Item 1. Business

Overview

American Midstream Partners, LP (along with its consolidated subsidiaries, "we", "us," "our," or the "Partnership") 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 three reporting segments, (i) gathering and processing, (ii) transmission and (iii) terminals, we are engaged 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.

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 transmission and terminal assets are located in key demand markets in Alabama, Louisiana, Mississippi and, Tennessee, and in the Port of New Orleans in Louisiana and the Port of Brunswick in Georgia.

We own or have ownership interests in more than 3,800 miles of onshore and offshore natural gas, crude oil, NGL and saltwater pipelines across 15 gathering systems, six interstate pipelines and eight intrastate pipelines; eight natural gas processing plants; four fractionation facilities; an offshore semisubmersible floating production system with nameplate processing capacity of 80 MMbl/d of crude oil and 200 MMcf/d of natural gas; and three marine terminal sites with approximately 2.4 MMBbls of above-ground aggregate storage capacity for petroleum products, distillates, chemicals and agricultural products.

A portion of our cash flow is derived from our investments in unconsolidated affiliates in our consolidated financial statements including a 49.7% operated interest in Destin Pipeline Company, L.L.C. (“Destin”), a natural gas pipeline; a 20.1% non-operated indirect interest in Class A units in the entities that own the Delta House 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 25.3% non-operated interest in Wilprise Pipeline Company, L.L.C. (“Wilprise”), an NGL pipeline; and a 66.7% non-operated interest in Main Pass Oil Gathering Company ("MPOG"), a crude oil gathering and processing system.

In our Gathering and Processing segment, we receive fee-based and fixed-margin compensation for gathering, processing, transporting and treating natural gas and crude oil. Where we provide processing services at the plants that we own or share an interest, or obtain processing services for our own account under our elective processing arrangements, we typically retain and sell a percentage of the residue natural gas and/or resulting NGLs under percent-of-proceeds ("POP") arrangements.

In our Transmission segment, 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.

In our Terminals segment, we generally receive fee-based compensation under 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.

Recent Developments

JPE Merger

On March 8, 2017, the Partnership completed the acquisition of 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. The Partnership issued a total of 20.2 million of the Partnership’s common units to complete the

acquisition, including 9.8 million common units to ArcLight affiliates. Unless stated otherwise, this Annual Report discusses the activities of the Partnership as of December 31, 2016. Any reference to the combined company considers activities subsequent to the JPE Merger and includes discussion regarding the Partnership and JPE (the "Combined Company").

As both the Partnership and JPE were controlled by ArcLight affiliates, the acquisition represents a transaction among entities under common control and will be accounted for as a common control transaction. Although the Partnership is the legal acquirer, JPE is considered to the acquirer for accounting purposes as ArcLight obtained control of JPE prior to it obtaining control of the Partnership on April 15, 2013. As a result, JPE will record the acquisition of the Partnership at ArcLight’s historical cost basis. The Partnership will file recast historical cost financial statements for the combined entity in May 2017.

JPE owns, operates and develops a diversified portfolio of midstream energy assets with three business segments (i) crude oil pipelines and storage, (ii) refined products terminals and storage and (iii) NGL distribution and sales, which together provide midstream infrastructure solutions for the growing supply of crude oil, refined products and NGLs, in the United States.

Third Amendment to Partnership Agreement

The Partnership also executed Amendment No. 3 to our Fifth Amended and Restated Partnership Agreement (as amended, the “Partnership Agreement”), which amends the distribution payment terms of the Partnership’s outstanding Series A Preferred Units to provide for the payment of Series A payment-in-kind (“ PIK ”) preferred units for the quarter (the “ Series A Preferred Quarterly Distribution ”) in which the JPE Merger is consummated (which is the quarter ended March 31, 2017) and thereafter equal to the quotient of (i) the greater of (a) $0.4125 and (b) the "Series A Distribution Amount", as such term is defined in the Partnership Agreement, divided by (ii) the Series A Adjusted Issue Price, as such term is defined in the Partnership Agreement. However, in our General Partner’s discretion, which determination shall be made prior to the record date for the relevant quarter, the Series A Preferred Quarterly Distribution may be paid as (x) an amount in cash up to the greater of (1) $0.4125 and (2) the Series A Distribution Amount, and (y) a number of Series A Preferred Units equal to the quotient of (a) the remainder of (i) the greater of (I) $0.4125 and (II) the Series A Distribution Amount less (ii) the amount of cash paid pursuant to clause (x), divided by (b) the Series A Adjusted Issue Price.

Second Amended and Restated Credit Agreement

On March 8, 2017, the Partnership and its operating company, American Midstream, LLC, along with other subsidiaries of the Partnership (collectively, the “Borrowers”) entered into a Second Amended and Restated Credit Agreement with Bank of America, N.A., as Administrative Agent, Collateral Agent and L/C Issuer, Wells Fargo Bank, National Association, as Syndication Agent,  and other lenders (the “Second Amended Credit Agreement”).  By entering into the Second Amended Credit Agreement, the Partnership amended its existing credit facility to increase its borrowing capacity thereunder from $750 million to $900 million and to provide for an accordion feature that will permit, subject to the customary conditions, the borrowing capacity under the facility to be increased to a maximum of $1.1 billion. The $900 million in lending commitments under the Second Amended Credit Agreement includes a $30 million sublimit for borrowings by the Blackwater Borrower and a $100 million sublimit for standby letters of credit, which was increased in this Second Amended Credit Agreement from $50 million. The Second Amended Credit Agreement matures on September 5, 2019.  The Second Amended Credit Agreement facilitates the joinder to the credit facility of certain surviving entities from the JPE Merger ( the " JPE Entities") and adjusts certain covenants, representations and warranties under the credit facility to support the JPE Entities.  All obligations under the Second Amended Credit Agreement and the guarantees of those obligations are secured, subject to certain exceptions, by a first-priority lien on and security interest in substantially all of the Borrowers’ assets and the assets of all, subject to certain exceptions, existing and future subsidiaries and all of the capital stock of the Partnership’s existing and future subsidiaries.

When we use the term “revolving credit facility” or “Credit Agreement,” we are referring to our First Amended and Restated Credit Facility and to our Second Amended and Restated Credit Facility, as the context may require.

8.50% Senior Notes

On December 28, 2016, the Partnership and American Midstream Finance Corporation, our wholly owned subsidiary (together with the Partnership, the “Issuers”) completed the issuance and sale of $300 million in aggregate principal amount of senior notes due 2021 (the "8.50% Senior Notes"). Wells Fargo Securities, LLC served as the representative of the initial purchasers, which included Merrill Lynch, Pierce, Fenner & Smith Incorporated, RBC Capital Markets, LLC, Citigroup Global Markets Inc., SunTrust Robinson Humphrey, Inc., Natixis Securities Americas LLC, ABN AMRO Securities (USA) LLC, Capital One Securities, Inc., Deutsche Bank Securities Inc., BNP Paribas Securities Corp., BMO Capital Markets Corp., Santander Investment Securities Inc. and BBVA Securities Inc. The 8.50% Senior Notes rank equal in right of payment with all existing and future senior indebtedness of the Issuers, and senior in right of payment to any future subordinated indebtedness of the Issuers. The 8.50% Senior Notes were

issued at par and provided net proceeds of approximately $294.0 million , after deducting the initial purchasers' discount of $6.0 million . This amount was deposited into escrow pending completion of the JPE Merger and is included in Restricted cash on the Partnership's consolidated balance sheet as of December 31, 2016. The Partnership also incurred $2.7 million of direct issuance costs resulting in net proceeds related to the 8.50% Senior Notes of $291.3 million . The notes were offered and sold to qualified institutional buyers in the United States pursuant to Rule 144A under the Securities Act, and to persons, other than U.S. persons, outside the United States pursuant to Regulation S under the Securities Act.

Upon the closing of the JPE Merger and the satisfaction of other related conditions the restricted cash was released from escrow on March 8, 2017. The Partnership used the net proceeds to repay and terminate JPE's revolving credit facility and to reduce borrowings under the Partnership’s Amended and Restated Credit Agreement (the "Credit Agreement").

Additional Delta House Investments

On April 25, 2016, American Midstream Delta House, LLC ("AMID Delta House"), our wholly-owned indirect subsidiary, entered into a unit purchase agreement with an ArcLight affiliate, pursuant to which AMID Delta House acquired 100% of the outstanding membership interests in D-Day Offshore Holdings, LLC ("D-Day"), which owned 912.4 Class A Units of Delta House FPS LLC ("Delta House FPS") and 53.5 Class A Units of Delta House Oil and Gas Lateral LLC ("Delta House Lateral") in exchange for approximately $9.9 million in cash funded with additional borrowings under the Partnership’s Credit Agreement. Delta House is a semisubmersible floating production system platform with associated crude oil and natural gas export pipelines, located in the Mississippi Canyon region of the deepwater Gulf of Mexico. Delta House FPS owns the floating production system and Delta House Lateral owns the associated crude oil and natural gas export pipelines. When we refer to "Delta House" we are referring to our investment in Delta House FPS and Delta House Lateral.

On October 31, 2016, D-Day acquired an additional 6.2% direct interest in Delta House by purchasing additional Class A Units in Delta House FPS and Delta House Lateral from unrelated parties for approximately $48.8 million , which was funded with net proceeds of $34.5 million from the issuance of 2,333,333 Series D convertible preferred units ("Series D Units") to an ArcLight affiliate, plus $14.3 million in cash funded with borrowings under our Credit Agreement. The Series D Units were issued at $15.00 per unit, less a 1.5% closing fee, and if any Series D Units remain outstanding on June 30, 2017, the Partnership will issue a warrant to purchase up to 700,000 common units representing limited partnership interests in the Partnership (“common units”) with an exercise price of $22.00 per common unit (the "Series D Warrants"). Magnolia Infrastructure Holdings, LLC (an affiliate of ArcLight) holds the Series D Units and participates in the related distributions which are to be made in cash. The Series D Units were issued, and the Series D Warrants, if issued, will be issued, in a private placement in reliance upon an exemption from the registration requirements of the Securities Act pursuant to Section 4(a)(2) thereof and the safe harbor provided by Rule 506 of Regulation D promulgated thereunder.

The investment in D-Day, together with our 26.3% interest in Pinto Offshore Holdings, LLC, an entity that owns a 49.0% non-operated interest in Delta House Class A Units, results in the Partnership holding a combined 20.1% non-operated indirect and direct interest in Delta House. Our interest in Delta House includes a 20.1% interest in Class A Units of Delta House FPS.The Class A Units in Delta House FPS are currently entitled to receive 100% of the distributions from Delta House FPS until a certain payout threshold is met. Once the payout threshold is met, approximately 7% of distributions from Delta House FPS will be paid to the Class B membership interests in Delta House FPS. It is currently estimated that the payout threshold on the Class A Units will be met in the year 2020.

3.77% Senior Notes

On September 30, 2016, Midla Financing, LLC (“Midla Financing”), American Midstream (Midla), LLC (“Midla”) and Mid Louisiana Gas Transmission LLC (“MLGT” and, together with Midla, the “Note Guarantors”), entered into a Note Purchase and Guaranty Agreement (the “3.77% Senior Note Purchase Agreement”) with Massachusetts Mutual Life Insurance Company and MassMutual Asia Limited (the “Purchasers”) whereby Midla Financing sold $60.0 million in aggregate principal amount of Senior Notes to the Purchasers, which bear interest at an annual rate of 3.77% to be paid quarterly (the "3.77% Senior Notes"). Principal and interest on the 3.77% Senior Notes is payable in installments on the last business day of each quarter beginning June 30, 2017 with the remaining balance payable in full on June 30, 2031. The average quarterly principal payment is approximately $1.1 million . The 3.77% Senior Notes were issued at par and provided net proceeds of approximately $57.7 million after deducting related issuance costs of $ 2.3 million . Morgan Stanley Senior Funding, Inc. served as the placement agent. The 3.77% Senior Notes were offered and sold in a private placement in reliance upon an exemption from the registration requirements of the Securities Act of 1933 pursuant to Section 4(a)(2) thereof and the safe harbor provided by Rule 506 of Regulation D promulgated thereunder.

 

Net proceeds from the 3.77% Senior Notes are restricted and will be used to fund the retirement of Midla's existing 1920’s pipeline, project costs incurred in connection with the construction of a new replacement pipeline from Winnsboro, Louisiana to Natchez, Mississippi (the “Midla-Natchez Line”), the move of our Baton Rouge operations to the MLGT system, and the reconfiguration of the DeSiard compression system and all related ancillary facilities. These proceeds can also be used to pay costs incurred in connection with the issuance of the 3.77% Senior Notes, and for general corporate purposes of Midla Financing. As of December 31, 2016, Restricted cash includes $24.5 million from the issuance of the 3.77% Senior Notes. Construction commenced on the Midla-Natchez Line in the second quarter of 2016 with service expected to begin within the first six months of 2017.

Acquisition of interests in Gulf of Mexico midstream assets

On April 15, 2016, American Panther, LLC (“American Panther”), a 60%-owned subsidiary of the Partnership, acquired approximately 200 miles of crude oil, natural gas, and salt water onshore and offshore Gulf of Mexico pipelines (“Gulf of Mexico Pipeline”) from Chevron Pipeline Company and Chevron Midstream Pipeline, LLC for approximately $2.7 million in cash and the assumption of certain asset retirement obligations. The Partnership controls American Panther and therefore consolidates it for financial reporting purposes.

The Gulf of Mexico Pipeline acquisition was accounted for using the acquisition method of accounting and as a result, the purchase price was allocated to the assets acquired and liabilities assumed based on their respective estimated fair values as of the acquisition date. The purchase price allocation included $16.6 million in pipelines, $0.4 million in land, $14.3 million in asset retirement obligations and $1.8 million in noncontrolling interests.

Emerald Transactions

On April 25, 2016 and April 27, 2016, American Midstream Emerald, LLC ("Emerald"), a wholly-owned indirect subsidiary of the Partnership, entered into two purchase and sale agreements with an ArcLight affiliate, for the purchase of membership interests in certain entities (together, the “Emerald Transactions”).

On April 25, 2016, Emerald entered into the first purchase and sale agreement for the purchase of membership interests in entities that own and operate natural gas pipeline systems and NGL pipelines in and around Louisiana, Alabama, Mississippi, and the Gulf of Mexico (the "Pipeline Purchase Agreement"). Pursuant to the Pipeline Purchase Agreement, Emerald acquired (i) 49.7% of the issued and outstanding membership interests of Destin, (ii) 16.7% of the issued and outstanding membership interests of Tri-States and (iii) 25.3% of the issued and outstanding membership interests of Wilprise, in exchange for approximately $183.6 million (the “Pipeline Transaction”).

On April 27, 2016, Emerald entered into the second purchase and sale agreement for the purchase of 66.7% of the issued and outstanding membership interests of Okeanos, in exchange for a cash purchase price of approximately $27.4 million . The Okeanos pipeline is a 100 -mile natural gas gathering system located in the Gulf of Mexico with a total capacity of 1.0 Bcf/d.

The Partnership funded the aggregate purchase price for the Emerald Transactions with the issuance of 8,571,429 Series C convertible preferred units (the “Series C Units”) representing limited partnership interests in the Partnership and a warrant (the “Series C Warrant”) to purchase up to 800,000 common units at an exercise price of $7.25 per common unit amounting to a combined value of approximately $120.0 million , plus additional borrowings of $91.0 million under our Credit Agreement. ArcLight affiliates hold and participate in distributions on our Series C Units with such distributions being made in paid-in-kind Series C Units, cash or a combination thereof at the election of the Board of Directors of our General Partner. Magnolia Infrastructure Holdings, LLC, an ArcLight affiliate, holds the Series C Units. The Series C Units and the Series C Warrant were both issued in a private placement in reliance upon an exemption from the registration requirements of the Securities Act pursuant to Section 4(a)(2) thereof and the safe harbor provided by Rule 506 of Regulation D promulgated thereunder. 

Because our interests in the entities underlying the Emerald Transactions were previously owned by an ArcLight affiliate, we accounted for our investments at our affiliate’s historical cost basis of $212.0 million , and recorded them in Investment in unconsolidated affiliates in our consolidated balance sheet, and as an investing activity of $100.9 million within the consolidated statement of cash flows. The amount by which the affiliate's historical basis exceeded total consideration was $1.0 million and is recorded as a contribution from our General Partner in the consolidated statements of changes in partners’ capital and noncontrolling interests.

Market Conditions

Average daily prices for New York Mercantile Exchange ("NYMEX") West Texas Intermediate ("WTI") crude oil ranged from a high of $54.45 per barrel to a low of $26.21 per barrel from January 1, 2016 through March 13, 2017. Average daily prices for NYMEX Henry Hub natural gas ranged from a high of $3.80 per MMBtu to a low of $1.49 per MMBtu from January 1, 2016 through March 13, 2017. We are unable to predict future 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 do not continue the current upward trend from 2016 to 2017, this could lead to reduced profitability and may impact our liquidity and compliance with the financial covenants in our Credit Agreement. Reduced profitability may result in future potential non-cash impairments of long-lived assets, goodwill, or intangible assets, as well as the reduction or elimination of distributions to our unitholders.

Business Strategies

Our principal business objective is to increase our quarterly cash flows over time while ensuring the long-term stability of our business. We expect to achieve this objective by focusing on the following strategies:

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 recently acquired 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. For example, we are evaluating the expansion of our existing Harvey terminal by adding 1.35 MMBbls of incremental storage capacity, additional rail capacity and a second deep water ship berth. There has been steady demand for storage capacity in the Port of New Orleans, and the Harvey site is currently 98% utilized and continues to attract interest for long-term storage.

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 from 74.4% to 88.9% for the fiscal years ended December 31, 2014 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. We expect our increased scale and diversification and improved financial position resulting from the JPE Merger will enhance our access to sources of capital.

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 producers, refiners and marketers including ConocoPhillips Co., Royal Dutch Shell plc, BP P.L.C., Chevron Corporation, Exxon Mobil Corp., LLOG Exploration Company, L.L.C. and Monsanto Company.

Significant scale and capability. As of December 31, 2016, after giving effect to the JPE Merger, we have $2.3 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 4,000 miles of onshore and offshore natural gas, crude oil, NGL and saltwater pipelines across 16 gathering systems, six 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 80 MBbl/d of crude oil and 200 MMcf/d of natural gas; six terminal sites with approximately 6.7 MMBbls of above-ground storage capacity; and a fleet of 97 crude oil gathering and LPG transport trucks. In addition, we have the third largest cylinder exchange business in the United States. 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 controls High Point Infrastructure Partners, LLC (“HPIP”), the majority owner of our general partner, owns 49.3% of our limited partner units 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 18 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 Assets

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 transmission and terminal assets are located in key demand markets in Alabama, Louisiana, Mississippi and Tennessee and in the Port of New Orleans in Louisiana and the Port of Brunswick in Georgia.

We own or have ownership interests in more than 3,800 miles of onshore and offshore natural gas, crude oil, NGL and saltwater pipelines across 15 gathering systems; six interstate pipeline; eight intrastate pipelines; eight natural gas processing plants; four fractionation facilities; an offshore semisubmersible floating production system with nameplate processing capacity of 80 MMBbl/d of crude oil and 200 MMcf/d of natural gas; and three marine terminal sites with approximately 2.4 MMBbls of above-ground aggregate storage capacity for petroleum products, distillates, chemicals and agricultural products.

A portion of our cash flow is derived from our investments in unconsolidated affiliates including a 49.7% operated interest in Destin, a natural gas pipeline; a 20.1% non-operated indirect interest in Class A units of Delta House, which is a floating production

system platform and related pipeline infrastructure; a 16.7% non-operated interest in Tri-States, an NGL pipeline; a 66.7% operated interest in Okeanos, a natural gas pipeline; a 25.3% non-operated interest in Wilprise, an NGL pipeline; and a 66.7% non-operated interest in MPOG, a crude oil gathering and processing system. We organize our operations into three business segments: i) Gathering and Processing; ii) Transmission; and iii) Terminals.

Gathering and Processing Segment

General

Our Gathering and Processing segment consists of midstream natural gas systems that provide the following services to our customers:

Our Gathering and Processing assets are located in Alabama, Louisiana, Mississippi, North Dakota 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 Gathering and Processing 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, 2016 , our fee-based, fixed-margin arrangements and our POP arrangements accounted for approximately 80.6% and 19.4% , respectively, of our segment gross margin for the Gathering and Processing segment. For the year ended December 31, 2015 , our fee-based, fixed-margin arrangements and our POP arrangements accounted for approximately 77.3% and 22.7% , respectively, of our segment gross margin for the Gathering and Processing segment.

The following table provides information regarding our Gathering and Processing segment assets for the years ended December 31, 2016 and 2015 .

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.

Magnolia System

The Magnolia gathering system is a Section 311 intrastate pipeline that gathers coal-bed methane 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 Pipeline System"), an interstate pipeline owned by The Williams Companies, Inc. The Magnolia System consists of approximately 118 miles of pipeline with small-diameter gathering lines and trunk lines ranging from six to 24 inches in diameter and four compressor stations with 4,690 horsepower.

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 County, Texas.

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.

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. As of December 2016, the Bazor Ridge facility is exclusively used as a central gathering and compression facility and processing was 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 10 MMcf/d. The facility is located near Laurel in Jones County, Mississippi.

American Panther System

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 475.0 MMcf/d and crude oil and saltwater capacity of 27.0 MBbl/d.

 

Other Gathering and Processing Systems

Gloria and Lafitte systems. The Gloria gathering system provides gathering 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 Gloria System may experience excess volumes from our Lafitte system. 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 and Burns Point Systems. 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 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.

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 16 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. As of December 31, 2016, the offshore pipe on both systems has been abandoned, and the onshore pipe is out of service.

Mesquite

We own a 48.4% non-operated interest in Mesquite, a joint venture with EnLink Midstream located near Midland, Texas. The Mesquite facility includes a rail terminal, 5,000 Bbl/d condensate stabilization facility 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. 

Customers and Contracts

For the year ended December 31, 2016 , our Gathering and Processing segment derived 11% of its revenue from ConocoPhillips. For the year ended December 31, 2015 , our Gathering and Processing segment derived 12% of its revenue from both ConocoPhillips and Penn Virginia, respectively. With respect to our Gathering and Processing segment, substantially all of the natural gas produced on our Lavaca System is gathered for Penn Virginia Corporation. Our contract with Penn Virginia Corporation expires in 2039. On our Gloria and Lafitte systems, we have a buy/sell agreement whereby most of the natural gas is sold to ConocoPhillips for use at the Alliance Refinery in Plaquemines Parish, Louisiana, under a contract that expires in 2026. Standard & Poor's Financial Services LLC ("Standard & Poor's") rated ConocoPhillips as "A-" and Moody's Investor Service ("Moody's") rated Penn Virginia as "D-PD" during 2016.

Transmission Segment

General

Our Transmission segment is comprised of interstate and intrastate pipelines that transport natural gas from interconnection points on other large pipelines or production points to customers, such as local distribution companies ("LDCs"), electric utilities, direct-served industrial complexes, or to interconnects on other pipelines. Certain of our pipelines are subject to regulation by FERC and by state regulators. In this segment, we often enter into firm transportation contracts with our shipper customers to transport natural gas sourced from large interstate or intrastate pipelines. Our Transmission segment assets are located in multiple parishes in Louisiana, including onshore and offshore producing regions around southeast Louisiana, and multiple counties in Mississippi, Alabama and Tennessee.

The following table provides information regarding our Transmission segment assets for the years ended December 31, 2016 and 2015 .

High Point System

The High Point System consists of approximately 574 miles 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 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.

Midla and MLGT Systems

Our Midla System is an interstate natural gas pipeline with approximately 355 miles of pipeline linking the Monroe Natural Gas Field in northern Louisiana and interconnections with the Transco Pipeline System to customers in Mississippi and Louisiana.

The northern portion of the system, including the T-32 lateral, consists of approximately four miles of high-pressure, 12-inch-diameter pipeline. Natural gas on the northern end of the Midla System is delivered to two power plants operated by Entergy by way of the T-32 lateral and the CLECO Sterlington plant by way of the Sterlington lateral. In addition, the new Angus Chemical market will be connected on the T-32 system in the first half of 2017, increasing the load by approximately 7,000 mcf/d.

The mainline consists of approximately 170 miles of low-pressure, 22-inch-diameter pipeline with laterals ranging in diameter from two to 16 inches. This section of the Midla System primarily serves small local distribution companies or LDCs under firm transportation contracts that automatically renew on a year-to-year basis. Substantially all of these contracts are at the maximum rates allowed under Midla's FERC tariff.

The southern portion of the system, including associated laterals, consists of approximately two miles of high and low-pressure, 12-inch-diameter pipeline. This section of the system primarily serves industrial and LDC customers in southern Louisiana.

The MLGT System is an intrastate transmission system that sources natural gas from interconnects with the FGT Pipeline system, the Tetco Pipeline system, the Transco Pipeline system and the Gulf South Pipeline to various markets including a Baton Rouge, Louisiana refinery owned and operated by ExxonMobil Corporation, several other industrial customers and Entergy. Our MLGT System is comprised of approximately 65 miles of pipeline with diameters ranging from three to 14 inches. The MLGT System is connected to six receipt and 28 delivery points.

On April 16, 2015, the FERC approved the Midla Agreement between Midla and its customers allowing Midla to retire the existing 1920's pipeline and replace the existing natural gas service with the new Midla-Natchez Line to serve existing residential, commercial, and industrial customers. Under the Midla Agreement, customers not served by the new Midla-Natchez Line will be 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 with service expected to begin in the first half of 2017. Under the Midla Agreement, Midla has executed long-term agreements seeking to recover its investment in the Midla-Natchez Line.

AlaTenn/Bamagas/Trigas

AlaTenn System . 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, an interstate pipeline owned by Kinder Morgan, the Tetco Pipeline system, an interstate pipeline owned by Spectra Energy Transmission, LLC, and the Columbia Gulf Pipeline system, an interstate pipeline owned by NiSource Gas Transmission and Storage. In mid-2017, AlaTenn will connect with the Southern Natural Gas system, an interstate pipeline owned by Kinder Morgan, which will provide access to new markets.

Bamagas System . 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 System . Our Trigas System is located in three counties in northwestern Alabama and has approximate design capacity of 60 MMcf/d. Our Trigas System currently serves primarily industrial loads.

Chalmette System . The Chalmette System is located in St. Bernard Parish, Louisiana. The approximate design capacity for the Chalmette System is 125 MMcf/d.

Customers

In our Transmission segment, we contract with LDCs, electric utilities, or direct-served industrial complexes, or to interconnections on other large pipelines, to provide firm and interruptible transportation services.

For our Midla and AlaTenn systems, and a portion of our High Point systems, which are interstate natural gas pipelines, the maximum and minimum rates for services are governed by each individual system's FERC-approved tariff. In some cases, with FERC approval, we can have rates or certain other terms that are different from those generally provided for in the FERC tariff. For our Bamagas and MLGT systems, which are intrastate pipelines providing interstate services under the Hinshaw exemption of the Natural Gas Act ("NGA"), we negotiate service rates with each of our shipper customers.

For our High Point systems, we have interruptible transportation contracts in place with various customers operating in both onshore and offshore producing regions around southeast Louisiana. During 2015, we converted a fixed-margin arrangement on our MLGT System to an interruptible transportation contract, which has reduced the amount of natural gas that we purchase and sell.

Superior Natural Gas Corporation and ConocoPhillips are the two largest purchasers of natural gas and transmission capacity in our Transmission segment and accounted for approximately 14% and 13% , respectively, of our segment revenue for the year ended December 31, 2016 . For the year ended December 31, 2015 , Superior Natural Gas Corporation and Enbridge Marketing (US) L.P. accounted for approximately 19% and 16% , respectively, of our segment revenue. The majority of our firm and interruptible transportation contracts in the Transmission segment are evergreen contracts. Standard & Poor's rated ConocoPhillips as "A-" and Superior as "BB-" during 2016.

Terminals Segment

General

Our Terminals 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 Terminals 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.

The following table provides information regarding our Terminals segment assets for the years ended December 31, 2016 and 2015 .

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, railcar and/or barge or ship. 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. The ship dock does not allow for transfer of railcar or a tank truck. When fully developed, the Harvey Terminal has the potential to provide more than 2 million barrels of storage capacity.

Customers

In our Terminals segment, we generally receive fee-based compensation on guaranteed firm storage contracts and throughput fees charged to our customers when their products are either received or disbursed along with other operational charges associated with ancillary services provided to our customers, such as excess throughput and truck weighing. The terms of our firm storage contracts are multiple years, with renewal options.

PBF Holding Company LLC and Occidental Chemical Corporation are the two largest customers in our Terminals segment and accounted for approximately 17% and 23% respectively, of our segment revenue for the year ended December 31, 2016 . Occidental Chemical Corporation and Monsanto Company accounted for approximately 21% and 13% , respectively, of our segment revenue for the year ended December 31, 2015. As of December 31, 2016 , the weighted-average remaining life of our guaranteed firm storage contracts in the Terminals segment is approximately 1.04 years. Standard & Poor's rated PBF Holding Company as "BB" and Moody's rated Occidental Petroleum (Occidental Chemical Corporation's parent company) as "A3" during 2016.

Investment in Unconsolidated Affiliates

Delta House

We own a 20.1% direct and indirect non-operating interests in Class A Units of Delta House. Delta House is a semi-submersible floating production system (“FPS”) with associated crude oil and natural gas export pipelines located in the Mississippi Canyon region of the deepwater Gulf of Mexico. The FPS 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.

Main Pass Oil Gathering System

We own a 66.7% non-operated interested in MPOG, 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 Panther Operating Companies, LLC, a subsidiary of the minority interest owner, Panther Asset Management, LLC.

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

We own a 49.7% operated interest in Destin, a FERC-regulated, 255-mile natural gas transportation 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 natural gas gathering, compression, treating and transportation business is very competitive. Our competitors in our Gathering and Processing segment include other midstream companies, producers, intrastate and interstate pipelines. Competition for natural gas volumes is primarily based on reputation, commercial terms, reliability, service levels, location, available capacity, capital expenditures and fuel efficiencies. Our major competitors in this segment include DCP Midstream LLC; Enbridge Energy Partners; LP; Energy Transfer Partners, L.P.; EnLink NGL Marketing, L.P.; Kinder Morgan Energy Partners, and Midcoast Energy Partners.

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.

In our Transmission segment, we compete with other pipelines that serve regional markets, specifically in our Baton Rouge market. An increase in competition could result from new pipeline installations or expansions of existing pipelines. Competitive factors include the commercial terms, available capacity, fuel efficiencies, the interconnected pipelines and natural gas quality issues. Our major competitors for this segment are Columbia Gulf Transmission Company; EnLink NGL Marketing, L.P.; Enterprise Gas Processing, LLC; Gulf South Pipeline Company, LP; Southern Natural Gas Company; Tennessee Gas Pipeline Company, LLC, and Texas Eastern Pipeline.

In our Terminals segment, we compete with a number of existing storage facilities within the New Orleans to Baton Rouge, Louisiana refining and manufacturing corridor, the southeast USA and the Florida and Georgia area. Our major competitors for this segment are International-Matex Tank Terminals; Kinder Morgan Energy Partners; LBC Tank Terminals; Royal Vopak; Stolt-Nielsen Limited, and Westway Terminals Company LLC.

Other Segment Information

For additional information on our segments, including revenues from customers, profit or loss and total assets, please see Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Item 15. "Exhibits and Financial Statement Schedules."

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:

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 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:

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. 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. 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.

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 Commission'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 Commission issued Order No. 735-A. In Order No. 735-A, the Commission 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 issued an order.

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:

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. 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 SO 2, 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 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 Section OOOO storage tank requirements. On September 23, 2013, the EPA published final revisions to the NSPS Section 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 volatile organic compounds emissions from oil and gas development and production operations, including hydraulic fracturing and other well completion activity. 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.

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 volatile organic compounds 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. On February

28, 2017, President Trump issued an executive order directing the EPA and the U.S. Army Corps of Engineers to review and, consistent with applicable law, to initiate rulemaking to rescind or revise 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. We own and operate an acid gas disposal well in Wayne County, Mississippi, as part of our Bazor Ridge gas treating facilities. This well takes a combination of hydrogen sulfide and carbon dioxide recovered from the raw field natural gas feeding the Bazor Ridge Gas plant and injects it into an underground formation permitted for this purpose. The well received an Underground Injection Control ("UIC") Class 2 permit through the Mississippi state oil and gas board in 1999. As part of our permit requirements, we perform regular inspection, maintenance and reporting to the state on the condition and operations of this well which is adjacent to our processing plant. We believe that our facilities will not be materially adversely affected by such 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

We do not have any employees. The officers of our General Partner manage our operations and activities. As of December 31, 2016, our General Partner employed approximately 329 people who provide direct, full-time support to our operations. All of the employees required to conduct and support our operations are employed by our General Partner. 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 on Form 10-K.