicators related to our Liquid Pipelines and Services segment (in thousands except operating and pricing data).
Three months ended September 30, | Nine months ended September 30, | ||||||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||||||
Segment Financial and Operating Data: | |||||||||||||||
Liquid Pipelines and Services segment | |||||||||||||||
Financial data: | |||||||||||||||
Commodity sales | $ | 82,948 | $ | 83,682 | $ | 241,459 | $ | 206,857 | |||||||
Services | 4,074 | 4,216 | 12,131 | 15,009 | |||||||||||
Revenue from operations | 87,022 | 87,898 | 253,590 | 221,866 | |||||||||||
Gain (loss) on commodity derivatives, net | (532 | ) | 177 | 137 | (772 | ) | |||||||||
Earnings in unconsolidated affiliates | 1,317 | 650 | 3,886 | 1,658 | |||||||||||
Segment revenue | 87,807 | 88,725 | 257,613 | 222,752 | |||||||||||
Cost of sales | 80,510 | 80,372 | 236,896 | 199,111 | |||||||||||
Direct operating expenses | 2,438 | 2,617 | 7,137 | 8,186 | |||||||||||
Other financial data: | |||||||||||||||
Segment gross margin (1) | $ | 7,808 | $ | 7,600 | $ | 21,209 | $ | 23,829 | |||||||
Operating data (2) : | |||||||||||||||
Average throughput Pipeline (Bbls/d) | 35,403 | 30,371 | 33,837 | 31,083 | |||||||||||
Average throughput Truck (Bbls/d) | 2,632 | 1,638 | 2,048 | 1,625 | |||||||||||
_______________________
(1) For the definition of segment gross margin and a discussion of how we use segment gross margin to evaluate our operating performance, see the information in this Item under the caption “How We Evaluate Our Operations.”
(2) These volumes exclude volumes from our equity investments.
Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016
Commodity Sales. Segment revenue from crude oil for the three months ended September 30, 2017 was $82.9 million compared to $83.7 million for the three months ended September 30, 2016. The decrease of $0.8 million was primarily due to the expiration of short-term marketing deals on COSL that expired in second quarter of 2016 for $19.6 million partially offset by $18.9 million of sour crude marketing contracts that started in May 2017.
Services revenue. Segment services revenue for the three months ended September 30, 2017 was $4.1 million and remained relatively flat compared to $4.2 million for the three months ended September 30, 2016.
Earnings in Unconsolidated Affiliates. Earnings in unconsolidated affiliates for the three months ended September 30, 2017 was $1.3 million compared to $0.6 million for the three months ended September 30, 2016. The increase of $0.7 million was due to increased volumes on Tri-States as a result of increased production from the Delta House and Thunderhorse platforms.
Cost of Sales. Purchases of crude oil for the three months ended September 30, 2017 was $80.5 million compared to $80.4 million for the three months ended September 30, 2016. The increase of $0.1 million was primarily due to $18.7 million of sour crude marketing transactions that began in May 2017 partially offset by $18.2 million of short-term marketing deals on COSL that expired in third quarter of 2016, and price increases in 2017 compared to 2016.
Segment Gross Margin. Segment gross margin for the three months ended September 30, 2017, was $7.8 million compared to $7.6 million for the three months ended September 30, 2016. The increase of $0.2 million is due to the reasons discussed above.
Direct Operating Expenses. Direct operating expenses of $2.4 million for the three months ended September 30, 2017 declined from $2.6 million for the three months ended September 30, 2016, mainly due to a decrease of $0.2 million for equipment lease and measurement costs.
21
Nine months ended September 30, 2017 Compared to Nine months ended September 30, 2016
Commodity Sales. Segment revenue from crude oil for the nine months ended September 30, 2017 was $241.5 million compared to $206.9 million for the nine months ended September 30, 2016. The increase of $34.6 million was primarily due to the sour crude marketing transactions that started in May 2017.
Services revenue. Segment services revenue for the nine months ended September 30, 2017 was $12.1 million compared to $15.0 million for the nine months ended September 30, 2016. The decrease of $2.9 million was primarily due to a $2.0 million reduction in transport gallons on AMID Trucking and tariff rate reductions of $0.6 million on Bakken.
Earnings in Unconsolidated Affiliates. Earnings in unconsolidated affiliates for the nine months ended September 30, 2017 was $3.9 million compared to $1.7 million for the nine months ended September 30, 2016, resulting from the acquisition of Tri-States and Wilprise in late April 2016, and increased volumes on Tri-States, due to increased production from the Delta House and Thunderhorse platforms.
Cost of Sales. Purchases of crude oil for the nine months ended September 30, 2017 was $236.9 million compared to $199.1 million for the nine months ended September 30, 2016. The increase of $37.8 million is primarily due to the increase in sour crude marketing transactions that started in May 2017 for $33.7 million and an increase in the average purchase cost of barrels in 2017 compared to 2016 on COSL of $4.7 million.
Segment Gross Margin. Segment gross margin for the nine months ended September 30, 2017, was $21.2 million compared to $23.8 million for the nine months ended September 30, 2016. The Segment margin decreased by $2.6 million due to the reasons discussed above.
Direct Operating Expenses. Direct operating expenses of $7.1 million for the nine months ended September 30, 2017 declined from $8.2 million for the nine months ended September 30, 2016 mainly due to $0.6 million equipment lease costs, $0.3 million of lower property tax expense and $0.2 million for measurement equipment costs.
Natural Gas Transportation Services Segment
The table below contains key segment performance indicators related to our Natural Gas Transportation Services segment
(in thousands except operating and pricing data).
Three months ended September 30, | Nine months ended September 30, | ||||||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||||||
Segment Financial and Operating Data: | |||||||||||||||
Natural Gas Transportation Services segment | |||||||||||||||
Financial data: | |||||||||||||||
Commodity sales | $ | 6,175 | $ | 6,805 | $ | 19,485 | $ | 15,682 | |||||||
Services | 4,956 | 3,904 | 15,481 | 12,701 | |||||||||||
Segment revenue | 11,131 | 10,709 | 34,966 | 28,383 | |||||||||||
Cost of sales | 5,692 | 6,994 | 17,630 | 15,245 | |||||||||||
Direct operating expenses | 2,240 | 1,324 | 5,403 | 4,515 | |||||||||||
Other financial data: | |||||||||||||||
Segment gross margin (1) | $ | 5,356 | $ | 3,709 | $ | 17,106 | $ | 13,115 | |||||||
Operating data: | |||||||||||||||
Average throughput (MMcf/d) | 423.0 | 517.0 | 407.0 | 461.0 | |||||||||||
_______________________
(1) For the definition of segment gross margin and a discussion of how we use segment gross margin to evaluate our operating performance, see the information in this Item under the caption “How We Evaluate Our Operations.”
22
Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016
Commodity Sales. Segment sales of natural gas, NGLs and condensate for the three months ended September 30, 2017 were $6.2 million compared to $6.8 million for the three months ended September 30, 2016. The small decrease of $0.6 million is primarily due to a contract expiration in June 2017.
Services revenue. Segment services revenue for the three months ended September 30, 2017 was $5.0 million compared to $3.9 million for the three months ended September 30, 2016. The increase of $1.1 million is primarily due to new firm transportation contracts on our Mid Louisiana Gas Transmission (MLGT) and Midla systems.
Cost of Sales. Purchases of natural gas, NGLs and condensate for the three months ended September 30, 2017 were $5.7 million as compared to $7.0 million for the three months ended September 30, 2016. The decrease of $1.3 million is primarily due to the expiration of a marketing contract in June 2017 for $1.0 million and an imbalance cost of $0.5 million on Midla.
Segment Gross Margin. Segment gross margin for the three months ended September 30, 2017, was $5.4 million compared to $3.7 million for the three months ended September 30, 2016. The increase of $1.7 million is primarily due to reasons discussed above.
Direct Operating Expenses. Direct operating expenses for the three months ended September 30, 2017 were $2.2 million compared to $1.3 million for the three months ended September 30, 2016. The increase of $0.9 million is primarily due to a $0.4 million increase in property tax expense, $0.3 million in environmental compliance fees and a $0.2 million increase in outside services.
Nine months ended September 30, 2017 Compared to Nine months ended September 30, 2016
Commodity Sales. Segment sales of natural gas, NGLs and condensate for the nine months ended September 30, 2017 were $19.5 million compared to $15.7 million for the nine months ended September 30, 2016. The increase of $3.8 million is primarily due to an increase on the Magnolia system of $3.6 million from higher prices in 2017 and marketing increases for $0.2 million.
Services revenue. Segment services revenue for the nine months ended September 30, 2017 was $15.5 million compared to $12.7 million for the nine months ended September 30, 2016. The increase of $2.8 million was mostly due to new firm transportation contracts on MLGT of $1.2 million, Midla of $0.8 million and AlaTenn of $0.6 million.
Cost of Sales. Purchases of natural gas, NGLs and condensate for the nine months ended September 30, 2017 were $17.6 million as compared to $15.2 million for the nine months ended September 30, 2016. The increase of $2.4 million is primarily due to higher prices on Magnolia of $3.3 million, offset by imbalances of $1.0 million on our AlaTenn, Chalmette and Midla systems.
Segment Gross Margin. Segment gross margin for the nine months ended September 30, 2017 was $17.1 million compared to $13.1 million for the nine months ended September 30, 2016. The increase of $4.0 million is primarily due to reasons discussed above.
Direct Operating Expenses. Direct operating expenses for the nine months ended September 30, 2017 were $5.4 million compared to $4.5 million for the nine months ended September 30, 2016. The increase of $0.9 million is primarily due to $0.6 million in property tax expense and environmental compliance fees as well as $0.3 million in outside services and repair and maintenance costs.
Offshore Pipelines and Services Segment
The table below contains key segment performance indicators related to our Offshore Pipelines and Services segment (in thousands except operating and pricing data).
23
Three months ended September 30, | Nine months ended Septmeber 30, | ||||||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||||||
Segment Financial and Operating Data: | |||||||||||||||
Offshore Pipelines and Services segment | |||||||||||||||
Financial data: | |||||||||||||||
Commodity sales | $ | 2,182 | $ | 1,734 | $ | 8,385 | $ | 5,556 | |||||||
Services | 12,178 | 13,145 | 32,945 | 26,970 | |||||||||||
Revenue from operations | 14,360 | 14,879 | 41,330 | 32,526 | |||||||||||
Gain (loss) on commodity derivatives, net | — | (2 | ) | — | (5 | ) | |||||||||
Earnings in unconsolidated affiliates | 15,510 | 9,819 | 45,895 | 27,855 | |||||||||||
Segment revenue | 29,870 | 24,696 | 87,225 | 60,376 | |||||||||||
Cost of sales | 558 | 570 | 6,487 | 2,429 | |||||||||||
Direct operating expenses | 3,940 | 2,898 | 10,010 | 7,954 | |||||||||||
Other financial data: | |||||||||||||||
Segment gross margin (1) | $ | 29,312 | $ | 24,126 | $ | 80,738 | $ | 57,947 | |||||||
Operating data (2): | |||||||||||||||
Average throughput (MMcf/d) | 257.0 | 467.0 | 328.0 | 464.0 | |||||||||||
_______________________
(1) For the definition of segment gross margin and a discussion of how we use segment gross margin to evaluate our operating performance, see the information in this Item under the caption “How We Evaluate Our Operations.”
(2) These volumes exclude Equity Investment volumes.
Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016
Commodity Sales. Segment sales of natural gas, NGLs and condensate for the three months ended September 30, 2017 was $2.2 million compared to $1.7 million for the three months ended September 30, 2016. The increase of $0.5 million was primarily due to increased volumes sold to the Alliance Refinery on our Gloria system for $0.9 million, offset by reduced condensate revenue on High Point Gas Transmission facility (“HPGT”) for $0.4 million.
Services revenue. Segment services revenue for the three months ended September 30, 2017 was $12.2 million compared to $13.1 million for the three months ended September 30, 2016. The decrease of $0.9 million was primarily due to a contract expiration and lower production volumes on HPGT of $4.0 million, partially offset by platform fee and transportation revenues on the VKGS system of $2.0 million, higher management fees on American Panther of $0.8 million and higher firm transportation on Gloria for $0.4 million.
Earnings in unconsolidated affiliates. Earnings for the three months ended September 30, 2017 were $15.5 million compared to $9.8 million for the three months ended September 30, 2016. The increase of $5.7 million was due to the additional Delta House acquisition in fourth quarter of 2016 for $4.8 million and it is continuing to perform near nameplate capacity as a result of strong performance by the producers that supply volumes to the offshore facility, and $0.9 million on Okeanos due to wells coming online as a result of the Thunderhorse south platform expansion.
Cost of Sales. Purchases of natural gas, NGLs and condensate remained flat for the three months ended September 30, 2017 compared to the three months ended September 30, 2016.
Segment Gross Margin. Segment gross margin for the three months ended September 30, 2017 was $29.3 million compared to $24.1 million for the three months ended September 30, 2016. The increase of $5.2 million was primarily due to increased earnings in unconsolidated affiliates as noted above.
Direct Operating Expenses. Direct operating expenses were $3.9 million and $2.9 million for the three months ended September 30, 2017 and 2016, respectively. The increase of $1.0 million is mainly due to $0.4 million in rental equipment, $0.3 million in property tax expense and $0.3 million in environmental compliance fees.
24
Nine months ended September 30, 2017 Compared to Nine months ended September 30, 2016
Commodity Sales. Segment sales of natural gas, NGLs and condensate for the nine months ended September 30, 2017 was $8.4 million compared to $5.6 million for the nine months ended September 30, 2016. The increase of $2.8 million was primarily due to increased volumes sold to the Alliance Refinery for $2.6 million and new wells coming on line for $1.2 million on our Gloria system, partially offset by a $0.6 million decrease in condensate revenue on our HPGT system.
Services revenue. Segment services revenue for the nine months ended September 30, 2017 was $32.9 million compared to $27.0 million for the nine months ended September 30, 2016. The increase of $5.9 million was primarily due to higher management fees of $5.7 million and $1.3 million for crude transportation volumes as a result of the acquisition of American Panther in April 2016, $2.5 million of platform fee and transportation revenues on VKGS as a result of the acquisition of VKGS in June 2017, and $1.0 million of new firm transportation contracts that started October 2016 on our Gloria system, partially offset by $5.0 million as a result of contracts expiring in December 2016 and January 2017, along with lower production volumes on HPGT.
Earnings in unconsolidated affiliates. Earnings for the nine months ended September 30, 2017 were $45.9 million compared to $27.9 million for the nine months ended September 30, 2016. The increase of $18.0 million was due to the additional Delta House acquisition in fourth quarter of 2016 for $12.6 million and it is continuing to perform near nameplate capacity as a result of strong performance by the producers that supply volumes to the offshore facility, $3.1 million on Destin from nine months of ownership in 2017 compared to five months in 2016, and higher volumes on Okeanos for $3.0 million, which were partially offset by $0.8 million on our Main Pass Oil Gathering (MPOG) system due to lower volumes as a result of platform operational issues and maintenance downtime.
Cost of Sales. Purchases of natural gas, NGLs and condensate for the nine months ended September 30, 2017 were $6.5 million compared to $2.4 million for the nine months ended September 30, 2016. The increase of $4.1 million was primarily due to additional throughput on our Gloria system as noted above.
Segment Gross Margin. Segment gross margin for the nine months ended September 30, 2017 was $80.7 million compared to $57.9 million for the nine months ended September 30, 2016. The increase of $22.8 million was primarily due to the items discussed above.
Direct Operating Expenses. Direct operating expenses were $10.0 million and $8.0 million for the nine months ended September 30, 2017 and 2016, respectively. This increase of $2.0 million is mainly due to $0.5 million in repair and maintenance, $0.4 million increase in rental equipment, $0.4 million increase in property tax expense, $0.4 million in environmental compliance fees and $0.3 million in outside services and contractors expense.
Terminalling Services Segment
The table below contains key segment performance indicators related to our Terminalling Services segment (in thousands except operating data).
25
Three months ended September 30, | Nine months ended September 30, | ||||||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||||||
Segment Financial and Operating Data: | |||||||||||||||
Terminalling Services segment | |||||||||||||||
Financial data: | |||||||||||||||
Commodity sales | $ | 1,094 | $ | 1,197 | $ | 8,644 | $ | 8,936 | |||||||
Services | 11,993 | 13,246 | 38,900 | 37,716 | |||||||||||
Revenue from operations | 13,087 | 14,443 | 47,544 | 46,652 | |||||||||||
Loss on commodity derivatives, net | — | — | — | (436 | ) | ||||||||||
Segment revenue | 13,087 | 14,443 | 47,544 | 46,216 | |||||||||||
Cost of sales | 1,146 | 836 | 7,612 | 6,583 | |||||||||||
Direct operating expenses | 3,432 | 2,876 | 9,503 | 7,873 | |||||||||||
Other financial data: | |||||||||||||||
Segment gross margin (2) | $ | 8,509 | $ | 10,731 | $ | 30,429 | $ | 31,760 | |||||||
Operating data: | |||||||||||||||
Contracted capacity (Bbls) | 4,759,978 | 5,224,067 | 5,066,337 | 4,920,533 | |||||||||||
Design capacity (Bbls) (3) | 5,400,800 | 5,342,467 | 5,400,800 | 5,098,022 | |||||||||||
Storage utilization (1) | 88.1 | % | 97.8 | % | 93.8 | % | 96.5 | % | |||||||
Terminalling and Storage throughput (Bbls/d) | 60,002 | 55,675 | 59,005 | 58,073 | |||||||||||
_______________________
(1) Excludes storage utilization associated with our discontinued operations.
(2) For the definition of segment gross margin and a discussion of how we use segment gross margin to evaluate our operating performance, see the information in this Item under the caption “How We Evaluate Our Operations.”
(3) Excludes Caddo Mills and North Little Rock.
Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016
Commodity Sales. Segment commodity sales for the three months ended September 30, 2017 was $1.1 million compared to $1.2 million for the three months ended September 30, 2016. The decrease of $0.1 million relates to our refined products and is driven by product volume losses.
Services Revenue. Segment services revenue for the three months ended September 30, 2017 was $12.0 million compared to $13.2 million for the three months ended September 30, 2016. The decrease of $1.2 million is primarily driven by a $1.5 million reduction in storage and utilization at our Cushing terminal from a new contract with lower storage and rate terms and a $0.3 million reduction in storage and ancillary service revenue from the loss of a customer at our Harvey terminal, partially offset by $0.6 million increase in throughput revenues at our Caddo Mills terminal as a result of facility enhancements.
Cost of Sales. Segment purchases of NGLs for the three months ended September 30, 2017 were $1.1 million compared to $0.8 million for the three months ended September 30, 2016. The increase of $0.3 million is primarily due to higher butane costs.
Segment Gross Margin. Segment gross margin for the three months ended September 30, 2017 was $8.5 million compared to $10.7 million for the three months ended September 30, 2016. The $2.2 million decrease is mostly driven by the decrease in Cushing storage and higher operating costs at Harvey.
Direct Operating Expenses. Segment direct operating expenses for the three months ended September 30, 2017 was $3.4 million compared to $2.9 million for the three months ended September 30, 2016. This increase was mainly due to $0.3 million in environmental costs and $0.2 million for railcar derailment repairs, railroad demurrage and boiler repair costs at our Harvey facility.
Nine months ended September 30, 2017 Compared to Nine months ended September 30, 2016
Commodity Sales. Segment commodity sales for the nine months ended September 30, 2017 was $8.6 million compared to $8.9 million for the nine months ended September 30, 2016. The decrease of $0.3 million relates to our refined products and is driven by a decrease in butane blending volumes.
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Services Revenue. Segment services revenue for the nine months ended September 30, 2017 was $38.9 million compared to $37.7 million for the nine months ended September 30, 2016. The $1.2 million increase is driven by a $1.9 million increase in contracted capacity and related ancillary services as a result of the expansion efforts at the Harvey terminal and by a $1.3 million increase in throughput revenue primarily from new volumes from an existing customer starting in April 2017 and facility enhancements at our Caddo Mills terminal, partially offset by a $1.5 million reduction in storage and utilization at our Cushing terminal from a new contract with lower storage and rate terms and $0.5 million, and a decrease in throughput revenue at our North Little Rock terminal due to the loss of a customer in July 2016.
Cost of Sales. Segment purchases of NGLs for the nine months ended September 30, 2017 was $7.6 million compared to $6.6 million for the nine months ended September 30, 2016. The increase of $1.0 million is primarily due to higher butane costs.
Segment Gross Margin. Segment gross margin for the nine months ended September 30, 2017 was $30.4 million compared to $31.8 million for the nine months ended September 30, 2016. The $1.4 million decrease is mostly driven by the decrease in Cushing storage, higher operating costs at Harvey and higher butane costs, partially offset by the Harvey expansion efforts and the Caddo Mills facility enhancements discussed above.
Direct Operating Expenses. Segment direct operating expenses for the nine months ended September 30, 2017 was $9.5 million compared to $7.9 million for the nine months ended September 30, 2016. This increase was mainly driven by $0.5 million in environmental costs, $0.6 million in contractors and outside services for the Harvey facility expansion, $0.3 million increase in property taxes and $0.2 million for railcar derailment repairs, railroad demurrage and boiler repair costs at the Harvey facility.
Liquidity and Capital Resources
Our business is capital intensive and requires significant investment for the maintenance of existing assets and the acquisition and development of new systems and facilities.
Our principal sources of liquidity include cash from operating activities, borrowings under our Credit Agreement (as defined herein), or through private transactions. In addition, we may seek to raise capital through the issuance of secured and unsecured senior notes. Given our historical success in accessing various sources of liquidity, we believe that the sources of liquidity described above will be sufficient to meet our short-term working capital requirements, medium-term maintenance capital expenditure requirements, and quarterly cash distributions for at least the next four quarters. In the event these sources are not sufficient, we would pursue other sources of cash funding, including, but not limited to, additional forms of debt or equity financing. In addition, we would reduce non-essential capital expenditures, direct operating expenses and corporate expenses, as necessary, and our Partnership Agreement allows us to reduce or eliminate quarterly distributions, if required to maintain ongoing operations. We plan to finance our growth capital expenditures mainly through additional forms of debt or equity financing, as well as proceeds from the sale of non-core assets.
Changes in natural gas, crude oil, NGL and condensate prices and the terms of our contracts may have a direct impact on our generation and use of cash from operations due to their impact on net income (loss), along with the resulting changes in working capital. In the past, we mitigated a portion of our anticipated commodity price risk associated with the volumes from our gathering and processing activities with fixed price commodity swaps. For additional information regarding our derivative activities, see the information provided under Part II, Item 7A of our 2016 Annual Report on Form 10-K, under the caption, “Quantitative and Qualitative Disclosures about Market Risk” and Part I, Item 3 of the Quarterly Report under the caption “Quantitative and Qualitative Disclosures about Market Risk”.
The counterparties to certain of our commodity swap contracts are investment-grade rated financial institutions. Under these contracts, we may be required to provide collateral to the counterparties in the event that our potential payment exposure exceeds a predetermined collateral threshold. Collateral thresholds are set by us and each counterparty, as applicable, in the master contract that governs our financial transactions based on our and the counterparty’s assessment of creditworthiness. The assessment of our position with respect to the collateral thresholds is determined on a counterparty by counterparty basis, and is impacted by the representative forward price curves and notional quantities under our swap contracts. Due to the interrelation between the representative natural gas and crude oil forward price curves, it is not practical to determine a single pricing point at which our swap contracts will meet the collateral thresholds as we may transact multiple commodities with the same counterparty. Depending on daily commodity prices, the amount of collateral posted can go up or down on a daily basis. As of September 30, 2017, we have not been required to post collateral with our counterparties.
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At-The-Market (“ATM”) Offering
On October 18, 2015, we filed a prospectus supplement related to the offer and sale from time to time of common units in an at-the-market offering. For the quarter ended September 30, 2017, we did not sell any common units under our ATM program and have approximately $96.8 million remaining available for sale under the Partnership’s ATM Equity Offering Sales Agreement.
Our Revolving Credit Facilities
AMID
On March 8, 2017, we entered into the Second Amended and Restated Credit Agreement, with Bank of America N.A., as Administrative Agent, Collateral Agent and L/C Issuer, Wells Fargo Bank, National Association, as Syndication Agent, and other lenders or Credit Agreement, which increased our borrowing capacity from $750.0 million to $900.0 million and provided for an accordion feature that will permit, subject to customary conditions, the borrowing capacity under the facility to be increased to a maximum of $1.1 billion.
On September 30, 2016, in connection with the Note Purchase Agreement (as defined below), we entered into the Limited Waiver and Third Amendment to the Credit Agreement, which among other things, (i) allows Midla Holdings (as defined below), for so long as the 3.77% Senior Notes are outstanding, to be excluded from guaranteeing the obligations under the Credit Agreement and being subject to certain covenants thereunder, (ii) releases the lien granted under the original credit agreement on D-Day’s equity interests in FPS Equity, and (iii) deems the FPS Equity excluded property under the Credit Agreement. All other terms under the Credit Agreement remain the same.
For the nine months ended September 30, 2017 and 2016, the weighted average interest rate on borrowings under our Credit Agreement and the JPE Revolver (as defined below) was approximately 4.85% and 2.82%, respectively. At September 30, 2017 and December 31, 2016, letters of credit outstanding under the Credit Agreement were $33.1 million and $7.4 million, respectively. As of September 30, 2017, we had approximately $709.7 million of borrowings and $33.1 million of letters of credit outstanding under the Credit Agreement resulting in $157.3 million of available borrowing capacity.
As of September 30, 2017, our consolidated total leverage ratio was 4.68 and our interest coverage ratio was 4.41, which were both in compliance with the related requirements of our Credit Agreement. Our ability to maintain compliance with the leverage and interest coverage ratios included in the Credit Agreement may be subject to, among other things, the timing and success of initiatives we are pursuing, which may include expansion capital projects, acquisitions, or drop down transactions, as well as the associated financing for such initiatives. See Note 13 - Debt Obligations to our condensed consolidated financial statements included in Item 1 of Part I of the Quarterly Report for further discussion of the Credit Agreement.
We use the term “revolving credit facility” or “Credit Agreement,” to refer to our First Amended and Restated Credit Facility and to our Second Amended and Restated Credit Facility, as the context may require.
JPE Revolver
JPE had a $275.0 million revolving loan, which included a sub-limit of up to $100.0 million for letters of credit with Bank of America, N.A. (the “JPE Revolver”). The JPE Revolver was scheduled to mature on February 12, 2019, but on March 8, 2017, in connection with the closing of the JPE acquisition, the $199.5 million outstanding balance of the JPE Revolver was paid off in full and terminated. For the nine months ended September 30, 2016, the weighted average interest rate on borrowings under the JPE Revolver was approximately 2.82%.
8.50% Senior Unsecured Notes
On December 28, 2016, the Issuers completed the issuance and sale of the $300 million 8.50% Senior Notes. The 8.50% Senior Notes rank equal in right of payment with all existing and future senior indebtedness of the Issuers, and senior in right of payment to any future subordinated indebtedness of the Issuers. The 8.50% Senior Notes were issued at par and provided approximately $294.0 million in proceeds, after deducting the initial purchasers' discount of $6.0 million. This amount was deposited into escrow pending completion of the JPE Acquisition and is included in Restricted cash-long term on our unaudited consolidated balance sheet as of December 31, 2016.
We also incurred $2.7 million of debt issuance costs resulting in net proceeds related to the 8.50% Senior Notes of $291.3 million. The 8.50% Senior notes were offered and sold to qualified institutional buyers in the United States pursuant to Rule 144A under the Securities Act, and to persons, other than U.S. persons, outside the United States pursuant to Regulation S under the Securities
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Act. Upon the closing of the JPE Acquisition and the satisfaction of other conditions related thereto, the proceeds were used to repay and terminate the JPE Revolver and reduce borrowings under our Credit Agreement.
The 8.50% Senior Notes will mature on December 15, 2021 with interest payable in cash semi-annually in arrears on June 15 and December 15, commencing June 15, 2017. See Note 13 - Debt Obligations to our unaudited condensed consolidated financial statements included in Item 1 of Part I of the Quarterly Report for further discussion of the 8.50% Senior Notes.
3.77% Senior Secured Notes
On September 30, 2016, Midla Financing (“Midla Financing”) American Midstream (Midla) LLC (“Midla”), and Mid Louisiana Gas Transmission LLC (“MLGT” and together with Midla, the “Note Guarantors”) entered into the 3.77% Senior Note Purchase and Guaranty Agreement (the “Note Purchase Agreement”) with the purchasers party thereto (the “Purchasers”). Pursuant to the Note Purchase Agreement, Midla Financing issued and sold $60.0 million in aggregate principal amount of 3.77% Senior Notes (non-recourse) due June 30, 2031 (the “3.77% Senior Notes”) to the Purchasers, which bear interest at an annual rate of 3.77% to be paid quarterly. The average quarterly principal payment is approximately $1.1 million. Principal on the 3.77% Senior Notes will be paid on the last business day of each fiscal quarter end which began June 30, 2017. The 3.77% Senior Notes are payable in full on June 30, 2031. The 3.77% Senior Notes were issued at par and provided net proceeds of approximately $49.8 million (after deducting related issuance costs). The proceeds are contractually restricted. The 3.77% Senior Notes are non-recourse to the Partnership.
In connection with the Note Purchase Agreement, the Note Guarantors guaranteed the payment in full of all Midla Financing’s obligations under the Note Purchase Agreement. Also, Midla Financing and the Note Guarantors granted a security interest in substantially all of their tangible and intangible personal property, including the membership interests in each Note Guarantor held by Midla Financing, and Financing Holdings pledged the membership interests in Midla Financing to the Collateral Agent.
Net proceeds from the 3.77% Senior Notes are restricted and have been be used (1) to fund project costs incurred in connection with (a) the construction of the Midla-Natchez Line (b) the retirement of Midla’s existing 1920’s vintage pipeline (c) the move of our Baton Rouge operations to the MLGT system (d) the reconfiguration of the DeSiard compression system and all related ancillary facilities, (2) to pay transaction fees and expenses in connection with the issuance of the 3.77% Senior Notes, and (3) for other general corporate purposes of Midla Financing. See Note 13 - Debt Obligations to our unaudited condensed consolidated financial statements included in Item 1 of Part I of the Quarterly Report on further discussion of the 3.77% Senior Notes.
Acquisition Support and Reimbursement
During the third quarter of 2017, our general partner agreed to provide support of $9.8 million in terms of our support agreement that was executed in conjunction with the JPE Acquisition. The Partnership has utilized the full $25.0 million of support as of September 30, 2017.
Working Capital
Working capital is the amount by which current assets exceed current liabilities and is a measure of our ability to pay our liabilities as they become due. Our working capital requirements are primarily driven by changes in accounts receivable and accounts payable. These changes are impacted by changes in the prices of commodities that we buy and sell. In general, our working capital requirements increase in periods of rising commodity prices and decrease in periods of declining commodity prices. However, our working capital needs do not necessarily change at the same rate as commodity prices because both accounts receivable and accounts payable are impacted by the same commodity prices. In addition, the timing of payments received from our customers or paid to our suppliers can also cause fluctuations in working capital because we settle with most of our larger suppliers and customers on a monthly basis and often near the end of the month. We expect that our future working capital requirements will be impacted by these same factors. Our working capital was $14.9 million at September 30, 2017, compared with a working capital deficit of $16.4 million at December 31, 2016.
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Cash Flows
The following table reflects cash flows for the applicable periods (in thousands):
Nine months ended September 30, | |||||||
2017 | 2016 | ||||||
Net cash provided by (used in): | |||||||
Operating activities | $ | 23,368 | $ | 84,059 | |||
Investing activities | 292,811 | (200,981 | ) | ||||
Financing activities | (315,106 | ) | 121,582 | ||||
Net cash increase in cash and cash equivalents | $ | 1,073 | $ | 4,660 | |||
Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016
Operating Activities. During the nine months ended September 30, 2017, we had $23.4 million of cash provided by operating activities, a decrease of $60.7 million when compared to $84.1 million of cash provided by operating activities in the same period in 2016. The decrease in cash flows from operating activities year-over-year, resulted primarily from a increase in corporate expenses of $23.6 million driven mostly by our transaction and merger related expenses and an increase in interest expense of $26.3 million driven by our higher borrowings and higher operating costs of $3 million related primarily to our newly acquired assets.,
Investing Activities. During the nine months ended September 30, 2017, net cash provided by investing activities was $292.8 million, an increase of $493.8 million as compared to net cash used in investing activities of $201.0 million in the same period of 2016. The increase of cash flows from investing activities resulted primarily from the release of $302.7 million in restricted cash in March 2017 that was recorded since the end of 2016 and held in escrow and the proceeds of $168.0 million from the sale of our Propane Business, net of cash on hand, partially offset by a cash outflow related to increased acquisitions as compared to the nine months ended September 30, 2016.
Financing Activities. During the nine months ended September 30, 2017, net cash used in financing activities was $315.1 million, a decrease of $436.7 million as compared to net cash provided by financing activities of $121.6 million in the same period in 2016. The decrease in cash flows from financing activities was due primarily to the additional pay downs on our Credit Agreement of $373.8 million and distributions to our General Partner from our common control transactions associated with Delta House for $75.5 million partially offset by $38.3 million related to General Partner’s contributions.
Distribution to our unitholders
In the nine months ended September 30, 2017, we paid a total of approximately $89.0 million of distributions to our unitholders. This was made possible primarily by $23.4 million of cash generated from operating activities, plus $38.2 million of support from our general partner and approximately $9.1 million of distributions relating to our unconsolidated affiliates return of capital.
Off-Balance Sheet Arrangements
We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. At September 30, 2017, our material off-balance sheet arrangements and transactions included operating lease arrangements and service contracts. There are no other transactions, arrangements, or other relationships associated with our investments in unconsolidated affiliates or related parties that are reasonably likely to materially affect our liquidity or availability of, or requirements for, capital resources. At September 30, 2017, our off-balance sheet arrangements totaled $34.9 million.
Capital Requirements
The energy business is capital intensive, requiring significant investment for the maintenance of existing assets and the acquisition and development of new systems and facilities. We categorize our capital expenditures as either:
• | maintenance capital expenditures, which are cash expenditures (including expenditures for the addition or improvement to, or the replacement of, our capital assets) made to maintain our operating income or operating capacity; or |
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• | expansion capital expenditures, incurred for acquisitions of capital assets or capital improvements that we expect will increase our operating income or operating capacity over the long term. |
Historically, our maintenance capital expenditures have not included all capital expenditures required to maintain volumes on our systems. It is customary in the regions in which we operate for producers to bear the cost of well connections, but we cannot be assured that this will be the case in the future. Although we classified our capital expenditures as expansion and maintenance, we believe those classifications approximate, but do not necessarily correspond to, the definitions of estimated maintenance capital expenditures and expansion capital expenditures under our Partnership Agreement.
For the three months ended September 30, 2017, capital expenditures totaled $20.7 million, including expansion capital expenditures of $18.2 million, maintenance capital expenditures of $2.4 million and reimbursable project expenditures (capital expenditures for which we expect to be reimbursed for all or part of the expenditures by a third party) of $0.1 million. For the nine months ended September 30, 2017, capital expenditures totaled $65.0 million, including expansion capital expenditures of $55.9 million, maintenance capital expenditures of $6.6 million and reimbursable project expenditures (capital expenditures for which we expect to be reimbursed for all or part of the expenditures by a third party) of $2.6 million. Of these capital expenditures amounts, $0.7 million and $3.1 million were incurred for the Propane Business that we disposed on September 1, 2017, as discussed in Note 4 - Dispositions.
Distributions
We intend to pay a quarterly distribution for the foreseeable future although we do not have a legal obligation to make distributions except as provided in our Partnership Agreement.
On October 26, 2017, we announced that the Board of Directors of our General Partner declared a quarterly cash distribution of $0.4125 per common unit for the quarter ended September 30, 2017, or $1.65 per common unit on an annualized basis. The cash distribution is expected to be paid on November 14, 2017, to unitholders of record as of the close of business on November 7, 2017.
Critical Accounting Estimates
There were no changes to our critical accounting estimates from those disclosed in our Recast Form 8-K.
Recent Accounting Pronouncements
For information regarding new accounting policies or updates to existing accounting policies as a result of new accounting pronouncements, refer to Note 2 - New Accounting Pronouncements in Part I, Item 1 of the Quarterly Report, which is incorporated herein by reference.
PART II. OTHER INFORMATION
Item 6. Exhibits
Exhibit Number | Exhibit Description | |
31.1* | Certification of Lynn L. Bourdon III, President and Chief Executive Officer of American Midstream GP, LLC, the General Partner of American Midstream Partners, LP. | |
31.2* | Certification of Eric T. Kalamaras, Senior Vice President & Chief Financial Officer of American Midstream GP, LLC, the General Partner of American Midstream Partners, LP. | |
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this Amendment No. 1 to Quarterly Report on Form 10-Q/A to be signed on its behalf by the undersigned thereunto duly authorized.
Date: December 12, 2017
AMERICAN MIDSTREAM PARTNERS, LP | |
By: | American Midstream GP, LLC, its General Partner |
By: | /s/ Lynn L. Bourdon III |
Lynn L. Bourdon III | |
Chairman, President and Chief Executive Officer | |
(Principal Executive Officer) | |
By: | /s/ Eric T. Kalamaras |
Eric T. Kalamaras | |
Senior Vice President and Chief Financial Officer | |
(Principal Financial Officer) | |
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