Document
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
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x | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
| For the fiscal year ended December 31, 2017 |
Or
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o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
| For the transition period from to |
Commission File Number: 001-35257
AMERICAN MIDSTREAM PARTNERS, LP
(Exact name of registrant as specified in its charter)
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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, Texas | | 77042 |
(Address of principal executive offices) | | (Zip code) |
(346) 241-3400(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
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Title of Each Class | | Name of Each Exchange on Which Registered |
Common Units Representing Limited Partnership Interests | | New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No x
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No x
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained in, to the best of the registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer," "non-accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.
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Large accelerated filer | | o | | Accelerated filer | | x |
Non-accelerated filer | | o (Do not check if a smaller reporting company) | | Smaller reporting company | | o |
| | | | Emerging growth company | | o |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act): Yes o No x
The aggregate market value of common units held by non-affiliates of the registrant on June 30, 2017, was $481,090,495. The aggregate market value was computed by reference to the closing price of the registrant's common units on the New York Stock Exchange on June 30, 2017.
There were 52,852,752 common units, 11,009,729 Series A Units and 9,241,642 Series C Units of American Midstream Partners, LP outstanding as of March 26, 2018. Our common units trade on the New York Stock Exchange under the ticker symbol "AMID."
Documents Incorporated by Reference: None.
TABLE OF CONTENTS
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PART I | |
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1 | | |
1A | | |
1B | | |
2 | | |
3 | | |
4 | | |
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PART II | |
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5 | | |
6 | | |
7 | | |
7A | | |
8 | | |
9 | | |
9A | | |
9B | | |
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PART III | |
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10 | | |
11 | | |
12 | | |
13 | | |
14 | | |
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PART IV | |
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15 | | |
16 | | |
CAUTIONARY STATEMENT ABOUT 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" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. You can typically identify forward-looking statements by the use of 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. These risks and uncertainties, many of which are beyond our control, include, but are not limited to, the risks set forth in Item 1A - Risk Factors of this Annual Report on Form 10-K (the "Annual Report") as well as the following risks and uncertainties:
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• | our ability to obtain financing required to complete the SXE Merger (as defined herein) or to obtain financing on terms other than those currently anticipated; |
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• | our ability to complete the SXE Transactions (as defined herein) in a timely manner or at all, and to successfully integrate the operations of SXE; |
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• | dispositions of assets owned by us or SXE prior to or following the completion of the SXE Merger, which assets may have been material to us or SXE; |
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• | the outcome of any legal proceedings related to the SXE Merger; |
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• | greater than expected operating costs, customer loss and business disruption following the SXE Merger, including difficulties in maintaining relationships with employees; |
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• | diversion of management time on SXE Transactions-related issues; |
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• | our ability to timely and successfully identify, consummate and integrate our current and future acquisitions (including the SXE Transactions) and complete strategic dispositions, including the realization of all anticipated benefits of any such transaction, which otherwise could negatively impact our future financial performance; |
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• | our ability to maintain compliance with financial covenants and ratios in our revolving credit facility; |
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• | our ability to generate sufficient cash from operations to pay distributions to unitholders; |
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• | 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; |
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• | the demand for natural gas, refined products, condensate or crude oil and NGL products by the petrochemical, refining or other industries; |
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• | the performance of certain of our current and future projects and unconsolidated affiliates that we do not control and disruptions to cash flows from our joint ventures due to operational or other issues that our beyond our control; |
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• | 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; |
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• | security threats such as terrorist attacks, and cybersecurity breaches, against, or otherwise impacting, our facilities and systems; |
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• | general economic, market and business conditions, including industry changes and the impact of consolidations and changes in competition; |
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• | the level of creditworthiness of counterparties to transactions; |
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• | the amount of collateral required to be posted from time to time in our transactions. |
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• | 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 timing and extent of changes in natural gas, crude oil, NGLs and other commodity prices, interest rates and demand for our services; |
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• | our success in risk management activities, including the use of derivative financial instruments to hedge commodity and interest rate risks; |
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• | our dependence on a relatively small number of customers for a significant portion of our gross margin; |
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• | our ability to renew our gathering, processing, transportation and terminal contracts; |
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• | our ability to successfully balance our purchases and sales of natural gas; |
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• | our ability to grow through contributions from affiliates, acquisitions or internal growth projects; |
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• | the cost and effectiveness of our remediation efforts with respect to the material weaknesses discussed in Part II, Item 9A - Controls and Procedures of this Annual Report; and |
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• | costs associated with compliance with environmental, health and safety and pipeline regulations; |
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 Annual Report will prove to be accurate. Some of these and other risks and uncertainties that could cause actual results to differ materially from such forward-looking statements are more fully described in Item 1A - Risk Factors of this Annual Report. Statements in this Annual Report speak as of the date of this Annual Report. Except as may be required by applicable securities laws, we undertake no obligation to publicly update or advise investors of any change in any forward-looking statement, whether as a result of new information, future events or otherwise.
GLOSSARY OF TERMS
As generally used in the energy industry and in this Annual Report, the identified terms have the following meanings:
Bbl Barrels: 42 U.S. gallons measured at 60 degrees Fahrenheit.
Bbl/d Barrels per day.
Bcf Billion cubic feet.
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Btu | British thermal unit; the approximate amount of heat required to raise the temperature of one pound of water by one degree Fahrenheit. |
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Condensate | Liquid hydrocarbons present in casinghead gas that condense within the gathering system and are removed prior to delivery to the natural gas plant. This product is generally sold on terms more closely tied to crude oil pricing. |
/d Per day.
FERC Federal Energy Regulatory Commission.
Fractionation Process by which natural gas liquids are separated into individual components.
GAAP Generally Accepted Accounting Principles in the United States of America.
Gal Gallons.
Mgal/d Million gallons per day.
MBbl Thousand barrels.
MMBbl Million barrels.
MBbl/d Thousand barrels per day.
MMBbl/d Million barrels per day.
MMBtu Million British thermal units.
Mcf Thousand cubic feet.
MMcf Million cubic feet.
MMcf/d Million cubic feet per day.
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NGL or NGLs | Natural gas liquid(s): The combination of ethane, propane, normal butane, isobutane and natural gasoline that, when removed from natural gas, become liquid under various levels of higher pressure and lower temperature. |
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Throughput | The volume of natural gas, NGLs, crude oil, and refined products transported or passing through a pipeline, plant, terminal or other facility during a particular period. |
As used in this Annual Report, unless the context otherwise requires, "we," "us," "our," the "Partnership" and similar terms refer to American Midstream Partners LP, together with its consolidated subsidiaries. References in this Annual Report to our "General Partner" refer to American Midstream GP, LLC.
PART I
Item 1. Business
Overview
American Midstream Partners, LP is 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 reportable 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 and storing specialty chemical products and refined products. As of September 1, 2017, as a result of the disposition of the Propane Marketing Services business ("Propane Business") described in Note 4 - Discontinued Operations, in Part II, Item 8 of this Annual Report, 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, (iv) the Bakken Shale of North Dakota and (v) 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, Arkansas, 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 for more information about our recent acquisitions and dispositions.
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, seven 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 active transportation trucks and a total trailer fleet of 130, of which 35 are Liquefied Petroleum Gas ("LPG") trailers and 95 are crude oil trailers.
A portion of our cash flow is derived from our investments in unconsolidated affiliates, including a 66.67% operated interest in Destin Pipeline Company, L.L.C. (“Destin”), a natural gas pipeline; a 35.7% non-operated interest in the Class A units of Delta House FPS LLC ("FPS") and of Delta House Oil and Gas Lateral LLC ("Lateral") (collectively referred to herein as "Delta House"), which is a floating production system platform and related pipeline infrastructure; a 16.7% non-operated interest in Tri-States NGL Pipeline, L.L.C. ("Tri-States"), an NGL pipeline; a 66.7% operated interest in Okeanos Gas Gathering Company, LLC ("Okeanos"), a natural gas pipeline; and a 25.3% non-operated interest in Wilprise Pipeline Company, L.L.C. (“Wilprise”), a NGL pipeline.
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 NGLs, 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.
Recent Developments
In 2017, we completed the following acquisitions and dispositions:
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• | On March 8, 2017, we completed the acquisition of JP Energy Partners LP (“JPE”), an entity controlled by affiliates of ArcLight Capital Partners, LLC (“ArcLight”), in a unit-for-unit merger (the “JPE Merger”). In connection with the transaction, each JPE common or subordinated unit held by investors not affiliated with ArcLight was converted into the right to receive 0.5775 of a Partnership common unit, and each JPE common or subordinated unit held by ArcLight affiliates was converted into the right to receive 0.5225 of a Partnership common unit. We issued a total of 20.2 million of our common units to complete the acquisition, including 9.8 million common units to ArcLight affiliates. |
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• | On June 2, 2017, we acquired 100% of the Viosca Knoll Gathering System (“VKGS”) from Genesis Energy, L.P. for total consideration of approximately $32 million in cash. |
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• | On August 8, 2017, we acquired 100% of the interest in Panther Offshore Gathering Systems, LLC (“POGS”), Panther Pipeline, LLC (“PPL”) and Panther Operating Company, LLC (“POC” and, together with POGS and PPL, “Panther”) from Panther Asset Management LLC (“Panther Asset Management”) for approximately $60.9 million. The consideration included $39.1 million cash, funded from borrowings under our revolving credit facility, and the issuance of common units, valued at $12.5 million based on unit value as of the acquisition date. |
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• | On September 1, 2017, we completed the disposition of our Propane Business pursuant to the Membership Interest Purchase Agreement dated July 21, 2017, between our wholly-owned subsidiary AMID Merger LP, and SHV Energy N.V. |
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• | On September 29, 2017, we acquired an additional 15.5% equity interest in Class A units of Delta House from affiliates of ArcLight for total cash consideration of approximately $125.4 million. |
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• | On October 27, 2017, our wholly-owned subsidiary, American Midstream Emerald, LLC, entered into a Purchase and Sale Agreement with Emerald Midstream, LLC, an ArcLight affiliate, to purchase an additional 17.0% equity interest in Destin for total consideration of $30.0 million. With the acquisition, we now own a 66.67% interest in Destin. |
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• | On November 6, 2017, we acquired 100% of the equity interests in Trans-Union Interstate Pipeline, LP (“Trans-Union”) from affiliates of ArcLight, for a total consideration of approximately $49.4 million. The consideration consisted of approximately $16.9 million cash funded from borrowings under our revolving credit facility and the assumption of $32.5 million of non-recourse debt. |
See Note 3 - Acquisitions, Note 4 - Discontinued Operations and Note 25 - Subsequent Events in Part II, Item 8 of this Annual Report for additional information.
Pending 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.
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 canceled 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 canceled 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” and together with the SXE Merger, the “SXE Transactions”). A portion of the consideration will be 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.
As disclosed in the Registration statement on Form S-4, as filed with the Securities and Exchange Commission ("SEC") on January 11, 2018, the SXE Merger has a total aggregate consideration of $817.9 million, including a total assumed debt of $644.6 million.
Other developments
In the fourth quarter of 2017, we were notified by the operator of Delta House FPS that certain third party-owned upstream infrastructure would require remedial work, resulting in a temporary delay of production volumes flowing into Delta House. This remediation is scheduled to be completed later in the second quarter of 2018, at which time full production is anticipated to resume flowing into Delta House. This has resulted in a reduction in cash distributions from Delta House, including those attributable to our 35.7% interest, during the curtailment.
On March 11, 2018, we and Magnolia Infrastructure Holdings, LLC ("Magnolia"), an affiliate of ArcLight, entered into a Capital Contribution Agreement to provide additional capital and corporate overhead support to us during the first three quarters of 2018 in connection with temporary curtailment of production flows at Delta House. Pursuant to the agreement, Magnolia has agreed to provide support to us in an amount to be agreed, up to the difference between the actual cash distribution received by us on account of our interest in Delta House and the quarterly cash distribution expected to be received if production flows to Delta House had not been not curtailed.
On February 16, 2018, we announced the sale of the Refined Products Terminals (the "Refined Products Business") consisting of two terminal facilities, located in Caddo Mills, Texas ("Caddo Mills") and North Little Rock, Arkansas ("NLR"), to DKGP Energy Terminals LLC, a joint venture between Delek Logistics Partners, LP and Green Plains Partners LP, for approximately $138.5 million in cash, subject to working capital adjustments. Closing of the sale of the Refined Products Business is subject to customary closing conditions, including clearance under the Hart-Scott-Rodino Act. The transaction is expected to close in the first half of 2018.
Market Conditions
Average daily prices for New York Mercantile Exchange ("NYMEX") West Texas Intermediate ("WTI") crude oil ranged from a high of $66.27 per barrel to a low of $42.48 per barrel from January 1, 2017 through March 26, 2018. Average daily prices for NYMEX Henry Hub natural gas ranged from a high of $6.24 per MMBtu to a low of $2.44 per MMBtu from January 1, 2017 through March 26, 2018.
Fluctuations in energy prices can greatly affect the development of new crude oil and natural gas reserves. Further increases in commodity prices of crude oil and natural gas, as observed through the later part of 2017, could have a positive impact on exploration, development and production activity, and, if sustained, could lead to a material increase in such activity. Sustained expansion or reductions in exploration or production activity in our areas of operation would lead to continued or further increased or 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.
Business Strategies
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 on a per unit basis. 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.
Utilize our strategically located and integrated assets to maximize value for our customers. We own and operate a portfolio of midstream assets strategically located in some of the most prolific natural gas and crude oil producing regions and key demand markets in the United States and offshore in the Gulf of Mexico. Through our diversified and integrated asset base, we provide critical infrastructure that links producers of natural gas, crude oil, NGLs, condensate and specialty chemicals to numerous intermediate and end-use markets while allowing us to generate revenue and service the same energy molecules at various stages along the midstream value chain.
Enhance existing assets and realize operating efficiencies. We intend to enhance the profitability of our assets by increasing utilization, realizing operating efficiencies and providing additional midstream services desired by our customers. We continually seek to attract new volumes from existing and new customers through superior customer service and asset optimization. In addition, we expect to be able to provide additional midstream services to our customers by cross-selling complementary services. For example, we intend to leverage our crude oil and NGL trucking capabilities across our onshore gathering and processing footprint and expand our service offering in the Permian Basin and Cotton Valley/Haynesville Shale. We can accommodate additional volumes at minimal incremental cost, which provides highly attractive economics.
Capitalize on organic growth opportunities. We continually seek to identify and evaluate economically attractive organic expansion opportunities that leverage our asset footprint and strategic relationships with our customers. These organic projects include new interconnects, repurposing underutilized assets and adding additional capacity to meet increased demand from our customers.
Pursue accretive acquisitions. We plan to pursue accretive acquisitions of complementary midstream assets that will allow us to increase market share and density in our core operating areas and realize operational efficiencies and commercial synergies. Future acquisition opportunities may include bolt-on acquisitions within our asset footprint, consolidation of third party interests in our joint ventures and strategic acquisitions. Our partnership with ArcLight may present us with future drop-down opportunities and the ability to jointly pursue third party acquisitions that may not otherwise be feasible on a stand-alone basis.
Maintain focus on stable, fee-based and fixed-margin cash flow with minimal direct exposure to commodity prices. We seek to minimize our direct commodity price exposure and maintain stable cash flow by generating a substantial portion of our total gross margin pursuant to fee-based and fixed-margin contracts. We have been successful executing on this strategy and have increased the percentage of gross margin generated from fee-based and fixed-margin contracts for the fiscal years ended December 31, 2017 and 2016, respectively.
Maintain a conservative and flexible capital structure. We plan to pursue a disciplined financial policy and maintain a conservative capital structure to allow us to pursue additional organic growth projects and acquisitions, with a conservative mix of debt and equity, even in challenging market environments.
Competitive Strengths
We believe we are well-positioned to successfully execute our strategy because of the following competitive strengths:
Stable and predictable cash flows supported by fee-based and fixed-margin contracts. Substantially all of our transmission and terminal assets are contracted on a firm transportation or take-or-pay basis and a majority of our offshore assets are contracted under long-term, life-of-lease dedications. We believe that the nature of our contracts minimizes our direct commodity price exposure and enhances the stability of our business and the predictability of our financial performance.
Diversified and strategically located portfolio of midstream assets. Our assets are diversified geographically and by business line, which contribute to the stability of our cash flows. We operate throughout many of the most prolific crude oil and natural gas producing regions in the United States and offshore Gulf of Mexico. We have access to multiple sources of crude oil, natural gas and liquids and are in close proximity to various interstate and intrastate pipelines as well as utility, industrial and other commercial end users. Our diverse and creditworthy customer base includes several large producers, refiners and marketers.
Significant scale and capability. As of December 31, 2017, after giving effect to the JPE Merger and other acquisitions, we have approximately $1.9 billion in total assets across the midstream value chain providing onshore and offshore crude oil and natural gas gathering, processing, transmission and storage as well as hydrocarbon and refined product terminal assets and NGL fractionation, distribution and sales. Following the closing of the JPE Merger, we own or have an ownership interest in approximately 5,100 miles of onshore and offshore natural gas, crude oil, NGL and saltwater pipelines across 17 gathering systems, seven interstate pipelines and nine intrastate pipelines; eight natural gas processing plants; four fractionation facilities; an offshore semi-submersible 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 storage capacity; and 90 transportation trucks and a total trailer fleet of 130, of which 35 are LPG trailers and 95 are crude oil trailers. We believe our size, scale and capabilities enhance our ability to serve our customers and provide financial flexibility and an increased ability to access the capital markets.
Strategically located offshore position with high barriers to entry. We have a substantial footprint in the deepwater Gulf of Mexico with our ownership interest in the Delta House platform and associated assets. This state-of-the-art floating, production and storage facility is located in one of the most active parts of the deep-water Gulf of Mexico and we have well-established relationships and long-term agreements with key participants along the entire value chain in the region. We believe producers in the areas of the Gulf of Mexico in which we operate are motivated to connect their production to our existing pipelines as construction of new pipelines is often not feasible due to cost and timing considerations. In addition, we have acquired additional strategic assets that provide us with substantial operational flexibility including multiple delivery and offload points as we move hydrocarbons from source to market, allowing us to provide a valuable and differentiated service to our customers.
Relationship with ArcLight. Our relationship with ArcLight provides us with access to ArcLight’s extensive operational and commercial expertise. ArcLight indirectly owns 48.6% of our limited partner interests and 100% of the IDRs. We believe that ArcLight is economically incentivized to promote and support our business plan and to pursue projects that enhance the overall value of our business.
Experienced management and operational teams. Our executive management team has an average of approximately 20 years of experience in the midstream energy industry. The team possesses a comprehensive skill set to support our business and execute our business strategy through asset optimization, accretive development projects and acquisitions.
Our Segments
AMID manages its business under five distinct operating segments: Gas Gathering and Processing Services, Liquid Pipelines and Services, Natural Gas Transportation Services, Offshore Pipelines and Services and Terminalling Services. Each segment is explained below along with description of the assets that support each of those segments.
Gas Gathering and Processing (G&P) 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 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 II, Item 7A of this Report under the caption - Quantitative and Qualitative Disclosures about Market Risk - Commodity Price Risk.
Our Gas Gathering and Processing Services assets are located in Alabama, Louisiana, Mississippi, and Texas and in shallow state and federal waters in the Gulf of Mexico off the coast of Louisiana and are positioned in areas with opportunities for organic growth. We continually seek new sources of raw natural gas and crude oil supply to maintain and increase the throughput volume on our gathering systems and through our processing plants.
We generally derive revenue in our Gas Gathering and Processing Services segment from fee-based, fixed-margin and POP arrangements, for our producer and supplier customers and our own account. For the year ended December 31, 2017, our fee-based, fixed-margin arrangements and our POP arrangements accounted for approximately 59.1% and 40.9%, respectively, of our segment gross margin for the Gathering and Processing Services segment.
In our G&P segment, we have the following assets:
Lavaca System
The Lavaca System consists of 203 miles of high and low-pressure pipelines ranging from four to 12 inches in diameter with 24,960 horsepower of leased compression, 3,215 horsepower of owned compression and associated facilities located in the Eagle Ford shale in Gonzales and Lavaca Counties, Texas. The Lavaca System currently has a design capacity of approximately 218 MMcf/d. Natural gas production gathered by the system is compressed and delivered to a third-party for processing or redelivered to producers for gas lift.
Longview System
The Longview gathering and processing system consists of approximately 620 miles of high and low pressure gathering lines with diameters ranging from two to twenty inches with a combined compression capacity of 19,980 horsepower. Our Longview System also contains two cryogenic processing plants with a design capacity of approximately 50 MMcf/d, one fractionation unit with 8,500 Bbls/d of capacity, product storage tanks, and truck racks to receive off-spec NGLs and condensate. The Longview System is located near Longview in Gregg County, Texas. Located adjacent to the Longview System is a rail facility designed to receive and deliver NGLs and condensate which commenced operations in the first quarter of 2016.
Chapel Hill System
The Chapel Hill gathering and processing system consists of approximately 90 miles of gathering lines with a combined compression capacity of 2,540 horsepower. Our Chapel Hill System also contains a cryogenic processing plant with a design capacity of approximately 20 MMcf/d, one fractionation unit with 1,250 Bbls/d of capacity, product storage tanks, and truck racks to deliver propane, butane, and natural gasoline. The Chapel Hill System is located near Tyler in Smith County, Texas.
Yellow Rose System
The Yellow Rose gathering and processing system consists of approximately 47 miles of high and low-pressure pipelines, a rich-gas gathering system and a 40 MMcf/d cryogenic processing plant, with pipeline takeaway for residue gas and liquids. The Yellow Rose System is located in the Permian Basin in Martin, Andrews, and Dawson counties, Texas.
Chatom System
The Chatom System consists of a 25 MMcf/d refrigeration processing plant, a 1,600 Bbl/d fractionation unit, a 160 long-ton per day sulfur recovery unit, and a 24-mile gas gathering system and compression capacity of 3,456 horsepower. The system is located in Washington County, Alabama, approximately 15 miles from our Bazor Ridge processing plant in Wayne County, Mississippi. The Chatom System gathers natural gas from onshore crude oil and natural gas wells in the Norphlet and Smackover formations in Alabama and Mississippi. Chatom also has a truck rack and the capability to receive and fractionate NGLs.
Bazor Ridge System
The Bazor Ridge gathering and processing system consists of approximately 169 miles of pipeline, with diameters ranging from three to eight inches, and three compressor stations with a combined compression capacity of 1,069 horsepower. Our Bazor Ridge System is located in Jasper, Clarke, Wayne and Greene counties of Mississippi. The Bazor Ridge System also contains an idled sour natural gas treating and cryogenic processing plant located in Wayne County, Mississippi, with a design capacity of approximately 22 MMcf/d as well as four inlets and one discharge compressor with approximately 5,218 of combined horsepower. The natural gas supply for our Bazor Ridge System is derived primarily from rich natural gas produced from crude oil wells targeting the mature Upper Smackover formation. Since 2016, the Bazor Ridge facility has been exclusively used as a central gathering and compression facility and processing has been re-routed to the Chatom System.
Glade Crossing
The Glade Crossing processing facility consists of a refrigeration unit, amine plant, and dehydration equipment with a design capacity of 5 MMcf/d. The facility is located near Laurel in Jones County, Mississippi.
Burns Point
Burns Point Plant is a cryogenic processing plant with a design capacity of 165 MMcf/d that is jointly owned by us and the plant operator, Enterprise Gas Processing, LLC ("Enterprise"). We hold a 50% undivided, non-operated interest in the Burns Point Plant. We acquired an interest in the asset group and not in a legal entity. We and Enterprise are proportionately liable for the liabilities. Outside of the rights and responsibilities of the operator, we and Enterprise have equal rights and obligations to the assets. Significant non-capital and maintenance capital expenditures, plant expansions and significant plant dispositions require the approval of both owners. The plant has been shut down since December 2017 due to maintenance issues.
Offshore Texas System
The Offshore Texas System consists of the GIGS and Brazos systems, which have approximately 56 miles of pipeline with diameters ranging from six to sixteen inches and a design capacity of approximately 100 MMcf/d. The Offshore Texas System is in a position to provide gathering and dehydration services to natural gas producers in the shallow waters of the Gulf of Mexico offshore Texas. Since 2016, the offshore pipe on both systems was abandoned, and the onshore pipe was out of service.
Mesquite
We own a 48.4% non-operated interest in Mesquite, a collaborative arrangement with EnLink Midstream located near Midland, Texas. The Mesquite facility includes a rail terminal and 5,000 Bbl/d fractionation unit that facilitates the receipt, treatment and sale of off-spec condensate and NGLs via pipeline, truck and rail.
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, pursuant to the agreement with the shipper, we 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 or commodity 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.
Following are brief descriptions of the assets that make up the Liquid Pipelines and Services segment:
Bakken System
The Bakken crude oil gathering pipeline system consists of a 43-mile pipeline with capacity to transport up to approximately 40,000 Bbls/d of crude oil to the Tesoro Logistics pipeline located Northeast of Watford City, North Dakota and a planned interconnect with the Energy Transfer Dakota Access Pipeline. The system, which commenced operations in October 2015, provides producers in the area with access to refinery, rail and pipeline markets. The system also has the capability to receive volumes through its truck rack, which also commenced operations in November 2015.
Silver Dollar Pipeline
The Silver Dollar Pipeline is located in the Permian basin and with capacity to transport approximately 130,000 Bbls/d of crude oil. The pipeline was constructed in 2013.
Crude Oil Supply and Logistics (COSL) and AMID Liquids Trucking
Our Marketing business operates around both crude pipeline assets and trucking hubs. We buy and sell crude in North Dakota and Texas to facilitate movements on our pipelines. We operate crude oil trucks in the West Texas, South Texas and the Texas Panhandle. We have a fleet of over 75 crude oil trucks as well as 20 NGL trucks that assist our marketing efforts.
Other Systems
Tri-States, Cayenne and Wilprise are also part of the Liquid Pipelines and Services segment and are listed under Investment in Unconsolidated Affiliates below.
Natural Gas Transportation Services Segment
Results of operations from the Natural Gas Transportation Services segment are determined by a capacity reservation charge from firm transportation contracts, a variable-use or commodity charge for 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, pursuant to the agreement with the shipper, we 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 or commodity charge with respect to quantities actually transported by us.
Interruptible Transportation Arrangements. Our obligation to provide interruptible transportation service means that, pursuant to the agreement with the shipper, we only 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 or commodity 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.
Following are brief descriptions of the assets that make up the Natural Gas Transportation Services segment:
Midla and MLGT Systems
Our Midla System is a FERC-regulated interstate natural gas pipeline. On April 16, 2015, the FERC approved the Midla Agreement between Midla and its customers allowing Midla to retire the existing 1920's pipeline, which was comprised of approximately 355 miles of pipeline ranging in diameter from two to 22 inches and linked the Monroe Natural Gas Field in northern Louisiana and interconnections with the Transco Pipeline System to customers in Mississippi and Louisiana, and replace the existing natural gas service with a new 52-mile, high pressure 12-inch pipeline (the Midla-Natchez Line) to serve long-standing residential, commercial, and industrial customers. Under the Midla Agreement, customers not served by the new Midla-Natchez Line were connected to other interstate or intrastate pipelines, other gas distribution systems, or offered conversion to propane service. On June 29, 2015, the Partnership filed for authorization to construct the Midla-Natchez pipeline with the FERC, which was approved on December 17, 2015. Construction commenced in the second quarter of 2016 and service on the Midla-Natchez line began on March 31, 2017. Under the Midla Agreement, Midla executed multiple long-term agreements seeking to recover its investment in the Midla-Natchez Line. As of December 2017, the 1920’s vintage pipeline was inactive.
The Mid Louisiana Gas Transmission LLC (“MLGT”) System is an intrastate transmission system that sources natural gas from interconnects with the Florida Gas Transmission (FGT) Pipeline system, the TETCO Pipeline system, the Transco Pipeline system and the Gulf South Pipeline and delivers to various markets including the city of Baton Rouge utility demand, Louisiana refinery owned and operated by ExxonMobil Corporation, and several other industrial customers. Our MLGT-Baton Rouge System is comprised of approximately 65 miles of pipeline with diameters ranging from three to 16 inches.
The northern portion of the MLGT system, which includes the T-32 lateral that was acquired from Midla in 2017 in conjunction with the FERC approved Midla Agreement, consists of approximately ten miles of high-pressure pipeline with diameters ranging from six to 16 inches. Natural gas on this system is sourced from Tennessee Gas Pipeline and delivered to multiple power plants operated by Entergy. In addition, the ANGUS Chemical facility was connected on the T-32 system in the first half of 2017, increasing the T-32 system load by approximately 7,000 Mcf/d. The entire MLGT System is connected to six receipt and 28 delivery points.
AlaTenn
The AlaTenn System is a FERC-regulated interstate natural gas pipeline that interconnects with three major interstate pipelines and travels west to east delivering natural gas to industrial customers in northwestern Alabama. In addition, the AlaTenn System serves numerous loads via North Alabama Gas District, as well as Alabama municipalities such as the cities of Athens, Hartselle, Sheffield, and Huntsville. Our AlaTenn System has a design capacity of approximately 200 MMcf/d and is comprised of approximately 294 miles of pipeline with diameters ranging from three to 16 inches and includes two compressor stations with combined capacity of 3,665 horsepower. The AlaTenn System is connected to over 60 active delivery and four receipt points, including two interconnects with the Tennessee Gas Pipeline (TGP) system, Texas Eastern Pipeline (TETCO), and the Columbia Gulf Pipeline (CGP). In mid-2017, AlaTenn was connected with the Southern Natural Gas (SONAT) which provides access to new markets.
Bamagas
Our Bamagas System is a Hinshaw intrastate natural gas pipeline that travels west to east from an interconnection point with TGP in Colbert County, Alabama, to two power plants in Morgan County, Alabama. The Bamagas System consists of 52 miles of high-pressure, 30-inch pipeline with a design capacity of approximately 450 MMcf/d. Currently, 100% of the throughput on this system is contracted under long-term firm transportation agreements.
Trigas
Our Trigas System is located in three counties in northwestern Alabama and has design capacity of approximately 60 MMcf/d. Our Trigas System currently serves primarily industrial loads.
Magnolia System
The Magnolia system is a Section 311 intrastate pipeline that transports coal-bed methane and receives natural gas from other sources. It is located in Tuscaloosa, Greene, Bibb, Chilton and Hale counties of Alabama and delivers this natural gas to an interconnect with the Transcontinental Gas Pipe Line Co. pipeline system (Transco), an interstate pipeline owned by The Williams Companies, Inc. The Magnolia System consists of approximately 118 miles of pipeline and trunk lines ranging from six to 24 inches in diameter and four compressor stations with 4,413 horsepower.
Trans-Union
Trans-Union is a 42-mile, 30-inch diameter high-pressure FERC-regulated natural gas interstate pipeline with 546,000 MMbtu/day of maximum capacity.
Offshore Pipelines and Services Segment
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, pursuant to the agreement with the shipper, we 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, pursuant to the agreement with the shipper, we only 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.
Following are brief descriptions of the assets that make up the Offshore Pipelines and Services segment:
High Point System
The High Point System consists of natural gas and liquids pipeline assets located in southeast Louisiana and the shallow water and deep shelf Gulf of Mexico. The High Point System gathers natural gas from both onshore and offshore producing regions around southeast Louisiana. The onshore footprint is in Plaquemines and St. Bernard Parish, Louisiana. The offshore footprint consists of the following federal Gulf of Mexico zones: Mississippi Canyon, Viosca Knoll, West Delta, Main Pass, South Pass and Breton Sound. Natural gas is collected at more than 63 receipt points that connect to hundreds of wells targeting various geological zones in water depths up to 1,000 feet, with an emphasis on crude oil and liquids-rich reservoirs. The High Point System
is comprised of FERC-regulated transmission assets and non-jurisdictional gathering assets, both of which accept natural gas from well production and interconnected pipeline systems. The High Point System delivers the natural gas to the Toca Gas Processing Plant, which is operated by Enterprise, where the products are processed and the residue gas is sent to an unaffiliated interstate system owned by Kinder Morgan Energy Partners. The system also includes VKGS, which was purchased from Genesis Energy in June 2017. VKGS consists of natural gas gathering and crude oil gathering lines of various diameter sizes as well as the platform at VK817.
American Panther System (AmPan)
The American Panther system is comprised of approximately 200 miles of crude oil, natural gas, and salt water onshore and offshore Gulf of Mexico pipelines. The system is located in Southern Louisiana and the Gulf of Mexico and has a natural gas design capacity of 475 MMcf/d and crude oil and saltwater capacity of 27.0 MBbl/d.
Main Pass Oil Gathering System (MPOG)
MPOG is a crude oil gathering system located offshore the Southeast coast of Louisiana in the Gulf of Mexico. The approximately 100-mile system has a total design capacity of approximately 160,000 Bbl/d and is currently operated by our wholly-owned subsidiary, Panther Operating Company, LLC.
Gloria and Lafitte
The Gloria gathering system provides transportation and compression services through our assets, as well as processing services through our elective processing arrangements. The Gloria System is located in Lafourche, Jefferson, Plaquemines, St. Charles and St. Bernard parishes of Louisiana and consists of approximately 138 miles of pipeline, with diameters ranging from three to 16 inches, and four compressors with a combined size of 2,962 horsepower. The Lafitte gathering system consists of approximately 40 miles of gathering pipeline, with diameters ranging from four to 12 inches and a design capacity of approximately 71 MMcf/d. The Lafitte System originates onshore in southern Louisiana and terminates in Plaquemines Parish, Louisiana, at the Alliance Refinery owned by Phillips 66. We are the sole supplier of natural gas to the Alliance Refinery through our Lafitte and Gloria systems. We supply natural gas to the Alliance Refinery pursuant to a long-term contract that expires in 2026.
Quivira
The Quivira gathering system consists of approximately 34 miles of pipeline, with a 12-inch diameter mainline and several laterals ranging in diameter from six to eight inches. The system originates offshore of Iberia and St. Mary parishes of Louisiana in Eugene Island Block 24 and terminates onshore in St. Mary Parish, Louisiana, at a connection with the Burns Point Plant, a cryogenic processing plant.
Chalmette
The Chalmette System is located in St. Bernard Parish, Louisiana. The approximate design capacity for the Chalmette System is 125 MMcf/d.
Other Systems
Delta House, Destin and Okeanos are also part of the Offshore Pipelines and Services segment and are listed under Investments in Unconsolidated Affiliates below.
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 Terminalling Services segment consists of approximately 2.4 million barrels of storage capacity across three marine terminal sites located in Westwego, Louisiana; Brunswick, Georgia; and Harvey, Louisiana and 3.0 million barrels of storage capacity at
Cushing, Oklahoma. Our refined products terminals in North Little Rock, Arkansas and Caddo Mills, TX provide butane blending capabilities.
Following are brief descriptions of the assets that make up the Terminalling Services segment:
Westwego Terminal Operations
The Westwego Terminal site consists of 48 above-ground storage tanks with a combined capacity of 1,044,600 barrels. Our operations support many different commercial customers, including commodity brokers, refiners and chemical manufacturers. Our location within the Port of New Orleans, the warehousing and international distribution attributes this location provides, along with our broad customer base, contributes to the potential diversity of the products customers may want stored in our terminal. The products will generally fall into two broad categories: chemical and agricultural.
Our income from the Westwego Terminal is derived from storage capacity contracts, throughput charges for receipt and delivery of our customers' products; and other services requested by our customers, such as blending services. The terms of our storage capacity contracts range from month-to-month to multiple years, with renewal options.
At the Westwego Terminal, we generally receive our customers' liquid product by river vessel at our Mississippi River dock and by railcar. The product is transferred from the river vessels and railcars to the specified storage tank via the terminal's internal pipeline system. The customer's product is removed from storage at our terminal by truck, railcar and/or water vessel. The length of time that the customer's product is held in storage without transfer varies depending upon the customer's needs.
Brunswick Terminal Operations
The Brunswick Terminal site consists of one 60,000-barrel above-ground storage tank, two 80,000-barrel above-ground storage tanks and two 500-barrel above-ground storage tanks with a combined capacity of 221,000 barrels. The Brunswick Terminal is currently leasing land from the Georgia Ports Authority pursuant to a lease that is in effect until April 2026.
This terminal is ideally suited to serve petroleum, chemical and agricultural customers who need deep-water access and distribution in the southeastern United States. Income from the Brunswick Terminal is derived from storage capacity contracts, throughput charges for receipt and delivery of our customers' products and other services requested by our customers, such as blending services. The terms of our storage capacity contracts will range from month-to-month to multiple years, with renewal options.
At the Brunswick Terminal, we offer product transfer via river vessel, railcar and bulk-liquid carrying truck. At the Brunswick Terminal, the customer's liquid product is received by barge or ship at the dock. The product is transferred from barges or ships to the storage tank via the terminal's internal pipeline system. The customer's product is removed from storage at our terminal by truck or railcar. The length of time that the customer's product is to be held in storage without transfer will vary depending on the customer's needs.
Harvey Terminal Operations
The Harvey Terminal is located on 56 acres on the west bank of the Mississippi River in the Port of New Orleans and equipped to handle a wide variety of petroleum and chemical products. Terminal storage operations at the Harvey Terminal commenced in July 2014 and currently consists of 34 above-ground storage tanks with a combined capacity of approximately 1,135,200 barrels. The Harvey Terminal is a full-service storage site, including 3,000 feet of rail track that can accommodate up to 50 cars and a two bay semi-automated truck loading facility. At the Harvey Terminal, we generally receive our customers' liquid product by river vessel at our Mississippi River dock and by railcar. The product is transferred from the river vessels and railcars to the specified storage tank via the terminal's internal pipeline system. The customer's product is removed from storage at our terminal by truck, railcar and/or water vessel. When fully developed, the Harvey Terminal has the potential to provide more than 2 million barrels of storage capacity.
Cushing
Our crude oil storage facility in Cushing, Oklahoma has an aggregate shell capacity of approximately 3.0 million barrels. We generate crude oil storage revenues by charging customers a fixed monthly fee per barrel of shell capacity that is not contingent on the customer's actual usage of our storage tanks, i.e., take-or-pay firm storage contracts.
North Little Rock and Caddo Mills
Our refined products terminals have aggregate storage capacity of approximately 1.3 million barrels at two refined products terminals located in North Little Rock, Arkansas and Caddo Mills, Texas. Our North Little Rock terminal has storage capacity of approximately 550,000 barrels from 11 tanks and is primarily supplied by a refined products pipeline operated by Enterprise TE Products Pipeline Company LLC. Our Caddo Mills terminal has storage capacity of approximately 770,000 barrels from 10 tanks and is primarily supplied by the Explorer Pipeline. We generate fee-based loading revenues with customers under contracts that, consistent with industry practice, typically contain evergreen provisions after an initial term of six months to two years. We also generate revenue from (i) blending activities, such as ethanol blending and butane blending, and (ii) our vapor recovery units. A majority of the customers in our refined products terminals and storage segment are large, well-known oil companies and independent refiners.
On February 16, 2018, we entered into a definitive agreement for the sale of our refined products terminals to DKGP Energy Terminals LLC, a joint venture between Delek Logistics Partners, LP and Greens Plains Partners LP, for approximately $138.5 million in cash, subject to working capital adjustments. Closing of the sale is subject to customary closing conditions, including clearance under the Hart-Scott-Rodino Act. The transaction is expected to close in the first half of 2018.
Investments in Unconsolidated Affiliates
Delta House
On September 29, 2017, we acquired an additional 15.5% equity interest in Class A units of Delta House, from affiliates of ArcLight for total cash consideration of approximately $125.4 million. Post-closing, we and ArcLight indirectly own a 35.7% and 23.3% interest, respectively, in Delta House.
Delta House is a semi-submersible floating production system with associated crude oil and natural gas export pipelines located in the Mississippi Canyon region of the deepwater Gulf of Mexico. The semi-submersible floating production system receives raw production from deepwater wells, which includes a mixture of crude oil, natural gas, and produced water, and separates the production into its components. The separated crude oil and natural gas pressures are increased, creating pipeline quality crude oil and natural gas that flows into the respective crude oil and natural gas export pipelines. Delta House is operated by LLOG Exploration Offshore, LLC ("LLOG Exploration") and has nameplate processing capacity of 80,000 Bbl/d and 200 MMcf/d and peak processing capacity of 100,000 Bbl/d and 240 MMcf/d.
Cayenne JV
On August 8, 2017, we entered into a joint venture agreement with Targa Midstream Services, LLC (“Targa”) by which our previously wholly owned subsidiary Cayenne Pipeline, LLC (“Cayenne”) became the Cayenne joint venture between Targa and us (“Cayenne JV”). We received $5.0 million in cash in exchange for the sale of 50% ownership interest in Cayenne to Targa. The sole asset of the joint venture is a natural gas pipeline, which has been converted into a natural gas liquids pipeline. Both parties will each have 50% economic interests and 50% voting rights, with Targa serving as the operator of the pipeline and the joint venture. The additional costs of conversion and associated construction are shared equally by us and Targa. The pipeline became operational on December 28, 2017.
Okeanos
We own a 66.7% operated interest in Okeanos, a 100-mile natural gas gathering system located in the Gulf of Mexico with a total capacity of 1.0 Bcf/d. The Okeanos pipeline connects two platforms and one lateral, terminating at the Destin Main Pass 260 platform in the Mississippi Canyon region of the Gulf of Mexico. Contracted volumes on the Okeanos pipeline are based on life-of-field dedication.
Destin
On October 27, 2017, American Midstream Emerald, LLC, a wholly-owned subsidiary of the Partnership, entered into a Purchase and Sale Agreement with Emerald Midstream, LLC, an ArcLight affiliate, to purchase an additional 17.0% equity interest in Destin Pipeline Company, LLC for total consideration of $30.0 million. With the acquisition, the Partnership owns a 66.67% interest in Destin. The Destin pipeline is a FERC-regulated, 255-mile natural gas transport system with total capacity of 1.2 Bcf/d. The system originates offshore in the Gulf of Mexico and includes connections with four producing platforms, and six producer-operated laterals, including Delta House. The 120-mile offshore portion of the Destin system terminates at the Pascagoula processing plant, owned by Enterprise Products Partners, LP, and is the single source of raw natural gas to the plant. The onshore portion of
Destin is the sole delivery point for merchant-quality gas from the Pascagoula processing plant and extends 135 miles north in Mississippi. Destin currently serves as the primary transfer of gas flows from the Barnett and Haynesville shale plays to Florida markets through interconnections with major interstate pipelines. Contracted volumes on the Destin pipeline are based on life-of-field dedication, dedicated volumes over a given period, or interruptible volumes as capacity permits.
Wilprise
We own a 25.3% non-operated interest in Wilprise, a FERC-regulated, approximately 30-mile NGL pipeline that originates at the Kenner Junction and terminates in Sorrento, Louisiana, where volumes flow via pipeline to a Baton Rouge fractionator.
Tri-States
We own a 16.7% non-operated interest in Tri-States, a FERC-regulated, 161-mile NGL pipeline and sole form of transport to Louisiana-based fractionators for NGLs produced at the Pascagoula plant served by Destin and other facilities.
Competition
The midstream business is very competitive, with a number of publicly traded and private equity backed entities servicing the space based on reputation, commercial terms, reliability, service levels, location, available capacity, capital expenditures and efficiencies. Competition is often the greatest in geographic areas experiencing robust drilling by producers and during periods of high commodity prices for natural gas, crude oil and/or NGLs. Competition is also increased in those geographic areas where our commercial contracts with our customers are shorter term and therefore must be renegotiated on a more frequent basis. An increase in competition could result from new pipeline, processing facility, or storage installations or expansions of existing facilities. Major competitors in various aspects of our business include DCP Midstream LLC; Energy Transfer Partners, L.P.; EnLink NGL Marketing, L.P.; Kinder Morgan Energy Partners; Enbridge Energy Partners, L.P.; Columbia Gulf Transmission Company; Enterprise Gas Processing, LLC; Gulf South Pipeline Company, LP; Southern Natural Gas Company; Tennessee Gas Pipeline Company, LLC; Texas Eastern Pipeline; International-Matex Tank Terminals; LBC Tank Terminals; Royal Vopak; Stolt-Nielsen Limited, Westway Terminals Company LLC, and Williams, among others.
Other Segment Information
For additional information on our segments, including revenues from customers, profit or loss and total assets, see Management's Discussion and Analysis of Financial Condition and Results of Operations, in Part II, Item 7 of this Annual Report and Note 23 - Reportable Segments, in Part II, Item 8 of this Annual Report.
Safety and Maintenance
We are subject to regulation by the Pipeline and Hazardous Materials Safety Administration ("PHMSA") pursuant to the Natural Gas Pipeline Safety Act of 1968 ("NGPSA"), and by the Pipeline Safety Improvement Act of 2002 ("PSIA"), which was reauthorized and amended by the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006. The NGPSA regulates safety requirements in the design, construction, operation and maintenance of gas pipeline facilities, while the PSIA establishes mandatory inspections for all U.S. crude oil and natural gas transportation pipelines and some gathering lines in high-consequence areas. The PHMSA has developed regulations implementing the PSIA that require transportation pipeline operators to implement integrity management programs, including more frequent inspections and other measures to ensure pipeline safety in "high-consequence areas," such as high population areas. The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, which became law in January 2012, increases the penalties for safety violations, establishes additional safety requirements for newly constructed pipelines and requires studies of safety issues that could result in the adoption of new regulatory requirements for existing pipelines. The PHMSA issued a final rule applying safety regulations to certain rural low-stress hazardous liquid pipelines that were not covered previously by some of its safety regulations. We believe that this rule does not apply to any of our pipelines. PHMSA issued, but has yet to publish, its final rule for hazardous liquids pipelines on January 13, 2017. That rule extends regulatory reporting requirements to all liquid gathering lines, requires additional event-driven and periodic inspections, requires use of leak detection systems on all hazardous liquid pipelines, modifies repair criteria, and requires certain pipelines to eventually accommodate inline inspection tools. It is unclear when or if this rule will go into effect as, on January 20, 2017, the Trump Administration directed that all regulations that had been sent to the Office of the Federal Register, but not yet published, be immediately withdrawn for further review. In March 2016, PHMSA published a notice of proposed rulemaking regarding natural gas pipelines that would amend existing integrity management requirements, expand assessment and repair requirements to pipelines in areas with medium population densities, and extend regulatory requirements to onshore gas gathering lines that are currently exempt. While we cannot predict the outcome of these legislative or regulatory initiatives, such legislative and regulatory changes could have a material effect on our operations, particularly by extending more stringent and comprehensive safety regulations (such as integrity
management requirements) to pipelines not previously subject to such requirements. While we expect any legislative or regulatory changes to allow us time to become compliant with new requirements, costs associated with compliance may have a material effect on our operations. We cannot predict with any certainty at this time the terms of any new laws or rules or the costs of compliance associated with such requirements.
We regularly inspect our pipelines, and third parties assist us in interpreting the results of the inspections.
States are largely preempted by federal law from regulating pipeline safety for interstate lines, but most states are certified by the U.S. Department of Transportation ("DOT") to assume responsibility for enforcing federal intrastate pipeline regulations and inspection of intrastate pipelines. In practice, because states can adopt stricter standards for intrastate pipelines than those imposed by the federal government for interstate lines, states vary considerably in their authority and capacity to address pipeline safety. These state crude oil and gas standards may include requirements for facility design and management in addition to requirements for pipelines. We do not anticipate any significant difficulty in complying with applicable state laws and regulations. Our natural gas pipelines have continuous inspection and compliance programs designed to keep the facilities in compliance with pipeline safety and pollution control requirements.
In addition, we are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act ("OSHA"), and comparable state statutes, the purposes of which are to protect the health and safety of workers, both generally and within the pipeline industry. In addition, the OSHA hazard communication standard, the Environmental Protection Agency ("EPA"), community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act (Superfund") and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that such information be provided to employees, state and local government authorities, and citizens. We and the entities in which we own an interest are also subject to OSHA Process Safety Management ("PSM") regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. We have an internal program of inspection designed to monitor and enforce compliance with worker safety requirements. We believe that we are in material compliance with all applicable laws and regulations relating to worker health and safety, Superfund and PSM.
We and the entities in which we own an interest are subject to:
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• | EPA Chemical Accident Prevention Provisions, also known as the Risk Management Plan requirements, which are designed to prevent the accidental release of toxic, reactive, flammable or explosive materials; and |
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• | Department of Homeland Security Chemical Facility Anti-Terrorism Standards, which are designed to regulate the security of high-risk chemical facilities. |
Regulation of Operations
Regulation of pipeline gathering and transportation services, natural gas sales and transportation of NGLs may affect certain aspects of our business and the market for our products and services.
Regulation of our terminals require us to maintain and currently hold approvals and permits from federal, state and local regulatory agencies for air quality and water discharge, as well as standard local occupational licenses.
Interstate Natural Gas Pipeline Regulation
Our interstate natural gas transportation systems are subject to the jurisdiction of FERC pursuant to the Natural Gas Act ("NGA"). Under the NGA, FERC has authority to regulate natural gas companies that provide natural gas pipeline transportation services in interstate commerce. Federal regulation of our interstate pipelines extends to such matters as:
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• | rates, services, and terms and conditions of service; |
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• | the types of services offered to customers; |
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• | the certification and construction of new facilities; |
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• | the acquisition, extension, disposition or abandonment of facilities; |
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• | the maintenance of accounts and records; |
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• | relationships between affiliated companies involved in certain aspects of the natural gas business; |
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• | the initiation and discontinuation of services; |
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• | market manipulation in connection with interstate sales, purchases or transportation of natural gas; and |
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• | participation by interstate pipelines in cash management arrangements. |
Under the NGA, the rates for service on these interstate facilities must be just and reasonable and not unduly discriminatory.
The rates and terms and conditions for our interstate pipeline services are set forth in FERC-approved tariffs. Pursuant to FERC's jurisdiction over rates, existing rates may be challenged by complaint and proposed rate increases may be challenged by protest. Any successful complaint or protest against our rates could have an adverse impact on our revenue associated with providing transportation service.
In 2008, FERC issued Order No. 717, a final rule that implements standards of conduct that include three primary rules: (1) the "independent functioning rule," which requires transmission function and marketing function employees to operate independently of each other; (2) the "no-conduit rule," which prohibits passing transmission function information to marketing function employees; and (3) the "transparency rule," which imposes posting requirements to help detect any instances of undue preference. The FERC has since issued four rehearing orders that generally reaffirmed the determinations in Order No. 717 and also clarified certain provisions of the Standards of Conduct.
In April 2008, the FERC issued a Policy Statement regarding the composition of proxy groups for determining the appropriate return on equity for natural gas and crude oil pipelines using FERC's Discounted Cash Flow ("DCF") model for setting cost-of-service or recourse rates. In the policy statement, FERC concluded, among other matters that Master Limited Partnerships ("MLPs") should be included in the proxy group used to determine return on equity for both natural gas and crude oil pipelines, but the long-term growth component of the DCF model should be limited to fifty percent of long-term gross domestic product. The adjustment to the long-term growth component, and all other things being equal, results in lower returns on equity than would be calculated without the adjustment. However, the actual return on equity for our interstate pipelines will depend on the specific companies included in the proxy group and the specific conditions at the time of the future rate case proceeding.
In July 2016, the D.C. Circuit issued its opinion in United Airlines, Inc., et al.v. FERC, finding that FERC had acted arbitrarily and capriciously when it failed to demonstrate that permitting an interstate petroleum products pipeline organized as a limited partnership to include an income tax allowance in the cost of service underlying its rates in addition to the discounted cash flow return on equity would not result in the pipeline partnership owners double-recovering their income taxes. The court vacated FERC’s order and remanded to FERC to consider mechanisms for demonstrating that there is no double recovery as a result of the income tax allowance. On December 15, 2016, FERC issued a Notice of Inquiry seeking comment on how to address any double recovery resulting from income tax allowance policy. On March 15, 2018, FERC issued an order on remand in the United Airlines case and a revised policy statement on income tax recovery that disallows income tax allowances for master limited partnerships in cost of service rates. In addition, FERC issued a notice of proposed rulemaking on March 15, 2018 that proposes to require all interstate natural gas pipelines to submit cost of service information to account for reductions in cost of service resulting from FERC’s new policy on income tax allocations for master limited partnerships and the reduction in the corporate tax rate from the Tax Cuts and Jobs Act that went into effect January 1, 2018. Depending upon the resolution of these issues, the cost of service rates of our interstate natural gas pipelines could be affected to the extent they propose new rates or changes to their existing rates or if their rates are subject to complaint or challenged by FERC. However, we have considered the impact the proposed policy changes by the FERC would have on us, and we have determined that based on the current rate structure on the Partnership's FERC regulated pipelines, the proposed changes are expected to have a negligible impact on the earnings and cash flow of the Partnership. Although we cannot predict whether FERC will propose any additional policy revisions, we expect any such policy revisions will have limited application to us, because a substantial majority of the Partnership's operations are not FERC regulated.
Section 311 Pipelines
Intrastate transportation of natural gas is largely regulated by the state in which such transportation takes place. To the extent that our intrastate natural gas transportation systems transport natural gas in interstate commerce without an exemption under the NGA, the rates, terms and conditions of such services are subject to FERC jurisdiction under Section 311 of the Natural Gas Policy Act, or NGPA, and Part 284 of the FERC's regulations. Pipelines providing transportation service under Section 311 are required to provide services on an open and nondiscriminatory basis. The NGPA regulates, among other things, the provision of transportation services by an intrastate natural gas pipeline on behalf of a local distribution company or an interstate natural gas pipeline. The rates, terms and conditions of some transportation services provided on our Section 311 pipeline systems are subject to FERC regulation pursuant to Section 311 of the NGPA. Under Section 311, rates charged for intrastate transportation must be fair and equitable, and amounts collected in excess of fair and equitable rates are subject to refund with interest. The terms and conditions of service set forth in the intrastate facility's statement of operating conditions are also subject to FERC's review and approval. Should the FERC determine not to authorize rates equal to or greater than our currently approved Section 311 rates, our business may be adversely affected. Failure to observe the service limitations applicable to transportation and storage services under Section 311, failure to comply with the rates approved by the FERC for Section 311 service, and failure to comply with the terms
and conditions of service established in the pipeline's FERC-approved statement of operating conditions could result in alteration of jurisdictional status, and/or the imposition of administrative, civil and criminal remedies.
Hinshaw Pipelines
Intrastate natural gas pipelines are defined as pipelines that operate entirely within a single state, and generally are not subject to FERC's jurisdiction under the NGA. Hinshaw pipelines, by definition, also operate within a single state, but can receive gas from outside their state without becoming subject to FERC's NGA jurisdiction. Specifically, Section 1(c) of the NGA exempts from the FERC's NGA jurisdiction those pipelines that transport gas in interstate commerce if (1) they receive natural gas at or within the boundary of a state, (2) all the gas is consumed within that state and (3) the pipeline is regulated by a state commission. Following the enactment of the NGPA, the FERC issued Order No. 63 authorizing Hinshaw pipelines to apply for authorization to transport natural gas in interstate commerce in the same manner as intrastate pipelines operating pursuant to Section 311 of the NGPA. Hinshaw pipelines frequently operate pursuant to blanket certificates to provide transportation and sales service under the FERC's regulations.
Historically, FERC did not require intrastate and Hinshaw pipelines to meet the same rigorous transactional reporting guidelines as interstate pipelines. However, as discussed below, in 2010 the FERC issued Order No. 735, which increases FERC regulation of certain intrastate and Hinshaw pipelines. See Market Behavior Rules; Posting and Reporting Requirements.
Gathering Pipeline Regulation
Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of FERC. However, some of our natural gas gathering activity is subject to Internet posting requirements imposed by FERC as a result of FERC's market transparency initiatives. We believe that our natural gas pipelines meet the traditional tests that FERC has used to determine that a pipeline is a gathering pipeline and is, therefore, not subject to FERC jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services, however, is the subject of substantial, on-going litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. In recent years, FERC's efforts to promote open access, transparency, and the unbundling of interstate pipeline services has prompted a number of interstate pipelines to transfer their non-jurisdictional gathering facilities to unregulated affiliates. As a result of these activities, natural gas gathering may begin to receive greater regulatory scrutiny at both the state and federal levels. Our natural gas gathering operations could be adversely affected should they be subject to more stringent application of state or federal regulation of rates and services. Our natural gas gathering operations also may be or become subject to additional safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.
Our natural gas gathering operations are subject to ratable take and common purchaser statutes in most of the states in which we operate. These statutes generally require our gathering pipelines to take natural gas without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. The regulations under these statutes can have the effect of imposing some restrictions on our ability as an owner of gathering facilities to decide with whom we contract to gather natural gas. The states in which we operate have adopted a complaint-based regulation of natural gas gathering activities, which allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to gathering access and rate discrimination. We cannot predict whether such a complaint will be filed against us in the future. Failure to comply with state regulations can result in the imposition of administrative, civil and criminal remedies. To date, there has been no adverse effect to our system due to these regulations.
Market Behavior Rules; Posting and Reporting Requirements
On August 8, 2005, Congress enacted the Energy Policy Act of 2005, ("EP Act 2005"). Among other matters, the EP Act 2005 amended the NGA to add an anti-manipulation provision that makes it unlawful for any entity to engage in prohibited behavior in contravention of rules and regulations to be prescribed by FERC and, furthermore, provides FERC with additional civil penalty authority. On January 19, 2006, FERC issued Order No. 670, a rule implementing the anti-manipulation provision of the EP Act 2005, and subsequently denied rehearing. The rules make it unlawful for any entity, directly or indirectly in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC or the purchase or sale of transportation services subject to the jurisdiction of FERC to (1) use or employ any device, scheme or artifice to defraud; (2) to make any untrue statement of material
fact or omit to make any such statement necessary to make the statements made not misleading; or (3) to engage in any act or practice that operates as a fraud or deceit upon any person. The new anti-manipulation rules apply to interstate gas pipelines and storage companies and intrastate gas pipelines and storage companies that provide interstate services, such as Section 311 service, as well as otherwise non-jurisdictional entities to the extent the activities are conducted "in connection with" gas sales, purchases or transportation subject to FERC jurisdiction. The new anti-manipulation rules do not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but only to the extent such transactions do not have a "nexus" to jurisdictional transactions. The EP Act 2005 also amends the NGA and the NGPA to give FERC authority to impose civil penalties for violations of these statutes, up to $1,000,000 per day per violation for violations occurring after August 8, 2005. This maximum penalty authority established by statute will continue to be adjusted periodically for inflation. In connection with this enhanced civil penalty authority, FERC issued a policy statement on enforcement to provide guidance regarding the enforcement of the statutes, orders, rules and regulations it administers, including factors to be considered in determining the appropriate enforcement action to be taken. Should we fail to comply with all applicable FERC-administered statutes, rule, regulations and orders, we could be subject to substantial penalties and fines.
The EP Act of 2005 also added a section 23 to the NGA authorizing the FERC to facilitate price transparency in markets for the sale or transportation of physical natural gas in interstate commerce. In 2007, FERC took steps to enhance its market oversight and monitoring of the natural gas industry by issuing several rulemaking orders designed to promote gas price transparency and to prevent market manipulation. In December 2007, FERC issued a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing, or Order No. 704. Order No. 704 requires buyers and sellers of annual quantities of natural gas of 2,200,000 MMBtu or more, including entities not otherwise subject to FERC jurisdiction, to submit on May 1 of each year an annual report to FERC describing their aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to or may contribute to the formation of price indices. Order No. 704 also requires market participants to indicate whether they report prices to any index publishers and, if so, whether their reporting complies with FERC's policy statement on price reporting. In June 2010, the FERC issued the last of its three orders on rehearing further clarifying its requirements.
In May 2010, the FERC issued Order No. 735, which requires intrastate pipelines providing transportation services under Section 311 of the NGPA and Hinshaw pipelines operating under Section 1(c) of the NGA to report on a quarterly basis more detailed transportation and storage transaction information, including: rates charged by the pipeline under each contract; receipt and delivery points and zones or segments covered by each contract; the quantity of natural gas the shipper is entitled to transport, store, or deliver; the duration of the contract; and whether there is an affiliate relationship between the pipeline and the shipper. Order No. 735 further requires that such information must be supplied through a new electronic reporting system and will be posted on FERC's website, and that such quarterly reports may not contain information redacted as privileged. The FERC promulgated this rule after determining that such transactional information would help shippers make more informed purchasing decisions and would improve the ability of both shippers and the FERC to monitor actual transactions for evidence of market power or undue discrimination. Order No. 735 also extends the FERC's periodic review of the rates charged by the subject pipelines from three years to five years. Order No. 735 became effective on April 1, 2011. In December 2010, the FERC issued Order No. 735-A. In Order No. 735-A, the FERC generally reaffirmed Order No. 735 requiring section 311 and "Hinshaw" pipelines to report on a quarterly basis storage and transportation transactions containing specific information for each transaction, aggregated by contract.
In July 2010, for the first time the FERC issued an order finding that the prohibition against buy/sell arrangements applies to interstate open access services provided by Section 311 and Hinshaw pipelines. The FERC denied the numerous requests for rehearing of the July order. However, in October 2010, the FERC issued a Notice of Inquiry seeking public comment on the issue of whether and how parties that hold firm capacity on some intrastate pipelines can allow others to use their capacity, including to what extent buy/sell transactions should permitted and whether the FERC should consider requiring such pipelines to offer capacity release programs. In the Notice of Inquiry, the FERC granted a blanket waiver regarding such transactions while the FERC is considering these policy issues. The comment period has ended but the FERC has not yet issued an order.
Interstate Oil and Liquids Pipeline Regulation
Our Bakken crude oil gathering system, FERC-regulated American Panther, LLC offshore liquids pipelines (known as the Tiger Shoals and MP 77 offshore pipeline systems) and the Tri-States and Wilprise NGL pipelines, in which we have equity investments, are regulated as common carrier interstate pipelines by the FERC under the Interstate Commerce Act (“ICA”), the Energy Policy Act of 1992 (“EP Act 1992”) and the rules and regulations promulgated under those laws. Under the ICA, FERC has authority regarding the rates and terms and conditions of service for the transportation of oil and natural gas liquids in interstate commerce. Such pipelines are regulated as common carriers. FERC regulation is limited to rate-related issues, and does not extend to the construction of new facilities or cessation of service. The ICA and FERC’s regulations require that rates and terms and conditions of service for interstate service on common carrier pipelines be just and reasonable and must not be
unduly discriminatory or confer any undue preference upon any shipper. FERC’s regulations also require interstate common carrier pipelines to file with FERC and publicly post tariffs stating their interstate transportation rates and terms and conditions of service.
In general, interstate common carrier pipeline rates are initially set through negotiations with non-affiliated shippers or via cost of service ratemaking. In addition, rates can be set via settlement agreed to by all shippers and market-based rates may be permitted in certain circumstances. Effective January 1, 1995, the FERC implemented regulations pursuant to EP Act 1992 establishing an indexing system that permits an oil pipeline, subject to limited challenges, to annually increase or decrease its transportation rates due to inflationary changes in costs using a FERC-approved index, without making a cost of service filing. Every five years, the FERC reviews the appropriateness of the index in relation to industry costs. On December 17, 2015, the FERC established a new Producer Price Index for Finished Goods (the “PPI-FG”) of PPI-FG plus 1.23 percent for the five-year period beginning July 1, 2016. Under FERC’s regulations, pipelines can request a rate increase that exceeds the rate obtained through application of the indexing methodology by using a cost-of-services approach, but only after the pipeline establishes that a substantial divergence exists between the actual costs experienced by the pipeline and the rates resulting from application of the indexing methodology.
Under the ICA, FERC or interested persons may challenge existing or proposed new or changed rates, services, or terms and conditions of service. FERC is authorized to investigate such charges and may suspend the effectiveness of a new rate for up to seven months. FERC could require a common carrier pipeline to collect rates subject to refund until completion of an investigation during which FERC could find that the new or changed rate is unlawful. In contrast, FERC has clarified that initial rates and terms of service agreed upon with committed shippers in a transportation services agreement are not subject to protest or a cost-of-service analysis where the pipeline held an open season offering all potential shippers service on the same terms.
A successful rate challenge could result in a common carrier pipeline paying refunds of revenue collected in excess of the just and reasonable rate, together with interest for the period the rate was in effect, if any. FERC may also order a pipeline to reduce its rates prospectively, and may require a common carrier pipeline to pay shippers reparations retroactively for rate overages for a period of up to two years prior to the filing of a complaint. FERC also has the authority to change terms and conditions of service if it determines that they are unjust or unreasonable or unduly discriminatory or preferential.
On March 15, 2018, FERC issued an order on remand in the United Airlines case and a revised policy statement on income tax recovery that disallows income tax allowances for master limited partnerships in cost of service rates. Under the revised policy statement, pipelines can no longer include income tax allowances in their annual FERC Form 6 report regarding their cost of service. In addition, FERC announced in the revised policy statement that it intends to account for its new policy on income tax allowances for MLPs and the reduction in the corporate tax rate from the Tax Cuts and Jobs Act in its next five-year assessment of the oil pipeline index in 2020. However, we have considered the impact the proposed policy changes by the FERC would have on us, and we have determined that based on the current rate structure on the Partnership's FERC regulated pipelines, the proposed changes are expected to have a negligible impact on the earnings and cash flow of the Partnership. Although we cannot predict whether FERC will propose any additional policy revisions, we expect any such policy revisions will have limited application to us, because a substantial majority of the Partnership's operations are not FERC regulated.
Offshore Natural Gas Pipelines
Our offshore natural gas gathering pipelines are subject to federal regulation under the Outer Continental Shelf Lands Act, which requires that all pipelines operating on or across the outer continental shelf provide open and nondiscriminatory access to shippers. From 1982 until 2012, the Minerals Management Service ("MMS"), of the U.S. Department of the Interior ("DOI"), was the federal agency that managed the nation's crude oil, natural gas, and other mineral resources on the outer continental shelf, which is all submerged lands lying seaward of state coastal waters which are under U.S. jurisdiction, and collected, accounted for, and disbursed revenues from federal offshore mineral leases. On June 18, 2010, the Minerals Management Service was renamed the Bureau of Ocean Energy Management, Regulation and Enforcement ("BOEMRE"). In October 2011, the BOEMRE was reorganized into and replaced by two separate agencies, the Bureau of Ocean Energy Management ("BOEM") and the Bureau of Safety and Environmental Enforcement ("BSEE"). The BOEM manages the exploration and development of the nation's offshore resources. BOEM seeks to appropriately balance economic development, energy independence, and environmental protection through crude oil and gas leases, renewable energy development and environmental reviews and studies. BSEE works to promote safety, protect the environment, and conserve resources offshore through vigorous regulatory oversight and enforcement.
Sales of Natural Gas and NGLs
The price at which we sell natural gas is not currently subject to federal rate regulation and, for the most part, is not subject to state regulation. However, with regard to our physical sales of these energy commodities, we are required to observe anti-market
manipulation laws and related regulations enforced by the FERC and/or the Commodity Futures Trading Commission ("CFTC"), and the Federal Trade Commission ("FTC"). Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third-party damage claims by, among others, sellers, royalty owners and taxing authorities.
Sales of NGLs are not currently regulated and are made at negotiated prices. Nevertheless, Congress could enact price controls in the future.
As discussed above, the price and terms of access to pipeline transportation are subject to extensive federal and state regulation. The FERC is continually proposing and implementing new rules and regulations affecting interstate natural gas pipelines and those initiatives may also affect the intrastate transportation of natural gas both directly and indirectly.
Environmental Matters
General
Our operation of pipelines, plants, terminals and other facilities for the gathering, compressing, treating and transporting of natural gas and other products is subject to stringent and complex federal, state and local laws and regulations relating to the protection of the environment. As an owner or operator of these facilities, we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as:
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• | requiring the installation of pollution-control equipment or otherwise restricting the way we operate; |
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• | limiting or prohibiting construction activities in sensitive areas, such as wetlands, coastal regions or areas inhabited by endangered or threatened species; |
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• | delaying system modification or upgrades during permit reviews; |
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• | requiring investigatory and remedial actions to mitigate pollution conditions caused by our operations or attributable to former operations; and |
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• | enjoining the operations of facilities deemed to be in non-compliance with permits issued pursuant to such environmental laws and regulations. |
Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties. Certain environmental statutes impose strict joint and several liability for costs required to clean up and restore sites where substances, hydrocarbons or wastes have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment.
The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation and actual future expenditures may be different from the amounts we currently anticipate. We try to anticipate future regulatory requirements that might be imposed and plan accordingly to remain in compliance with changing environmental laws and regulations and to minimize the costs of such compliance. We also actively participate in industry groups that help formulate recommendations for addressing existing or future regulations.
We do not believe that compliance with federal, state or local environmental laws and regulations will have a material adverse effect on our business, financial position or results of operations or cash flows. In addition, we believe that the various environmental activities in which we are presently engaged are not expected to materially interrupt or diminish our operational ability to gather, compress, treat and transport natural gas. We cannot assure, however, that future events, such as changes in existing laws or enforcement policies, the promulgation of new laws or regulations or the development or discovery of new facts or conditions will not cause us to incur significant costs. Below is a discussion of the material environmental laws and regulations that relate to our business. We believe that we are in substantial compliance with all of these environmental laws and regulations.
Hazardous Substances and Waste
Our operations are subject to environmental laws and regulations relating to the management and release of hazardous substances, solid and hazardous wastes and petroleum hydrocarbons. These laws generally regulate the generation, storage, treatment, transportation and disposal of solid and hazardous waste and may impose strict joint and several liability for the investigation and remediation of affected areas where hazardous substances may have been released or disposed. For instance, the Comprehensive Environmental Response, Compensation, and Liability Act ("CERCLA"), and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a hazardous
substance into the environment. These persons include the current or former owner or operator of the site where the release occurred, and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. We may handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.
We also generate industrial wastes that are subject to the requirements of the Resource Conservation and Recovery Act ("RCRA"), and comparable state statutes. While RCRA regulates both solid and hazardous wastes, it imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. We generate little hazardous waste; however, it is possible that these wastes, which could include wastes currently generated during our operations, will in the future be designated as "hazardous wastes" and, therefore, be subject to more rigorous and costly disposal requirements. In December 2016, the EPA and environmental groups entered into a consent decree to address EPA’s alleged failure to timely assess its RCRA Subtitle D criteria regulations exempting certain exploration and production related oil and gas wastes from regulation as hazardous wastes under RCRA. The consent decree requires EPA to propose a rulemaking by March 2019 for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or to sign a determination that revision of the regulations is not necessary. Any such changes in the laws and regulations could have a material adverse effect on our maintenance capital expenditures and operating expenses.
We currently own or lease properties where hydrocarbons are being or have been handled for many years. Although previous operators have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us or on or under the other locations where these hydrocarbons and wastes have been transported for treatment or disposal. These properties and the wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated soil and groundwater) or to perform remedial operations to prevent future contamination. We are not currently aware of any facts, events or conditions relating to such requirements that could materially impact our operations or financial condition.
Air Quality and Climate Change
Our operations are subject to the federal Clean Air Act and comparable state and local laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including our compressor stations and processing plants, and also impose various monitoring and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations and utilize specific emission control technologies to limit emissions. Failure to comply with applicable air statutes or regulations may lead to the assessment of administrative, civil or criminal penalties and may result in the limitation or cessation of construction or operation of certain air emission sources. Although we can give no assurances, we believe such requirements will not have a material adverse effect on our financial condition or operating results, and the requirements are not expected to be more burdensome to us than to any similarly situated company. As the EPA issues new, lower National Ambient Air Quality Standards ("NAAQS"), we may be required to incur certain capital expenditures for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. For example, in June 2010, the EPA issued a new NAAQS for sulfur dioxide, or SO2, and replaced the 24-hour and annual standards with a more stringent hourly standard. In October 2015, the agency finalized a reduction of the national ambient air quality standard for ozone standard from 75 parts per billion to 70 parts per billion; both nitrogen oxides and VOCs are ozone precursors. This reduction is expected to increase the number of ozone nonattainment areas. In October 2016, the EPA also finalized Control Technology Guidelines for emissions of VOCs from crude oil and natural gas industry sources to be relied upon by states when implementing the ozone standard in ozone nonattainment areas. We believe that our operations will not be materially adversely affected by such requirements, and the requirements are not expected to be any more burdensome to us than to any other similarly situated companies.
On April 17, 2012, the EPA approved final rules under the Clean Air Act that establish new air emission controls for crude oil and natural gas production, pipelines and processing operations. These rules became effective on October 15, 2012. The established specific new requirements regarding emissions from wet seal and reciprocating compressors at production facilities, gathering systems, boosting facilities and onshore natural gas processing plants, effective October 15, 2012, and from pneumatic controllers and storage vessels at production facilities, gathering systems, boosting facilities and onshore natural gas processing plants, effective October 15, 2013. In addition, the rules revise existing requirements for volatile organic compound (VOC) emissions from equipment leaks at onshore natural gas processing plants by lowering the leak definition for valves from 10,000 parts per million to 500 parts per million and requiring the monitoring of connectors, pumps, pressure relief devices and open-ended lines, effective October 15, 2012. Initial compliance and ongoing compliance with the new subset of rules required capital expenditures and
ongoing compliance expenses. Following the publication of the final rule, the EPA received petitions for reconsideration of certain aspects of the standards. On April 12, 2013, the EPA published proposed updates to the NSPS Subpart OOOO storage tank requirements. On September 23, 2013, the EPA published final revisions to the NSPS Subpart OOOO storage tank requirements, including a phase-in of installation of VOC controls and alternate limits for tanks where emissions have declined. The EPA issued revised definitions related to the stages of well completions and amended storage tank requirements under NSPS Section OOOO in December 2014 and further revised the storage tank requirements in March 2015. More recently, in June 2016, the EPA published updates to new source performance standard requirements that would impose more stringent controls on methane and VOC emissions from oil and gas development and production operations, including hydraulic fracturing and other well completion activity. The EPA is currently engaged in rulemaking to stay the effective date of these rules. Also, the EPA published NSPS Subpart 0000a, effective August 2, 2016, which places requirements on sources constructed, modified or reconstructed after September 18, 2015. Many of the requirements of NSPS Subpart OOOO mirror those in NSPS Subpart OOOO; however, new equipment being regulated are pneumatic pumps and fugitive emissions at well sites and compressor stations. Similarly, in November 2016, the BLM issued rules requiring additional efforts by producers to reduce venting, flaring, and leaking of natural gas produced on federal and Native American lands. However, in December 2017, implementation of this rule was delayed until January 2019.
A number of states have adopted or considered programs to reduce “greenhouse gases,” or GHGs and the EPA has declared that GHGs “endanger” public health and welfare, and is regulating GHG emissions from mobile sources such as cars and trucks. According to the EPA, this final action on the GHG vehicle emission rule triggered regulation of carbon dioxide and other GHG emissions from stationary sources under certain Clean Air Act programs at both the federal and state levels, particularly the Prevention of Significant Deterioration program and Title V permitting. These requirements for stationary sources took effect on January 2, 2011; however, in June 2014 the U.S. Supreme Court reversed a D.C. Circuit Court of Appeals decision upholding these rules and struck down the EPA’s greenhouse gas permitting rules to the extent they impose a requirement to obtain a federal air permit based solely on emissions of greenhouse gases. Large sources of other air pollutants, such as VOC or nitrogen oxides, could still be required to implement process or technology controls and obtain permits regarding emissions of greenhouse gases. The EPA has also published various rules relating to the mandatory reporting of GHG emissions, including mandatory reporting requirements of GHGs from petroleum and natural gas systems. In October 2015, the EPA amended and expanded greenhouse gas reporting requirements to all segments of the crude oil and natural gas industry, including gathering and boosting facilities and blowdowns of natural gas transmission pipelines, starting with the 2016 reporting year, and in January 2016, the EPA proposed additional revisions to leak detection methodology to align the reporting rule with the new source performance standards.
The permitting, regulatory compliance and reporting programs taken as a whole increase the costs and complexity of operating oil and gas operations in compliance with these legal requirements, with resulting potential to adversely affect our cost of doing business, demand for the oil and gas we transport and may require us to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions.
Water Discharges
The Federal Water Pollution Control Act ("Clean Water Act"), and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into state waters as well as waters of the U.S. and to conduct construction activities in waters and wetlands. In May 2015, the EPA and the U.S. Army Corps of Engineers issued a final rule to clarify which waters and wetlands are subject to Clean Water Act regulation. The implementation of this rule was stayed nationwide in October 2015 as a result of litigation. In January 2018, the Supreme Court ruled that district courts have jurisdiction over challenges to the rule. Litigation surrounding this rule is ongoing, and, in addition to delaying the rule's applicability date until February 6, 2020, the EPA has instituted a rule-making process to repeal the rule. Certain state regulations and the general permits issued under the Federal National Pollutant Discharge Elimination System program prohibit the discharge of pollutants and chemicals. Spill Prevention Control and Countermeasure ("SPCC") requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of regulated waters in the event of a hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. These permits may require us to monitor and sample the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. We believe that compliance with existing permits and compliance with foreseeable new permit requirements will not have a material adverse effect on our financial condition, results of operations or cash flow.
Safe Drinking Water Act
The underground injection of crude oil and natural gas wastes are regulated by the Underground Injection Control program authorized by the Safe Drinking Water Act. The primary objective of injection well operating requirements is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. As of December 31, 2017, the Partnership is in compliance with the requirements.
Endangered Species
The Endangered Species Act ("ESA") restricts activities that may affect endangered or threatened species or their habitats. While some of our pipelines may be located in areas that are designated as habitats for endangered or threatened species, we believe that we are in substantial compliance with the ESA. However, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected states.
National Environmental Policy Act
The National Environmental Policy Act ("NEPA") establishes a national environmental policy and goals for the protection, maintenance, and enhancement of the environment and provides a process for implementing these goals within federal agencies. A major federal agency action having the potential to significantly impact the environment requires review under NEPA and, as a result, many activities requiring FERC approval must undergo NEPA review. Many of our activities are covered under categorical exclusions that result in a shorter NEPA review process. The Council on Environmental Quality has issued final guidance to reinvigorate NEPA reviews that, while intended to streamline the process, may result in longer review processes that could lead to delays and increased costs that could materially adversely affect our revenues and results of operations.
Anti-terrorism Measures
The federal Department of Homeland Security regulates the security of chemical and industrial facilities pursuant to regulations known as the Chemical Facility Anti-Terrorism Standards. These regulations apply to oil and gas facilities, among others, that are deemed to present “high levels of security risk.” Pursuant to these regulations, certain of our facilities are required to comply with certain regulatory provisions, including requirements regarding inspections, audits, recordkeeping, and protection of chemical-terrorism vulnerability information.
Title to Properties and Rights-of-Way
Our real property falls into two categories: i) parcels that we own in fee and ii) parcels in which our interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities, permitting the use of such land for our operations. Portions of the land on which our plants and other major facilities are located are owned by us in fee title, and we believe that we have satisfactory title to these lands. The remaining land on which our plant sites and major facilities are located, are held by us pursuant to surface leases between us, as lessee, and the fee owner of the lands, as lessors. Our predecessors leased or owned these lands for many years without any material challenge known to us relating to the title to the land upon which the assets are located, and we believe that we have satisfactory leasehold estates or fee ownership in such lands. We have no knowledge of any challenge to the underlying fee title of any material lease, easement, right-of-way, permit or license held by us or to our title to any material lease, easement, right-of-way, permit or lease, and we believe that we have satisfactory title to all of our material leases, easements, rights-of-way, permits and licenses.
Employees
The Partnership does not have any employees. All of the employees required to conduct and support our operations are employed by our General Partner, and the officers of our General Partner manage our operations and activities. As of December 31, 2017, our General Partner employed approximately 490 people who provide direct, full-time support to our operations. None of these employees are covered by collective bargaining agreements, and our General Partner considers its employee relations to be positive.
General
We make certain filings, and amendments thereto, with the Securities and Exchange Commission (the "SEC"), including our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports. All of these filings are available as soon as reasonably practicable after the electronic filing with the SEC free of charge on our website, www.americanmidstream.com. The filings are also available at the SEC's Public Reference Room at 100 F Street, NE, Washington, DC 20549 or by calling the SEC at 1-800-SEC-0330. Additionally, the filings are available on the Internet at www.sec.gov. We intend to use our website as a means for disseminating information in accordance with Regulation FD under the Exchange Act. The information contained on our website is not part of, nor is it incorporated by reference into, this Annual Report.
Item 1A. Risk Factors
Limited partner interests are inherently different from capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in similar businesses. We urge you to carefully consider the following risk factors together with all of the other information included in this Annual Report in evaluating an investment in our common units.
If any of the following risks were to occur, our business, financial condition, results of operations or cash flows could be materially adversely affected. In that case, we might not be able to pay the minimum quarterly distribution on our common units, the trading price of our common units could decline and you could lose all or part of your investment in us.
The risks described below are not the only ones that we face. Additional risks not presently known to us or that we currently deem immaterial individually or in the aggregate may also impair our business operations. This Annual Report also contains forward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those anticipated in these forward-looking statements as a result of various factors, including the risks and uncertainties faced by us described below.
Risks Related to our Business
Our current and future indebtedness levels may limit our flexibility in obtaining additional financing and in pursuing other business opportunities.
As of December 31, 2017, we had approximately $1.2 billion in principal amount of debt outstanding (including approximately $697.9 million of borrowings outstanding under our revolving credit facility). Our level of indebtedness could have important consequences to us, including the following:
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• | our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms; |
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• | covenants contained in our existing and future credit and debt arrangements will require us to meet financial tests that may affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities; |
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• | our funds available for operations, future business opportunities and distributions to unitholders will be reduced by that portion of our cash flow required to make principal and interest payments on our indebtedness; |
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• | our indebtedness level may make us more vulnerable than our competitors with less debt to competitive pressures or a downturn in our business or the economy generally; and |
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• | our flexibility in responding to changing business and economic conditions may be limited. |
Any of these factors could result in a material adverse effect on our business, financial condition, results of operations, business prospects and ability to make cash distributions to our unitholders.
Our ability to service our indebtedness will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing distributions to our unitholders, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets, restructuring or refinancing our indebtedness, or seeking additional equity capital or bankruptcy protection. We may not be able to effect any of these remedies on satisfactory terms, or at all.
We have identified material weaknesses in our internal controls for 2017 and have been unable to remediate the material weakness identified in 2016. If we fail to remediate these material weaknesses or otherwise fail to develop, implement and maintain appropriate internal controls in future periods, our ability to report our financial condition and results of operations accurately and on a timely basis could be adversely affected.
At December 31, 2016, we identified a material weakness in our internal controls over the level of accounting knowledge, expertise and training commensurate with our financial reporting requirements. This material weakness was not remediated at December 31, 2017. At December 31, 2017, we did not maintain an effective control environment as we lacked sufficient oversight of activities related to our internal control over financial reporting and had an insufficient complement of resources with an
appropriate level of accounting knowledge, expertise and training commensurate with our financial reporting requirements. This material weakness contributed to additional material weaknesses, as the Partnership did not design and maintain effective controls over: verifying that complex, non-routine transactions were recorded appropriately; all financial statement assertions of revenues and receivables, specifically the review of the accounting for certain contracts, the review that price, volume and other key contractual terms used to record revenue are consistent with the terms of the arrangement and the review that revenue is recorded in the proper period; all financial statement assertions related to acquisitions and divestitures, specifically verifying the existence, rights and obligations associated with assets acquired and liabilities assumed, reviewing the valuation of the purchase price allocation and reviewing the completeness and accuracy of related disclosures; the period-end financial reporting process, specifically the review of account reconciliations and financial statement analyses to support the completeness and accuracy of the consolidated financial statements and disclosures; and the accuracy and valuation of asset retirement obligations, goodwill, other intangible assets and finite-lived assets, specifically the review of the model, data, assumptions and calculations used in determining the estimated asset retirement obligation and in impairment tests, and the related identification of changes in events and circumstances that indicate it is more likely than not that an impairment indicator has occurred. Additionally, we did not maintain effective controls over certain information technology ("IT") general controls for a significant application used in the preparation of our financial statements. Specifically, we did not maintain user access controls to ensure appropriate segregation of duties and adequate restriction of user and privileged access to the financial application, programs, and data to appropriate Partnership personnel. These IT deficiencies did not result in a material misstatement to the financial statements, however, the deficiencies, when aggregated, could impact our ability to maintain effective segregation of duties, as well as maintain effective IT-dependent controls which could result in misstatements of substantially all of the financial statement accounts and disclosures resulting in a material misstatement to the annual or interim consolidated financial statements that otherwise would not be prevented or detected. Accordingly, our management determined that, as of December 31, 2017, our disclosure controls and procedures and our internal control over financial reporting were not effective. The specific material weaknesses and our remediation efforts are described in Item 9A, Controls and Procedures of this Annual Report. A “material weakness” is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis. We were not able to remediate material weaknesses identified at December 31, 2016 during 2017, and we cannot assure you that we will adequately remediate the material weaknesses or that additional material weaknesses in our internal controls will not be identified in the future.
We are in the process of remediating the identified material weaknesses in our internal controls, but we are unable at this time to estimate when the remediation effort will be completed. During the course of implementing additional processes and controls, as well as controls operating effectiveness testing, we may identify additional control deficiencies, which could give rise to other material weaknesses, in addition to the material weaknesses described above. As we continue to evaluate and work to improve our internal control over financial reporting, we may determine to take additional measures to address these material weaknesses or modify certain of the remediation measures. Further and continued determinations that there are material weaknesses in the effectiveness of our internal controls could reduce our ability to obtain financing or could increase the cost of any financing we obtain and require additional expenditures of resources to comply with applicable requirements.
The indenture governing our senior notes and our credit facility contain certain financial covenants and ratios and other restrictions. We may have difficulty maintaining compliance with such financial covenants and ratios and other restrictions, which could adversely affect our business, financial condition, results of operations and ability to pay distributions to our unitholders.
We are dependent upon certain earnings and cash flow generated by our operations in order to meet our debt service obligations. We also depend on our credit facility for working capital and future expansion capital needs and, as necessary, to fund a portion of cash distributions to unitholders. The indenture governing the notes and our revolving credit facility contain, and any future financing agreements may contain, operating and financial restrictions and covenants that could restrict our ability to finance future operations or capital needs, or to expand or pursue our business activities, which may, in turn, limit our ability to pay distributions to our unitholders. For example, our revolving credit facility limits our ability to, among other things:
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• | incur or guarantee additional indebtedness; |
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• | make certain investments and acquisitions; |
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• | redeem or repay other debt or make other restricted payments; |
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• | enter into certain types of transactions with affiliates; |
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• | enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us; |
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• | enter into sale and leaseback transactions; |
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• | merge or consolidate with another company; |
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• | transfer, sell or otherwise dispose of assets, including equity interests in our subsidiaries; |
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• | cancel or modify material contracts; |
Our Second Amended and Restated Credit Agreement (the “Credit Agreement”) contains certain financial covenants, including (i) a consolidated total leverage ratio that requires our indebtedness not to exceed 5.00 times adjusted consolidated EBITDA (except during a specified acquisition period, as determined under the terms of the Credit Agreement, at which time such ratio is increased to 5.50 times adjusted consolidated EBITDA), (ii) a consolidated secured leverage ratio that requires our secured indebtedness not to exceed 3.50 times adjusted consolidated EBITDA, and (iii) a minimum interest coverage ratio that requires our adjusted consolidated EBITDA to exceed consolidated interest charges by not less than 2.50 times. The financial covenants in our Credit Agreement may limit the amount available to us for borrowing to less than $900.0 million. As of December 31, 2017, our consolidated total leverage ratio was 5.23, our secured leverage ratio was 3.29 and our interest coverage ratio was 3.62, which were in compliance with the financial covenants. Our ability to comply with these covenants and ratios in the future is uncertain and will be affected by the levels of cash flow from our operations and events or circumstances beyond our control, including events and circumstances that may stem from the condition of the financial markets and commodity price levels.
We may not have sufficient cash from operations to enable us to pay distributions to holders of our common units.
We may not have sufficient available cash from operations each quarter to enable us to pay the minimum quarterly distribution of $0.4125 per common unit or at all. These distributions may only be made from cash available for distribution after the preferred quarterly distribution to which our convertible preferred units are entitled, the establishment of cash reserves, and payment of our fees and expenses. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:
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• | the volume of natural gas we and our joint ventures gather, process and transport, and related revenues earned under our and our joint ventures’ transportation contracts; |
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• | the level of production of crude oil and natural gas and the resultant market prices of crude oil and natural gas and NGLs; |
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• | realized pricing impacts on our revenue and expenses that are directly subject to commodity price exposure; |
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• | capacity charges and volumetric fees associated with our transportation services; |
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• | the level of competition from other midstream energy companies in our geographic markets; |
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• | the level of our operating, maintenance and corporate costs; and |
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• | regulatory action affecting the supply of, or demand for, natural gas, the transportation rates we can charge on our regulated pipelines, how we contract for services, our existing contracts, our operating costs and our operating flexibility. |
In addition, the actual amount of cash we will have available for distribution will depend on other factors, including:
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• | the level and timing of capital expenditures we make; |
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• | the cost of acquisitions, and the resulting costs of integrations, if any; |
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• | our debt service payments and requirements and other liabilities; |
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• | fluctuations in our working capital needs; |
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• | our ability to borrow funds and access capital markets; |
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• | restrictions contained in our Credit Agreement; |
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• | the amount of cash reserves established by our General Partner; and |
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• | other business risks affecting our cash levels. |
There is no guarantee that unitholders will receive quarterly distributions from us. Our distributions are determined each quarter by the Board of Directors of our General Partner based on the board’s consideration of the foregoing factors, our financial position, earnings, cash flow, current and future business needs and other relevant factors at that time. We may reduce or eliminate distributions at any time we have insufficient cash available for distributions. This may be due to insufficient cash reserves, requirements to fund current or anticipated future operations, capital expenditures, acquisitions, growth or expansion projects, debt repayment or other business needs.
The amount of cash we have available for distribution depends primarily upon our cash flow and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record net losses for financial reporting purposes and may not make cash distributions during periods when we record net income for financial reporting purposes.
Any decrease in the volumes of natural gas, NGLs or crude oil that we or our joint ventures gather, process or transport could adversely affect our business and operating results.
The volumes that support our business are dependent on the level of production from natural gas and crude oil wells connected to our systems, including volumes from significant customers, the production of which will naturally decline over time. As a result, our cash flows associated with these wells will also decline over time. In order to maintain or increase throughput levels on our systems, we must obtain new sources of natural gas and crude oil. The primary factors affecting our ability to obtain non-dedicated sources of natural gas and crude oil include (i) the level of successful drilling activity in our areas of operation and (ii) our ability to compete for volumes from successful new wells.
We have no control over the level of drilling activity in our areas of operation, the amount of reserves associated with wells connected to our systems or the rate at which production from a well declines. In addition, we have no control over producers or their drilling or production, which are affected by, among other things:
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• | prevailing and projected natural gas, crude oil and NGL prices; |
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• | the availability and cost of capital; |
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• | demand for natural gas, crude oil and NGLs; |
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• | geological considerations; |
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• | environmental or other governmental regulations, including the availability of drilling permits; |
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• | the absence of operational issues that curtail production; and |
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• | the availability of drilling rigs and other production and development costs. |
Sustained reductions in exploration or production activity in our areas of operation would lead to 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 prices on our operations. If commodity prices decreased or if producers experienced sustained curtailment of production, this could lead to reduced profitability and may impact our liquidity and compliance with financial covenants in our revolving credit facility. Reduced profitability may also result in future non-cash impairments of long-lived assets, goodwill, or intangible assets.
Because of these and other factors, even if new natural gas, NGL and crude oil reserves are known to exist in areas served by our assets, producers may choose not to develop those reserves. If reductions in drilling activity result in our inability to maintain the current levels of throughput on our systems, it could reduce our revenue and cash flow and adversely affect our ability to make cash distributions to our unitholders.
Natural gas, crude oil, NGL and other commodity prices are volatile, and a reduction in these prices in absolute terms, or an adverse change in the prices of natural gas and NGLs relative to one another, could adversely affect our net income, gross margin and cash flow and our ability to make distributions to our unitholders.
We are subject to risks due to frequent and often substantial fluctuations in commodity prices. In the past, the prices of natural gas and crude oil have been extremely volatile, and we expect this volatility to continue. Natural gas and crude oil prices declined dramatically in late 2015 and have fluctuated throughout 2016 and 2017. These factors include the supply of and demand for these commodities, which fluctuate with changes in market and economic conditions and other factors, including:
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• | worldwide economic conditions and political events, including actions taken by foreign oil and gas producing nations |
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• | worldwide weather events and conditions, including natural disasters and seasonal changes; |
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• | the levels of world-wide and domestic production and consumer demand; |
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• | the availability of imported, or market for exported, crude oil and liquefied natural gas, or LNG; |
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• | the availability of transportation systems with adequate capacity; |
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• | the volatility and uncertainty of regional pricing differentials; |
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• | the nature and extent of governmental regulation and taxation; and |
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• | the current and anticipated future prices of natural gas, crude oil, NGLs and other commodities. |
Our growth strategy, and ability to fund expansion capital projects, requires access to new capital. Our ability to access the capital markets, tightened capital markets or other factors that increase our cost of capital, or limit our access to capital, could impair our ability to grow.
We continuously consider potential acquisitions and opportunities for expansion capital projects. Acquisition opportunities arise quickly and unexpectedly, may occur at any time and may be significant in size relative to our existing assets and operations. Our ability to fund our capital projects and make acquisitions depends on whether we can access the necessary financing to fund these activities. The delayed filing of this Annual Report has made us currently ineligible to use a registration statement on Form S-3 to register the offer and sale of securities, which could increase the expense of accessing the capital markets. Any limitations
on our access to capital or increase in the cost of that capital could significantly impair our growth strategy. Our ability to maintain our targeted credit profile, including our target debt-to-equity ratio, could affect our cost of capital as well as our ability to execute our growth strategy. In addition, a variety of factors beyond our control could impact the availability or cost of capital, including domestic or international economic conditions, increases in key benchmark interest rates or credit spreads, the adoption of new or amended banking or capital market laws or regulations, the re-pricing of market risks and volatility in capital and financial markets.
Due to these factors, we cannot be certain that funding for our capital needs will be available from bank credit arrangements, our revolving credit facility or capital markets on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, we may be unable to implement our development plans, enhance our existing business, complete acquisitions and construction projects, take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our revenues and results of operations.
Our business is subject to a number of weather related risks, including severe weather in the U.S. Gulf of Mexico, which can cause significant damage and disruption to our business interests located in that region.
The U.S. Gulf of Mexico experiences hurricanes and other extreme weather conditions on a frequent basis, the frequency of which may increase with climate change. Our High Point system, our Offshore Texas system, our Destin system, our Okeanos system, our MPOG system and non-operated interests Delta House and any future systems that we acquire in the U.S. Gulf of Mexico, are susceptible to adverse weather conditions in the U.S. Gulf of Mexico, including hurricanes and other extreme weather conditions. Our insurance and weather derivatives may not cover all associated loss. High winds, storm surge, and turbulent seas can cause significant damage and curtail these operations for extended periods during and after such weather conditions, which may result in decreased revenues from our interests in these operations. In addition, these adverse weather conditions in the U.S. Gulf of Mexico can affect producers connected to our facilities even if our facilities are not damaged, which may result in decreased revenues from our interests in these operations.
To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease depending on the duration and magnitude of the changes, leading either to increased investment or decreased revenues.
We are subject to the risk of loss resulting from nonpayment or nonperformance by our customers and counterparties in the ordinary course of our business.
We are subject to the risk of loss resulting from nonpayment or nonperformance by our customers and counterparties in the ordinary course of our business. Generally, we either consider our customers creditworthy or require those who are not creditworthy to make prepayments or provide security to satisfy credit concerns. However, our credit procedures and policies will not completely eliminate customer and counterparty credit risk. Our customers and counterparties include entities whose creditworthiness may be suddenly and disparately impacted by, among other factors, commodity price volatility, deteriorating energy market conditions, and public and regulatory opposition to energy producing activities.
In addition, in connection with the acquisition of certain of our assets, we have entered into agreements pursuant to which various counterparties have agreed to indemnify us, subject to certain limitations, for certain matters arising from the pre-closing ownership and operation of assets.
The low commodity price environment in prior years negatively impacted many oil and gas companies causing them significant economic stress including, in some cases, to file for bankruptcy protection or to renegotiate contracts, and this could recur. To the extent one or more of our key customers or counterparties commences bankruptcy proceedings, our contracts with such customers or counterparties may be subject to rejection under applicable provisions of the United States Bankruptcy Code or may be renegotiated. Further, during any such bankruptcy proceeding, prior to assumption, rejection or renegotiation of such contracts, the bankruptcy court may temporarily authorize the payment of value for our services less than contractually required, which could have a material adverse effect on our business, results of operations, cash flows and financial conditions. If we fail to adequately assess the creditworthiness of existing or future customers and counterparties or otherwise do not take or are unable to take sufficient mitigating actions, including obtaining sufficient collateral, deterioration in their creditworthiness and any resulting increase in nonpayment or nonperformance by them could cause us to write down or write off accounts receivable. Such write-downs or write-offs could negatively affect our operating results in the periods in which they occur, and, if significant, could have a material adverse effect on our business, results of operations, cash flows and financial condition.
If third-party pipelines or other midstream facilities interconnected to our gathering or transportation systems become partially or fully unavailable, or if the volumes we gather or transport do not meet the natural gas quality requirements of such pipelines or facilities, our revenue and cash available for distribution could be adversely affected.
Our natural gas gathering and processing and transportation systems connect to other pipelines or facilities, the majority of which are owned and operated by third parties. The continuing operation of such third-party pipelines and other midstream facilities is not within our control. These pipelines and other midstream facilities and others upon which we rely may become unavailable because of testing, turnarounds, line repair, reduced operating pressure, lack of operating capacity, regulatory requirements, curtailments of receipt or deliveries due to insufficient capacity or because of damage from hurricanes or other operational hazards. For example, the explosion and fire at the Pascagoula Gas plant in June of 2016 suspended operations from that facility for over eight months. If any of these pipelines or other midstream facilities becomes unable to receive or transport natural gas, or if the volumes we gather or transport do not meet the natural gas quality requirements of such pipelines or facilities, our revenue and cash available for distribution may be adversely affected.
The adoption and implementation of new statutory and regulatory requirements for swap transactions could have an adverse impact on our ability to hedge risks associated with our business.
Congress adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) in 2010. Among other things, the Dodd-Frank Act mandated significant changes to the over-the-counter derivative market and requires the Commodities Futures Trading Commission (the “CFTC”), the SEC and other regulators to promulgate rules and regulations establishing federal oversight and regulation of the over-the-counter derivative market. Although as of December 31, 2017, the rules and regulations under the Dodd-Frank Act have not had an adverse effect on our ability to use certain derivative instruments, such rules and regulations may have an adverse effect on our ability to do so in the future.
The rulemaking process under the Dodd-Frank Act has not been fully completed. As a result, the full impact of the Dodd-Frank Act and related regulatory requirements upon our business will not be known until the regulations are implemented and the market for derivatives contracts has adjusted. When fully implemented, the Dodd-Frank Act and any new regulations could increase the operational and transactional cost of derivatives contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize and restructure our existing derivatives contracts, impact commodity prices and affect the number or creditworthiness of available counterparties. For example, the rules and regulations under the Dodd-Frank Act may increase the costs of certain derivative products as a result of the imposition of capital, margin, clearing and exchange-trading requirements either on us or on our counterparties. Any requirement to post more collateral to our counterparties in excess of what we currently post to collateralize our obligations may have a negative impact upon our liquidity. Further, the CFTC has proposed rules that would place position limits on certain core futures contracts and equivalent swap contracts for or linked to certain physical commodities, subject to certain exceptions which, if finalized, could further restrict our ability to utilize these products. If, as a result of the Dodd-Frank Act and the rules and regulations promulgated thereunder, we reduce our use of certain derivatives, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures or increase our distributions.
We do not control certain of the entities that own our projects and we may acquire future projects that we do not control.
We own a 50% membership interest in Cayenne, 35.7% of the Class A units of Delta House FPS LLC and Delta House Oil and Gas Lateral LLC, a 25.3% membership interest in Wilprise, and a 16.7% membership interest in Tri-States. We do not control these projects or joint ventures or their governing boards. As a result, our ability to pay cash distributions to our unitholders will depend in part on factors beyond our control, such as the performance of these projects or joint ventures and their distributions of cash to us. Cash distributions to us may be reduced or suspended if the assets comprising the businesses of these projects or joint ventures, or the assets of their customers, are adversely impacted by operational hazards.
Further, additional projects we may acquire may be subject to a similar structure where we do not own a majority of the project or project entity and we may invest in joint ventures in which we share control or in which we are a minority investor. In these instances, the majority investor or controlling investor may not have the level of experience, technical expertise, human resources management and other attributes necessary to operate these assets optimally.
A decrease in demand for natural gas, NGLs or condensate by the petrochemical, refining or heating industries, could adversely affect the profitability of our midstream business.
Various factors impact the demand for natural gas, NGLs and condensate, including general economic conditions, extended periods of ethane rejection, increased competition from petroleum-based products due to pricing differences, adverse weather conditions, availability of natural gas processing and transportation capacity and government regulations affecting prices and
production levels of natural gas, NGLs and condensate. In addition, certain of our operating costs and expenses are fixed and do not vary with the volumes we transport or redeliver. These costs and expenses may not decrease ratably or at all should we experience a reduction in the volumes we sell, transport or redeliver. As a result, a decrease in demand for natural gas, NGLs or condensate by the petrochemical, refining or heating industries, could decrease volumes and adversely affect the margin and profitability of our midstream business.
We depend on a relatively small number of customers for a significant portion of our gross margin. The loss of any one of these customers could adversely affect our ability to make distributions.
A significant percentage of the gross margin in each of our segments is attributable to a relatively small number of customers. Additionally, a number of customers upon which our business depends are small companies that may have limited access to capital or that may, as a result of operational incidents or other events, be disproportionately affected as compared to larger, better capitalized companies. Although we have gathering, processing and transmission contracts with significant customers of varying duration and commercial terms, if one or more of these customers were to default on their contract or if we were unable to renew our contract with one or more of these customers on favorable terms, we may not be able to replace these customers in a timely fashion, on favorable terms or at all. In any of these situations, our gross margin and cash flows and our ability to make cash distributions to our unitholders may be adversely affected. We expect our exposure to concentrated risk of non-payment or non-performance to continue as long as we remain substantially dependent on a relatively small number of customers for a substantial portion of our gross margin.
Our industry is highly competitive and increased competitive pressure could adversely affect our business and operating results.
We compete with other midstream companies in our areas of operation. In addition, some of our competitors are large companies that have greater financial, managerial and other resources than we do. Our competitors may expand or construct gathering, compression, treating, processing, transportation or terminaling systems that would create additional competition for the services we provide to our customers. In addition, our customers may develop their own gathering, compression, treating, processing or transportation systems in lieu of using ours. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenue and cash flow could be adversely affected by the activities of our competitors and our customers. All of these competitive pressures could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.
Our gathering, processing, transportation and terminal contracts subject us to renewal risks.
We gather, purchase, process, transport and sell most of the commodities on our systems under contracts with terms of various durations, including contracts that have terms as short as one month or which are cancellable on as little as 30 days’ notice, and which may be difficult to extend or replace. We provide NGL sales and distribution services, refined products terminals, crude oil pipeline services and above-ground storage services that support various commercial customers. As these contracts expire, we may have to negotiate extensions or renewals with existing suppliers and customers or enter into new contracts with other suppliers and customers. We may be unable to obtain new contracts on favorable commercial terms, if at all. We also may be unable to maintain the economic structure of a particular contract with an existing customer or the overall mix of our contract portfolio. For example, depending on prevailing market conditions at the time of a contract renewal, gathering and processing customers with percent-of-proceeds contracts may choose to switch to fee-based gathering and transportation contracts, or a producer with whom we have a natural gas purchase contract may choose to enter into a transportation contract with us and retain title to its natural gas. To the extent we are unable to renew our existing contracts on terms that are favorable to us or successfully manage our overall contract mix over time, our revenue, gross margin and cash flows could decline and our ability to make distributions to our unitholders could be materially and adversely affected.
A significant increase in motor fuel costs or other commodity prices may adversely affect our profits.
Motor fuel is a significant operating expense for us in connection with the operation of both our crude oil pipelines and storage and NGL distribution and sales segments. Although contracts typically have a fuel surcharge, a significant increase in motor fuel prices will result in increased transportation costs to us. The price and supply of motor fuel is unpredictable and fluctuates based on events we cannot control, such as geopolitical developments, supply and demand for oil and gas, actions by oil and gas producers, war and unrest in oil-producing countries and regions, regional production patterns and weather concerns. As a result, any increases in these prices may adversely affect our profitability and competitiveness.
Environmental, health and safety costs and liabilities, and changing environmental, health and safety regulation, could have a material adverse effect on our financial position, results of operations and cash flows.
Our operations are subject to various environmental, health and safety requirements and potential liabilities under extensive federal, state and local laws and regulations. Further, we cannot ensure that existing environmental, health and safety laws or regulations will not be revised or that new laws or regulations will not be adopted or become applicable to us. Governmental authorities have the power to enforce compliance with applicable laws, regulations and permits and to subject violators to civil and criminal penalties, including substantial fines, injunctions or both. Certain environmental laws, including CERCLA and analogous state laws and regulations, may impose strict, joint and several liability for costs required to clean-up and restore sites where hazardous substances or hydrocarbons have been disposed or otherwise released. Moreover, third parties, including neighboring landowners, may also have the right to pursue legal actions to enforce compliance or to recover for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. Failure to comply with these requirements may expose us to fines, penalties, remedial liabilities or interruptions or delays in our operations that could have a material adverse effect on our financial position, results of operations and cash flows.
In addition, future environmental, health and safety law developments, such as stricter laws, regulations, permits or enforcement policies, could significantly increase some costs of our operations. Areas of potential future environmental, health and safety law development include the following items:
Greenhouse Gases/Climate Change. From time to time, the U.S. Congress has considered legislation to reduce emissions of greenhouse gases but no such legislation has yet been adopted by Congress. In addition, some states, including states in which our facilities or operations are located, have individually or in regional cooperation, imposed restrictions on greenhouse gas emissions under various policies and approaches, including establishing a cap on emissions, requiring efficiency measures, or providing incentives for pollution reduction, use of renewable energy sources, or use of replacement fuels with lower carbon content.
The EPA initiated the regulation of greenhouse gases under its Clean Air Act authority in 2009, requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States beginning in 2011 for emissions occurring in 2010. On November 30, 2010, the EPA published a final rule expanding its existing GHG emissions reporting rule for petroleum and natural gas facilities, including natural gas transmission compression facilities that emit 25,000 metric tons or more of carbon dioxide equivalent per year. The rule, which went into effect on December 30, 2010, requires reporting of greenhouse gas emissions by regulated facilities to the EPA annually. In October 2015, the EPA amended and expanded greenhouse gas reporting requirements to all segments of the crude oil and natural gas industry, including gathering and compression facilities and blowdowns of natural gas transmission pipelines, starting with the 2016 reporting year, and in January 2016, the EPA proposed additional revisions to leak detection methodology to align the reporting rule with the new source performance standards. A number of our facilities, including our Bazor Ridge and Chatom systems, are subject to greenhouse gas reporting, and we have filed annual emission reports for these facilities since March 2012.
Federal agencies also have begun directly regulating emissions of methane (a greenhouse gas) from crude oil and natural gas operations. In June 2016, the EPA issued new source performance standards for methane from new and modified crude oil and natural gas industry sources. These regulations will expand upon the 2012 EPA new source performance standard rulemaking for equipment-specific emissions control requirements, and will, for example, require additional controls for pneumatic controllers and pumps, and compressors, and impose leak detection and repair requirements for natural gas compressor and booster stations. However, the EPA is currently engaged in rulemaking to stay the effective date of these rules. The EPA had announced plans to begin work on regulations to regulate methane emissions from existing oil and gas sources. In November 2016, the BLM issued rules requiring additional efforts by producers to reduce venting, flaring, and leaking of natural gas produced on federal and Native American lands. In December 2017, implementation of this rule was delayed until January 2019. On an international level, in April 2016, the United States became one of almost 175 nations that signed onto the Paris Agreement, an international climate change agreement that calls for countries to set their own greenhouse gas emissions targets and be transparent about the measures each country will use to achieve its greenhouse gas emissions targets. However, in June 2017, President Trump announced that the United States plans to withdraw from the Paris Agreement and to seek negotiations either to reenter the Paris Agreement on different terms or establish a new framework agreement.
The adoption and implementation of any international, federal, state or local regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could require us to incur significant costs to reduce emissions of greenhouse gases associated with our operations or could adversely affect demand for the commodities that we buy or sell, transport, store or otherwise handle in connection with our midstream services. In addition, the adoption and implementation of any international, federal, state or local regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, the equipment and operations of our producer customers could affect their ability to produce the commodities that we
buy or sell, transport, store or otherwise handle in connection with our midstream services. The potential increase in our operating costs could include among other things costs to operate and maintain our facilities, install new emission controls on our facilities, acquire allowances to authorize our greenhouse gas emissions, pay taxes related to our greenhouse gas emissions, and administer and manage a greenhouse gas emissions program. We may not be able to recover such increased costs through customer prices or rates. In addition, changes in regulatory policies that result in a reduction in the demand for hydrocarbon products that are deemed to contribute to greenhouse gases, or restrictions on their use, may reduce volumes available to us for processing, transportation, marketing and storage. These developments could have a material adverse effect on our financial position, results of operations and cash flows. Finally, increasing attention to the risks of climate change has resulted in an increased possibility of lawsuits brought by public and private entities against oil and gas companies in connection with their greenhouse gas emissions. Should we be targeted by any such litigation, we may incur liability, which, to the extent that societal pressures or political or other factors are involved, could be imposed without regard to the company’s causation of or contribution to the asserted damage, or to other mitigating factors.
Hydraulic Fracturing. Certain of our customers employ hydraulic fracturing techniques to stimulate natural gas and crude oil production from unconventional geological formations (including shale formations), which entails the injection of pressurized fracturing fluids (consisting of water, sand and certain chemicals) into a well bore. From time to time, the United States has considered the adoption of legislation to provide for federal regulation of hydraulic fracturing, and several governmental reviews, including a study being performed by the EPA, are underway that focus on environmental aspects of hydraulic fracturing activities. Moreover, some states and localities, have adopted, and others are considering adopting, regulations or ordinances that could restrict hydraulic fracturing in certain circumstances, or that would impose higher taxes, fees or royalties on natural gas production, or otherwise limit the use of the technique. States could elect to prohibit high volume hydraulic fracturing altogether, following the approach taken by the State of New York in 2015. Increased regulation to the hydraulic fracturing process also could lead to a reduction in crude oil and natural gas drilling activities using hydraulic fracturing techniques, whereas increased public opposition to activities using such techniques may result in operational delays, restriction or litigation. Additional legislation or regulation could also lead to operational delays or increased operating costs in the production of crude oil and natural gas incurred by our customers or could make it more difficult for them to perform hydraulic fracturing. If these legislative and regulatory initiatives cause a material decrease in the drilling or production of new wells and related servicing activities, it may affect the volume of hydrocarbon projects available to our midstream business and have a material adverse effect on our financial position, results of operations and cash flows.
The value of our interests in operations located in the U.S. Gulf of Mexico could be adversely impacted by increased regulation and continuing regulatory uncertainty.
Operations in the U.S. Gulf of Mexico have been subject to an increasingly stringent regulatory environment including government regulations focused on offshore operating requirements, spill cleanup, and enforcement matters. These regulations also implement additional safety and certification requirements applicable to offshore activities in the U.S. Gulf of Mexico. Certain operating assets such as our High Point system, Destin system, Okeanos system and our Offshore Texas system, and certain non-operated interests in operations located in the U.S. Gulf of Mexico that we currently hold or may hold in the future, are subject to such increased regulations, including our non-operated interests in Delta House. In addition, the Bureau of Safety and Environmental Enforcement and the Bureau of Ocean Energy Management has increased regulatory activity including shortening the time period a line may be inactive before it must be removed or abandoned and requiring additional supplemental bonding or other forms of providing abandonment security for offshore facilities on the Outer Continental Shelf. These new regulations have increased our operating costs, and the operating costs of our producer customers. As a result, the value of our interests in these operations may be adversely affected by these regulations. Future regulatory requirements could delay activities from these operations and reduce our revenues, resulting in reduced cash flows and profitability. Moreover, any failure to satisfy these regulatory requirements by our producing customers could result in the commencement of enforcement proceedings or the taking of other remedial action, including assessing civil penalties, ordering suspension of operations or production, or initiating procedures to cancel leases, which, if upheld, could materially reduce the demand for our services.
Significant portions of our pipeline systems have been in service for several decades and we have a limited ownership history with respect to all of our assets. There could be unknown events or conditions or increased maintenance or repair expenses and downtime associated with our pipelines that could have a material adverse effect on our business and results of operations.
Significant portions of the pipeline systems that we have purchased had been in service for many decades prior to our purchase. Consequently, our executive management team has a limited history of operating such assets. There may be historical occurrences or latent issues regarding our pipeline systems that our executive management may be unaware of and that may have a material adverse effect on our business and results of operations. The age and condition of our pipeline systems could also result in increased maintenance or repair expenditures, and any downtime associated with increased maintenance and repair activities could materially reduce our revenue. Any significant increase in maintenance and repair expenditures or loss of revenue due to the age or condition
of our pipeline systems could adversely affect our business and results of operations and our ability to make cash distributions to our unitholders.
We may incur significant costs and liabilities as a result of increasingly stringent pipeline safety regulation, including pipeline integrity management program testing and related repairs.
Pursuant to the Pipeline Safety Improvement Act of 2002, as reauthorized and amended by the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006, the DOT, through PHMSA, has adopted regulations requiring pipeline operators to develop integrity management programs for transmission pipelines located in “high consequence areas,” including high population areas, unless the operator effectively demonstrates by risk assessment that the pipeline could not affect the area. The regulations require operators, including us, to:
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• | perform ongoing assessments of pipeline integrity; |
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• | identify and characterize applicable threats to pipeline segments that could impact a high consequence area; |
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• | maintain processes for data collection, integration and analysis; |
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• | repair and remediate pipelines as necessary; and |
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• | implement preventive and mitigating actions. |
In addition, many states have adopted regulations similar to existing DOT regulations for intrastate gathering and transmission lines. Although many of our natural gas facilities fall within a class that is not subject to these requirements, we may incur significant costs and liabilities associated with repair, remediation, preventative or mitigation measures associated with our non-exempt pipelines, particularly our AlaTenn and Midla pipelines. We currently estimate that we will incur future costs of approximately $2 million during 2018 to complete the testing required by existing DOT regulations. This estimate does not include the costs, if any, for repair, remediation, preventative or mitigating actions that may be determined to be necessary as a result of the testing program, which could be substantial. Such costs and liabilities might relate to repair, remediation, preventative or mitigating actions that may be determined to be necessary as a result of the testing program, as well as lost cash flows resulting from shutting down our pipelines during the pendency of such repairs. Additionally, should we fail to comply with DOT regulations, we could be subject to penalties and fines.
The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“2011 Pipeline Safety Act”), which became law in January 2012, increases the penalties for safety violations, establishes additional safety requirements for newly constructed pipelines and requires studies of safety issues that could result in the adoption of new regulatory requirements for existing pipelines. More recently, in June 2016, President Obama signed the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (“2016 Pipeline Safety Act”) that extends PHMSA’s statutory mandate through 2019 and, among other things, requires PHMSA to complete certain of its outstanding mandates under the 2011 Pipeline Safety Act and develop new safety standards for natural gas storage facilities by June 22, 2018. The 2016 Pipeline Safety Act also empowers PHMSA to address imminent hazards by imposing emergency restrictions, prohibitions and safety measures on owners and operators of gas or hazardous liquid pipeline facilities without prior notice or an opportunity for a hearing.
In April 2015, PHMSA proposed rulemaking that would require leak detection for all “hazardous liquid pipelines” such as crude oil and NGL pipelines and require periodic assessment of hazardous liquid pipelines not already covered by the integrity management requirements. On January 13, 2017, PHMSA issued a final rule requiring the use of leak detection systems beyond HCAs to all regulated, non-gathering hazardous liquid pipelines and requiring integrity assessments at least once every ten years of onshore, piggable, transmission hazardous liquid pipeline segments located outside of HCAs. The effective date of this final rule is currently uncertain due to a regulatory freeze implemented by the Trump administration. In addition, in March 2016, PHMSA announced a proposed rulemaking that would impose new or more stringent requirements for certain gas lines and gathering lines including, among other things, expanding certain of PHMSA’s current regulatory safety programs for gas pipelines in newly defined “moderate consequence areas” that contain as few as 5 dwellings within a potential impact area; requiring gas pipelines installed before 1970 and thus excluded from certain pressure testing obligations to be tested to determine their maximum allowable operating pressures (“MAOP”); and requiring certain onshore and offshore gathering lines in Class I areas to comply with damage prevention, corrosion control, public education, MAOP limits, line markers and emergency planning standards. Additional requirements proposed by this proposed rulemaking would increase PHMSA’s integrity management requirements and also require consideration of seismicity in evaluating threats to pipelines. Such legislative and regulatory changes could have a material effect on our operations and costs of transportation services. Additionally, legislative and regulatory changes may also result in higher penalties for the violation of federal pipeline safety regulations and the costs associated with compliance may have a material effect on our operations. We cannot predict with any certainty at this time the terms of any new laws or rules or the costs of compliance associated with such requirements.
A downgrade in our credit ratings could impact our access to capital and costs of doing business, and maintaining credit ratings is under the control of independent third parties.
Rating agencies may reevaluate our ratings, and any additional actual or anticipated downgrades in such credit ratings could limit our ability to access credit and capital markets, including to finance the SXE Transactions, or to restructure or refinance our indebtedness. On November 1, 2017, S&P and Moody’s both announced that our long term credit rating had been placed on watch as a result of the announcement of the SXE Transactions. As a result of any potential downgrades, future financing or refinancing, including to finance the SXE Transactions, may result in higher borrowing costs and require more restrictive terms and covenants, including obligations to post collateral with third parties, which may further restrict our operations and negatively impact liquidity.
Credit rating agencies perform independent analysis when assigning credit ratings. The analysis includes a number of criteria including, but not limited to, business composition, market and operational risks, as well as various financial tests. Credit rating agencies continue to review the criteria for industry sectors and various debt ratings and may make changes to those criteria from time to time. Credit ratings are not recommendations to buy, sell or hold investments in the rated entity. Ratings are subject to revision or withdrawal at any time by the rating agencies, and we cannot assure you that we will maintain our current credit ratings.
We intend to grow our business in part by continuing to seek strategic acquisition opportunities. If we are unable to make acquisitions on economically acceptable terms from third parties, our future growth will be limited, and the acquisitions we do make may reduce, rather than increase, our cash generated from operations on a per unit basis.
Our ability to grow depends, in part, on our ability to make acquisitions that increase our cash generated from operations on a per unit basis. The acquisition component of our strategy is based, in large part, on our expectation of ongoing divestitures of midstream energy assets by industry participants. A material decrease in such divestitures would limit our opportunities for future acquisitions and could adversely affect our ability to grow our operations and increase our distributions to our unitholders.
If we are unable to make accretive acquisitions from third parties, whether because we are: (i) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts, (ii) unable to obtain financing for these acquisitions on economically acceptable or attractive terms or (iii) outbid by competitors or for any other reason, then our future growth and ability to increase distributions will be limited. Furthermore, even if we do make acquisitions that we believe will be accretive, these acquisitions may nevertheless result in a decrease in the cash generated from operations on a per unit basis.
Any acquisition involves potential risks, including, among other things:
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• | assumptions about volumes, revenue, decline rates, drilling activity and cost savings, including synergies; |
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• | inability to secure adequate customer commitments to use the acquired systems or facilities; |
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• | inability to integrate successfully the assets or businesses we acquire, particularly given the relatively small size of our management team and its limited history with certain assets; |
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• | assumption of unknown liabilities, including environmental contamination; |
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• | limitations on rights to indemnity from the seller; |
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• | assumptions about the overall costs of equity or debt; |
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• | diversion of management’s and employees’ attention from other business concerns; |
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• | entry of competitors in the markets where the acquired business competes; |
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• | difficulties operating in new geographic areas and business lines; and |
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• | customer or key employee losses at the acquired businesses. |
If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and our unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.
Our construction of new assets may not result in increased revenue and will be subject to regulatory, environmental, political, legal and economic risks, which could adversely affect our results of operations and financial condition.
One of the ways we intend to grow our business is through organic growth projects. The construction of additions or modifications to our existing systems and the construction of new midstream assets involve numerous regulatory, environmental, political, legal and economic uncertainties that are beyond our control, including the availability of skilled labor, equipment and materials to complete expansion projects and potential changes in federal, state and local statutes and regulations, including environmental requirements, that may delay or prevent a project from proceeding or increase the anticipated cost of the project. Such expansion projects may also require the expenditure of significant amounts of capital, and financing may not be available on economically acceptable terms or at all. If we undertake these projects, they may not be completed on schedule, at the budgeted
cost, or at all. Cost overruns on construction projects may cause unexpected changes in project economics. Moreover, our revenue may not increase immediately upon the expenditure of funds on a particular project.
For instance, if we expand a pipeline, the construction may occur over an extended period of time, yet we will not receive any material increases in revenue until the project is completed and placed into service. Moreover, we could construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize or only materializes over a period materially longer than expected. Since we are not engaged in the exploration for, and development of, natural gas and crude oil reserves, we often do not have access to third-party estimates of potential reserves in an area prior to constructing facilities in that area. To the extent we rely on estimates of future production in our decision to construct additions to our systems, such estimates may prove to be inaccurate as a result of the numerous uncertainties inherent in estimating quantities of future production. As a result, new facilities may not attract enough throughput to achieve our expected investment return, which could adversely affect our results of operations and financial condition.
In addition, the construction of additions to our existing gathering and transportation assets, or the construction of new gathering and transportation assets, may require us to obtain new rights-of-way. We may be unable to obtain such rights-of-way and may, therefore, be unable to connect new natural gas volumes to our systems or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us to obtain new rights-of-way or to renew existing rights-of-way. If the cost of renewing or obtaining new rights-of-way increases materially, our cash flows could be adversely affected.
In connection with our expansion capital programs, we have agreed, and may in the future agree, to construct oil and gas gathering pipelines to service existing and future oil and gas properties, which involves potential risks.
In connection with our expansion capital programs, we have agreed, and may in the future agree, at our cost and expense, to design, acquire right-of-way for, obtain all permits from governmental authorities for, procure materials for, construct, operate, and maintain additional gathering pipelines for connection to certain current and future producing crude oil and natural gas properties. There are risks involved with such obligations, including:
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• | general construction cost overruns and delays resulting from numerous factors, many of which may be out of our control; |
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• | the inability to obtain required permits for the pipelines; |
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• | the inability to obtain rights-of-way for the gathering pipelines, which may result in pipelines being re-routed, which itself could result in cost overruns and delays; |
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• | the risk associated with producer’s exploration and production activities and the associated potential failure of the gathering pipelines to generate attractive cash flows given our obligation to construct and operate them; and |
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• | title issues or environmental or regulatory compliance matters or liabilities or accidents associated with the construction or operation of the pipelines. |
We currently expect to fund these costs with borrowings under our revolving credit facility or by accessing the capital markets. If we are unable to finance the expansion costs with existing liquidity, we could be required to seek alternative sources of liquidity, which could be costly or may not be available. In the event expansion and extension of the crude oil and natural gas properties is significantly more expensive than we expect or we are unable to obtain financing for such construction, it could have a material adverse effect on our financial condition, including our results of operations and cash flows.
Our business involves many hazards, operational risks and litigation risks, some of which may not be fully covered by insurance. If a significant accident, event or judgment occurs for which we are not adequately insured, our operations and financial results could be adversely affected.
Our operations are subject to all of the risks and hazards inherent in the gathering, compressing, treating, processing and transportation of natural gas, including:
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• | damage to pipelines, plants, storage facilities, related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires, earthquakes and other natural disasters and acts of terrorism; |
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• | inadvertent damage from construction, vehicles, farm and utility equipment; |
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• | leaks of natural gas and other hydrocarbons or losses of natural gas as a result of the malfunction of equipment or facilities; |
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• | ruptures, fires and explosions; and |
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• | other hazards that could also result in personal injury and loss of life, pollution and suspension of operations. |
These risks could result in substantial losses due to personal injury or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage. These risks may also result in curtailment or suspension of our operations. In addition, we have been, and are likely to continue to be, a defendant in various legal proceedings and litigation arising in the ordinary course of business, both as a result of these operating hazards and risks and as a result of other aspects of our business. A natural disaster or other hazard affecting the areas in which we operate could have a material adverse effect on our operations.
We are not fully insured against all risks inherent in our business. For example, we do not have any casualty insurance on our underground pipeline systems that would cover damage to the pipelines. We are self-insured for general and product, workers’ compensation and automobile liabilities up to predetermined amounts above which third-party insurance applies. Additionally, we do not have business interruption/ loss of income insurance that would provide coverage in the event of damage to any of our underground facilities. In addition, although we are insured for environmental pollution resulting from environmental accidents that occur on a sudden and accidental basis, we may not be insured against all environmental accidents that might occur, some of which may result in toxic tort claims. We cannot guarantee that our insurance will be adequate to protect us from all material expenses related to potential future claims for personal injury and property damage. If a significant accident or event occurs for which we are not fully insured, it could have a material adverse effect on our operations and financial condition. Furthermore, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies may substantially increase. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. Additionally, we may be unable to recover from prior owners of our assets, pursuant to our contractual indemnification rights for potential environmental liabilities.
Our interstate natural gas, crude oil and NGL pipelines are subject to regulation by FERC, which could adversely affect our ability to make distributions to our unitholders.
Our AlaTenn, Trans-Union and Midla interstate natural gas transportation systems, our Destin pipeline, which we operate and own 66.7%, and a portion of our High Point system, are subject to regulation by FERC, under the NGA. Under the NGA, the rates for and terms of conditions of service on these interstate facilities must be just and reasonable and not unduly discriminatory. The rates and terms and conditions for our interstate pipeline services are set forth in tariffs that must be filed with and approved by FERC. Pursuant to FERC’s jurisdiction over rates, existing rates may be challenged by complaint and proposed rate increases may be challenged by protest. Any successful complaint or protest against our rates could have an adverse impact on our revenue associated with providing transportation service.
Under the NGA, FERC has the authority to regulate companies that provide natural gas pipeline transportation services in interstate commerce. FERC’s authority over such companies includes such matters as:
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• | rates, terms and conditions of service; |
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• | the types of services interstate pipelines may offer to their customers; |
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• | the certification and construction of new facilities; |
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• | the acquisition, extension, disposition or abandonment of facilities; |
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• | the maintenance of accounts and records; |
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• | relationships between affiliated companies involved in certain aspects of the natural gas business; |
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• | the initiation and discontinuation of services; |
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• | market manipulation in connection with interstate sales, purchases or transportation of natural gas; and |
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• | participation by interstate pipelines in cash management arrangements. |
The EP Act 2005 amended the NGA to add an anti-manipulation provision. Pursuant to the amended NGA, FERC established rules prohibiting energy market manipulation. Also, FERC’s rules require interstate pipelines and their affiliates to adhere to Standards of Conduct that, among other things, require that transportation employees function independently of marketing employees. We are subject to audit by FERC of our compliance in general, including adherence to all its rules and regulations. A violation of these rules, or any other rules, regulations or orders issued or administered by FERC, may subject us to civil penalties, disgorgement of certain profits, or appropriate non-monetary remedies imposed by FERC. In addition, the EP Act 2005 amended the NGA and the NGPA, to increase civil and criminal penalties for any violation of the NGA, NGPA and any rules, regulations or orders of FERC. Under the EP Act 2005, the FERC is authorized to impose civil penalties of up to $1,000,000 per violation, per day for violations of the NGA, the NGPA or the rules, regulations, restrictions, conditions and orders promulgated under those statutes. This maximum penalty authority established by statute will continue to be adjusted periodically for inflation. The current maximum daily penalty for a violation is $1,238,271.
Additionally, existing rates may not reflect our current costs of operations, which may have risen since the last time our rates were approved by FERC.
Our Bakken crude oil gathering system, FERC-regulated American Panther, LLC offshore liquids pipelines (known as the Tiger Shoals and MP 77 offshore pipeline systems) and the Tri-States and Wilprise NGL pipelines, in which we have equity investments, are regulated as common carrier interstate pipelines by the FERC under the ICA, the EP Act 1992 and the rules and regulations promulgated under those laws. FERC regulations require that rates and terms and conditions of service for interstate service pipelines that transport crude oil be just and reasonable and must not be unduly discriminatory or confer any undue preference upon any shipper. FERC’s regulations also require interstate common carrier petroleum pipelines to file with FERC and publicly post tariffs stating their interstate transportation rates and terms and conditions of service.
Rates of interstate liquids pipelines are currently regulated by FERC primarily through an annual indexing methodology, under which pipelines increase or decrease their rates in accordance with an index adjustment specified by FERC. For the five-year period beginning on July 1, 2016, FERC established an annual index adjustment equal to the change in the producer price index for finished goods plus 1.23%. Under FERC’s regulations, liquids pipelines can request a rate increase that exceeds the rate obtained through application of the indexing methodology by using a cost-of-services approach, but only after the pipeline establishes that a substantial divergence exists between the actual costs experienced by the pipeline and the rates resulting from application of the indexing methodology.
Under the ICA, FERC or interested persons may challenge existing or proposed new or changed rates, services, or terms and conditions of service. FERC is authorized to investigate such charges and may suspend the effectiveness of a new rate for up to seven months. FERC could require a common carrier pipeline to collect rates subject to refund until completion of an investigation during which FERC could find that the new or changed rate is unlawful. In contrast, FERC has clarified that initial rates and terms of service agreed upon with committed shippers in a transportation services agreement are not subject to protest or a cost-of-service analysis where the pipeline held an open season offering all potential shippers service on the same terms.
A successful rate challenge could result in a common carrier pipeline paying refunds of revenue collected in excess of the just and reasonable rate, together with interest for the period the rate was in effect, if any. FERC may also order a pipeline to reduce its rates prospectively, and may require a common carrier pipeline to pay shippers reparations retroactively for rate overages for a period of up to two years prior to the filing of a complaint. FERC also has the authority to change terms and conditions of service if it determines that they are unjust or unreasonable or unduly discriminatory or preferential.
Our intrastate natural gas and gathering transportation and sales services are subject to regulation by state and federal agencies, which could adversely affect our ability to make cash distributions to our unitholders.
Certain of our intrastate natural gas pipeline operations are subject to regulation by various agencies of the states in which they are located. Most states have agencies that possess the authority to review and authorize natural gas transportation transactions and the construction, acquisition, abandonment and interconnection of physical facilities. Some states also have state agencies that regulate transportation rates, service terms and conditions and contract pricing to ensure their reasonableness and to ensure that the intrastate pipeline companies that they regulate do not discriminate among similarly situated customers. Such agencies could limit our ability to increase our rates or order us to reduce our rates and pay refunds to shippers. State agencies can also regulate whether a service may be provided or cancelled. If state agencies in the states in which we offer intrastate transportation services change their policies or aggressively regulate our rates or terms and conditions of service, it could also adversely affect our ability to make cash distributions to our unitholders.
Certain of our intrastate natural gas pipelines transport gas in interstate commerce that is subject to FERC jurisdiction under Section 311 of the NGPA or are exempt from FERC jurisdiction as Hinshaw pipelines but have received blanket authorization to transport natural gas on behalf of interstate pipelines. The maximum rates for services provided under Section 311 of the NGPA may not exceed a “fair and equitable rate,” as defined in the NGPA. The rates are generally subject to review every five years by FERC or by an appropriate state agency. The inability to obtain approval of rates at acceptable levels could result in refund obligations and an inability to make cash distributions to our unitholders.
Intrastate natural gas pipelines, which operate entirely within a single state, are generally not subject to FERC’s jurisdiction under the NGA. Hinshaw pipelines operate within a single state but may receive gas from outside their state without becoming subject to FERC jurisdiction under the NGA. Specifically, a Hinshaw pipeline is exempt from FERC’s general NGA regulation if: (1) it receives natural gas at or within the boundary of a state; (2) all the gas is consumed within that state; and (3) the pipeline is regulated by a state commission. Hinshaw pipelines may also receive authorization under Part 284, subpart G of the FERC’s regulations to transport natural gas on behalf of interstate pipelines or a local distribution company served by an interstate pipeline.
Certain of our pipelines which transport gas in interstate commerce are “Hinshaw” pipelines exempt from the jurisdiction of the FERC jurisdiction under Section 1(c) of the NGA, and we may have additional Hinshaw pipelines in the future. Each of our current Hinshaw pipelines has received a “blanket certificate” under 18 C.F.R. Section 284.244 to transport gas. The maximum
rates for services provided the blanket certificate may not exceed a “fair and equitable rate,” as defined in the FERC Regulations. The rates are generally subject to review every five years by FERC or by an appropriate state agency. The inability to obtain approval of rates at acceptable levels could result in refund obligations and an inability to make cash distributions to our unitholders.
The FERC’s anti-manipulation rules apply to non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction. The new anti-manipulation rules do not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but only to the extent such transactions do not have a “nexus” to jurisdictional transactions. As noted above, the FERC’s civil penalty authority under the EP Act of 2005 would apply to violations of these rules to the extent applicable to our intrastate natural gas services.
The application of certain FERC policy statements could affect the rate of return on our equity that we are allowed to recover through rates and the amount of any allowance our interstate systems can include for income taxes in establishing their rates for service, which would in turn impact our revenue or equity earnings.
FERC currently allows partnerships, including MLPs, to include in their cost-of-service an income tax allowance if the partnership’s owners have actual or potential income tax liability, a matter that will be reviewed by FERC on a case-by-case basis. In July 2016, the United States Court of Appeals for the District of Columbia Circuit issued its opinion in United Airlines, Inc., et al. v. FERC, finding that FERC had acted arbitrarily and capriciously when it failed to demonstrate that permitting an interstate petroleum products pipeline organized as a limited partnership to include an income tax allowance in the cost of service underlying its rates in addition to the discounted cash flow return on equity would not result in the pipeline partnership double-recovering the income tax liability of its investors. The court vacated FERC’s order and remanded to FERC to consider mechanisms for demonstrating that there is no double recovery as a result of the income tax allowance. On December 15, 2016, FERC issued a Notice of Inquiry seeking comment on how to address any double recovery resulting from income tax allowance policy. The ultimate outcome of this proceeding is not certain and could result in changes going forward to FERC’s treatment of income tax allowances in the cost of service or to the discounted cash flow return on equity. On March 15, 2018, FERC issued an order on remand in the United Airlines case and a revised policy statement on income tax recovery that disallows income tax allowances for master limited partnerships in cost of service rates. In addition, FERC issued a notice of proposed rulemaking on March 15, 2018 that proposes to require all interstate natural gas pipelines to submit cost of service information to account for reductions in cost of service resulting from FERC’s new policy on income tax allocations for master limited partnerships and the reduction in the corporate tax rate from the Tax Cuts and Jobs Act that went into effect January 1, 2018. As a result of this new policy and proposed rule, the cost of service rates of our interstate pipelines could be affected to the extent they propose new rates or changes to their existing rates or if their rates are subject to complaint or challenged by FERC. However, we have considered the impact the proposed policy changes by the FERC would have on us, and we have determined that based on the current rate structure on the Partnership's FERC regulated pipelines, the proposed changes are expected to have a negligible impact on the earnings and cash flow of the Partnership. Although we cannot predict whether FERC will propose any additional policy revisions, we expect any such policy revisions will have limited application to us, because a substantial majority of the Partnership's operations are not FERC regulated.
A change in the jurisdictional characterization or regulation of our assets by federal, state or local regulatory agencies or a change in policy by those agencies could result in increased regulation of our assets which could materially and adversely affect our financial condition, results of operations and cash flows.
Gas gathering facilities and intrastate transportation facilities that do not provide interstate transmission services are exempt from the jurisdiction of FERC under the NGA. In Docket No. CP12-9, the FERC determined that certain portions of our High Point system met the gathering exemption from regulation under the NGA. Although FERC has not made any formal determinations with respect to any of our other facilities, we believe that our gathering and intrastate natural gas pipelines and related facilities that are not engaged in providing interstate transmission services are engaged in exempt gathering and intrastate transportation and, therefore, are not subject to FERC jurisdiction. We believe that our natural gas gathering pipelines meet the traditional tests that FERC has used to determine if a pipeline is a gathering pipeline and is therefore not subject to FERC’s jurisdiction. The distinction between FERC- regulated transmission services and federally unregulated gathering services is the subject of substantial ongoing litigation and, over time, FERC’s policy for determining which facilities it regulates has changed. In addition, the distinction between FERC-regulated transmission facilities, on the one hand, and intrastate transportation and gathering facilities, on the other, is a fact-based determination made by FERC on a case- by-case basis. If FERC were to consider the status of an individual facility and determine that the facility or services provided by it are not exempt from FERC regulation under the NGA, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by FERC under the NGA. Such regulation could decrease revenue, increase operating costs, and, depending upon the facility in question, could adversely affect our results of operations and cash flows. In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the NGA or NGPA, this could result in the imposition of civil penalties as well as a requirement to disgorge charges collected for such service in excess of the cost-based rate established by FERC.
Moreover, FERC regulation affects our gathering, transportation and compression business generally. FERC’s policies and practices across the range of its natural gas regulatory activities, including, for example, its policies on open access transportation, market manipulation, ratemaking, capacity release and market transparency and market center promotion, directly and indirectly affect our gathering business. In addition, the classification and regulation of our gathering and intrastate transportation facilities also are subject to change based on future determinations by FERC, the courts or Congress.
State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. We are subject to some state ratable take and common purchaser statutes. The ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. States in which we operate that have adopted some form of complaint-based regulation, like Texas, generally allow natural gas and crude oil producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering access and rate discrimination.
In recent years, FERC’s efforts to promote open access, transparency, and the unbundling of interstate pipeline services has prompted a number of interstate pipelines to transfer their non-jurisdictional gathering facilities to unregulated affiliates. As a result of these activities, natural gas gathering may begin to receive greater regulatory scrutiny at both the state and federal levels. Such additional scrutiny could result in increased expenses to us and a resulting materially adverse change in our finances.
We are subject to stringent environmental, safety and health laws and regulations that may expose us to significant costs and liabilities.
Our operations are subject to stringent and complex federal, state and local environmental laws and regulations that govern the discharge of materials into the environment or otherwise relate to environmental protection. Examples of these laws include:
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• | the federal Clean Air Act and analogous state laws that restrict the emission of air pollutants from many sources, imposes various pre-construction, monitoring, and reporting requirements, which the Environmental Protection Agency has relied upon as authority for adopting climate change regulatory initiatives; |
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• | the federal CERCLA and analogous state laws that regulate the cleanup of hazardous substances that may be or have been released at properties currently or previously owned or operated by us or at locations to which our wastes are or have been transported for disposal; |
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• | the federal Clean Water Act and analogous state laws that regulate discharges of pollutants from facilities to state and federal waters and establishes the extent to which waterways are subject to federal jurisdiction and rulemaking as protected waters of the United States; |
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• | the federal Oil Pollution Act of 1990 and analogous state laws that establish strict liability for releases of oil into waters of the United States; |
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• | U.S. Department of the Interior regulations, which relate to offshore oil and natural-gas operations in U.S. waters and impose obligations for establishing financial assurances for decommissioning activities, liabilities for pollution cleanup costs resulting from operations, and potential liabilities for pollution damages; |
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• | the federal Resource Conservation and Recovery Act of 1976 and analogous state laws that impose requirements for the generation, storage, treatment, transport and disposal of solid and hazardous waste from our facilities; |
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• | the Endangered Species Act of 1973 and analogous state laws that restrict activities that may affect federally or state identified endangered and threatened species or their habitats through the implementation of operating restrictions or a temporary, seasonal, or permanent ban in affected areas; |
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• | the Toxic Substances Control Act, and analogous state laws that impose requirements on the use, storage and disposal of various chemicals and chemical substances at our facilities; and |
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• | the U.S. Occupational Safety and Health Act and analogous state laws that establish workplace standards for the protection of the health and safety of employees, including the implementation of hazard communications programs designed to inform employees about hazardous substances in the workplace, potential harmful effects of these substances, and appropriate control measures. |
These laws and regulations may impose numerous obligations that are applicable to our operations, including the acquisition of permits to conduct regulated activities, the incurrence of capital or operating expenditures to limit or prevent releases of materials from our pipelines and facilities, the imposition of specific safety and health criteria addressing worker protection, and the imposition of substantial liabilities and remedial obligations for pollution resulting from our operations. Numerous governmental authorities, such as the EPA, and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly corrective actions. Failure to comply with these laws, regulations
and permits may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of injunctions limiting or preventing some or all of our operations.
In addition, we may experience a delay in obtaining or be unable to obtain required permits, which may cause us to lose potential and current customers, interrupt our operations or delay expansion projects and limit our growth and revenue. See “Business - Environmental Matters - Air Quality and Climate Control” in Item 1 of this Annual Report for more information about these matters.
There is a risk that we may incur significant environmental costs and liabilities in connection with our operations due to historical industry operations and waste disposal practices, our handling of hydrocarbons and other wastes and potential emissions and discharges related to our operations. Joint and several strict liability may be incurred, without regard to fault, under certain of these environmental laws and regulations in connection with discharges or releases of hydrocarbons and other wastes on, under or from our properties and facilities, many of which have been used for midstream activities for a number of years, oftentimes by third parties not under our control. Private parties, including the owners of the properties through which our gathering or transportation systems pass and facilities where our hydrocarbons and other wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance, as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property or natural resource damage. For example, an accidental release from one of our pipelines could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations. We may not be able to recover all or any of these costs from insurance. In addition, changes in environmental laws and regulations occur frequently, and any such changes that result in more stringent and costly waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our results of operations or financial position. See “Business - Environmental Matters” in Item 1 of this Annual Report for more information.
We may be unable to obtain or renew permits necessary for our operations or the operations we may acquire in future acquisitions.
Our facilities operate under a number of required federal and state permits, licenses and approvals with terms and conditions containing a significant number of prescriptive limits and performance standards in order to operate. All of these permits, licenses, approvals, limits and standards require a significant amount of monitoring, record keeping and reporting in order to demonstrate compliance with the underlying permit, license, approval, limit or standard. Noncompliance or incomplete documentation of our compliance status may result in the imposition of fines, penalties and injunctive relief. A decision by a government agency to deny or delay issuing a new or renewed material permit, license or approval, or to revoke or substantially modify an existing permit, license or approval, could have a material adverse effect on our financial condition, including our results of operations and cash flows.
We do not own all of the land on which our pipelines and facilities are located, which could result in disruptions to our operations.
We do not own all of the land on which our pipelines and facilities have been constructed, and we are, therefore, subject to the possibility of more onerous terms or increased costs to retain necessary land use if we do not have valid rights-of-way or if such rights-of-way lapse or terminate or do not allow us to change our operations, or we may not be able to renew our contract leases on commercially reasonable terms or at all. We obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for a specific period of time for specific types of operations. Our loss of these rights, through our inability to renew right-of-way contracts or otherwise or our inability to amend these rights for new operations, could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.
A failure in our operational systems or cyber security attacks on any of our facilities, or those of third parties, may adversely affect our financial results.
Our business is dependent upon our operational systems to process a large amount of data and complex transactions. If any of our financial, operational, or other data processing systems fail or have other significant shortcomings or downtime, our financial results could be adversely affected. Our financial results could also be adversely affected if an employee causes our operational systems to fail, either as a result of inadvertent error or by deliberately tampering with or manipulating our operational systems. In addition, dependence upon automated systems may further increase the risk that operational system flaws, employee tampering or manipulation of those systems will result in losses that are difficult to detect.
Due to increased technology advances, we have become more reliant on technology to help increase efficiency in our business. We use computer programs to help run our financial and operational departments, and these systems may subject our business to increased risks. As of December 31, 2017, we did not maintain effective controls over certain information technology general controls for a significant application used in the preparation of our financial statements. Any future cyber security attacks that affect our facilities, our customers and any financial data, including as a result of our inability to adequately restrict user and privileged access to our financial application, programs and data, could have a material adverse effect on our business. In addition, cyber-attacks on our financial, customer and employee data may result in financial loss and may negatively impact our reputation. We may experience increased capital and operating costs to implement increased security for our facilities and pipelines, such as additional physical facility and pipeline security, and additional security personnel. Third-party systems on which we rely could also suffer operational system failure. Any of these occurrences could disrupt our business, result in potential liability or reputational damage or otherwise have an adverse effect on our financial results.
Terrorist attacks and the threat of terrorist attacks may adversely impact our results of operations.
Increased security measures taken by us as a precaution against possible terrorist attacks have resulted in increased costs to our business. Uncertainty surrounding terrorist attacks in the U.S. may affect our operations in unpredictable ways, including disruptions of crude oil supplies or storage facilities, and markets for refined products, and the possibility that infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror.
Risks Related to the SXE Transactions
We may be unable to obtain the regulatory clearances required to complete the SXE Merger or, in order to do so, we may be required to comply with material restrictions or satisfy material conditions.
AMID and SXE received early termination of the applicable waiting period under the HSR Act on December 8, 2017. The Merger may still be reviewed under antitrust statutes of other governmental authorities, including by state regulatory authorities such as the MPSC. The closing of the SXE Merger is subject to the condition that there is no law, injunction, judgment or ruling by a governmental authority in effect enjoining, restraining, preventing or prohibiting the SXE Merger. We can provide no assurance that all required regulatory clearances will be obtained. If a governmental authority asserts objections to the SXE Merger, we may be required to divest assets in order to obtain antitrust clearance. There can be no assurance as to the cost, scope or impact of the actions that may be required to obtain antitrust or other regulatory approval. If we take such actions, it could be detrimental to it or to the combined organization following the consummation of the SXE Merger. Furthermore, these actions could have the effect of delaying or preventing completion of the SXE Merger or imposing additional costs on or limiting the revenues or cash available for distribution of the combined organization following the consummation of the SXE Merger.
State attorneys general could seek to block or challenge the SXE Merger as they deem necessary or desirable in the public interest at any time, including after completion of the transaction. In addition, in some circumstances, a third party could initiate a private action under antitrust laws challenging or seeking to enjoin the SXE Merger, before or after it is completed. We may not prevail and may incur significant costs in defending or settling any action under the antitrust laws.
The MPSC requires that when a company proposes a change of control of a certificate of public convenience and necessity (“CPCN”), the company must obtain an order from the MPSC approving the sale and transfer of the CPCN. Southcross Mississippi Industrial Gas Sales, L.P. (“Southcross Mississippi”), an indirect subsidiary of SXE, has a CPCN that, subject to the approval of the MPSC, will be transferred in connection with the SXE Transactions. The MPSC could decide not to issue an order authorizing the transfer of the CPCN. Moreover, there is no guarantee that, if granted, such order will be granted in a timely manner or will be free from potentially burdensome conditions.
We may have difficulty attracting, motivating and retaining employees in light of the SXE Merger.
Uncertainty about the effect of the SXE Merger on our employees may have an adverse effect on the combined organization. This uncertainty may impair our ability to attract, retain and motivate personnel until the SXE Merger is completed. Employee retention may be particularly challenging during the pendency of the SXE Merger, as employees may feel uncertain about their future roles with the combined organization. If employees depart because of issues relating to the uncertainty and difficulty of integration or a desire not to become employees of the combined organization, the combined organization’s ability to realize the anticipated benefits of the SXE Merger could be reduced.
We are subject to business uncertainties and contractual restrictions while the SXE Transactions are pending, which could adversely affect our business and operations.
In connection with the pending SXE Transactions, it is possible that some customers, suppliers and other persons with whom we have business relationships may delay or defer certain business decisions or might decide to seek to terminate, change or renegotiate their relationship with us as a result of the SXE Transactions, which could negatively affect our revenues, earnings and cash available for distribution, as well as the market price of AMID Common Units, regardless of whether the SXE Transactions completed.
Under the terms of the Merger Agreement, we are subject to certain restrictions on the conduct of our business prior to completing the SXE Merger, which may adversely affect our ability to execute certain of our business strategies. Such limitations could negatively affect our business and operations prior to the completion of the SXE Merger.
Furthermore, the process of planning to integrate two businesses and organizations for the post-merger period can divert management attention and resources and could ultimately have an adverse effect on each party.
However, we are permitted to engage in certain activities and transactions prior to completion of the SXE Merger, such as certain financings, incurrence of indebtedness, issuances of equity, sales of assets and acquisitions. Any of these transactions could affect our current and future financial and operating results and of the combined company.
The SXE Merger is subject to conditions, including certain conditions that may not be satisfied on a timely basis, if at all. Failure to complete the SXE Merger, or significant delays in completing the SXE Merger, could negatively affect the trading price of AMID Common Units and our future business and financial results.
The completion of the SXE Merger is subject to a number of conditions. The completion of the SXE Merger is not assured and is subject to risks, including the risk that approval of the SXE Merger by SXE Unitholders or by governmental agencies is not obtained or that other closing conditions are not satisfied. If the SXE Merger is not completed, or if there are significant delays in completing the SXE Merger, the trading price of AMID Common Units and our future business and financial results could be negatively affected, and we will be subject to several risks, including the following:
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• | we may be liable for damages to SXE under the terms and conditions of the Merger Agreement; |
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• | negative reactions from the financial markets, including declines in the price of AMID Common Units due to the fact that current prices may reflect a market assumption that the SXE Merger will be completed; and |
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• | the attention of our management will have been diverted to the SXE Merger rather than our own operations and pursuit of other opportunities that could have been beneficial to us. |
The SXE Merger will not occur if the conditions to closing the SXE Contribution under the SXE Contribution Agreement, including the refinancing by us of SXE’s indebtedness, are not satisfied and the closing of the SXE Contribution does not occur or if the SXE Contribution Agreement is otherwise terminated.
It is a condition to the closing of the SXE Merger under the terms of the SXE Merger Agreement that the SXE Contribution will have closed in accordance with the SXE Contribution Agreement. Additionally, the SXE Merger Agreement will terminate automatically, and the SXE Merger will not occur, if the SXE Contribution Agreement is terminated. The completion of the SXE Contribution is subject to a number of conditions, is not assured and is subject to risks, including the risk that approval by governmental agencies is not obtained or that other closing conditions are not satisfied. Additionally, if we have not obtained sufficient financing to make the cash payments required to be made at the closing of the SXE Contribution, including for the refinancing of SXE’s indebtedness, we may be required under certain circumstances to pay a reverse termination fee of $17 million to Holdings LP. We do not have in place committed financing sufficient to make the payments at the closing of the SXE Contribution, and there can be no assurances that we will be able to obtain such financing on acceptable terms or at all. Any such failure to obtain financing would likely result in the termination of the SXE Contribution Agreement and SXE Merger Agreement and the failure to complete the SXE Merger.
The number of outstanding AMID Common Units will increase as a result of the SXE Transactions, which could make it more difficult for us to pay our current level of quarterly distributions.
As of December 31, 2017, there were approximately 52.7 million AMID Common Units outstanding. We estimate that we will issue approximately 3.5 million AMID Common Units in connection with the SXE Merger and 13.6 million AMID Common Units in connection with the Contribution. Accordingly, the aggregate dollar amount required to pay the current per unit quarterly distribution on all AMID Common Units will increase, which could increase the likelihood that we will not have sufficient funds
to pay the current level of quarterly distributions to all AMID Common Unitholders. Using a $0.4125 per AMID Common Unit distribution (the distribution AMID had declared with respect to the fourth fiscal quarter of 2017 paid on February 14, 2018 to holders of record as of February 7, 2018) the aggregate cash distribution paid to AMID Common Unitholders totaled approximately $21.7 million, including a distribution to AMID GP in respect of its general partner interest. The combined pro forma AMID distribution with respect to the fourth fiscal quarter of 2017, had the SXE Merger been completed prior to such distribution, would have resulted in $0.4125 per unit being distributed on approximately 69.8 million AMID Common Units, or a total of approximately $29.1 million including a distribution of $0.3 million to AMID GP in respect of its general partner interest. As a result, we would have been required to distribute an additional $7.4 million in order to maintain the distribution level of $0.4125 per AMID Common Unit payable with respect to the fourth fiscal quarter of 2017.
A substantial number of AMID Common Units and other securities convertible into, or exercisable for, AMID Common Units, will be issued in connection with the SXE Transactions, which will dilute the ownership interests of existing unitholders, or may otherwise reduce the value of AMID Common Units.
Upon the terms and subject to the conditions set forth in the SXE Merger Agreement, at the Effective Time, each SXE Common Unit issued and outstanding as of immediately prior to the Effective Time will be converted into the right to receive 0.160 of an AMID Common Unit. In addition, upon the terms and subject to the conditions set forth in the Contribution Agreement, Holdings LP will receive AMID Common Units, Series E preferred units, which will be convertible into AMID Common Units, and the Options, which will be exercisable into AMID Common Units. The issuance of AMID Common Units in the Transaction and the issuance of AMID Common Units upon conversion of the Series E preferred units or the exercise of the Options issued in the SXE Contribution will dilute the ownership interests of existing unitholders.
While Holdings LP has agreed not to sell any AMID Common Units, or any other securities convertible into, or exercisable for, AMID Common Units, for a specified period set forth in the SXE Contribution Agreement, any sales, or expectation of sales, in the public market of AMID Common Units, including those issuable upon the conversion of the Series E preferred units or the exercise of the Options, after the expiration of such period could adversely affect prevailing market prices of AMID Common Units.
We will incur substantial transaction-related costs in connection with the SXE Transactions.
We expect to incur a number of non-recurring transaction-related costs associated with completing the SXE Transactions, combining the operations of the acquired organizations and achieving desired synergies. These fees and costs will be substantial. Non-recurring transaction costs include, but are not limited to, fees paid to financial, legal and accounting advisors, filing fees and printing costs. Additional unanticipated costs may be incurred in the integration of the our business with the business of SXE and the other businesses acquired from Holdings LP. There can be no assurance that the elimination of certain duplicative costs, as well as the realization of other efficiencies related to the integration of the two businesses, will offset the incremental transaction-related costs over time.
Failure to successfully combine our business with the business of SXE and the other businesses acquired from Holdings LP in the expected time frame may adversely affect the future results of the combined organization, and, consequently, the value of our common units.
The success of the SXE Merger will depend, in part, on our ability to realize the anticipated benefits and synergies from combining our business with the business of SXE and the other businesses acquired from Holdings LP. To realize these anticipated benefits, the businesses must be successfully combined. If the combined organization is not able to achieve these objectives, or is not able to achieve these objectives on a timely basis, the anticipated benefits of the SXE Merger may not be realized fully or at all. In addition, the actual integration may result in additional and unforeseen expenses, which could reduce the anticipated benefits of the SXE Merger. These integration difficulties could result in declines in the market value of our common units.
Risks Related to Our Units, Partnership Structure and Ownership
As our common units are yield-oriented securities, increases in interest rates could adversely impact our unit price, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at our intended levels.
Interest rates have increased recently and may continue to increase in the future. As a result, interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our unit price is impacted by our level of our cash distributions and distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a
rising interest rate environment could have an adverse impact on our unit price, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at our intended levels.
Affiliates of ArcLight directly own our General Partner, which has sole responsibility for conducting our business and managing our operations. These affiliates elect all of the members of the board of our general partner. These affiliates and our general partner have conflicts of interest with us and limited fiduciary duties, and they may favor their own interests to the detriment of us and our unitholders.
Affiliates of ArcLight and our general partner have the power to appoint all of the officers and directors of our general partner. The directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner that is beneficial to it, and have no duty to us or our common unitholders. Conflicts of interest may arise between these affiliates and our general partner, on the one hand, and us and our noteholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of these affiliates over our interests and the interests of our noteholders. These conflicts include the following situations, among others:
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• | neither our Fifth Amended and Restated Agreement of Limited Partnership (as amended, the “Partnership Agreement") nor any other agreement requires these affiliates of ArcLight to pursue a business strategy that favors us, and the officers and directors of these affiliates may have a fiduciary duty to make these decisions in the best interests of these affiliates of ArcLight and their respective direct and indirect owners, respectively, which may be contrary to our interests. These affiliates of ArcLight may choose to shift the focus of their investment and growth to areas not served by our assets; |
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• | these affiliates of ArcLight, their respective direct and indirect owners and their respective affiliates are not limited in their ability to compete with us and may offer business opportunities or sell midstream assets to third parties without first offering us the right to bid for them; |
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• | our general partner is allowed to take into account the interests of parties other than us in resolving conflicts of interest and exercising certain rights under our Partnership Agreement, which has the effect of limiting its duty to our unitholders; |
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• | our Partnership Agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties, limits our general partner’s liabilities, and also restricts the remedies available to our noteholders for actions that, without the limitations, might constitute breaches of such fiduciary duty; |
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• | except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval; |
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• | disputes may arise under our commercial agreements or acquisition agreements with these affiliates of ArcLight; |
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• | our general partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities and the creation, reduction or increase of reserves, each of which can affect the amount of cash that is distributed to our unitholders; |
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• | our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and to our general partner as well as the conversion of the Convertible Preferred Units into common units; |
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• | our general partner determines which costs incurred by it are reimbursable by us; |
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• | our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the Convertible Preferred Units, to make incentive distributions or to accelerate the expiration of a subordination period; |
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• | our Partnership Agreement permits us to classify up to $11.5 million as operating surplus, even if it is generated from asset sales, nonworking capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions on our Convertible Preferred Units or to our general partner in respect of the general partner interest or the incentive distribution rights; |
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• | our Partnership Agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf; |
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• | our general partner intends to limit its liability regarding our contractual and other obligations; |
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• | our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if they own more than 80% of the common units; |
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• | our general partner controls the enforcement of the obligations that it and its affiliates owe to us; |
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• | our general partner decides whether to retain separate counsel, accountants or others to perform services for us; |
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• | our general partner may transfer its IDRs without unitholder approval; |
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• | our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the Conflicts |
Committee of the Board of Directors of our general partner (“Conflicts Committee”) or our unitholders. This election may result in lower distributions to our common unitholders in certain situations; and
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• | although ArcLight has provided cash and other support for our liquidity in the past, it is under no obligation to do so in the future. |
The affiliates of ArcLight that own our general partner are not limited in their ability to compete with us and are not obligated to offer us the opportunity to acquire additional assets or businesses, which could limit our ability to grow and could adversely affect our results of operations and cash available for distribution to our unitholders.
The affiliates of ArcLight that own our general partner are not prohibited from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, in the future, affiliates of our general partner and the entities owned or controlled by affiliates of our general partner, including these affiliates of ArcLight may acquire, construct or dispose of additional midstream or other assets and may be presented with new business opportunities, without any obligation to offer us the opportunity to purchase or construct such assets or to engage in such business opportunities. Moreover, while these affiliates of ArcLight may offer us the opportunity to buy additional assets from them, they are under no contractual obligation to do so and we are unable to predict whether or when such acquisitions might be completed. Although ArcLight has provided us with financial support in the past, it is under no obligation to do so in the future. This may create actual and potential conflicts of interest between us and affiliates of our general partner, and result in less than favorable treatment of us and our unitholders.
The New York Stock Exchange (“NYSE”) does not require a publicly traded partnership like us to comply with certain of its corporate governance requirements.
Our common units are listed on the NYSE. Because we are a publicly traded partnership, the NYSE does not require us to have a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. Additionally, any future issuance of additional common units or other securities, including to affiliates, will not be subject to the NYSE’s shareholder approval rules. Accordingly, unitholders will not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements.
If you are not an eligible holder, you may not receive distributions or allocations of income or loss on your common units and your common units will be subject to redemption.
We have adopted certain requirements regarding those investors who may own our units. Eligible holders are U.S. individuals or entities subject to U.S. federal income taxation on the income generated by us or entities not subject to U.S. federal income taxation on the income generated by us, so long as all of the entity’s owners are U.S. individuals or entities subject to such taxation. If you are not an eligible holder, our General Partner may elect not to make distributions or allocate net income or loss on your units, and you run the risk of having your units redeemed by us at the lower of your purchase price for the units and the then-current market price. The redemption price may be paid in cash or by delivery of a promissory note, as determined by our General Partner.
Common units held by persons who are non-taxpaying assignees will be subject to the possibility of redemption.
Our Partnership Agreement gives our General Partner the power to amend the agreement to avoid any adverse effect on the maximum applicable rates chargeable to customers by us under FERC regulations or to reverse an adverse determination that has occurred regarding such maximum rate. If our General Partner determines that our not being treated as an association taxable as a corporation or otherwise taxable as an entity for U.S. federal income tax purposes, coupled with the tax status (or lack of proof thereof) of one or more of our limited partners, has, or is reasonably likely to have, a material adverse effect on the maximum applicable rates chargeable to customers by us, then our General Partner may adopt such amendments to our Partnership Agreement as it determines are necessary or advisable to obtain proof of the U.S. federal income tax status of our limited partners (and their owners, to the extent relevant) and permit us to redeem the units held by any person whose tax status has or is reasonably likely to have a material adverse effect on the maximum applicable rates or who fails to comply with the procedures instituted by our General Partner to obtain proof of the U.S. federal income tax status.
Our Partnership Agreement requires that we distribute our available cash, which could limit our ability to grow and make acquisitions.
Our Partnership Agreement requires us to distribute our available cash to our unitholders. Accordingly, we will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. As a result, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow.
In addition, because we intend to distribute our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our Partnership Agreement, or in our revolving credit facility, on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other indebtedness to finance our growth strategy would result in increased interest expense, which in turn may impact the available cash that we have to distribute to our unitholders.
Our Partnership Agreement limits our General Partner’s fiduciary duties to us and the holders of our common units and restricts the remedies available to holders of our common units for actions taken by our General Partner that might otherwise constitute breaches of fiduciary duty.
Our Partnership Agreement contains provisions that eliminate and replace the fiduciary duties to which our General Partner would otherwise be held by state fiduciary duty law. For example, our Partnership Agreement:
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• | provides that whenever our General Partner makes a determination or takes, or declines to take, any other action in its capacity as our General Partner, our General Partner is required to make such determination, or take or decline to take such other action, in good faith, and will not be subject to any other or different standard imposed by our Partnership Agreement, Delaware law, or any other law, rule or regulation, or at equity; |
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• | provides that our General Partner will not have any liability to us or our unitholders for decisions made in its capacity as a General Partner so long as such decisions are made in good faith, meaning that it believed that the decision was in, or not opposed to, the best interest of our partnership; |
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• | provides that our General Partner and its officers and directors will not be liable for monetary damages to us, our limited partners or their assignees resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our General Partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and |
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• | provides that our General Partner will not be in breach of its obligations under the Partnership Agreement or its fiduciary duties to us or our unitholders if a transaction with an affiliate or the resolution of a conflict of interest is: |
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a. | approved by the Conflicts Committee of the Board of Directors of our General Partner, although our General Partner is not obligated to seek such approval; |
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b. | approved by the vote of a majority of the outstanding common units, excluding any common units owned by our General Partner and its affiliates; |
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c. | on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or |
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d. | fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us. |
In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by our General Partner must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the Conflicts Committee, and the Board of Directors of our General Partner determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest satisfies either of the standards set forth in subclauses (c) and (d) above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the Partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.
Our General Partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our General Partner’s incentive distribution rights without the approval of the Conflicts Committee of our General Partner’s board or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.
Our General Partner has the right, at any time it has received incentive distributions exceeding the target distribution described in our Partnership Agreement for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our cash distribution at the time of the exercise of the reset election. Following a reset election by our General Partner, the minimum quarterly distribution will be reset to an amount equal to the average cash distribution per unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the “reset minimum quarterly distribution”), and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.
We anticipate that our General Partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion; however, it is possible that our General Partner could exercise this reset election at a time when we are experiencing declines in our aggregate cash distributions or at a time when our General Partner expects that we will experience declines in our aggregate cash distributions in the foreseeable future. In such situations, our General Partner may be experiencing, or may expect to experience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to be issued common units, which are entitled to specified priorities with respect to our distributions and which therefore may be more advantageous for the General Partner to own in lieu of the right to receive incentive distribution payments based on target distribution levels that are less certain to be achieved in the then current business environment. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued common units to our General Partner in connection with resetting the target distribution levels related to our General Partner’s incentive distribution rights.
Holders of our common units have limited voting rights and are not entitled to elect our General Partner or its directors.
Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will have no right on an annual or ongoing basis to elect our General Partner or its board of directors. The Board of Directors of our General Partner will be chosen by HPIP and AMID GP Holdings, LLC (“AMID GP Holdings”). Furthermore, if the unitholders are dissatisfied with the performance of our General Partner, they will have little ability to remove our General Partner. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price. Our Partnership Agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.
Even if holders of our common units are dissatisfied, they cannot currently remove our General Partner without its consent.
Our unitholders are unable to remove our General Partner without its consent because our General Partner and its affiliates own sufficient units to be able to prevent its removal. The vote of the holders of at least 66 2/3% of all outstanding limited partner interests voting together as a single class is required to remove our General Partner. As of December 31, 2017, ArcLight indirectly held common units or convertible preferred units representing 48.60% of our then-outstanding common units (on an as converted basis).
Our Partnership Agreement restricts the voting rights of unitholders owning 20% or more of our common units.
Unitholders’ voting rights are further restricted by a provision of our Partnership Agreement providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our General Partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the Board of Directors of our General Partner, cannot vote on any matter.
Our General Partner interest or the control of our General Partner may be transferred to a third party without unitholder consent.
Our General Partner may transfer its General Partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our Partnership Agreement does not restrict the ability of HPIP or AMID GP Holdings to transfer all or a portion of their ownership interests in our General Partner to a third party. The new owner of our General Partner would then be in a position to replace the board of directors and officers of our General Partner with its own designees and thereby exert significant control over the decisions made by the board of directors and officers.
We may issue additional units, including units that are senior to the common units and pari passu with our existing convertible preferred units, without your approval, which would dilute your existing ownership interests.
Our Partnership Agreement does not limit the number of additional limited partner interests that we may issue at any time without the approval of our unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:
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• | our existing unitholders’ proportionate ownership interest in us will decrease; |
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• | the amount of cash available for distribution on each unit may decrease; |
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• | because of the convertible preferred units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase; |
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• | the ratio of taxable income to distributions may increase; |
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• | the relative voting strength of each previously outstanding unit may be diminished; and |
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• | the market price of the common units may decline. |
ArcLight may sell units in the public or private markets, and such sales could have an adverse impact on the trading price of the common units.
As of March 26, 2018, ArcLight held all of our Series A-1 Units, Series A-2 Units and Series C Units through its affiliates. The Series A-1, A-2 and C are all convertible into common units at the election of ArcLight at any time. The sale of these units and the common units owned directly and indirectly by ArcLight and its affiliates could have an adverse impact on the price of the common units or on any trading market that may develop.
Our General Partner has a limited call right that may require you to sell your units at an undesirable time or price.
If at any time our General Partner and its affiliates own more than 80% of our common units, our General Partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price that is not less than their then-current market price, as calculated pursuant to the terms of our Partnership Agreement. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units.
Your liability may not be limited if a court finds that unitholder action constitutes control of our business.
A General Partner of a partnership generally has unlimited liability for the obligations of the Partnership, except for those contractual obligations of the Partnership that are expressly made without recourse to the General Partner. Our partnership is organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. You could be liable for any and all of our obligations as if you were a General Partner if a court or government agency were to determine that:
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• | we were conducting business in a state but had not complied with that particular state’s partnership statute; or |
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• | your right to act with other unitholders to remove or replace our General Partner, to approve some amendments to our Partnership Agreement or to take other actions under our Partnership Agreement constitute “control” of our business. |
Unitholders may have liability to repay distributions that were wrongfully distributed to them.
Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable both for the obligations of the assignor to make contributions to the Partnership that were known to the substituted limited partner at the time it became a limited partner and for those obligations that were unknown if the liabilities could have been determined from the Partnership Agreement. Neither liabilities to partners on account of their partnership interest nor liabilities that are non-recourse to the Partnership are counted for purposes of determining whether a distribution is permitted.
If we are deemed an “investment company” under the Investment Company Act of 1940, it would adversely affect the price of our common units and could have a material adverse effect on our business.
Our assets include 35.7% non-operated interest in Delta House Class A Units, a 16.7% non-operated interest in Tri- States, a 25.3% non-operated interest in Wilprise, a non-operated interest in Mesquite and a 26.3% non-operated interest in Pinto, any of which may be deemed to be an “investment security” within the meaning of the Investment Company Act of 1940, as amended (the “Investment Company Act”). In the future, we may acquire additional minority owned interests that could be deemed “investment securities.” If a sufficient amount of our assets are deemed to be “investment securities” within the meaning of the Investment Company Act, we would either have to register as an investment company under the Investment Company Act, obtain exemptive relief from the SEC or modify our organizational structure or our contract rights to fall outside the definition of an investment company. Registering as an investment company could, among other things, materially limit our ability to engage
transactions with affiliates, including the purchase and sale of certain securities or other property to or from our affiliates, restrict our ability to borrow funds or engage in other transactions involving leverage and require us to add additional directors who are independent of us or our affiliates. The occurrence of some or all of these events may have a material adverse effect on our business. Moreover, treatment of us as an investment company would prevent our qualification as a partnership for U.S. federal income tax purposes in which case we would be treated as a corporation for U.S. federal income tax purposes, and be subject to U.S. federal income tax at the corporate tax rate, significantly reducing the cash available for distributions.
Additionally, distributions to our unitholders would be taxed again as corporate distributions and none of our income, gains, losses or deductions would flow through to our unitholders.
Additionally, as a result of our desire to avoid having to register as an investment company under the Investment Company Act, we may have to forego potential future acquisitions of interests in companies that may be deemed to be investment securities within the meaning of the Investment Company Act or dispose of our current interests in any of our assets that are deemed to be “investment securities.”
Tax Risks to Common Unitholders
Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service (“IRS”) were to treat us as a corporation for U.S. federal income tax purposes or we become subject to material additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution to the unitholders would be substantially reduced.
The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for U.S. federal income tax purposes.
Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a publicly traded partnership such as ours to be treated as a corporation for U.S. federal income tax purposes. Although we do not believe based upon our current operations that we are so treated, the IRS could disagree with the positions we take or a change in our business (or a change in current law) could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation as an entity.
If we were treated as a corporation for U.S. federal income tax purposes, we would pay U.S. federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 21%, and would likely pay state income tax at varying rates. Distributions to a unitholder would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions, or credits would flow through to the unitholder. Because a tax would be imposed upon us as a corporation, our cash available for distribution to unitholders would be substantially reduced. Therefore, treatment of us as a corporation for U.S. federal income tax purposes would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.
Our Partnership Agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.
The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. From time to time, members of the U.S. Congress propose and consider such substantive changes to the existing U.S. federal income tax laws that affect publicly traded partnerships. If successful, such proposals or other similar proposals could eliminate the qualifying income exception to the treatment of all publicly traded partnerships as corporations upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted, but it is possible that a change in law could affect us and may, if enacted, be applied retroactively. Any such changes could negatively impact the value of an investment in our common units.
On January 24, 2017, the U.S. Treasury Department and the IRS published final regulations (the “Final Regulations”) regarding qualifying income under Section 7704(d)(1)(E) of the Code. We believe the income that we treat as qualifying satisfies the
requirements under these regulations. However, there are no assurances that the regulations will not be revised to take a position that is contrary to our interpretation of current law.
Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. For example, we are required to pay the State of Texas a margin tax that is assessed at 0.75% of taxable margin apportioned to Texas. Imposition of such a tax on us by any state will reduce the cash available for distribution to unitholders. The Partnership Agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution levels will be adjusted to reflect the impact of that law on us.
Compliance with and changes in tax laws could adversely affect our performance.
We are subject to extensive tax laws and regulations, including federal and state income tax laws and transactional tax laws such as excise, sales/use, payroll, franchise and ad valorem tax laws. New tax laws and regulations and changes in existing tax laws and regulations are continuously being enacted that could result in increased tax expenditures in the future. Further, taxing authorities may change their application of existing taxes, so that additional entities or transactions may become subject to an existing tax. Many of these tax liabilities are subject to audits by the respective taxing authority. These audits may result in additional tax payments, as well as interest and penalties. The costs of these audits are borne indirectly by the unitholders and our General Partner because such costs reduce our cash available for distribution.
If the IRS contests the U.S. federal income tax positions we take, the market for our common units may be adversely impacted, and the cost of any IRS contest will reduce our cash available for distribution to the unitholders.
We have not requested a ruling from the IRS with respect to our treatment as a partnership for U.S. federal income tax purposes. The IRS may adopt positions that differ from the conclusions of our counsel expressed in a prospectus or from the positions we take, and the IRS’s positions may ultimately be sustained. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take. A court may not agree with some or all of our counsel’s conclusions or positions we take. Any contest with the IRS, and the outcome of any such contest, may increase a unitholder’s tax liability and result in adjustment to items unrelated to us and could materially and adversely impact the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by the unitholders and our General Partner because such costs will reduce our cash available for distribution.
If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it may collect any resulting taxes (including any applicable penalties and interest) directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced.
If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it may collect any resulting taxes (including any applicable penalties and interest) directly from us. Although our General Partner may elect to have our unitholders and former unitholders take such audit adjustments into account and pay any resulting taxes (including applicable penalties or interest) in accordance with their interests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible or effective in all circumstances. If we are unable to have the unitholders take such audit adjustment into account in accordance with their interests during the taxable year under audit, the current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own units during the taxable year under audit. If we are required to make payments of taxes, penalties and interest resulting from audit adjustments, our cash available for distribution to our unitholders might be substantially reduced.
The unitholders' share of our income will be taxable to them for U.S. federal income tax purposes even if the unitholders do not receive any cash distributions from us.
Because a unitholder will be treated as a partner to whom we will allocate taxable income, which could be different in amount than the cash we distribute, a unitholder's allocable share of our taxable income will be taxable to it, which may require the payment of U.S. federal income taxes and, in some cases, state and local income taxes on its share of our taxable income even if it receives no cash distributions from us. The unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the tax liability that results from that income.
Certain actions that we may take, such as issuing additional units, may increase the U.S. federal income tax liability of unitholders.
In the event we issue additional units or engage in certain other transactions in the future, the allocable share of nonrecourse liabilities allocated to the unitholders will be recalculated to take into account our issuance of any additional units. Any reduction in a unitholder's share of our nonrecourse liabilities will be treated as a distribution of cash to that unitholder and will result in a corresponding tax basis reduction in a unitholder's units. A deemed cash distribution may, under certain circumstances, result in the recognition of taxable gain by a unitholder, to the extent that the deemed cash distribution exceeds such unitholder's tax basis in its units.
In addition, the U.S. federal income tax liability of a unitholder could be increased if we dispose of assets or make a future offering of units and use the proceeds in a manner that does not produce substantial additional deductions, such as to repay indebtedness currently outstanding or to acquire property that is not eligible for depreciation or amortization for U.S. federal income tax purposes or that is depreciable or amortizable at a rate significantly slower than the rate currently applicable to the our assets.
Unitholders may be subject to limitations on their ability to deduct interest expense we incur.
Our ability to deduct business interest expense will be limited for U.S. federal income tax purposes to an amount equal to the sum of (i) our business interest income during the taxable year and (ii) 30% of our adjusted taxable income for such taxable year. For the purposes of this limitation, adjusted taxable income is computed without regard to any business interest expense or business interest income, and in the case of taxable years beginning before January 1, 2022, any deduction allowable for depreciation, amortization, or depletion. If we are not entitled to fully deduct our business interest in any taxable year, such excess business interest expense will be allocated to each unitholder as excess business interest and can be carried forward by the unitholder to successive taxable years and used to offset any excess taxable income allocated by us to such unitholder. Any excess business interest expense allocated to a unitholder will reduce such unitholder’s tax basis in its partnership interest in the year of the allocation even if the expense does not give rise to a deduction to the unitholder in that year. Immediately prior to a disposition of its shares, a unitholder’s tax basis will be increased by the amount by which such basis reduction exceeds the excess interest expense that has been deducted by such unitholder.
There are limits on the deductibility of losses that may adversely affect unitholders.
In the case of taxpayers subject to the passive loss rules (generally, individuals, closely-held corporations and regulated investment companies), any losses generated by us will only be available to offset our future income and cannot be used to offset income from other activities, including other passive activities or investments. Unused losses may be deducted when the unitholder disposes of the unitholder’s entire investment in us in a fully taxable transaction with an unrelated party. A unitholder’s share of our net passive income may be offset by unused losses from us carried over from prior years, but not by losses from other passive activities, including losses from other publicly traded partnerships.
Further, in addition to the other limitations described above, non-corporate taxpayers may only deduct business losses up the gross income or gain attributable to such trade or business plus $250,000 ($500,000 for unitholders filing jointly). Amounts that may not be deducted in a taxable year may be carried forward into the following taxable year. This limitation shall be applied after the passive loss limitations and, unless amended, applies only to taxable years beginning prior to December 31, 2025.
Tax gain or loss on the disposition of our common units could be more or less than expected.
If a unitholder sells its common units, the unitholder will recognize a gain or loss equal to the difference between the amount realized and the unitholder's tax basis in those common units. Because distributions to a unitholder in excess of the total net taxable income allocated to the unitholder decrease the unitholder's tax basis in the unitholder's common units, the amount, if any, of such prior excess distributions with respect to the units sold will, in effect, become taxable income to the unitholder if the unitholder sells the common units at a price greater than the unitholder's tax basis in those common units, even if the price received by the unitholder is less than the original cost. Furthermore, a substantial portion of the amount realized on any sale of a unitholder's common units, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder's share of our nonrecourse liabilities, if the unitholder sells its common units, the unitholder may incur a tax liability in excess of the amount of cash the unitholder receives from the sale.
Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.
Investment in common units by tax-exempt entities, such as individual retirement accounts, or IRAs, other retirement plans and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are
exempt from U.S. federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income, which may be taxable to them. Further, with respect to taxable years beginning after December 31, 2017, a tax-exempt entity with more than one unrelated trade or business (including by attribution from investment in a partnership such as ours that is engaged in one or more unrelated trade or business) is required to compute the unrelated business taxable income of such tax-exempt entity separately with respect to each such trade or business (including for purposes of determining any net operating loss deduction). As a result, for years beginning after December 31, 2017, it may not be possible for tax-exempt entities to utilize losses from an investment in our partnership to offset unrelated business taxable income from another unrelated trade or business and vice versa. Tax-exempt entities should consult a tax advisor before investing in our common units.
Non-U.S. persons are generally taxed and subject to U.S. federal income tax filing requirements on income effectively connected with a U.S. trade or business. Income allocated to our unitholders and, under recently enacted legislation, any gain from the sale of our units will generally be considered to be “effectively connected” with a U.S. trade or business. As a result, distributions to a non-U.S. unitholder will be subject to withholding at the highest applicable effective tax rate, and a non-U.S. unitholder who sells or otherwise disposes of its interest will be subject to U.S. federal income tax on gain realized from the sale or disposition of that unit to the extent the gain is effectively connected with a U.S. trade or business of the non-U.S. unitholder.
Recently enacted legislation also imposes a federal income tax withholding obligation of 10% of the amount realized upon a non-U.S. person’s sale or exchange of an interest in a partnership that is engaged in a U.S. trade or business. However, due to challenges of administering a withholding obligation applicable to open market trading and other complications, the application of this withholding rule to dispositions of publicly traded partnership interests has been temporarily suspended by the IRS until regulations or other guidance that resolves the challenges have been issued. It is not clear if or when such regulations or guidance will be issued. Non-U.S. persons should consult a tax advisor before investing in our common units.
We treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.
Because we cannot match transferors and transferees of common units and because of other reasons, we have adopted depreciation and amortization positions that may not conform to all aspects of existing Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to the unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to the unitholders' tax returns.
We prorate our items of income, gain, loss and deduction for U.S. federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among the unitholders.
We prorate our items of income, gain, loss and deduction for U.S. federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. Treasury recently adopted final regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders to ours. These regulations apply to certain publicly-traded partnerships, including us, for taxable years beginning on or after August 3, 2015. However, these regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among the unitholders.
We have adopted certain valuation methodologies for tax purposes that may result in a shift of income, gain, loss and deduction between our General Partner and the unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.
When we issue additional units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and the General Partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and our General Partner, which may be unfavorable to such unitholders. Moreover, subsequent purchasers of common units may have a greater portion of the Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Code Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between our General Partner and certain of the unitholders.
A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to the unitholders. It also could affect the amount of gain from the unitholders' sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to the unitholders’ tax returns without the benefit of additional deductions.
Unitholders may be subject to state and local taxes and return filing requirements in states and jurisdictions where they do not reside as a result of investing in our units.
In addition to U.S. federal income taxes, unitholders may be subject to other taxes, including foreign, state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property, even if the unitholders do not live in any of those jurisdictions. Unitholders may be required to file foreign, state and local income tax returns and pay state and local income taxes in some or all of these jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. As we make acquisitions or expand our business, we may own assets or do business in additional states that impose a personal income tax or an entity level tax. It is each unitholder's responsibility to file all U.S. federal, foreign, state, local and non-U.S. tax returns.
Some of the states in which we do business or own property may require us to, or we may elect to, withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the state. Withholding, the amount of which may be greater or less than a particular unit holder's income tax liability to the state, generally does not relieve the nonresident unitholder from the obligation to file an income tax return. Amounts withheld may be treated as if distributed to unitholders for purposes of determining the amounts distributed by us.
Item 1B. Unresolved Staff Comments
None
Item 2. Properties
A description of our properties is contained in Item 1 - Business of this Annual Report and is incorporated into this Item 2. by reference.
Our principal executive offices are located at 2103 CityWest Blvd., Bldg. 4, Suite 800, Houston, Texas 77042 and our telephone number is 346-241-3400. We believe that our existing facilities are adequate to meet our needs for the immediate future and that additional facilities will be available on commercially reasonable terms as needed.
Item 3. Legal Proceedings
On December 18, 2015, Vintage Assets, Inc., et al. (“Vintage”), filed a lawsuit in the Judicial District Court in Plaquemines Parish, Louisiana alleging that defendants Southern Natural Gas Company, L.L.C. (“SNG”) and Tennessee Gas Pipeline Company, L.L.C. failed to maintain the canals in which their pipelines were laid and failed to maintain the associated banks causing erosion, ecological damage, and unspecified monetary damages, and trespassed on Plaintiffs’ property. The case was removed to the United States District Court for the Eastern District of Louisiana on January 27, 2016. Our subsidiaries High Point Gas Transmission, L.L.C. (“HPGT”) and High Point Gas Gathering, L.L.C. (“HPGG”) are successors in interest to SNG with regard to certain of the property interests at issue in this proceeding. On October 24, 2016, HPGT and HPGG were added to the lawsuit as co-defendants. Plaintiffs subsequently demanded either restoration of their property or, alternatively, $44.0 million in damages (the plaintiff’s alleged estimated cost of restoration). A bench trial was held in September 2017, but a judgment has not been rendered. The purchase and sale agreements pursuant to which HPGG and HPGT acquired its property interests contain provisions pursuant to which the sellers agreed to indemnify HPGT or HPGG, as applicable, from all liabilities, including attorney’s fees, attributable to the period prior to such acquisition.
While the ultimate impact of any proceedings cannot be predicted with certainty, our management believes that the resolution of any of our pending proceedings will not have a material adverse effect on our financial condition or results of operations.
Item 4. Mine Safety Disclosures
Not applicable.
PART II
Item 5. Market for Registrant's Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities
Market Information
Our common units have been listed on the New York Stock Exchange ("NYSE") since July 27, 2011, under the symbol "AMID." The following table sets forth the high and low sales prices of our common units, as reported by the NYSE for each quarter during 2017 and 2016, together with distributions declared for that quarter through December 31, 2017:
|
| | | | | | | | | | | | |
Period Ended | First Quarter | Second Quarter | Third Quarter | Fourth Quarter |
2017 | | | | |
High Price | $ | 18.45 |
| $ | 15.25 |
| $ | 15.00 |
| $ | 14.75 |
|
Low Price | $ | 14.20 |
| $ | 11.10 |
| $ | 12.35 |
| $ | 11.65 |
|
Distribution per common unit | $ | 0.4125 |
| $ | 0.4125 |
| $ | 0.4125 |
| $ | 0.4125 |
|
2016 | | | | |
High Price | $ | 8.49 |
| $ | 14.00 |
| $ | 15.19 |
| $ | 18.30 |
|
Low Price | $ | 4.03 |
| $ | 6.18 |
| $ | 10.39 |
| $ | 13.06 |
|
Distribution per common unit(1) | $ | 0.7375 |
| $ | 0.7375 |
| $ | 0.7375 |
| $ | 0.7375 |
|
(1) Recast to reflect both AMID and JPE quarterly distributions.
Unitholder Matters
As of March 26, 2018, there were 127 unitholders of record of our common units. This number does not include unitholders whose units are held in trust by other entities. The actual number of unitholders is greater than the number of holders of record. As of March 26, 2018 we have approximately 11,009,729 Series A Units, 9,241,642 Series C Units and 964,563 General Partner units. Our General Partner and its affiliates receive quarterly distributions on the General Partner units only after the requisite distributions have been paid on the common units, Series A Units and Series C Units. If the SXE Transactions are consummated, we will issue a new class of preferred units called Series E preferred units at the closing of the SXE Transactions pursuant to the SXE Transaction Agreements.
Our Distribution Policy
Our Partnership Agreement requires us to distribute all of our available cash quarterly. Our cash distribution policy reflects our belief that our unitholders will be better served if we distribute rather than retain our available cash. Generally, our available cash is the sum of our i) cash on hand at the end of a quarter after the payment of our expenses and the establishment of cash reserves and ii) cash on hand resulting from working capital borrowings made after the end of the quarter. We pay quarterly a cash dividend to those unitholders of record on the applicable record date, as determined by the General Partner.
Our cash distribution policy, as expressed in our Partnership Agreement, may not be modified or repealed without amending our Partnership Agreement. The actual amount of our cash distributions for any quarter is subject to fluctuations based on the amount of cash we generate from our business and the amount of reserves our General Partner establishes in accordance with our Partnership Agreement as described above. We will pay our distributions on or about the 15th of each February, May, August and November to holders of record on or about the 5th of each such month. If the distribution date does not fall on a business day, we will make the distribution on the business day immediately preceding the indicated distribution date.
The following table sets forth the number of units outstanding at December 31, 2017 and 2016 (in thousands):
|
| | | | | | |
| | December 31, |
| | 2017 | | 2016 |
Series A convertible preferred units | | 10,719 |
| | 10,107 |
|
Series C convertible preferred units | | 8,965 |
| | 8,792 |
|
Series D convertible preferred units (1) | | — |
| | 2,333 |
|
Limited partner common units | | 52,711 |
| | 51,351 |
|
General Partner units | | 965 |
| | 680 |
|
(1) Series D convertible preferred units (“Series D Units”) were redeemed as of October 2, 2017.
General Partner Units
Our General Partner's initial 2.0% interest in distributions has been reduced to 1.32% as of December 31, 2017 due to the issuance of additional units and the General Partner has not contributed a proportionate amount of capital to us to maintain its initial 2.0% General Partner notional interest.
Series A Units
Distributions on Series A Units can be made with paid-in-kind Series A Units, cash or a combination thereof, at the discretion of the Board of Directors, which began since the distribution for the three months ended June 30, 2014. At December 31, 2017, we accrued $4.4 million of contractual paid-in-kind distributions on the Series A Units which were distributed on February 14, 2018.
Series C Units
Distributions on Series C Units can be made with paid-in-kind Series C Units, cash or a combination thereof, at the discretion of the Board of Directors and upon the consent of the holders of the Series C Units. At December 31, 2017, we accrued $3.7 million of contractual paid-in-kind distributions on the Series C Units which were distributed on February 14, 2018.
Securities Authorized for Issuance Under Equity Compensation Plans
The following table summarizes information about our equity compensation plans, LTIP and Assumed LTIP:
|
| | | | | | | | | |
Plan Category | Number of securities to be issued upon exercise of outstanding options, warrants and rights | | Weighted-average exercise price of outstanding options, warrants and rights | | Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) |
LTIP | | | | | |
Restricted units (phantom units) | 1,397,634 |
| | | | |
Performance units | 524,000 |
| | | | |
Options | 245,000 |
| | $ | 8.50 |
| | |
Total | 2,166,634 |
| |
| | 4,134,412 |
|
| | | | | |
Assumed LTIP | | | | | |
Phantom units | 10,344 |
| | | | 151,845 |
|
Total AMID | 2,176,978 |
|
|
|
| 4,286,257 |
|
Item 6. Selected Historical Financial and Operating Data
The following table presents selected historical consolidated financial and operating data for the periods and as of the dates indicated. We derived this information from our historical consolidated financial statements and accompanying notes. This information should be read together with, and is qualified in its entirety, by reference to those consolidated financial statements and notes, which for the years 2017, 2016, and 2015 begin on page F-1 to this Annual Report.
On March 8, 2017 we acquired JPE in a unit-for-unit exchange. As both the Partnership and JPE were controlled by ArcLight, the acquisition represents a transaction among entities under common control and is accounted for as a common control transaction in a manner similar to a pooling of interests. Although the Partnership is the legal acquirer, JPE is considered to be the acquirer for accounting purposes as ArcLight obtained control of JPE before it obtained control the Partnership. The following selected historical financial information represent JPE’s historical cost basis financial information which has been recast to reflect the acquisition of the Partnership at ArcLight’s historical cost basis effective April 15, 2013, the date on which ArcLight obtained control of the Partnership.
On September 1, 2017, the Partnership completed the disposition of its Propane Business. Through the transaction, the Partnership divested 100% of the Propane Business, including Pinnacle Propane’s 40 service locations; Pinnacle Propane Express’ cylinder exchange business and related logistic assets; and the Alliant Gas utility system. In connection with the transaction, the Partnership
received $170.0 million in cash and recorded a gain on the sale of $47.4 million, net of $2.5 million transaction costs. As a result of the disposition of the Propane Business, the Partnership has classified the accounts and the results of operations of the Propane Business as discontinued operations for all periods.
For a detailed discussion of the following table, see Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations.
|
| | | | | | | | | | | | | | | | | | | | |
| | Years ended December 31, |
| | 2017 (1) | | 2016 (2) | | 2015 (2) | | 2014 (2) | | 2013 (2) |
| | (in thousands, except per unit and operating data) |
Statements of Operations Data: | | | | | | | | | | |
Revenues: | | | | | | | | | | |
Total operating revenue | | $ | 651,435 |
| | $ | 589,026 |
| | $ | 750,304 |
| | $ | 838,949 |
| | $ | 436,021 |
|
| | | | | | | | | | |
Operating expenses: | | | | | | | | | | |
Cost of sales | | 457,371 |
| | 393,351 |
| | 567,682 |
| | 672,948 |
| | 331,831 |
|
Direct operating expenses | | 82,256 |
| | 71,544 |
| | 71,729 |
| | 58,048 |
| | 33,962 |
|
Corporate expenses | | 112,058 |
| | 89,438 |
| | 65,327 |
| | 60,465 |
| | 51,193 |
|
Depreciation, amortization and accretion | | 103,448 |
| | 90,882 |
| | 81,335 |
| | 57,818 |
| | 43,458 |
|
Loss (gain) on sale of assets, net | | (4,063 | ) | | 688 |
| | 2,860 |
| | 4,087 |
| | (17 | ) |
Impairment of long-lived assets / intangible assets | | 116,609 |
| | 697 |
| | — |
| | 21,344 |
| | 8,830 |
|
Impairment of goodwill | | 77,961 |
| | 2,654 |
| | 148,488 |
| | — |
| | — |
|
Total operating expenses | | 945,640 |
| | 649,254 |
| | 937,421 |
| | 874,710 |
| | 469,257 |
|
Operating loss | | (294,205 | ) | | (60,228 | ) | | (187,117 | ) | | (35,761 | ) | | (33,236 | ) |
Other income (expense): | | | | | | | | | | |
Interest expense | | (66,465 | ) | | (21,433 | ) | | (20,077 | ) | | (16,497 | ) | | (15,418 | ) |
Other income (expense) | | 36,254 |
| | 254 |
| | 1,460 |
| | (1,096 | ) | | 544 |
|
Loss on extinguishment of debt | | — |
| | — |
| | — |
| | (1,634 | ) | | — |
|
Earnings in unconsolidated affiliates | | 63,050 |
| | 40,158 |
| | 8,201 |
| | 348 |
| | — |
|
Loss from continuing operations before income taxes | | (261,366 | ) | | (41,249 | ) | | (197,533 | ) | | (54,640 | ) | | (48,110 | ) |
Income tax (expense) benefit | | (1,235 | ) | | (2,580 | ) | | (1,885 | ) | | (856 | ) | | 212 |
|
Loss from continuing operations | | (262,601 | ) | | (43,829 | ) | | (199,418 | ) | | (55,496 | ) | | (47,898 | ) |
Discontinued operations: | | | | | | | | | | |
Income (loss) from discontinued operations, net of tax | | 44,095 |
| | (4,715 | ) | | (423 | ) | | (24,071 | ) | | 13,446 |
|
Net loss | | (218,506 | ) | | (48,544 | ) | | (199,841 | ) | | (79,567 | ) | | (34,452 | ) |
Net income (loss) attributable to non-controlling interests | | 4,473 |
| | 2,766 |
| | (13 | ) | | 3,993 |
| | 705 |
|
Net loss attributable to the Partnership | | $ | (222,979 | ) | | $ | (51,310 | ) | | $ | (199,828 | ) | | $ | (83,560 | ) | | $ | (35,157 | ) |
General Partner's Interest in net loss | | $ | (2,981 | ) | | $ | (233 | ) | | $ | (1,823 | ) | | $ | (398 | ) | | $ | (864 | ) |
Limited Partners' Interest in net loss | | $ | (219,998 | ) | | $ | (51,077 | ) | | $ | (198,005 | ) | | $ | (83,162 | ) | | $ | (34,293 | ) |
| | | | | | | | | | |
Limited Partners' net (loss) per common unit: | | | | | | |
Basic and diluted: | | | | | | | | | | |
Loss from continuing operations | | $ | (5.70 | ) | | $ | (1.51 | ) | | $ | (4.91 | ) | | $ | (2.77 | ) | | $ | (3.21 | ) |
Income (loss) from discontinued operations | | 0.85 |
| | (0.09 | ) | | (0.01 | ) | | (0.52 | ) | | (0.07 | ) |
|
| | | | | | | | | | | | | | | | | | | | |
Net loss | | $ | (4.85 | ) | | $ | (1.60 | ) | | $ | (4.92 | ) | | $ | (3.29 | ) | | $ | (3.28 | ) |
Weighted average number of common units outstanding: | | | | | | | | | | |
Basic and diluted (3) | | 52,043 |
| | 51,176 |
| | 45,050 |
| | 27,524 |
| | 18,931 |
|
Statement of Cash Flow Data: | | | | | | | | | | |
Net cash provided by (used in): | | | | | | | | | | |
Operating activities | | $ | 14,986 |
| | $ | 90,639 |
| | $ | 86,978 |
| | $ | 51,635 |
| | $ | 29,500 |
|
Investing activities | | 252,310 |
| | (564,504 | ) | | (250,771 | ) | | (518,023 | ) | | (115,173 | ) |
Financing activities | | (264,180 | ) | | 477,544 |
| | 161,956 |
| | 466,577 |
| | 79,156 |
|
Other Financial Data: | | | | | | | | | | |
Adjusted EBITDA (4) | | $ | 176,394 |
| | $ | 177,565 |
| | $ | 100,721 |
| | $ | 74,286 |
| | $ | 63,707 |
|
Total segment gross margin (5) | | 242,084 |
| | 223,635 |
| | 179,856 |
| | 153,524 |
| | 96,809 |
|
Distribution declared per common unit | | $ | 1.65 |
| | $ | 1.99 |
| | $ | 2.14 |
| | $ | 1.85 |
| | $ | 1.75 |
|
Segment gross margin: | | | | | | | | | | |
Gas Gathering and Processing Services | | 49,010 |
| | 48,245 |
| | 65,692 |
| | 51,213 |
| | 5,673 |
|
Liquid Pipelines and Services | | 27,999 |
| | 31,556 |
| | 26,399 |
| | 25,038 |
| | 5,420 |
|
Natural Gas Transportation Services | | 23,424 |
| | 18,616 |
| | 18,073 |
| | 13,691 |
| | 13,150 |
|
Offshore Pipelines and Services | | 103,664 |
| | 82,346 |
| | 33,613 |
| | 29,089 |
| | 36,318 |
|
Terminalling Services | | 37,987 |
| | 42,872 |
| | 36,079 |
| | 34,493 |
| | 36,248 |
|
| | | | | | | | | | |
Balance Sheet Data (at period end): | | | | | | | | | | |
Cash and cash equivalents | | $ | 8,782 |
| | $ | 5,666 |
| | $ | 1,987 |
| | $ | 3,824 |
| | $ | 3,627 |
|
Accounts receivable and unbilled revenue | | 98,132 |
| | 67,625 |
| | 61,016 |
| | 116,676 |
| | 129,724 |
|
Property, plant and equipment, net | | 1,095,585 |
| | 1,066,608 |
| | 981,321 |
| | 887,045 |
| | 537,304 |
|
Total assets | | 1,923,466 |
| | 2,349,321 |
| | 1,751,889 |
| | 1,865,210 |
| | 1,292,695 |
|
Current portion of long-term debt | | 7,551 |
| | 5,438 |
| | 2,758 |
| | 3,141 |
| | 3,141 |
|
Long-term debt | | 1,201,456 |
| | 1,235,538 |
| | 687,100 |
| | 456,965 |
| | 314,764 |
|
Operating Data: | | | | | | | | | | |
Gas Gathering and Processing Services: | | | | | | | | | | |
Average throughput (MMcf/d) | | 202.0 |
| | 220.6 |
| | 240.0 |
| | 155.8 |
| | 129.5 |
|
Liquid Pipelines and Services: | | | | | | | | | | |
Average throughput Pipeline (Bbl/d) | | 34,248 |
| | 32,257 |
| | 34,946 |
| | 20,868 |
| | 13,738 |
|
Average throughput Truck (Bbl/d) | | 2,910 |
| | 1,628 |
| | — |
| | — |
| | — |
|
Natural Gas Transportation Services: | | | | | | | | | | |
Average throughput (MMcf/d) | | 420.4 |
| | 389.9 |
| | 364.1 |
| | 373.3 |
| | 364.9 |
|
Offshore Pipelines and Services: | | | | | | | | | | |
Average throughput (MMcf/d) | | 309.6 |
| | 466.4 |
| | 442.8 |
| | 524.6 |
| | 498.9 |
|
Terminalling Services: | | | | | | | | | | |
Storage Capacity (Bbls) | | 4,957,328 |
| | 5,011,133 |
| | 4,487,542 |
| | 4,247,058 |
| | 4,114,792 |
|
Design Capacity (Bbls) | | 5,400,800 |
| | 5,173,717 |
| | 4,688,950 |
| | 4,363,817 |
| | 4,165,600 |
|
Storage utilization | | 91.8 | % | | 96.9 | % | | 95.7 | % | | 97.3 | % | | 99.0 | % |
Terminalling and Storage throughput (Bbls/d) | | 58,670 |
| | 56,741 |
| | 62,075 |
| | 63,859 |
| | 69,071 |
|
__________________________
The following transactions affect comparability between years:
| |
(1) | i) In June 2017, we acquired a 100% interest in VKGS which was accounted for as a business combination and was included in our Offshore Pipelines and Services segment; ii) in August 2017, we acquired a 100% interest in POGS; the outstanding interests in one of our equity investments, MPOG, which was accounted for as a change in control and has been consolidated from the acquisition date; and the remaining equity interest in our consolidated subsidiary, AmPan, each of which were included in our Offshore Pipelines and Services segment; iii) in September 2017, we acquired an additional 15.5% equity |
interest in Delta House Class A units, which we accounted for as an equity method investment and was included in our Offshore Pipelines and Services segment; iv) in October 2017, we acquired an additional 17.0% membership interest in Destin which we accounted for as an equity method investment and was included in our Liquid Pipelines and Services segment and v) in November 2017, we acquired 100% of the equity interest in Trans-Union which represented an asset acquisition among entities under common control and was included in our Natural Gas Transportation Services segment.
| |
(2) | i) In October 2016 and April 2016, we acquired 6.2% and a 1% non-operated interests in Delta House Class A units, which we accounted for as equity method investments and were included in our Offshore Pipelines and Services segment; ii) in April 2016, we acquired membership interests in Destin (49.7%), Tri-States (16.7%), Okeanos (66.7%), and Wilprise (25.3%), which we accounted for as equity method investments and were included in our Liquid Pipelines and Services and Offshore Pipelines and Services segments; iii) in April 2016 we acquired a 60% interest in Ampan which we consolidated for financial reporting purposes and was included in our Offshore Pipelines and Services segment; iv) in September 2015, we acquired a non-operated 12.9% indirect interest in Delta House Class A units, which we accounted for as an equity method investment and was included in our Offshore Pipelines and Services segment; v) in February 2016, we completed the sale of our crude oil supply and logistics operations which was included in our Liquid Pipelines and Services segment; vi) in October 2014 and January 2014, we acquired the Costar and Lavaca systems, respectively, both of which were reported in our Gas Gathering and Processing Services segment; vii) in December 2013, we acquired Blackwater, which was reported in our Terminalling Services segment; and viii) in April 2013, we acquired the High Point System, which was included in our Natural Gas Transportation Services segment. |
(3) Includes unvested phantom units with distribution equivalent rights ("DERs"), which are considered participating securities, 200,000 units at December 31, 2017 and 2016.
(4) For a definition of Adjusted EBITDA and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP and a discussion of how we use Adjusted EBITDA to evaluate our operating performance, see Item 7. Management's Discussion and Analysis — How We Evaluate Our Operations. Adjusted EBITDA of the year ended December 31, 2016 has been revised to be consistent with all periods presented. See further information in Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations, How We Evaluate Our Operations of this Annual Report.
(5) For a definition of Total segment gross margin and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP and a discussion of how we use Total segment gross margin to evaluate our operating performance, see Item 7. Management's Discussion and Analysis — How We Evaluate Our Operations.
(6) Excludes volumes and gross production under our elective processing arrangements. For a description of our elective processing arrangements, see Item 7. Management's Discussion and Analysis — Our Operations - Gas Gathering and Processing Services Segment.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the audited consolidated financial statements and the related notes thereto included elsewhere in this Annual Report. 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 "Cautionary Statement About Forward-Looking Statements."
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 reportable 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 and storing specialty chemical products and refined products. As of September 1, 2017, as a result of the disposition of the Propane Business described in in Note 4 - Discontinued Operations, in Part II, Item 8 of this Annual Report, 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, (iv) the Bakken Shale of North Dakota, and (v) 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 in Part I, Item 1 of this Annual Report for more information about our recent acquisitions and dispositions.
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, seven 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 66.67% operated interest in Destin, a natural gas pipeline; a 66.7% operated interest in Okeanos, a natural gas pipeline; a 35.7% non-operated interest in the Class A units and common units of Delta House, a floating production system platform and related pipeline infrastructure; a 25.3% non-operated interest in Wilprise, an NGL pipeline; a 16.7% non-operated interest in Tri-States, an NGL pipeline; and up to August 8, 2017, prior our acquisition of Panther, a 66.7% interest in MPOG, a crude oil gathering and processing system. Subsequent to the acquisition of Panther, we consolidated and wholly owned MPOG.
Financial Highlights
Financial highlights during the year ended December 31, 2017, include the following:
• Net loss attributable to the Partnership increased to $223.0 million, or an increase of 334.6%, as compared to net loss of $51.3 million in 2016, which was primarily due to a combination of an increase in operating loss of $233.9 million, including non cash impairment charges of $194.6 million, and increased interest expense of $45.0 million associated with higher average debt balances from our growth initiatives as well as higher average interest costs, offset by the net gain on disposition of the Propane Business of $47.4 million and the gain of $36.0 million related to the MPOG acquisition. The impairment charges of $194.6 million, of which $116.6 million was associated with our property, plant and equipment and intangible assets associated with certain non core assets in our Gas Gathering and Processing Services segment and our Liquid Pipelines and Services segment and approximately $78.0 million in goodwill, associated with certain assets in our Liquid Pipelines and Services segment. See Note 9 - Property, Plant and Equipment and Note 10 - Goodwill and Intangible Assets, Net in Part II, Item 8 of this Annual Report for more information.
• Earnings in unconsolidated affiliates were $63.1 million, an increase of $22.9 million as compared to $40.2 million for the same period in 2016, which was primarily due to an increase of $13.2 million due to the incremental ownership in Delta House in the fourth quarter of 2016 and our subsequent increases in ownership in November 2017, $5.4 million from Destin as a result of twelve months of ownership reflected in 2017 as compared to eight months of ownership in 2016, as well as higher volumes on our Okeanos system for $4.0 million. Additionally, there was a $3.0 million increase driven by increasing volumes on Tri-States and Wilprise due to new wells (production) from the Thunderhorse platform.
• Segment gross margin amounted to $242.1 million, or an increase of $18.5 million as compared to $223.6 million of the same period in 2016. This increase of $18.5 million was primarily due to our Offshore Pipelines and Services segment earnings from unconsolidated affiliates of $19.8 million, $1.6 million from firm transportation contracts of 150 MMcf/d on MLGT, $1.0 million from new Midla Natchez contracts with higher rates, $1.0 million from the acquisition of Trans-Union in November 2017, partially offset by a decrease in our Terminalling Services segment of $4.9 million primarily attributable to a decrease in Cushing storage, higher operating costs at our Harvey terminal, and higher butane costs.
• Adjusted EBITDA decreased to $176.4 million, or an immaterial decrease of 0.7%, as compared to $177.6 million in 2016.
• We distributed $89.4 million to our common unitholders, or $1.65 per common unit, with respect to the year 2017. Our fourth quarter 2017 distribution was the 26th consecutive distribution since our initial public offering.
Operational highlights during the year ended December 31, 2017, include the following:
• Contracted capacity for our Terminalling Services segment averaged 4,957,328 Bbls, representing a 1.1% decrease compared to the same period in 2016;
• Average condensate production totaled 64 Mgal/d, representing a 18.9 Mgal/d or 22.8% decrease compared to the same period in 2016;
• Average gross NGL production totaled 326 Mgal/d, representing a 133 Mgal/d or 68.7 % increase compared to the same period in 2016;
• Throughput volumes attributable to the Natural Gas Transportation Services and Offshore Pipelines and Services segments totaled 730 MMcf/d, representing a 126 MMcf/d or 14.7% decrease compared to the same period in 2016;
• Throughput volumes attributable to the Liquid Pipelines and Services segment totaled 34,248 Bbls/d, representing a 1,991 Bbls/d or 6.2% 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 89.1%, representing a decrease of 2.5%, as compared to the same period in 2016.
Our 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 NGLs, 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 offspec condensate, we are able to lock in a
fixed margin on these transactions. We view the segment gross margin 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 II, Item 7A of this Annual 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, pursuant to the agreement with the shipper, we 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, pursuant to the agreement with the shipper, we only 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:
• Firm Transportation Arrangements. Our obligation to provide firm transportation service means that, pursuant to the agreement with the shipper, we 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 or commodity charge with respect to quantities actually transported by us.
• Interruptible Transportation Arrangements. Our obligation to provide interruptible transportation service means that, pursuant to the agreement with the shipper, we only 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 or commodity 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, pursuant to the agreement with the shipper, we 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 or commodity charge with respect to quantities actually transported by us.
• Interruptible Transportation Arrangements. Our obligation to provide interruptible transportation service means that, pursuant to the agreement with the shipper, we only transport natural gas nominated by the shipper to the extent that we have available capacity. For this service the shipper pays no reservation charge or commodity 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.
Our Terminalling Services segment consists of approximately 2.4 million barrels of storage capacity across three marine terminal sites located in Westwego, Louisiana; Brunswick, Georgia; and Harvey, Louisiana. Our Terminalling Services segment provides above-ground 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.
Cash distributions received from our unconsolidated affiliates amounted to $90.8 million, $83.0 million, and $20.6 million for the years ended December 31, 2017, 2016, and 2015, 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, total segment 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, 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 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 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 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.
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 (losses) on commodity derivatives, construction and operating management agreement income and less the cost of sales.
We define segment gross margin in our Liquid Pipelines and Services segment as total revenue plus unconsolidated affiliate earnings less unrealized gains (losses) on commodity derivatives and less the cost of sales 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 sales 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 sales 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 cost of sales and 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, and Terminalling Services segments. The GAAP measure most directly comparable to total segment gross margin is Net loss attributable to the Partnership. For a reconciliation of total segment gross margin to net 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 loss attributable to the Partnership. For a reconciliation of operating margin to net loss, see Non-GAAP Financial Measures below.
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.
We define Adjusted EBITDA as net loss attributable to the Partnership, plus depreciation, amortization and accretion expense, interest expense, debt issuance cost, 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, VKGS, Delta House, Panther and Trans-Union), income tax expense, distributions from unconsolidated affiliates and our General Partner's contribution, less earnings in unconsolidated affiliates, gains (losses) that are unusual such as gain on revaluation of equity interest, and the gain on sale of the Propane Business, other, net and gain on sale of assets, net.
The GAAP measure most directly comparable to our performance measure Adjusted EBITDA is net loss attributable to the Partnership. For a reconciliation of net loss to Adjusted EBITDA , see Non-GAAP Financial Measures below.
Note about 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 loss attributable to the Partnership, their most directly comparable GAAP measure, for the years ended December 31, 2017, 2016, and 2015 (in thousands):
|
| | | | | | | | | | | |
| Years Ended December 31, |
| 2017 (1) | | 2016 (2) | | 2015 (2) |
| | | (In thousands) | | |
Reconciliation of Total Segment Gross Margin to Net loss attributable to the Partnership | | | | |
|
|
Gas Gathering and Processing Services | $ | 49,010 |
| | $ | 48,245 |
| | $ | 65,692 |
|
Liquid Pipelines and Services | 27,999 |
| | 31,556 |
| | 26,399 |
|
Natural Gas Transportation Services | 23,424 |
| | 18,616 |
| | 18,073 |
|
Offshore Pipelines and Services | 103,664 |
| | 82,346 |
| | 33,613 |
|
Terminalling Services | 37,987 |
| | 42,872 |
| | 36,079 |
|
Total Segment Gross Margin | 242,084 |
| | 223,635 |
| | 179,856 |
|
Less: | | | | | |
Direct operating expenses (3) | 67,617 |
| | 60,762 |
| | 61,315 |
|
Operating margin | 174,467 |
| | 162,873 |
| | 118,541 |
|
Add: | | | | |
|
Gains (losses) on commodity derivatives, net | (119 | ) | | (1,617 | ) | | 1,345 |
|
Deduct: | | | | |
|
Corporate expenses | 112,058 |
| | 89,438 |
| | 65,327 |
|
Depreciation, amortization and accretion | 103,448 |
| | 90,882 |
| | 81,335 |
|
(Gain) loss on sale of assets, net | (4,063 | ) | | 688 |
| | 2,860 |
|
Impairment of long-lived assets / intangible assets | 116,609 |
| | 697 |
| | — |
|
Impairment of goodwill | 77,961 |
| | 2,654 |
| | 148,488 |
|
Interest expense | 66,465 |
| | 21,433 |
| | 20,077 |
|
Other income | (36,254 | ) | | (254 | ) | | (1,460 | ) |
Other, net (4) | (510 | ) | | |