Document
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
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x | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
| For the fiscal year ended December 31, 2016 |
Or
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o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
| For the transition period from to |
Commission File Number: 001-35257
AMERICAN MIDSTREAM PARTNERS, LP
(Exact name of registrant as specified in its charter)
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Delaware | | 27-0855785 |
(State or other jurisdiction of incorporation or organization) | | (I.R.S. Employer Identification No.) |
2103 CityWest Boulevard Building #4, Suite 800 Houston, Texas | | 77042 |
(Address of principal executive offices) | | (Zip code) |
(346) 241-3400(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
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Title of Each Class | | Name of Each Exchange on Which Registered |
Common Units Representing Limited Partnership Interests | | New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No x
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No x
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o
Indicate by checkmark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained in, to the best of the registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):
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Large accelerated filer | | o | | Accelerated filer | | x |
Non-accelerated filer | | o (Do not check if a smaller reporting company) | | Smaller reporting company | | o |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). (Check one): Yes o No x
The aggregate market value of common units held by non-affiliates of the registrant on June 30, 2016, was $321,334,978. The aggregate market value was computed by reference to the closing price of the registrant's common units on the New York Stock Exchange on June 30, 2016.
There were 51,585,690 common units, 10,266,642 Series A Units, 8,792,205 Series C Units, and 2,333,333 Series D Units of American Midstream Partners, LP outstanding as of March 20, 2017. Our common units trade on the New York Stock Exchange under the ticker symbol "AMID."
Documents Incorporated by Reference
None.
TABLE OF CONTENTS
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PART I | |
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1 | | |
1A | | |
1B | | |
2 | | |
3 | | |
4 | | |
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PART II | |
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5 | | |
6 | | |
7 | | |
7A | | |
8 | | |
9 | | |
9A | | |
9B | | |
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PART III | |
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10 | | |
11 | | |
12 | | |
13 | | |
14 | | |
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PART IV | |
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15 | | |
16 | | |
CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS
Our reports, filings and other public announcements may from time to time contain statements that do not directly or exclusively relate to historical facts. Such statements are "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. You can typically identify forward-looking statements by the use of words, such as "may," "could," "project," "believe," "anticipate," "expect," "estimate," "potential," "plan," "forecast" and other similar words.
All statements that are not statements of historical facts, including statements regarding our future financial position, business strategy, budgets, projected costs and plans and objectives of management for future operations, are forward-looking statements.
These forward-looking statements reflect our intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties and other factors, many of which are outside our control. Important factors that could cause actual results to differ materially from the expectations expressed or implied in the forward-looking statements include known and unknown risks. These risks and uncertainties, many of which are beyond our control, include, but are not limited to, the risks set forth in "Item 1A. Risk Factors" in this Annual Report on Form 10-K (the "Annual Report") as well as the following risks and uncertainties:
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• | our ability to integrate with JP Energy Partners LP (“JPE”) successfully after consummation of the JPE Merger (as defined herein) and to achieve anticipated benefits from the proposed transaction; |
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• | our ability to generate sufficient cash from operations to pay distributions to unitholders; |
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• | our ability to maintain compliance with financial covenants and ratios in our Credit Facility (as defined herein); |
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• | dispositions of assets owned by us or JPE prior to the completion of the JPE Merger, which assets may have been material to us or JPE; |
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• | our ability to timely and successfully identify, consummate and integrate our current and future acquisitions and complete strategic dispositions, including the realization of all anticipated benefits of any such transaction, which otherwise could negatively impact our future financial performance; |
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• | the timing and extent of changes in natural gas, crude oil, NGLs and other commodity prices, interest rates and demand for our services; |
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• | our ability to access capital to fund growth, including new and amended credit facilities and access to the debt and equity markets, which will depend on general market conditions; |
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• | severe weather and other natural phenomena, including their potential impact on demand for the commodities we sell and the operation of company-owned and third party-owned infrastructure; |
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• | the level of creditworthiness of counterparties to transactions; |
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• | the level and success of natural gas and crude oil drilling around our assets and our success in connecting natural gas and crude oil supplies to our gathering and processing systems; |
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• | our success in risk management activities, including the use of derivative financial instruments to hedge commodity and interest rate risks; |
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• | changes in laws and regulations, particularly with regard to taxes, safety, regulation of over-the-counter derivatives market and entities, and protection of the environment; |
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• | our failure or our counterparties’ failure to perform on obligations under commodity derivative and financial derivative contracts; |
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• | the performance of certain of our current and future projects and unconsolidated affiliates that we do not control; |
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• | the demand for NGL products by the petrochemical, refining or other industries; |
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• | our dependence on a relatively small number of customers for a significant portion of our gross margin; |
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• | general economic, market and business conditions, including industry changes and the impact of consolidations and changes in competition; |
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• | our ability to renew our gathering, processing, transportation and terminal contracts; |
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• | our ability to successfully balance our purchases and sales of natural gas; |
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• | the adequacy of insurance to cover our losses; |
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• | our ability to grow through contributions from affiliates, acquisitions or internal growth projects; |
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• | our management's history and experience with certain aspects of our business and our ability to hire as well as retain qualified personnel to execute our business strategy; |
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• | the cost and effectiveness of our remediation efforts with respect to the material weakness discussed in "Part II. Item 9A. Controls and Procedures"; |
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• | volatility in the price of our common units; |
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• | security threats such as military campaigns, terrorist attacks, and cybersecurity breaches, against, or otherwise impacting, our facilities and systems; and |
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• | the amount of collateral required to be posted from time to time in our transactions. |
Although we believe that the assumptions underlying our forward-looking statements are reasonable, any of the assumptions could be inaccurate, and, therefore, we cannot assure you that the forward-looking statements included in this Annual Report will prove to be accurate. Some of these and other risks and uncertainties that could cause actual results to differ materially from such forward-looking statements are more fully described in "Item 1A. Risk Factors" in this Annual Report. Statements in this Annual Report speak as of the date of this report. Except as may be required by applicable securities laws, we undertake no obligation to publicly update or advise investors of any change in any forward-looking statement, whether as a result of new information, future events or otherwise.
GLOSSARY OF TERMS
As generally used in the energy industry and in this Annual Report, the identified terms have the following meanings:
Bbl Barrels: 42 U.S. gallons measured at 60 degrees Fahrenheit.
Bbl/d Barrels per day.
Bcf Billion cubic feet.
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Btu | British thermal unit; the approximate amount of heat required to raise the temperature of one pound of water by one degree Fahrenheit. |
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Condensate | Liquid hydrocarbons present in casinghead gas that condense within the gathering system and are removed prior to delivery to the natural gas plant. This product is generally sold on terms more closely tied to crude oil pricing. |
/d Per day.
FERC Federal Energy Regulatory Commission.
Fractionation Process by which natural gas liquids are separated into individual components.
GAAP Generally Accepted Accounting Principles in the United States of America
Gal Gallons.
Mgal/d Million gallons per day.
MBbl Thousand barrels.
MMBbl Million barrels.
MMBbl/d Million barrels per day.
MMBtu Million British thermal units.
Mcf Thousand cubic feet.
MMcf Million cubic feet.
MMcf/d Million cubic feet per day.
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NGL or NGLs | Natural gas liquid(s): The combination of ethane, propane, normal butane, isobutane and natural gasoline that, when removed from natural gas, become liquid under various levels of higher pressure and lower temperature. |
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Throughput | The volume of natural gas transported or passing through a pipeline, plant, terminal or other facility during a particular period. |
As used in this Annual Report, unless the context otherwise requires, "we," "us," "our," the "Partnership" and similar terms refer to American Midstream Partners LP, together with its consolidated subsidiaries. References in this Annual Report to our "General Partner" refer to American Midstream GP, LLC.
PART I
Item 1. Business
Overview
American Midstream Partners, LP (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:
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• | sales of natural gas, crude oil, NGLs and condensate. |
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.
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| | Approximate Gathering System (Miles) | | Approximate Design Capacity (MMcf/d) (MBbl/d) | | Compression (Horsepower) | | Number of Plants and Fractionators | | Approximate Average Throughput (MMcf/d) (MBbl/d) |
| | Years Ended December 31, |
| | 2016 | | 2015 |
Gathering and Processing | | | | | | | | | | |
Lavaca | | 203 | | 218 | | 28,175 | | — | | 114.0 | | 119.1 |
Magnolia | | 118 | | 122 | | 4,690 | | — | | 25.4 | | 27.1 |
Longview | | 620 | | 50 | | 19,980 | | 3 | | 15.1 | | 17.2 |
Chapel Hill | | 90 | | 20 | | 2,540 | | 2 | | 14.0 | | 14.6 |
Yellow Rose | | 47 | | 40 | | 3,256 | | 1 | | 4.3 | | 4.2 |
Bakken (1) | | 43 | | 40 | | — | | — | | 7.2 | | 2.2 |
Chatom (2) | | 24 | | 25 | | 3,456 | | 2 | | 6.3 | | 5.9 |
Bazor Ridge | | 169 | | 22 | | 6,287 | | 1 | | 5.6 | | 7.6 |
Glade Crossing | | — | | 10 | | — | | 1 | | — | | — |
American Panther | | 200 | | 502 | | — | | — | | 86.6 | | — |
Other (3) | | 268 | | 346 | | 11,062 | | 2 | | 122.4 | | 142.5 |
Total | | 1,782 | | 1,395 | | 79,446 | | 12 | | 400.9 | | 340.4 |
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(1) | Average throughput for the year ended December 31, 2015 only reflects the months of October 2015 through December 2015. |
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(2) | We have included approximate average throughput at 100% for the Chatom System. For both periods ending December 31, 2016 and 2015, we owned 92.2% interest in the Chatom System. |
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(3) | Other primarily includes our Gloria, Lafitte, Quivira, Burns Point, and Offshore Texas systems. |
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.
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| Approximate Transmission System (Miles) | | Jurisdiction | | Compression (Horsepower) | | Approximate Design Capacity (MMcf/d) | | Approximate Average Throughput (MMcf/d) |
| | Years Ended December 31, |
| | 2016 | | 2015 |
Transmission | | | | | | | | | | | |
High Point | 574 | | Intrastate | | — | | 1,120 | | 318.7 | | 371.6 |
Midla/MLGT (1) | 424 | | Interstate/Intrastate | | 2,905 | | — | | 145.3 | | 139.7 |
AlaTenn/Bamagas/TriGas | 346 | | Interstate/Intrastate | | 3,665 | | 710 | | 204.7 | | 182.7 |
Chalmette | 39 | | Intrastate | | — | | 125 | | 14.6 | | 14.6 |
Total | 1,383 | |
| | 6,570 | | 1,955 | | 683.3 | | 708.6 |
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(1) | We filed for abandonment in December 2016. |
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.
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| | | As of December 31, 2016 | | As of December 31, |
Terminals | | | Number of Tanks | | Approximate Contracted Capacity (Bbls) | | Approximate Design Capacity (Bbls) | | 2016 | | 2015 |
Westwego | | | 48 | | 957,800 | | 1,044,600 | | 91.7% | | 93.9% |
Brunswick | | | 5 | | 221,000 | | 221,000 | | 100.0% | | 100.0% |
Harvey | | | 34 | | 1,115,000 | | 1,135,200 | | 98.2% | | 72.9% |
Total | | | 87 | | 2,293,800 | | 2,400,800 | | 95.5% | | 88.4% |
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:
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• | EPA Chemical Accident Prevention Provisions, also known as the Risk Management Plan requirements, which are designed to prevent the accidental release of toxic, reactive, flammable or explosive materials; and |
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• | Department of Homeland Security Chemical Facility Anti-Terrorism Standards, which are designed to regulate the security of high-risk chemical facilities. |
Regulation of Operations
Regulation of pipeline gathering and transportation services, natural gas sales and transportation of NGLs may affect certain aspects of our business and the market for our products and services.
Regulation of our terminals require us to maintain and currently hold approvals and permits from federal, state and local regulatory agencies for air quality and water discharge, as well as standard local occupational licenses.
Interstate Natural Gas Pipeline Regulation
Our interstate natural gas transportation systems are subject to the jurisdiction of FERC pursuant to the NGA. Under the NGA, FERC has authority to regulate natural gas companies that provide natural gas pipeline transportation services in interstate commerce. Federal regulation of our interstate pipelines extends to such matters as:
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• | rates, services, and terms and conditions of service; |
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• | the types of services offered to customers; |
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• | the certification and construction of new facilities; |
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• | the acquisition, extension, disposition or abandonment of facilities; |
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• | the maintenance of accounts and records; |
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• | relationships between affiliated companies involved in certain aspects of the natural gas business; |
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• | the initiation and discontinuation of services; |
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• | market manipulation in connection with interstate sales, purchases or transportation of natural gas and NGLs; and |
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• | participation by interstate pipelines in cash management arrangements. |
Under the NGA, the rates for service on these interstate facilities must be just and reasonable and not unduly discriminatory.
The rates and terms and conditions for our interstate pipeline services are set forth in FERC-approved tariffs. Pursuant to FERC's jurisdiction over rates, existing rates may be challenged by complaint and proposed rate increases may be challenged by protest. Any successful complaint or protest against our rates could have an adverse impact on our revenue associated with providing transportation service.
In 2008, FERC issued Order No. 717, a final rule that implements standards of conduct that include three primary rules: (1) the "independent functioning rule," which requires transmission function and marketing function employees to operate independently of each other; (2) the "no-conduit rule," which prohibits passing transmission function information to marketing function employees; and (3) the "transparency rule," which imposes posting requirements to help detect any instances of undue preference. The FERC has since issued four rehearing orders that generally reaffirmed the determinations in Order No. 717 and also clarified certain provisions of the Standards of Conduct.
In April 2008, the FERC issued a Policy Statement regarding the composition of proxy groups for determining the appropriate return on equity for natural gas and crude oil pipelines using FERC's Discounted Cash Flow ("DCF") model for setting cost-of-service or recourse rates. In the policy statement, FERC concluded, among other matters that Master Limited Partnerships ("MLPs") should be included in the proxy group used to determine return on equity for both natural gas and crude oil pipelines, but the long-term growth component of the DCF model should be limited to fifty percent of long-term gross domestic product. The adjustment to the long-term growth component, and all other things being equal, results in lower returns on equity than would be calculated without the adjustment. However, the actual return on equity for our interstate pipelines will depend on the specific companies included in the proxy group and the specific conditions at the time of the future rate case proceeding.
In July 2016, the D.C. Circuit issued its opinion in United Airlines, Inc., et al.v. FERC, finding that FERC had acted arbitrarily and capriciously when it failed to demonstrate that permitting an interstate petroleum products pipeline organized as a limited partnership to include an income tax allowance in the cost of service underlying its rates in addition to the discounted cash flow return on equity would not result in the pipeline partnership owners double-recovering their income taxes. The court vacated FERC’s order and remanded to FERC to consider mechanisms for demonstrating that there is no double recovery as a result of the income tax allowance. On December 15, 2016, FERC issued a Notice of Inquiry seeking comment on how to address any double recovery resulting from income tax allowance policy. 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:
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• | requiring the installation of pollution-control equipment or otherwise restricting the way we operate; |
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• | limiting or prohibiting construction activities in sensitive areas, such as wetlands, coastal regions or areas inhabited by endangered or threatened species; |
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• | delaying system modification or upgrades during permit reviews; |
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• | requiring investigatory and remedial actions to mitigate pollution conditions caused by our operations or attributable to former operations; and |
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• | enjoining the operations of facilities deemed to be in non-compliance with permits issued pursuant to such environmental laws and regulations. |
Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties. Certain environmental statutes impose strict joint and several liability for costs required to clean up and restore sites where substances, hydrocarbons or wastes have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment.
The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation and actual future expenditures may be different from the amounts we currently anticipate. We try to anticipate future regulatory requirements that might be imposed and plan accordingly to remain in compliance with changing environmental laws and regulations and to minimize the costs of such compliance. We also actively participate in industry groups that help formulate recommendations for addressing existing or future regulations.
We do not believe that compliance with federal, state or local environmental laws and regulations will have a material adverse effect on our business, financial position or results of operations or cash flows. In addition, we believe that the various environmental activities in which we are presently engaged are not expected to materially interrupt or diminish our operational ability to gather, compress, treat and transport natural gas. We cannot assure, however, that future events, such as changes in existing laws or enforcement policies, the promulgation of new laws or regulations or the development or discovery of new facts or conditions will not cause us to incur significant costs. Below is a discussion of the material environmental laws and regulations that relate to our business. We believe that we are in substantial compliance with all of these environmental laws and regulations.
Hazardous Substances and Waste
Our operations are subject to environmental laws and regulations relating to the management and release of hazardous substances, solid and hazardous wastes and petroleum hydrocarbons. These laws generally regulate the generation, storage, treatment, transportation and disposal of solid and hazardous waste and may impose strict joint and several liability for the investigation and remediation of affected areas where hazardous substances may have been released or disposed. For instance, the Comprehensive Environmental Response, Compensation, and Liability Act ("CERCLA"), and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a hazardous substance into the environment. We may handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.
We also generate industrial wastes that are subject to the requirements of the Resource Conservation and Recovery Act ("RCRA"), and comparable state statutes. While RCRA regulates both solid and hazardous wastes, it imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. We generate little hazardous waste; however, it is possible that these wastes, which could include wastes currently generated during our operations, will in the future be designated as "hazardous wastes" and, therefore, be subject to more rigorous and costly disposal requirements. In December 2016, the EPA and environmental groups entered into a consent decree to address EPA’s alleged failure to timely assess its RCRA Subtitle D criteria regulations exempting certain exploration and production related oil and gas wastes from regulation as hazardous wastes under RCRA. The consent decree requires EPA to propose a rulemaking by March 2019 for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or to sign a determination that revision of the regulations is not necessary. Any such changes in the laws and regulations could have a material adverse effect on our maintenance capital expenditures and operating expenses.
We currently own or lease properties where hydrocarbons are being or have been handled for many years. Although previous operators have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us or on or under the other locations where these hydrocarbons and wastes have been transported for treatment or disposal. These properties and the wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated soil and groundwater) or to perform remedial operations to prevent future contamination. We are not currently aware of any facts, events or conditions relating to such requirements that could materially impact our operations or financial condition.
Air Quality and Climate Change
Our operations are subject to the federal Clean Air Act and comparable state and local laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including our compressor stations and processing plants, and also impose various monitoring and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations and utilize specific emission control technologies to limit emissions. Failure to comply with applicable air statutes or regulations may lead to the assessment of administrative, civil or criminal penalties and may result in the limitation or cessation of construction or operation of certain air emission sources. Although we can give no assurances, we believe such requirements will not have a material adverse
effect on our financial condition or operating results, and the requirements are not expected to be more burdensome to us than to any similarly situated company. As the EPA issues new, lower National Ambient Air Quality Standards ("NAAQS"), we may be required to incur certain capital expenditures for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. For example, in June 2010, the EPA issued a new NAAQS for sulfur dioxide, or SO2, and replaced the 24-hour and annual standards with a more stringent hourly standard. In October 2015, the agency finalized a reduction of the national ambient air quality standard for ozone standard from 75 parts per billion to 70 parts per billion; both nitrogen oxides and VOCs are ozone precursors. This reduction is expected to increase the number of ozone nonattainment areas. In October 2016, the EPA also finalized Control Technology Guidelines for emissions of VOCs from crude oil and natural gas industry sources to be relied upon by states when implementing the ozone standard in ozone nonattainment areas. We believe that our operations will not be materially adversely affected by such requirements, and the requirements are not expected to be any more burdensome to us than to any other similarly situated companies.
On April 17, 2012, the EPA approved final rules under the Clean Air Act that establish new air emission controls for crude oil and natural gas production, pipelines and processing operations. These rules became effective on October 15, 2012. The established specific new requirements regarding emissions from wet seal and reciprocating compressors at production facilities, gathering systems, boosting facilities and onshore natural gas processing plants, effective October 15, 2012, and from pneumatic controllers and storage vessels at production facilities, gathering systems, boosting facilities and onshore natural gas processing plants, effective October 15, 2013. In addition, the rules revise existing requirements for volatile organic compound 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.
Item 1A. Risk Factors
Limited partner units are inherently different from capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in similar businesses. We urge you to carefully consider the following risk factors together with all of the other information included in this Annual Report in evaluating an investment in our common units.
If any of the following risks were to occur, our business, financial condition, results of operations or cash flows could be materially adversely affected. In that case, we might not be able to pay the minimum quarterly distribution on our common units, the trading price of our common units could decline and you could lose all or part of your investment in us.
The risks described below are not the only ones that we face. Additional risks not presently known to us or that we currently deem immaterial individually or in the aggregate may also impair our business operations. This Annual Report also contains forward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those anticipated in these forward-looking statements as a result of various factors, including the risks and uncertainties faced by us described below.
Risks Related to the Business of the Combined Company
We recently identified a material weakness in our internal controls. If we fail to remediate this material weakness or otherwise fail to develop, implement and maintain appropriate internal controls in future periods, our ability to report our financial condition and results of operations accurately and on a timely basis could be adversely affected.
We have identified a material weakness in our internal controls over the level of accounting knowledge, expertise and training to ensure that complex, non-routine transactions were recorded appropriately. This control deficiency resulted in out-of-period adjustments recorded to our consolidated statement of operations in the fourth quarter of 2016 and a revision to our 2015 consolidated balance sheet and consolidated statement of cash flows. Accordingly, our management determined that, as of December 31, 2016, our disclosure controls and procedures and our internal control over financial reporting were not effective. The specific material weakness and our remediation efforts are described in Item 9A, Controls and Procedures. A “material weakness” is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements would not be prevented or detected on a timely basis. We cannot assure you that we will adequately remediate the material weakness or that additional material weaknesses in our internal controls will not be identified in the future. Any failure to maintain or implement required new or improved controls, or any difficulties we encounter in their implementation, could result in additional material weaknesses, or could result in material misstatements in our financial statements. These misstatements could result in restatements of our financial statements, cause us to fail to meet our reporting obligations or cause investors to lose confidence in our reported financial information.
We are in the process of remediating the identified material weakness in our internal controls, but we are unable at this time to estimate when the remediation effort will be completed. During the course of implementing additional processes and controls, as well as controls operating effectiveness testing, we may identify additional control deficiencies, which could give rise to other material weaknesses, in addition to the material weakness described above. As we continue to evaluate and work to improve our internal control over financial reporting, we may determine to take additional measures to address material weakness or determine to modify certain of the remediation measures. It may be difficult or costly to remediate the material weakness, including through hiring new personnel with sufficient and tailored skill sets. If we fail to remediate this material weakness, there will continue to be an increased risk that our future financial statements could contain errors that will be undetected. Further and continued determinations that there are material weaknesses in the effectiveness of our internal controls could reduce our ability to obtain financing or could increase the cost of any financing we obtain and require additional expenditures of resources to comply with applicable requirements. The existence of a material weakness could result in errors in our financial statements that could result in a restatement of financial statements, which could cause us to fail to meet our reporting obligations, lead to a loss of investor confidence and have a negative impact on the trading price of our common stock.
Our current and future indebtedness levels may limit our flexibility in obtaining additional financing and in pursuing other business opportunities.
Our level of indebtedness could have important consequences to us, including the following:
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• | our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms; |
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• | covenants contained in our existing and future credit and debt arrangements will require us to meet financial tests that may affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities; |
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• | our funds available for operations, future business opportunities and distributions to unitholders will be reduced by that portion of our cash flow required to make principal and interest payments on our indebtedness; |
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• | our indebtedness level may make us more vulnerable than our competitors with less debt to competitive pressures or a downturn in our business or the economy generally; and |
•our flexibility in responding to changing business and economic conditions may be limited.
Any of these factors could result in a material adverse effect on our business, financial condition, results of operations, business prospects and ability to make cash distributions to our unitholders.
Our ability to service our indebtedness will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing distributions to our unitholders, reducing or delaying our business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing our indebtedness, or seeking additional equity capital or bankruptcy protection. We may not be able to effect any of these remedies on satisfactory terms, or at all.
The indenture governing the notes and our credit facility contain certain financial covenants and ratios and other restrictions. We may have difficulty maintaining compliance with such financial covenants and ratios and other restrictions, which could adversely affect our business, financial condition, results of operations and ability to pay distributions to our unitholders.
We are dependent upon certain earnings and cash flow generated by our operations in order to meet our debt service obligations. We also depend on our credit facility for working capital and future expansion capital needs and, as necessary, to fund a portion of cash distributions to unitholders. The indenture governing the notes and our revolving credit facility contain, and any future financing agreements may contain, operating and financial restrictions and covenants that could restrict our ability to finance future operations or capital needs, or to expand or pursue our business activities, which may, in turn, limit our ability to pay distributions to our unitholders. For example, our revolving credit facility limits our ability to, among other things:
•incur or guarantee additional indebtedness or issue preferred units;
•redeem or repurchase units or make distributions under certain circumstances;
•make certain investments and acquisitions;
•redeem or repay other debt or make other restricted payments;
•make capital expenditures above specified amounts;
•incur certain liens or permit them to exist;
•enter into certain types of transactions with affiliates;
•enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us;
•create non-guarantor subsidiaries;
•enter into sale and leaseback transactions;
•merge or consolidate with another company;
•transfer, sell or otherwise dispose of assets, including equity interests in our subsidiaries;
•cancel or modify material contracts;
•sell our income or receivables;
•enter into “take-or-pay” contracts; and
•amend our organizational documents.
Our Second Amended and Restated Credit Agreement contains certain financial covenants, including (i) a consolidated total leverage ratio that requires our indebtedness not to exceed 5.00 times adjusted consolidated EBITDA (as defined in the revolving credit facility) for the prior twelve month period, adjusted in accordance with the Second Amended and Restated Credit Agreement (except for the current and subsequent two quarters after the consummation of a permitted acquisition, at which time the covenant may be increased to 5.50 times adjusted consolidated EBITDA), (ii) a minimum interest coverage ratio that requires our adjusted consolidated EBITDA to exceed consolidated interest charges by at least 2.50 times for the prior twelve month period, and (iii) a consolidated secured leverage ratio that requires our consolidated secured indebtedness not to exceed 3.50 times adjusted consolidated EBITDA for the prior twelve month period. The financial covenants in our Second Amended and Restated Credit Agreement may limit the amount available to us for borrowing to less than $900.0 million. As of December 31, 2016, under our Credit Agreement at that time, our consolidated total leverage ratio was 4.07 and our interest coverage ratio was 7.43, which were
in compliance with the financial covenants. Under the Second Amended and Restated Credit Agreement, the maximum permitted consolidated total leverage ratio for the fiscal year is 5.00 and can increase to 5.50 with the election of a Specified Acquisition Period. As of December 31, 2016, we had approximately $711.3 million of outstanding borrowings under our Credit Agreement existing at that time. Our ability to comply with these covenants and ratios in the future is uncertain and will be affected by the levels of cash flow from our operations and events or circumstances beyond our control, including events and circumstances that may stem from the condition of the financial markets and commodity price levels. Our failure to comply with any of the covenants or ratios under our revolving credit facility could result in a default, which could cause all of our existing indebtedness to become immediately due and payable. If the payment of our indebtedness is accelerated and we are unable to repay the indebtedness in full, our lenders could foreclose on the assets pledged by us and the guarantors under the revolving credit facility. In that case, our assets may be insufficient to repay such indebtedness in full.
Because of the natural decline in production from existing wells in our areas of operation, our success depends on our ability to obtain new sources of natural gas, NGLs and crude oil, which is dependent on factors beyond our control. Any decrease in the volumes of natural gas that we gather, process or transport could adversely affect our business and operating results.
The commodity volumes that support our business are dependent on the level of production from natural gas and crude oil wells connected to our systems, including volumes from significant customers, the production of which will naturally decline over time. As a result, our cash flows associated with these wells will also decline over time. In order to maintain or increase throughput levels on our systems, we must obtain new sources of natural gas and crude oil. The primary factors affecting our ability to obtain non-dedicated sources of natural gas and crude oil include (i) the level of successful drilling activity in our areas of operation and (ii) our ability to compete for volumes from successful new wells.
We have no control over the level of drilling activity in our areas of operation, the amount of reserves associated with wells connected to our systems or the rate at which production from a well declines. In addition, we have no control over producers or their drilling or production decisions, which are affected by, among other things:
•prevailing and projected natural gas, crude oil and NGL prices;
•the availability and cost of capital;
•demand for natural gas, crude oil and NGLs;
•levels of reserves;
•geological considerations;
•environmental or other governmental regulations, including the availability of drilling permits; and
•the availability of drilling rigs and other production and development costs.
Fluctuations in energy prices, like the decline in commodity prices of crude oil, natural gas and NGLs from recent highs reached in mid-2014, can also greatly affect the development of new reserves. Further declines in crude oil, natural gas and NGLs prices could have a negative impact on exploration, development and production activity, and, if sustained, are likely to lead to further decreases in such activity. Sustained reductions in exploration or production activity in our areas of operation would lead to reduced utilization of our assets. We are unable to predict future potential movements in the market price for natural gas, crude oil and NGLs and thus, cannot predict the ultimate impact of prices on our operations. If commodity prices continue to remain low or fluctuate, this could lead to reduced profitability and may impact our liquidity and compliance with financial covenants in our revolving credit facility. Reduced profitability may also result in future non-cash impairments of long-lived assets, goodwill, or intangible assets.
Because of these and other factors, even if new natural gas, NGL and crude oil reserves are known to exist in areas served by our assets, producers may choose not to develop those reserves. If reductions in drilling activity result in our inability to maintain the current levels of throughput on our systems, it could reduce our revenue and cash flow and adversely affect our ability to make cash distributions to our unitholders.
Natural gas, crude oil, NGL and other commodity prices are volatile, and a reduction in these prices in absolute terms, or an adverse change in the prices of natural gas and NGLs relative to one another, could adversely affect our net income, gross margin and cash flow and our ability to make distributions to our unitholders.
We are subject to risks due to frequent and often substantial fluctuations in commodity prices. In the past, the prices of natural gas and crude oil have been extremely volatile, and we expect this volatility to continue. Natural gas prices have been under downward pressure in recent years and were highly volatile in 2014. The NYMEX daily settlement price for natural gas for the forward month contract in 2016 ranged from a high of $3.80 per MMBtu to a low of $1.49 per MMBtu. NGL prices are generally positively correlated to the price of WTI crude oil, which has also exhibited frequent and substantial fluctuations. Oil
prices declined dramatically in late 2014 and remained low in 2015 and early 2016. The NYMEX daily settlement price for WTI crude oil for the forward month contract in 2016 ranged from a high of $54.45 per Bbl to a low of $26.21 per Bbl.
The markets for and prices of natural gas, crude oil, NGLs and other hydrocarbon commodities depend on factors that are beyond our control. These factors include the supply of and demand for these commodities, which fluctuate with changes in market and economic conditions and other factors, including:
•worldwide economic conditions;
•worldwide political events, including actions taken by foreign oil and gas producing nations;
•worldwide weather events and conditions, including natural disasters and seasonal changes;
•the levels of world-wide and domestic production and consumer demand;
•the availability of imported, or market for exported, liquefied natural gas, or LNG;
•the market for exported crude oil;
•the availability of transportation systems with adequate capacity;
•the volatility and uncertainty of regional pricing differentials;
•the price and availability of alternative fuels;
•the effect of energy conservation measures;
•the nature and extent of governmental regulation and taxation; and
•the current and anticipated future prices of natural gas, crude oil, NGLs and other commodities.
In our Gathering and Processing segment, we have exposure to direct commodity price risk under percent-of-proceeds processing contracts as well as under our elective processing arrangements. Under percent-of-proceeds arrangements, we generally purchase natural gas from producers and retain an agreed percentage of the proceeds (in cash or in-kind) from the sale at market prices of pipeline-quality natural gas and NGLs resulting from our processing activities. We also purchase natural gas at various receipt points, process the gas at a third-party owned natural gas processing facility and sell our portion of the residue gas and NGLs. Under percent-of-proceeds arrangements, our revenue and our cash flows increase or decrease as the prices of natural gas, NGLs and crude oil fluctuate. When we process natural gas that we purchase for our own account, the relationship between natural gas prices and NGL prices also affects our profitability. When natural gas prices are low relative to NGL prices, it is more profitable for us to process the natural gas that we purchase and process for our own account. When natural gas prices are high relative to NGL prices, it is less profitable for us and our customers to process natural gas both because of the higher value of natural gas and because of the increased cost (principally that of natural gas shrink that occurs during processing and use of natural gas as a fuel) of separating the mixed NGLs from the natural gas. As a result, we may experience periods in which higher natural gas prices relative to NGL prices reduce our processing margins or reduce the volume of natural gas processed pursuant to our elective processing arrangements. For the years ended December 31, 2016 and 2015, percent-of-proceeds arrangements accounted for approximately 11.1% and 14.3%, respectively, of our gross margin, or 19.4% and 22.7%, respectively, of the segment gross margin in our Gathering and Processing segment.
If the current commodity price environment continues, it could result in a further decrease in exploration and development activities in the fields served by our gathering and pipeline transmission systems and our natural gas processing plants, which could lead to further reduced utilization of these assets. During periods of natural gas, crude oil, or NGL declines, the level of drilling activity generally decrease. When combined with a reduction of cash flow resulting from lower commodity prices, a reduction in our producers’ borrowing base under reserve-based credit facilities and lack of availability of debt or equity financing for our producers may result in a significant reduction in our producers’ spending for drilling activity, which could result in lower volumes being transported on our gathering and transmission systems.
In addition, in our refined products terminals and storage segment we generate revenue from (i) blending activities, such as ethanol blending and butane blending, and (ii) our vapor recovery units. Our blending activities are subject to direct commodity price exposure. Any significant reduction in the amount of services we provide to our customers because of direct or indirect commodity price exposure and any significant reduction in the refined products that we sell could have a material adverse effect on our business, results of operations, financial condition and our ability to make distributions to our unitholders.
Further, results of operations related to the retail distribution of propane is primarily based on the cents-per-gallon difference between the sales price we charge our customers and our costs to purchase and deliver propane to our propane distribution locations. We enter into propane sales commitments with a portion of our customers that provide for a contracted price agreement for a specified period of time. The propane cost per gallon is subject to various market conditions and may fluctuate based on changes in demand, supply and other energy commodity prices, such as crude oil and natural gas prices. We employ risk management techniques that attempt to mitigate risks related to the purchasing, storing, transporting and selling of propane. However, sudden and sharp propane cost increases cannot be passed on to customers with contracted pricing arrangements. In addition, even upon the expiration of short-term contracts, we may face competitive or relationship pressure to minimize any price increases. Therefore,
these commitments expose us to product price risk and reduced profit margins if those transactions are not immediately hedged with an offsetting propane purchase commitment.
Historically, we have relied on cash flows from our operations, borrowing under our revolving credit facility and the capital markets to fund our operations and capital expenditures and acquisitions. If commodity prices remain volatile, our cash flows could be adversely affected which, combined with limited availability under our revolving credit facility, could adversely affect our ability to finance our operations and capital expenditures and acquisitions.
Our growth strategy, and ability to fund expansion capital projects, requires access to new capital. Tightened capital markets or other factors that increase our cost of capital, or limit our access to capital, could impair our ability to grow.
We continuously consider potential acquisitions and opportunities for expansion capital projects. Acquisition opportunities arise quickly and unexpectedly, may occur at any time and may be significant in size relative to our existing assets and operations. Our ability to fund our capital projects and make acquisitions depends on whether we can access the necessary financing to fund these activities. Any limitations on our access to capital or increase in the cost of that capital could significantly impair our growth strategy. Our ability to maintain our targeted credit profile, including our target debt-to-equity ratio, could affect our cost of capital as well as our ability to execute our growth strategy. In addition, a variety of factors beyond our control could impact the availability or cost of capital, including domestic or international economic conditions, increases in key benchmark interest rates and/or credit spreads, the adoption of new or amended banking or capital market laws or regulations, the re-pricing of market risks and volatility in capital and financial markets.
Due to these factors, we cannot be certain that funding for our capital needs will be available from bank credit arrangements, our revolving credit facility or capital markets on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, we may be unable to implement our development plans, enhance our existing business, complete acquisitions and construction projects, take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our revenues and results of operations.
Our business is subject to a number of weather related risks, including severe weather in the U.S. Gulf of Mexico, which can cause significant damage and disruption to our business interests located in that region, and abnormal weather conditions, which can reduce the demand for propane.
The U.S. Gulf of Mexico experiences hurricanes and other extreme weather conditions on a frequent basis, the frequency of which may increase with climate change. Our High Point system, our Offshore Texas system, our Destin system, our Okeanos system, our non-operated interests in MPOG and Delta House and any future systems that we acquire in the U.S. Gulf of Mexico, are susceptible to adverse weather conditions in the U.S. Gulf of Mexico, including hurricanes and other extreme weather conditions. Our insurance may not cover all associated loss. High winds, storm surge, and turbulent seas can cause significant damage and curtail these operations for extended periods during and after such weather conditions, which may result in decreased revenues from our interests in these operations. In addition, these adverse weather conditions in the U.S. Gulf of Mexico can affect producers connected to our facilities even if our facilities are not damaged, which may result in decreased revenues from our interests in these operations.
In addition, weather conditions have a significant impact on the demand for propane. Actual weather conditions can vary substantially from year to year, significantly affecting our financial performance. Many of our customers rely on propane primarily as a heating source during the winter. Warmer than normal winter temperatures can substantially reduce our retail commercial and wholesale propane volumes. Conversely, our cylinder exchange business experiences higher volumes in the spring and summer. Sustained periods of poor weather, particularly in the grilling season, can reduce consumers’ propensity to purchase and use grills and other propane-fueled appliances, thereby reducing demand for cylinder exchange and our outdoor products.
To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease depending on the duration and magnitude of the changes, leading either to increased investment or decreased revenues.
We are subject to the risk of loss resulting from nonpayment and/or nonperformance by our customers and counterparties in the ordinary course of our business.
We are subject to the risk of loss resulting from nonpayment and/or nonperformance by our customers and counterparties in the ordinary course of our business. Generally, we either consider our customers creditworthy or require those who are not creditworthy to make prepayments or provide security to satisfy credit concerns. However, our credit procedures and policies will not completely eliminate customer and counterparty credit risk. Our customers and counterparties include entities whose
creditworthiness may be suddenly and disparately impacted by, among other factors, commodity price volatility, deteriorating energy market conditions, and public and regulatory opposition to energy producing activities.
In addition, in connection with the acquisition of certain of our assets, we have entered into agreements pursuant to which various counterparties have agreed to indemnify us, subject to certain limitations, for certain matters arising from the pre-closing ownership and operation of assets.
The current low commodity price environment has negatively impacted many oil and gas companies causing them significant economic stress including, in some cases, to file for bankruptcy protection or to renegotiate contracts. To the extent one or more of our key customers or counterparties commences bankruptcy proceedings, our contracts with such customers or counterparties may be subject to rejection under applicable provisions of the United States Bankruptcy Code or may be renegotiated. Further, during any such bankruptcy proceeding, prior to assumption, rejection or renegotiation of such contracts, the bankruptcy court may temporarily authorize the payment of value for our services less than contractually required, which could have a material adverse effect on our business, results of operations, cash flows and financial conditions. If we fail to adequately assess the creditworthiness of existing or future customers and counterparties or otherwise do not take or are unable to take sufficient mitigating actions, including obtaining sufficient collateral, deterioration in their creditworthiness and any resulting increase in nonpayment and/or nonperformance by them could cause us to write down or write off accounts receivable. Such write-downs or write-offs could negatively affect our operating results in the periods in which they occur, and, if significant, could have a material adverse effect on our business, results of operations, cash flows and financial condition.
If third-party pipelines or other midstream facilities interconnected to our gathering or transportation systems become partially or fully unavailable, or if the volumes we gather or transport do not meet the natural gas quality requirements of such pipelines or facilities, our revenue and cash available for distribution could be adversely affected.
Our natural gas gathering and processing and transportation systems connect to other pipelines or facilities, the majority of which are owned and operated by third parties. For example, our elective processing arrangements are entirely dependent on the Toca plant for processing services and the Sonat pipeline for natural gas takeaway capacity. As another example, our North Little Rock terminal is currently supplied by the TEPPCO Pipeline and is expected, in the future, to also be supplied by Magellan’s Fort Smith Pipeline, while our Caddo Mills terminal is supplied by the Explorer Pipeline. The continuing operation of such third-party pipelines and other midstream facilities is not within our control. These pipelines and other midstream facilities and others upon which we rely may become unavailable because of testing, turnarounds, line repair, reduced operating pressure, lack of operating capacity, regulatory requirements, curtailments of receipt or deliveries due to insufficient capacity or because of damage from hurricanes or other operational hazards. For example, the explosion and fire at the Pascagoula Gas plant in June of 2016 suspended operations from that facility for over eight months. If any of these pipelines or other midstream facilities becomes unable to receive or transport natural gas, or if the volumes we gather or transport do not meet the natural gas quality requirements of such pipelines or facilities, our revenue and cash available for distribution may be adversely affected.
Our hedging activities may not be effective in reducing our direct exposure to commodity price risk and may, in certain circumstances, increase the variability of our cash flows.
From time to time, we have entered into derivative transactions related to only a portion of the equity volumes of commodities to which we take title. As a result, we will continue to have direct commodity price risk to the unhedged portion of our commodity equity volumes. Our actual future volumes may be significantly higher or lower than we estimated at the time we entered into the derivative transactions for that period. If the actual amount is higher than we estimated, we will have greater commodity price risk than we intended. If the actual amount is lower than the amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale of the underlying physical commodity, resulting in a reduction of our liquidity. The derivative instruments we utilize for these hedges are based on posted market prices, which may be lower than the actual commodity prices that we realize in our operations. In addition, when there is not a hedging instrument available for a commodity to which we take title, we are forced to use an alternative hedge that may not adequately reduce price risk. As a result of these factors, our hedging activities may not be as effective as we intend in reducing the variability of our cash flows, and, in certain circumstances, may actually increase the variability of our cash flows. To the extent we hedge our commodity price risk, we may forego the benefits we would otherwise experience if commodity prices were to change in our favor. Further, there may be times where we terminate or enter into offsetting positions depending on our view of future market prices.
The adoption and implementation of new statutory and regulatory requirements for swap transactions could have an adverse impact on our ability to hedge risks associated with our business.
We hedge a portion of our commodity risk and our interest rate risk. The federal government regulates the derivatives market and entities, including businesses like ours, that participate in that market. The legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Act, requires the Commodities Futures Trading Commission, or CFTC, and the SEC to promulgate rules and regulations implementing the new legislation. Under the CFTC’s regulations, we are subject to reporting and recordkeeping obligations for transactions involving non-financial swap transactions. The CFTC initially adopted regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents, but these rules were successfully challenged in Federal district court by the Securities Industry Financial Markets Association and the International Swaps and Derivatives Association and largely vacated by the court. On November 5, 2013, the CFTC proposed new rules that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. The ultimate form and timing of the implementation of the regulatory regime affecting commodity derivatives remains uncertain.
The CFTC has imposed mandatory clearing requirements on certain categories of swaps, including certain interest rate swaps, but has exempted derivatives intended to hedge or mitigate commercial risk from the mandatory swap clearing requirement, where the counterparty such as us has a required identification number, is not a financial entity as defined by the regulations, and meets a minimum asset test. We believe our hedging transactions will qualify for the “commercial end user” exception. The Act may also require us to comply with margin requirements in connection with our hedging activities, although the application of those provisions to us is uncertain at this time. The Act may also require the counterparties to our derivative instruments to spin off some of their hedging activities to a separate entity, which may not be as creditworthy as the current counterparty. The new legislation and related regulations could significantly increase the cost of derivatives contracts for our industry (including requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivatives contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivatives contracts, and increase our exposure to less creditworthy counterparties, particularly if we are unable to utilize the commercial end user exception with respect to certain of our hedging transactions. If we reduce our use of hedging as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures and fund unitholder distributions. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our business, our financial condition, and our results of operations.
Our failure or our counterparties’ failure to perform on obligations under commodity derivative and financial derivative contracts could have a material adverse effect on our financial condition, results of operations and cash flows.
We enter into hedging arrangements to manage the cost of propane in our cylinder exchange business. We also may from time to time enter into derivative instruments to hedge our exposure to variable interest rates. Volatility in the oil and gas commodities sector for an extended period of time or intense volatility in the near-term could impair our or our counterparties’ ability to meet margin calls, which could cause us or our counterparties to default on commodity and financial derivative contracts. This could have a material adverse effect on our liquidity or our ability to procure product supply at prices reasonable to us or at all.
We do not control certain of the entities that own our projects and we may acquire future projects that we do not control.
We own a 49.7% membership interest in Destin, 20.1% of the Class A Units of Delta House FPS LLC and Delta House Oil and Gas Lateral LLC, a 16.7% membership interest in Tri-States, a 66.7% membership interest in Okeanos, and a 25.3% membership interest in Wilprise. We do not control these projects or project entities’ governing boards. As a result, our ability to pay cash distributions to our unitholders will depend in part on the performance of these projects or entities and their distributions of cash to us.
Further, additional projects we may acquire may be subject to a similar structure where we do not own a majority of the project or project entity and we may invest in joint ventures in which we share control or in which we are a minority investor. In these instances, the majority investor or controlling investor may not have the level of experience, technical expertise, human resources management and other attributes necessary to operate these assets optimally.
A decrease in demand for natural gas, NGLs or condensate by the petrochemical, refining or heating industries, could adversely affect the profitability of our midstream business.
Various factors impact the demand for natural gas, NGLs and condensate, including general economic conditions, extended periods of ethane rejection, increased competition from petroleum-based products due to pricing differences, adverse weather conditions, availability of natural gas processing and transportation capacity and government regulations affecting prices and production levels of natural gas, NGLs and condensate. In addition, certain of our operating costs and expenses are fixed and do not vary with the volumes we transport or redeliver. These costs and expenses may not decrease ratably or at all should we experience a reduction in the volumes we sell, transport or redeliver. As a result, a decrease in demand for natural gas, NGLs or condensate by the petrochemical, refining or heating industries, could decrease volumes and adversely affect the margin and profitability of our midstream business.
We depend on a relatively small number of customers for a significant portion of our gross margin. The loss of any one of these customers could adversely affect our ability to make distributions.
A significant percentage of the gross margin in each of our segments is attributable to a relatively small number of customers. Additionally, a number of customers upon which our business depends are small companies that may have limited access to capital or that may, as a result of operational incidents or other events, be disproportionately affected as compared to larger, better capitalized companies. For information regarding our concentration of customers and associated credit risk by segment, please refer to “Part I, Item 1. Business” in this Annual Report. Although we have gathering, processing and transmission contracts with significant customers of varying duration and commercial terms, if one or more of these customers were to default on their contract or if we were unable to renew our contract with one or more of these customers on favorable terms, we may not be able to replace these customers in a timely fashion, on favorable terms or at all. In any of these situations, our gross margin and cash flows and our ability to make cash distributions to our unitholders may be adversely affected. We expect our exposure to concentrated risk of non-payment or non-performance to continue as long as we remain substantially dependent on a relatively small number of customers for a substantial portion of our gross margin.
Our industry is highly competitive and increased competitive pressure could adversely affect our business and operating results.
We compete with other midstream companies in our areas of operation. In addition, some of our competitors are large companies that have greater financial, managerial and other resources than we do. Our competitors may expand or construct gathering, compression, treating, processing, transportation or terminaling systems that would create additional competition for the services we provide to our customers. In addition, our customers may develop their own gathering, compression, treating, processing or transportation systems in lieu of using ours. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenue and cash flow could be adversely affected by the activities of our competitors and our customers. All of these competitive pressures could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.
Our gathering, processing, transportation and terminal contracts subject us to renewal risks.
We gather, purchase, process, transport and sell most of the commodities on our systems under contracts with terms of various durations, including contracts that have terms as short as one month or which are cancellable on as little as 30 days’ notice, and which may be difficult to extend or replace. We provide NGL sales and distribution services, refined products terminals, crude oil pipeline services and above-ground storage services that support various commercial customers. As these contracts expire, we may have to negotiate extensions or renewals with existing suppliers and customers or enter into new contracts with other suppliers and customers. We may be unable to obtain new contracts on favorable commercial terms, if at all. We also may be unable to maintain the economic structure of a particular contract with an existing customer or the overall mix of our contract portfolio. For example, depending on prevailing market conditions at the time of a contract renewal, gathering and processing customers with percent-of-proceeds contracts may choose to switch to fee-based gathering and transportation contracts, or a producer with whom we have a natural gas purchase contract may choose to enter into a transportation contract with us and retain title to its natural gas. To the extent we are unable to renew our existing contracts on terms that are favorable to us or successfully manage our overall contract mix over time, our revenue, gross margin and cash flows could decline and our ability to make distributions to our unitholders could be materially and adversely affected.
We may not successfully balance our purchases and sales of natural gas, which would increase our exposure to commodity price risks.
We purchase from producers and other suppliers a substantial amount of the natural gas that flows through our pipelines and processing facilities for sale to third parties, including natural gas marketers and other purchasers. We are exposed to fluctuations
in the price of natural gas through volumes sold pursuant to percent-of-proceeds arrangements as well as through volumes sold pursuant to our fixed-margin contracts.
In order to mitigate our direct commodity price exposure, we do not enter into natural gas hedge contracts, but rather attempt to balance our natural gas sales with our natural gas purchases on an aggregate basis across all of our systems. We may not be successful in balancing our purchases and sales, and as such may become exposed to fluctuations in the price of natural gas. For example, we are currently net purchasers of natural gas on certain of our systems and net sellers of natural gas on certain of our other systems. Our overall net position with respect to natural gas can change over time and our exposure to fluctuations in natural gas prices could materially increase, which in turn could result in increased volatility in our revenue, gross margin and cash flows.
Although we enter into back-to-back purchases and sales of natural gas in our fixed-margin contracts in which we purchase natural gas from producers or suppliers at receipt points on our systems and simultaneously sell an identical volume of natural gas at delivery points on our systems, we may still be exposed to commodity price risks. For example, the volumes or timing of our purchases and sales may not correspond. In addition, a producer or supplier could fail to deliver contracted volumes or deliver in excess of contracted volumes, or a purchaser could purchase less than contracted volumes. Any of these actions could cause our purchases and sales to become unbalanced. If our purchases and sales are unbalanced, we will face increased exposure to commodity price risks, which in turn could result in increased volatility in our revenue, gross margin and cash flows.
The risk management policy governing our crude oil supply activities cannot eliminate all risks associated with our crude oil pipelines and storage business, and we cannot ensure that employees of our general partner will fully comply with the policy at all times, both of which could impact our financial and operational results and, in turn, our ability to make cash distributions to our unitholders.
We have in place a risk management policy that seeks to establish limits for the exposure in our crude oil pipelines and storage business by requiring that we restrict net open positions through the concurrent purchase and sale of like quantities of crude oil to create transactions intended to lock in positive margins based on the timing, location or quality of the crude oil purchased and delivered. Our risk management policy, however, cannot eliminate all risks. Any event that disrupts our anticipated physical supply of crude oil could create a net open position that would expose us to risk of loss resulting from price changes.
Moreover, we are exposed to price movements on products that are not hedged, such as our crude oil line fill, which must be maintained to operate our crude oil pipeline system. We are also exposed to certain price risks related to basis differentials. Basis differentials can be created to the extent that we hold or sell crude oil of a grade or quality at a location or at a time that differs from the specific delivery terms with respect to grade, quality, time or location of the applicable offsetting agreement. If this occurs, we may not be able to use the physical markets to fully hedge our price risk. Our exposure to price risks could impact our operational and financial results and our ability to make cash distributions to our unitholders.
We are also subject to the risk that employees of our general partner involved in our crude oil operations may not comply at all times with our risk management policy. We cannot ensure that all violations of our risk management policy, particularly if deception or other intentional misconduct is involved, will be detected prior to our businesses being materially affected.
A prolonged decline in index prices at Cushing, relative to other index prices, could reduce the demand for the services we provide in our crude oil storage business.
In recent years, a shortfall in takeaway pipeline capacity has at times led to an oversupply of crude oil at Cushing. This was cited as a principal reason for the decline in the West Texas Intermediate Index (“WTI Index”) price used at Cushing relative to other crude oil price indexes, including the Brent Crude Index over the same period. While the WTI Index price has recovered compared to the Brent Crude Index, a renewed decline in the WTI Index price relative to other index prices may reduce demand for transportation of crude oil to, and storage at our facility in, Cushing, which could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.
The results of our crude oil storage business could be adversely affected during periods in which the overall forward market for crude oil is backwardated.
The results of our crude oil storage business are influenced by the overall forward market for crude oil. A contango market (meaning that the price of crude oil for future delivery is higher than the current price) has a favorable impact on the demand for crude oil storage as it allows a party to simultaneously purchase crude oil at current prices for storage and sell at higher prices for future delivery. Conversely, a backwardated market (meaning that the price of crude oil for future deliveries is lower than current prices) can negatively affect the demand for crude oil storage because there is little incentive to store crude oil when prices offered
for future delivery are expected to be lower. Accordingly, a backwardated market can negatively impact the demand for crude oil storage. If the forward market for crude oil is backwardated at times when we are renewing our crude oil storage contract or entering into new crude oil storage contracts, it could adversely affect the results in our crude oil storage business.
High prices for propane can lead to customer conservation and attrition, resulting in reduced demand for our products.
Propane prices are subject to fluctuations in response to changes in wholesale prices and other market conditions beyond our control. Therefore, our average retail sales prices can vary significantly within a heating season or from year to year as wholesale prices fluctuate with propane commodity market conditions. During periods of high propane costs our selling prices generally increase. High prices can lead to customer conservation and attrition, resulting in reduced demand for our products.
We are dependent on third-party propane providers, which subjects us to increased costs and interruptions in supply and transportation.
While we intend to supply a portion of our propane needs, we still rely on third-party propane providers to supply a majority of our propane needs. A shortage in our propane supply or the propane supply from our principal third-party providers may require us to procure additional propane from alternative providers. The cost of procuring supplies and transporting those supplies from such alternative providers might be materially higher than expected and our earnings could be affected. Accordingly, disruptions in supply in certain areas could also have an adverse impact on our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.
Energy efficiency, advances in technology and competition from other energy sources may affect demand for propane and increases in propane prices may cause our residential customers to increase their conservation efforts.
The national trend toward increased conservation and technological advances, including installation of improved insulation and the development of more efficient furnaces and other heating devices, has generally reduced the demand for propane. Propane also competes with other sources of energy such as electricity, natural gas and fuel oil, some of which can be less costly for equivalent energy value. In particular, the gradual expansion of the nation’s natural gas distribution systems has increased the availability of affordable natural gas in rural areas, which historically found propane to be the more cost- effective choice. We cannot predict the effect that future conservation measures, technological advances in heating, conservation, energy generation or other devices or the development of alternative energy sources might have on our operations. As the price of propane increases, some of our customers tend to increase their conservation efforts and thereby decrease their consumption of propane.
A significant increase in motor fuel costs or other commodity prices may adversely affect our profits.
Motor fuel is a significant operating expense for us in connection with the operation of both our crude oil pipelines and storage and NGL distribution and sales segments. Although contracts typically have a fuel surcharge, a significant increase in motor fuel prices will result in increased transportation costs to us. The price and supply of motor fuel is unpredictable and fluctuates based on events we cannot control, such as geopolitical developments, supply and demand for oil and gas, actions by oil and gas producers, war and unrest in oil-producing countries and regions, regional production patterns and weather concerns. Additionally, we may be affected by increases in the cost of materials used to produce portable propane cylinders. As a result, any increases in these prices may adversely affect our profitability and competitiveness.
Environmental, health and safety costs and liabilities, and changing environmental, health and safety regulation, could have a material adverse effect on our financial position, results of operations and cash flows.
Our operations are subject to various environmental, health and safety requirements and potential liabilities under extensive federal, state and local laws and regulations. Further, we cannot ensure that existing environmental, health and safety laws or regulations will not be revised or that new laws or regulations will not be adopted or become applicable to us. Governmental authorities have the power to enforce compliance with applicable laws, regulations and permits and to subject violators to civil and criminal penalties, including substantial fines, injunctions or both. Certain environmental laws, including CERCLA and analogous state laws and regulations, may impose strict, joint and several liability for costs required to clean-up and restore sites where hazardous substances or hydrocarbons have been disposed or otherwise released. Moreover, third parties, including neighboring landowners, may also have the right to pursue legal actions to enforce compliance or to recover for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. Failure to comply with these requirements may expose us to fines, penalties, remedial liabilities and/or interruptions or delays in our operations that could have a material adverse effect on our financial position, results of operations and cash flows.
In addition, future environmental, health and safety law developments, such as stricter laws, regulations, permits or enforcement policies, could significantly increase some costs of our operations. Areas of potential future environmental, health and safety law development include the following items:
Greenhouse Gases/Climate Change. From time to time, the U.S. Congress has considered legislation to reduce emissions of greenhouse gases but no such legislation has yet been adopted by Congress. In addition, some states, including states in which our facilities or operations are located, have individually or in regional cooperation, imposed restrictions on greenhouse gas emissions under various policies and approaches, including establishing a cap on emissions, requiring efficiency measures, or providing incentives for pollution reduction, use of renewable energy sources, or use of replacement fuels with lower carbon content.
The EPA initiated the regulation of greenhouse gases under its Clean Air Act authority in 2009, requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States beginning in 2011 for emissions occurring in 2010. On November 30, 2010, the EPA published a final rule expanding its existing GHG emissions reporting rule for petroleum and natural gas facilities, including natural gas transmission compression facilities that emit 25,000 metric tons or more of carbon dioxide equivalent per year. The rule, which went into effect on December 30, 2010, requires reporting of greenhouse gas emissions by regulated facilities to the EPA annually. In October 2015, the EPA amended and expanded greenhouse gas reporting requirements to all segments of the crude oil and natural gas industry, including gathering and compression facilities and blowdowns of natural gas transmission pipelines, starting with the 2016 reporting year, and in January 2016, the EPA proposed additional revisions to leak detection methodology to align the reporting rule with the new source performance standards. A number of our facilities, including our Bazor Ridge and Chatom systems, are subject to greenhouse gas reporting, and we have filed annual emission reports for these facilities since March 2012.
Federal agencies also have begun directly regulating emissions of methane (a greenhouse gas) from crude oil and natural gas operations. In June 2016, the EPA issued new source performance standards for methane from new and modified crude oil and natural gas industry sources. These regulations will expand upon the 2012 EPA new source performance standard rulemaking for equipment-specific emissions control requirements, and will, for example, require additional controls for pneumatic controllers and pumps, and compressors, and impose leak detection and repair requirements for natural gas compressor and booster stations. The EPA had announced plans to begin work on regulations to regulate methane emissions from existing oil and gas sources. In November 2016, the BLM issued rules requiring additional efforts by producers to reduce venting, flaring, and leaking of natural gas produced on federal and Native American lands. On an international level, in April 2016, the United States became one of almost 175 nations that signed onto the Paris Agreement, an international climate change agreement that calls for countries to set their own greenhouse gas emissions targets and be transparent about the measures each country will use to achieve its greenhouse gas emissions targets.
The adoption and implementation of any international, federal, state or local regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could require us to incur significant costs to reduce emissions of greenhouse gases associated with our operations or could adversely affect demand for the commodities that we buy and/or sell, transport, store or otherwise handle in connection with our midstream services. In addition, the adoption and implementation of any international, federal, state or local regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, the equipment and operations of our producer customers could affect their ability to produce the commodities that we buy and/or sell, transport, store or otherwise handle in connection with our midstream services. The potential increase in our operating costs could include among other things costs to operate and maintain our facilities, install new emission controls on our facilities, acquire allowances to authorize our greenhouse gas emissions, pay taxes related to our greenhouse gas emissions, and administer and manage a greenhouse gas emissions program. We may not be able to recover such increased costs through customer prices or rates. In addition, changes in regulatory policies that result in a reduction in the demand for hydrocarbon products that are deemed to contribute to greenhouse gases, or restrictions on their use, may reduce volumes available to us for processing, transportation, marketing and storage. These developments could have a material adverse effect on our financial position, results of operations and cash flows.
Hydraulic Fracturing. Certain of our customers employ hydraulic fracturing techniques to stimulate natural gas and crude oil production from unconventional geological formations (including shale formations), which entails the injection of pressurized fracturing fluids (consisting of water, sand and certain chemicals) into a well bore. From time to time, the United States has considered the adoption of legislation to provide for federal regulation of hydraulic fracturing, and several governmental reviews, including a study being performed by the EPA, are underway that focus on environmental aspects of hydraulic fracturing activities. Moreover, some states and localities, have adopted, and others are considering adopting, regulations or ordinances that could restrict hydraulic fracturing in certain circumstances, or that would impose higher taxes, fees or royalties on natural gas production, or otherwise limit the use of the technique. States could elect to prohibit high volume hydraulic fracturing altogether, following the approach taken by the State of New York in 2015. Increased regulation to the hydraulic fracturing process also could lead to a reduction in crude oil and natural gas drilling activities using hydraulic fracturing techniques, whereas increased public
opposition to activities using such techniques may result in operational delays, restriction or litigation. Additional legislation or regulation could also lead to operational delays and/or increased operating costs in the production of crude oil and natural gas incurred by our customers or could make it more difficult for them to perform hydraulic fracturing. If these legislative and regulatory initiatives cause a material decrease in the drilling or production of new wells and related servicing activities, it may affect the volume of hydrocarbon projects available to our midstream business and have a material adverse effect on our financial position, results of operations and cash flows.
The value of our interests in operations located in the U.S. Gulf of Mexico could be adversely impacted by increased regulation and continuing regulatory uncertainty.
Operations in the U.S. Gulf of Mexico have been subject to an increasingly stringent regulatory environment including government regulations focused on offshore operating requirements, spill cleanup, and enforcement matters. These regulations also implement additional safety and certification requirements applicable to offshore activities in the U.S. Gulf of Mexico. Certain operating assets such as our High Point system, Destin system, Okeanos system and our Offshore Texas system, and certain non-operated interests in operations located in the U.S. Gulf of Mexico that we currently hold or may hold in the future, are subject to such increased regulations, including our non-operated interests in MPOG and Delta House. In addition, the Bureau of Safety and Environmental Enforcement and the Bureau of Ocean Energy Management has increased regulatory activity including shortening the time period a line may be inactive before it must be removed or abandoned and requiring additional supplemental bonding or other forms of providing abandonment security for offshore facilities on the Outer Continental Shelf. These new regulations have increased our operating costs, and the operating costs of our producer customers. As a result, the value of our interests in these operations may be adversely affected by these regulations. Future regulatory requirements could delay activities from these operations and reduce our revenues, resulting in reduced cash flows and profitability. Moreover, any failure to satisfy these regulatory requirements by our producing customers could result in the commencement of enforcement proceedings or the taking of other remedial action, including assessing civil penalties, ordering suspension of operations or production, or initiating procedures to cancel leases, which, if upheld, could materially reduce the demand for our services.
Significant portions of our pipeline systems have been in service for several decades and we have a limited ownership history with respect to all of our assets. There could be unknown events or conditions or increased maintenance or repair expenses and downtime associated with our pipelines that could have a material adverse effect on our business and results of operations.
Significant portions of the pipeline systems that we have purchased had been in service for many decades prior to our purchase. Consequently, our executive management team has a limited history of operating such assets. There may be historical occurrences or latent issues regarding our pipeline systems that our executive management may be unaware of and that may have a material adverse effect on our business and results of operations. The age and condition of our pipeline systems could also result in increased maintenance or repair expenditures, and any downtime associated with increased maintenance and repair activities could materially reduce our revenue. Any significant increase in maintenance and repair expenditures or loss of revenue due to the age or condition of our pipeline systems could adversely affect our business and results of operations and our ability to make cash distributions to our unitholders.
We may incur significant costs and liabilities as a result of increasingly stringent pipeline safety regulation, including pipeline integrity management program testing and related repairs.
Pursuant to the Pipeline Safety Improvement Act of 2002, as reauthorized and amended by the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006, the DOT, through PHMSA, has adopted regulations requiring pipeline operators to develop integrity management programs for transmission pipelines located in “high consequence areas,” including high population areas, unless the operator effectively demonstrates by risk assessment that the pipeline could not affect the area. The regulations require operators, including us, to:
•perform ongoing assessments of pipeline integrity;
•identify and characterize applicable threats to pipeline segments that could impact a high consequence area;
•maintain processes for data collection, integration and analysis;
•repair and remediate pipelines as necessary; and
•implement preventive and mitigating actions.
In addition, many states have adopted regulations similar to existing DOT regulations for intrastate gathering and transmission lines. Although many of our natural gas facilities fall within a class that is not subject to these requirements, we may incur significant costs and liabilities associated with repair, remediation, preventative or mitigation measures associated with our non-exempt pipelines, particularly our AlaTenn and Midla pipelines. We currently estimate that we will incur future costs of approximately $2.0 million during 2017 to complete the testing required by existing DOT regulations. This estimate does not
include the costs, if any, for repair, remediation, preventative or mitigating actions that may be determined to be necessary as a result of the testing program, which could be substantial. Such costs and liabilities might relate to repair, remediation, preventative or mitigating actions that may be determined to be necessary as a result of the testing program, as well as lost cash flows resulting from shutting down our pipelines during the pendency of such repairs. Additionally, should we fail to comply with DOT regulations, we could be subject to penalties and fines.
The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“2011 Pipeline Safety Act”), which became law in January 2012, increases the penalties for safety violations, establishes additional safety requirements for newly constructed pipelines and requires studies of safety issues that could result in the adoption of new regulatory requirements for existing pipelines. More recently, in June 2016, President Obama signed the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (“2016 Pipeline Safety Act”) that extends PHMSA’s statutory mandate through 2019 and, among other things, requires PHMSA to complete certain of its outstanding mandates under the 2011 Pipeline Safety Act and develop new safety standards for natural gas storage facilities by June 22, 2018. The 2016 Pipeline Safety Act also empowers PHMSA to address imminent hazards by imposing emergency restrictions, prohibitions and safety measures on owners and operators of gas or hazardous liquid pipeline facilities without prior notice or an opportunity for a hearing.
In April 2015, PHMSA proposed rulemaking that would require leak detection for all “hazardous liquid pipelines” such as crude oil and NGL pipelines and require periodic assessment of hazardous liquid pipelines not already covered by the integrity management requirements. On January 13, 2017, PHMSA issued a final rule requiring the use of leak detection systems beyond HCAs to all regulated, non-gathering hazardous liquid pipelines and requiring integrity assessments at least once every ten years of onshore, piggable, transmission hazardous liquid pipeline segments located outside of HCAs. The effective date of this final rule is currently uncertain due to a regulatory freeze implemented by the Trump administration. In addition, in March 2016, PHMSA announced a proposed rulemaking that would impose new or more stringent requirements for certain gas lines and gathering lines including, among other things, expanding certain of PHMSA’s current regulatory safety programs for gas pipelines in newly defined “moderate consequence areas” that contain as few as 5 dwellings within a potential impact area; requiring gas pipelines installed before 1970 and thus excluded from certain pressure testing obligations to be tested to determine their maximum allowable operating pressures (“MAOP”); and requiring certain onshore and offshore gathering lines in Class I areas to comply with damage prevention, corrosion control, public education, MAOP limits, line markers and emergency planning standards. Additional requirements proposed by this proposed rulemaking would increase PHMSA’s integrity management requirements and also require consideration of seismicity in evaluating threats to pipelines. Such legislative and regulatory changes could have a material effect on our operations and costs of transportation services. Additionally, legislative and regulatory changes may also result in higher penalties for the violation of federal pipeline safety regulations and the costs associated with compliance may have a material effect on our operations. We cannot predict with any certainty at this time the terms of any new laws or rules or the costs of compliance associated with such requirements.
We and JPE will incur substantial transaction-related costs in connection with the JPE Merger.
We and JPE expect to incur a number of non-recurring transaction-related costs associated with combining the operations of the two organizations and achieving desired synergies. These fees and costs will be substantial. Unanticipated costs may be incurred in the integration of the businesses of AMID and JPE. There can be no assurance that the elimination of certain duplicative costs, as well as the realization of other efficiencies related to the integration of the two businesses, will offset the incremental transaction- related costs over time. Thus, any net benefit may not be achieved in the near term, the long term or at all.
Failure to successfully combine the businesses of AMID and JPE in the expected time frame may adversely affect the future results of the combined company.
The success of the JPE Merger will depend, in part, on our ability to realize the anticipated benefits and synergies from combining the businesses of AMID and JPE. To realize these anticipated benefits, the businesses must be successfully combined. If the combined company is not able to achieve these objectives, or is not able to achieve these objectives on a timely basis, the anticipated benefits of the JPE Merger may not be realized fully or at all. In addition, the actual integration and the costs associated with operating a larger organization may result in additional and unforeseen expenses, which could reduce the anticipated benefits of the JPE Merger. These difficulties could adversely affect the financial condition and operating results of the combined company.
We or JPE may have difficulty attracting, motivating and retaining executives and other employees in light of the JPE Merger.
Uncertainty about the effect of the JPE Merger on AMID or JPE employees may have an adverse effect on the combined organization. This uncertainty may impair these companies’ ability to attract, retain and motivate personnel until the JPE Merger are completed. Employee retention may be particularly challenging during the pendency of the JPE Merger, as employees may feel uncertain about their future roles with the combined organization. In addition, JPE may have to provide additional compensation
in order to retain employees. If employees of JPE depart because of issues relating to the uncertainty and difficulty of integration or a desire not to become employees of the combined organization, the combined organization’s ability to realize the anticipated benefits of the JPE Merger could be reduced.
We intend to grow our business in part by continuing to seek strategic acquisition opportunities. If we are unable to make acquisitions on economically acceptable terms from third parties, our future growth will be limited, and the acquisitions we do make may reduce, rather than increase, our cash generated from operations on a per unit basis.
Our ability to grow depends, in part, on our ability to make acquisitions that increase our cash generated from operations on a per unit basis. The acquisition component of our strategy is based, in large part, on our expectation of ongoing divestitures of midstream energy assets by industry participants. A material decrease in such divestitures would limit our opportunities for future acquisitions and could adversely affect our ability to grow our operations and increase our distributions to our unitholders.
If we are unable to make accretive acquisitions from third parties, whether because we are: (i) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts, (ii) unable to obtain financing for these acquisitions on economically acceptable or attractive terms or (iii) outbid by competitors or for any other reason, then our future growth and ability to increase distributions will be limited. Furthermore, even if we do make acquisitions that we believe will be accretive, these acquisitions may nevertheless result in a decrease in the cash generated from operations on a per unit basis.
Any acquisition involves potential risks, including, among other things:
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• | assumptions about volumes, revenue, decline rates, drilling activity and cost savings, including synergies; |
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• | inability to secure adequate customer commitments to use the acquired systems or facilities; |
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• | inability to integrate successfully the assets or businesses we acquire, particularly given the relatively small size of our management team and its limited history with certain assets; |
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• | assumption of unknown liabilities, including environmental contamination; |
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• | limitations on rights to indemnity from the seller; |
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• | assumptions about the overall costs of equity or debt; |
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• | diversion of management’s and employees’ attention from other business concerns; |
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• | entry of competitors in the markets where the acquired business competes; |
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• | difficulties operating in new geographic areas and business lines; and |
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• | customer or key employee losses at the acquired businesses. |
If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and our unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.
Our construction of new assets may not result in increased revenue and will be subject to regulatory, environmental, political, legal and economic risks, which could adversely affect our results of operations and financial condition.
One of the ways we intend to grow our business is through organic growth projects. The construction of additions or modifications to our existing systems and the construction of new midstream assets involve numerous regulatory, environmental, political, legal and economic uncertainties that are beyond our control. Such expansion projects may also require the expenditure of significant amounts of capital, and financing may not be available on economically acceptable terms or at all. If we undertake these projects, they may not be completed on schedule, at the budgeted cost, or at all. Cost overruns on construction projects may cause unexpected changes in project economics. Moreover, our revenue may not increase immediately upon the expenditure of funds on a particular project.
For instance, if we expand a pipeline, the construction may occur over an extended period of time, yet we will not receive any material increases in revenue until the project is completed and placed into service. Moreover, we could construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize or only materializes over a period materially longer than expected. Since we are not engaged in the exploration for, and development of, natural gas and crude oil reserves, we often do not have access to third-party estimates of potential reserves in an area prior to constructing facilities in that area. To the extent we rely on estimates of future production in our decision to construct additions to our systems, such estimates may prove to be inaccurate as a result of the numerous uncertainties inherent in estimating quantities of future production. As a result, new facilities may not attract enough throughput to achieve our expected investment return, which could adversely affect our results of operations and financial condition.
In addition, the construction of additions to our existing gathering and transportation assets, or the construction of new gathering and transportation assets, may require us to obtain new rights-of-way. We may be unable to obtain such rights-of-way and may, therefore, be unable to connect new natural gas volumes to our systems or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us to obtain new rights-of-way or to renew existing rights-of-way. If the cost of renewing or obtaining new rights-of-way increases materially, our cash flows could be adversely affected.
In connection with our expansion capital programs, we have agreed, and may in the future agree, to construct oil and gas gathering pipelines to service existing and future oil and gas properties, which involves potential risks.
In connection with our expansion capital programs, we have agreed, and may in the future agree, at our cost and expense, to design, acquire right-of-way for, obtain all permits from governmental authorities for, procure materials for, construct, operate, and maintain additional gathering pipelines for connection to certain current and future producing crude oil and natural gas properties. There are risks involved with such obligations, including:
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• | general construction cost overruns and delays resulting from numerous factors, many of which may be out of our control; |
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• | the inability to obtain required permits for the pipelines; |
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• | the inability to obtain rights-of-way for the gathering pipelines, which may result in pipelines being re-routed, which itself could result in cost overruns and delays; |
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• | the risk associated with producer’s exploration and production activities and the associated potential failure of the gathering pipelines to generate attractive cash flows given our obligation to construct and operate them; and |
title issues or environmental or regulatory compliance matters or liabilities or accidents associated with the construction or operation of the pipelines.
We currently expect to fund these costs with borrowings under our revolving credit facility or by accessing the capital markets. If we are unable to finance the expansion costs with existing liquidity, we could be required to seek alternative sources of liquidity, which could be costly or may not be available. In the event expansion and extension of the crude oil and natural gas properties is significantly more expensive than we expect or we are unable to obtain financing for such construction, it could have a material adverse effect on our financial condition, including our results of operations and cash flows.
We do not intend to obtain independent evaluations of natural gas reserves connected to our gathering and transportation systems on a regular or ongoing basis; therefore, in the future, volumes of natural gas on our systems could be less than we anticipate.
We do not intend to obtain independent evaluations of natural gas reserves connected to our systems on a regular or ongoing basis. Accordingly, we may not have independent estimates of total reserves dedicated to some or all of our systems or the anticipated life of such reserves. If the total reserves or estimated life of the reserves connected to our gathering and transportation systems are less than we anticipate and we are unable to secure additional sources of natural gas, it could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.
Our business involves many hazards, operational risks and litigation risks, some of which may not be fully covered by insurance. If a significant accident, event or judgment occurs for which we are not adequately insured, our operations and financial results could be adversely affected.
Our operations are subject to all of the risks and hazards inherent in the gathering, compressing, treating, processing and transportation of natural gas, including:
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• | damage to pipelines, plants, storage facilities, related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires, earthquakes and other natural disasters and acts of terrorism; |
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• | inadvertent damage from construction, vehicles, farm and utility equipment; |
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• | leaks of natural gas and other hydrocarbons or losses of natural gas as a result of the malfunction of equipment or facilities; |
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• | ruptures, fires and explosions; and |
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• | other hazards that could also result in personal injury and loss of life, pollution and suspension of operations. |
These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage. These risks may also result in curtailment or suspension of our operations. In addition, we have been, and are likely to continue to be, a defendant in various legal proceedings and litigation arising in the ordinary course of business, both as a result of these operating hazards and risks and as a result of other aspects of
our business. A natural disaster or other hazard affecting the areas in which we operate could have a material adverse effect on our operations.
We are not fully insured against all risks inherent in our business. For example, we do not have any casualty insurance on our underground pipeline systems that would cover damage to the pipelines. We are self-insured for general and product, workers’ compensation and automobile liabilities up to predetermined amounts above which third-party insurance applies. Additionally, we do not have business interruption/ loss of income insurance that would provide coverage in the event of damage to any of our underground facilities. In addition, although we are insured for environmental pollution resulting from environmental accidents that occur on a sudden and accidental basis, we may not be insured against all environmental accidents that might occur, some of which may result in toxic tort claims. We cannot guarantee that our insurance will be adequate to protect us from all material expenses related to potential future claims for personal injury and property damage. If a significant accident or event occurs for which we are not fully insured, it could have a material adverse effect on our operations and financial condition. Furthermore, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies may substantially increase. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. Additionally, we may be unable to recover from prior owners of our assets, pursuant to our contractual indemnification rights for potential environmental liabilities.
Our interstate natural gas, crude oil and NGL pipelines are subject to regulation by FERC, which could adversely affect our ability to make distributions to our unitholders.
Our AlaTenn and Midla interstate natural gas transportation systems, our Destin pipeline and a portion of our High Point system, are subject to regulation by FERC, under the NGA. Under the NGA, the rates for and terms of conditions of service on these interstate facilities must be just and reasonable and not unduly discriminatory. The rates and terms and conditions for our interstate pipeline services are set forth in tariffs that must be filed with and approved by FERC. Pursuant to FERC’s jurisdiction over rates, existing rates may be challenged by complaint and proposed rate increases may be challenged by protest. Any successful complaint or protest against our rates could have an adverse impact on our revenue associated with providing transportation service.
Under the NGA, FERC has the authority to regulate companies that provide natural gas pipeline transportation services in interstate commerce. FERC’s authority over such companies includes such matters as:
•rates, terms and conditions of service;
•the types of services interstate pipelines may offer to their customers;
•the certification and construction of new facilities;
•the acquisition, extension, disposition or abandonment of facilities;
•the maintenance of accounts and records;
•relationships between affiliated companies involved in certain aspects of the natural gas business;
•the initiation and discontinuation of services;
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• | market manipulation in connection with interstate sales, purchases or transportation of natural gas and NGLs; and |
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• | participation by interstate pipelines in cash management arrangements. |
The EP Act 2005 amended the NGA to add an anti-manipulation provision. Pursuant to the amended NGA, FERC established rules prohibiting energy market manipulation. Also, FERC’s rules require interstate pipelines and their affiliates to adhere to Standards of Conduct that, among other things, require that transportation employees function independently of marketing employees. We are subject to audit by FERC of our compliance in general, including adherence to all its rules and regulations. A violation of these rules, or any other rules, regulations or orders issued or administered by FERC, may subject us to civil penalties, disgorgement of certain profits, or appropriate non-monetary remedies imposed by FERC. In addition, the EP Act 2005 amended the NGA and the NGPA, to increase civil and criminal penalties for any violation of the NGA, NGPA and any rules, regulations or orders of FERC. The FERC is authorized to impose civil penalties of up to $1,000,000 per violation, per day for violations of the NGA, the NGPA or the rules, regulations, restrictions, conditions and orders promulgated under those statutes. This maximum penalty authority established by statute will continue to be adjusted periodically for inflation.
Additionally, existing rates may not reflect our current costs of operations, which may have risen since the last time our rates were approved by FERC.
Our Bakken crude oil gathering system and our Tri-States and Wilprise NGL pipelines are regulated as common carrier interstate pipelines by the FERC under the ICA, the EP Act 1992, and the rules and regulations promulgated under those laws. FERC regulations require that rates and terms and conditions of service for interstate service pipelines that transport crude oil be just and reasonable and must not be unduly discriminatory or confer any undue preference upon any shipper. FERC’s regulations
also require interstate common carrier petroleum pipelines to file with FERC and publicly post tariffs stating their interstate transportation rates and terms and conditions of service.
Rates of interstate liquids pipelines are currently regulated by FERC primarily through an annual indexing methodology, under which pipelines increase or decrease their rates in accordance with an index adjustment specified by FERC. For the five-year period beginning on July 1, 2016, FERC established an annual index adjustment equal to the change in the producer price index for finished goods plus 1.23%. Under FERC’s regulations, liquids pipelines can request a rate increase that exceeds the rate obtained through application of the indexing methodology by using a cost-of-services approach, but only after the pipeline establishes that a substantial divergence exists between the actual costs experienced by the pipeline and the rates resulting from application of the indexing methodology.
Under the ICA, FERC or interested persons may challenge existing or proposed new or changed rates, services, or terms and conditions of service. FERC is authorized to investigate such charges and may suspend the effectiveness of a new rate for up to seven months. FERC could require a common carrier pipeline to collect rates subject to refund until completion of an investigation during which FERC could find that the new or changed rate is unlawful. In contrast, FERC has clarified that initial rates and terms of service agreed upon with committed shippers in a transportation services agreement are not subject to protest or a cost-of-service analysis where the pipeline held an open season offering all potential shippers service on the same terms.
A successful rate challenge could result in a common carrier pipeline paying refunds of revenue collected in excess of the just and reasonable rate, together with interest for the period the rate was in effect, if any. FERC may also order a pipeline to reduce its rates prospectively, and may require a common carrier pipeline to pay shippers reparations retroactively for rate overages for a period of up to two years prior to the filing of a complaint. FERC also has the authority to change terms and conditions of service if it determines that they are unjust or unreasonable or unduly discriminatory or preferential.
Our intrastate natural gas and gathering transportation and sales services are subject to regulation by state and federal agencies, which could adversely affect our ability to make cash distributions to our unitholders.
Certain of our intrastate natural gas pipeline operations are subject to regulation by various agencies of the states in which they are located. Most states have agencies that possess the authority to review and authorize natural gas transportation transactions and the construction, acquisition, abandonment and interconnection of physical facilities. Some states also have state agencies that regulate transportation rates, service terms and conditions and contract pricing to ensure their reasonableness and to ensure that the intrastate pipeline companies that they regulate do not discriminate among similarly situated customers. Such agencies could limit our ability to increase our rates or order us to reduce our rates and pay refunds to shippers. State agencies can also regulate whether a service may be provided or cancelled. If state agencies in the states in which we offer intrastate transportation services change their policies or aggressively regulate our rates or terms and conditions of service, it could also adversely affect our ability to make cash distributions to our unitholders.
Certain of our intrastate natural gas pipelines transport gas in interstate commerce that is subject to FERC jurisdiction under Section 311 of the NGPA or are exempt from FERC jurisdiction as Hinshaw pipelines but have received blanket authorization to transport natural gas on behalf of interstate pipelines. The maximum rates for services provided under Section 311 of the NGPA may not exceed a “fair and equitable rate,” as defined in the NGPA. The rates are generally subject to review every five years by FERC or by an appropriate state agency. The inability to obtain approval of rates at acceptable levels could result in refund obligations and an inability to make cash distributions to our unitholders.
Intrastate natural gas pipelines, which operate entirely within a single state, are generally not subject to FERC’s jurisdiction under the NGA. Hinshaw pipelines operate within a single state but may receive gas from outside their state without becoming subject to FERC jurisdiction under the NGA. Specifically, a Hinshaw pipeline is exempt from FERC’s general NGA regulation if: (1) it receives natural gas at or within the boundary of a state; (2) all the gas is consumed within that state; and (3) the pipeline is regulated by a state commission. Hinshaw pipelines may also receive authorization under Part 284, subpart G of the Commission’s regulations to transport natural gas on behalf of interstate pipelines or a local distribution company served by an interstate pipeline.
Certain of our pipelines which transport gas in interstate commerce are “Hinshaw” pipelines exempt from the jurisdiction of the FERC jurisdiction under Section 1(c) of the NGA, and we may have additional Hinshaw pipelines in the future. Each of our current Hinshaw pipelines has received a “blanket certificate” under 18 C.F.R. Section 284.244 to transport gas. The maximum rates for services provided the blanket certificate may not exceed a “fair and equitable rate,” as defined in the FERC Regulations. The rates are generally subject to review every five years by FERC or by an appropriate state agency. The inability to obtain approval of rates at acceptable levels could result in refund obligations and an inability to make cash distributions to our unitholders.
The FERC’s anti-manipulation rules apply to non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction. The new anti-manipulation rules do not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but only to the extent such transactions do not have a “nexus” to jurisdictional transactions. As noted above, the FERC’s civil penalty authority under the EP Act of 2005 would apply to violations of these rules to the extent applicable to our intrastate natural gas services.
The application of certain FERC policy statements could affect the rate of return on our equity that we are allowed to recover through rates and the amount of any allowance our interstate systems can include for income taxes in establishing their rates for service, which would in turn impact our revenue and/or equity earnings.
FERC currently allows partnerships, including MLPs, to include in their cost-of-service an income tax allowance if the partnership’s owners have actual or potential income tax liability, a matter that will be reviewed by FERC on a case-by-case basis. In July 2016, the United States Court of Appeals for the District of Columbia Circuit issued its opinion in United Airlines, Inc., et al. v. FERC, finding that FERC had acted arbitrarily and capriciously when it failed to demonstrate that permitting an interstate petroleum products pipeline organized as a limited partnership to include an income tax allowance in the cost of service underlying its rates in addition to the discounted cash flow return on equity would not result in the pipeline partnership double-recovering the income tax liability of its investors. The court vacated FERC’s order and remanded to FERC to consider mechanisms for demonstrating that there is no double recovery as a result of the income tax allowance. On December 15, 2016, FERC issued a Notice of Inquiry seeking comment on how to address any double recovery resulting from income tax allowance policy. The ultimate outcome of this proceeding is not certain and could result in changes going forward to FERC’s treatment of income tax allowances in the cost of service or to the discounted cash flow return on equity. Depending upon the resolution of these issues, the cost of service rates of our interstate pipelines could be affected to the extent they propose new rates or changes to their existing rates or if their rates are subject to complaint or challenged by FERC.
A change in the jurisdictional characterization or regulation of our assets by federal, state or local regulatory agencies or a change in policy by those agencies could result in increased regulation of our assets which could materially and adversely affect our financial condition, results of operations and cash flows.
Gas gathering facilities and intrastate transportation facilities that do not provide interstate transmission services are exempt from the jurisdiction of FERC under the NGA. In Docket No. CP12-9, the FERC determined that certain portions of our High Point system met the gathering exemption from regulation under the NGA. Although FERC has not made any formal determinations with respect to any of our other facilities, we believe that our gathering and intrastate natural gas pipelines and related facilities that are not engaged in providing interstate transmission services are engaged in exempt gathering and intrastate transportation and, therefore, are not subject to FERC jurisdiction. We believe that our natural gas gathering pipelines meet the traditional tests that FERC has used to determine if a pipeline is a gathering pipeline and is therefore not subject to FERC’s jurisdiction. The distinction between FERC- regulated transmission services and federally unregulated gathering services is the subject of substantial ongoing litigation and, over time, FERC’s policy for determining which facilities it regulates has changed. In addition, the distinction between FERC-regulated transmission facilities, on the one hand, and intrastate transportation and gathering facilities, on the other, is a fact-based determination made by FERC on a case- by-case basis. If FERC were to consider the status of an individual facility and determine that the facility and/or services provided by it are not exempt from FERC regulation under the NGA, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by FERC under the NGA. Such regulation could decrease revenue, increase operating costs, and, depending upon the facility in question, could adversely affect our results of operations and cash flows. In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the NGA or NGPA, this could result in the imposition of civil penalties as well as a requirement to disgorge charges collected for such service in excess of the cost-based rate established by FERC.
Moreover, FERC regulation affects our gathering, transportation and compression business generally. FERC’s policies and practices across the range of its natural gas regulatory activities, including, for example, its policies on open access transportation, market manipulation, ratemaking, capacity release and market transparency and market center promotion, directly and indirectly affect our gathering business. In addition, the classification and regulation of our gathering and intrastate transportation facilities also are subject to change based on future determinations by FERC, the courts or Congress.
State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. We are subject to some state ratable take and common purchaser statutes. The ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. States in which we operate that have adopted some form of complaint-based regulation, like Texas, generally allow natural gas and crude oil producers and shippers
to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering access and rate discrimination.
In recent years, FERC’s efforts to promote open access, transparency, and the unbundling of interstate pipeline services has prompted a number of interstate pipelines to transfer their non-jurisdictional gathering facilities to unregulated affiliates. As a result of these activities, natural gas gathering may begin to receive greater regulatory scrutiny at both the state and federal levels. Such additional scrutiny could result in increased expenses to us and a resulting materially adverse change in our finances.
We are subject to stringent environmental, safety and health laws and regulations that may expose us to significant costs and liabilities.
Our operations are subject to stringent and complex federal, state and local environmental laws and regulations that govern the discharge of materials into the environment or otherwise relate to environmental protection. Examples of these laws include:
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• | the federal Clean Air Act and analogous state laws that restrict the emission of air pollutants from many sources, imposes various pre-construction, monitoring, and reporting requirements, which the Environmental Protection Agency has relied upon as authority for adopting climate change regulatory initiatives; |
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• | the federal CERCLA and analogous state laws that regulate the cleanup of hazardous substances that may be or have been released at properties currently or previously owned or operated by us or at locations to which our wastes are or have been transported for disposal; |
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• | the federal Clean Water Act and analogous state laws that regulate discharges of pollutants from facilities to state and federal waters and establishes the extent to which waterways are subject to federal jurisdiction and rulemaking as protected waters of the United States; |
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• | the federal Oil Pollution Act of 1990 and analogous state laws that establish strict liability for releases of oil into waters of the United States; |
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• | U.S. Department of the Interior regulations, which relate to offshore oil and natural-gas operations in U.S. waters and impose obligations for establishing financial assurances for decommissioning activities, liabilities for pollution cleanup costs resulting from operations, and potential liabilities for pollution damages; |
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• | the federal Resource Conservation and Recovery Act of 1976 and analogous state laws that impose requirements for the generation, storage, treatment, transport and disposal of solid and hazardous waste from our facilities; |
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• | the Endangered Species Act of 1973 and analogous state laws that restrict activities that may affect federally or state identified endangered and threatened species or their habitats through the implementation of operating restrictions or a temporary, seasonal, or permanent ban in affected areas; |
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• | the Toxic Substances Control Act, and analogous state laws that impose requirements on the use, storage and disposal of various chemicals and chemical substances at our facilities; and |
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• | the U.S. Occupational Safety and Health Act and analogous state laws that establish workplace standards for the protection of the health and safety of employees, including the implementation of hazard communications programs designed to inform employees about hazardous substances in the workplace, potential harmful effects of these substances, and appropriate control measures. |
These laws and regulations may impose numerous obligations that are applicable to our operations, including the acquisition of permits to conduct regulated activities, the incurrence of capital or operating expenditures to limit or prevent releases of materials from our pipelines and facilities, the imposition of specific safety and health criteria addressing worker protection, and the imposition of substantial liabilities and remedial obligations for pollution resulting from our operations. Numerous governmental authorities, such as the EPA, and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly corrective actions. Failure to comply with these laws, regulations and permits may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of injunctions limiting or preventing some or all of our operations.
In addition, we may experience a delay in obtaining or be unable to obtain required permits, which may cause us to lose potential and current customers, interrupt our operations or delay expansion projects and limit our growth and revenue. Please read “Business - Environmental Matters - Air Quality and Climate Control” for more information about these matters.
There is a risk that we may incur significant environmental costs and liabilities in connection with our operations due to historical industry operations and waste disposal practices, our handling of hydrocarbons and other wastes and potential emissions and discharges related to our operations. Joint and several strict liability may be incurred, without regard to fault, under certain of these environmental laws and regulations in connection with discharges or releases of hydrocarbons and other wastes on, under or from our properties and facilities, many of which have been used for midstream activities for a number of years, oftentimes by third parties not under our control. Private parties, including the owners of the properties through which our gathering or
transportation systems pass and facilities where our hydrocarbons and other wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance, as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property or natural resource damage. For example, an accidental release from one of our pipelines could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations. We may not be able to recover all or any of these costs from insurance. In addition, changes in environmental laws and regulations occur frequently, and any such changes that result in more stringent and costly waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our results of operations or financial position. Please read “Business - Environmental Matters” for more information.
We may be unable to obtain or renew permits necessary for our operations or the operations we may acquire in future acquisitions.
Our facilities operate under a number of required federal and state permits, licenses and approvals with terms and conditions containing a significant number of prescriptive limits and performance standards in order to operate. All of these permits, licenses, approvals, limits and standards require a significant amount of monitoring, record keeping and reporting in order to demonstrate compliance with the underlying permit, license, approval, limit or standard. Noncompliance or incomplete documentation of our compliance status may result in the imposition of fines, penalties and injunctive relief. A decision by a government agency to deny or delay issuing a new or renewed material permit, license or approval, or to revoke or substantially modify an existing permit, license or approval, could have a material adverse effect on our financial condition, including our results of operations and cash flows.
Our operations may impact the environment or cause environmental contamination, which could result in material liabilities to us.
Our operations use or generate quantities of hazardous materials and other wastes and may affect runoff or drainage water. In the event of environmental contamination or a release of hazardous materials or other wastes, we could become subject to claims for toxic torts, natural resource damages and other damages and for the investigation and cleanup of soil, surface water, groundwater, and other media. Such claims may arise out of conditions at sites that we currently own or operate, as well as at sites that we previously owned or operated, or may acquire. Our liability for such claims may be joint and several, so that we may be held responsible for more than our share of the contamination or other damages, or even for the entire share. These and other adverse impacts that our operations may have on the environment, as well as exposures to hazardous materials or other wastes associated with our operations, could result in costs and liabilities that could have a material adverse effect on us. Please read “Business - Environmental Matters” for more information.
We do not own all of the land on which our pipelines and facilities are located, which could result in disruptions to our operations.
We do not own all of the land on which our pipelines and facilities have been constructed, and we are, therefore, subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights-of-way or if such rights-of-way lapse or terminate or do not allow us to change our operations, or we may not be able to renew our contract leases on commercially reasonable terms or at all. We obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for a specific period of time for specific types of operations. Our loss of these rights, through our inability to renew right-of-way contracts or otherwise or our inability to amend these rights for new operations, could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.
A shortage of skilled labor in the midstream industry could reduce labor productivity and increase costs, which could have a material adverse effect on our business and results of operations.
The gathering, treating, processing and transporting of natural gas and crude oil requires skilled laborers in multiple disciplines such as equipment operators, mechanics and engineers, among others. We have from time to time encountered shortages for these types of skilled labor. If we experience shortages of skilled labor in the future, our labor and overall productivity or costs could be materially and adversely affected. If our labor prices increase or if we experience materially increased health and benefit costs with respect to our general partner’s employees, our results of operations could be materially and adversely affected.
Our work force could become unionized in the future, which could adversely affect the stability of our production and materially reduce our profitability.
Substantially all of our systems are operated by non-union employees. Our employees have the right at any time under the National Labor Relations Act to form or affiliate with a union. If our employees choose to form or affiliate with a union and the terms of a union collective bargaining agreement are significantly different from our current compensation and job assignment arrangements with our employees, these arrangements could adversely affect the stability of our operations and materially reduce our profitability.
A failure in our operational systems or cyber security attacks on any of our facilities, or those of third parties, may adversely affect our financial results.
Our business is dependent upon our operational systems to process a large amount of data and complex transactions. If any of our financial, operational, or other data processing systems fail or have other significant shortcomings or downtime, our financial results could be adversely affected. Our financial results could also be adversely affected if an employee causes our operational systems to fail, either as a result of inadvertent error or by deliberately tampering with or manipulating our operational systems. In addition, dependence upon automated systems may further increase the risk that operational system flaws, employee tampering or manipulation of those systems will result in losses that are difficult to detect.
Due to increased technology advances, we have become more reliant on technology to help increase efficiency in our business. We use computer programs to help run our financial and operational departments, and these systems may subject our business to increased risks. Any future cyber security attacks that affect our facilities, our customers and any financial data could have a material adverse effect on our business. In addition, cyber-attacks on our customer and employee data may result in financial loss and may negatively impact our reputation. Third-party systems on which we rely could also suffer operational system failure. Any of these occurrences could disrupt our business, result in potential liability or reputational damage or otherwise have an adverse effect on our financial results.
Terrorist attacks, the threat of terrorist attacks, and sustained military campaigns may adversely impact our results of operations.
Increased security measures taken by us as a precaution against possible terrorist attacks have resulted in increased costs to our business. Uncertainty surrounding continued hostilities in the Middle East and North Africa or other sustained military conflicts may affect our operations in unpredictable ways, including disruptions of crude oil supplies or storage facilities, and markets for refined products, and the possibility that infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror.
Risks Related to Our Units, Partnership Structure and Ownership
Master limited partnerships (“MLPs”) do not have the same flexibility as other types of organizations to accumulate cash. This may limit cash available to make distributions to our unitholders.
Subject to the limitations on restricted payments in the indenture governing the notes and in our revolving credit facility and any future indebtedness we may incur, we are required by our partnership agreement to distribute all of our “available cash” each quarter to our limited partners and our general partner. Available cash is defined in our partnership agreement and generally means, for any quarter, all cash and cash equivalents on hand at the end of that quarter:
•less, the amount of cash reserves established by our general partner to:
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• | provide for the proper conduct of our business (including reserves for future capital expenditures, for anticipated future credit needs subsequent to that quarter, for legal matters and for refunds of collected rates reasonably likely to be refunded as a result of a settlement or hearing related to FERC rate proceeding); |
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• | comply with applicable law or regulation, any of our debt instruments or other agreements; or |
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• | provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters (provided that our general partner may not establish cash reserves for distributions if the effect of the establishment of such reserves will prevent us from distributing the minimum quarterly distribution on all common units and any cumulative arrearages on such common units for the current quarter); |
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• | plus, if our general partner so determines, all or any portion of the cash on hand on the date of distribution of available cash for the quarter, including cash on hand resulting from working capital borrowings made subsequent to the end of such quarter. |
As a result, we do not accumulate significant amounts of cash and thus do not have the same flexibility as corporations or other entities that do not pay dividends or have complete flexibility regarding the amounts they will distribute to their equity holders. The timing and amount of our distributions could significantly reduce the cash available to pay the principal, premium (if any) and interest on the notes. The board of directors of our general partner will determine the amount and timing of such distributions and has broad discretion to establish and make additions to our reserves or the reserves of our operating subsidiaries as it determines are necessary or appropriate.
Although our payment obligations to our unitholders are subordinate to our payment obligations with respect to the notes, we expect that the value of our units would decrease if we decrease the amount we distribute per unit. Accordingly, if we experience a liquidity problem in the future, we may not be able to issue equity to recapitalize and our ability to service our indebtedness, including the notes, may be materially impaired.
We may not have sufficient cash from operations to enable us to pay distributions to holders of our common units.
We may not have sufficient available cash from operations each quarter to enable us to pay the minimum quarterly distribution of $0.4125 per common unit or at all. These distributions may only be made from cash available for distribution after the preferred quarterly distribution to which our Convertible Preferred Units are entitled, the establishment of cash reserves, and payment of our fees and expenses. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:
•the volume of natural gas we gather, process and transport;
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• | the level of production of crude oil and natural gas and the resultant market prices of crude oil and natural gas and NGLs; |
•realized pricing impacts on our revenue and expenses that are directly subject to commodity price exposure;
•changes in the fees we charge for our services;
•the market prices of natural gas and NGLs relative to one another, which affects our processing margins;
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• | the effect of seasonal variations in temperature on the amount of natural gas and crude oil that we transport and the amount of natural gas that we store, process and treat; |
•capacity charges and volumetric fees associated with our transportation services;
•storage capacity utilization associated with our terminals segment;
•the level of competition from other midstream energy companies in our geographic markets;
•the creditworthiness of our customers;
•the level of our operating, maintenance and corporate costs;
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• | regulatory action affecting the supply of, or demand for, natural gas, the transportation rates we can charge on our regulated pipelines, how we contract for services, our existing contracts, our operating costs and our operating flexibility; and |
•acts of God.
In addition, the actual amount of cash we will have available for distribution will depend on other factors, including:
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• | the level and timing of capital expenditures we make; |
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• | the cost of acquisitions, and the resulting costs of integrations, if any; |
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• | our debt service payments and requirements and other liabilities; |
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• | fluctuations in our working capital needs; |
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• | our ability to borrow funds and access capital markets; |
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• | restrictions contained in our Credit Agreement; |
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• | the amount of cash reserves established by our General Partner; and |
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• | other business risks affecting our cash levels. |
There is no guarantee that unitholders will receive quarterly distributions from us. Our distributions are determined each quarter by the Board of Directors of our General Partner based on the board’s consideration of the foregoing factors, our financial position, earnings, cash flow, current and future business needs and other relevant factors at that time. We may reduce or eliminate distributions at any time we have insufficient cash available for distributions. This may be due to insufficient cash reserves, requirements to fund current or anticipated future operations, capital expenditures, acquisitions, growth or expansion projects, debt repayment or other business needs.
The amount of cash we have available for distribution depends primarily upon our cash flow and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record net losses
for financial reporting purposes and may not make cash distributions during periods when we record net income for financial reporting purposes.
We have a holding company structure in which our subsidiaries and unconsolidated affiliates conduct our operations and own our operating assets, and our ability to make cash distributions depends on the performance of these entities and their ability to distribute funds to us.
We are a holding company, and our subsidiaries and unconsolidated affiliates conduct all of our operations and own all of our operating assets. We do not have significant assets other than equity in our subsidiaries and unconsolidated affiliates. As a result, our ability to make distributions depends on the performance of our subsidiaries and these other entities and their ability to distribute funds to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, our revolving credit facility, the terms of debt and other agreements to which they are a party, their organizational documents and applicable state corporation, limited liability company, limited partnership or similar statutes and other laws and regulations. Moreover, we are a minority owner in several of our unconsolidated affiliates and may not possess the power to cause those entities to make distributions of cash to us. We cannot assure you that the earnings from, or other available assets of, our subsidiaries and other unconsolidated affiliates will be sufficient to enable us to make cash distributions.
As our common units are yield-oriented securities, increases in interest rates could adversely impact our unit price, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at our intended levels.
Interest rates have increased recently and may continue to increase in the future. As a result, interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our unit price is impacted by our level of our cash distributions and distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at our intended levels.
Affiliates of ArcLight directly own our general partner, which has sole responsibility for conducting our business and managing our operations. These affiliates elect all of the members of the board of our general partner. These affiliates and our general partner have conflicts of interest with us and limited fiduciary duties, and they may favor their own interests to the detriment of us and our unitholders.
Affiliates of ArcLight and our general partner have the power to appoint all of the officers and directors of our general partner. The directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner that is beneficial to it, and have no duty to us or our common unitholders. Conflicts of interest may arise between these affiliates and our general partner, on the one hand, and us and our noteholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of these affiliates over our interests and the interests of our noteholders. These conflicts include the following situations, among others:
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• | neither our Partnership Agreement nor any other agreement requires these affiliates of ArcLight to pursue a business strategy that favors us, and the officers and directors of these affiliates may have a fiduciary duty to make these decisions in the best interests of these affiliates of ArcLight and their respective direct and indirect owners, respectively, which may be contrary to our interests. These affiliates of ArcLight may choose to shift the focus of their investment and growth to areas not served by our assets; |
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• | These affiliates of ArcLight, their respective direct and indirect owners and their respective affiliates are not limited in their ability to compete with us and may offer business opportunities or sell midstream assets to third parties without first offering us the right to bid for them; |
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• | our general partner is allowed to take into account the interests of parties other than us in resolving conflicts of interest and exercising certain rights under our Partnership Agreement, which has the effect of limiting its duty to our unitholders; |
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• | our Partnership Agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties, limits our general partner’s liabilities, and also restricts the remedies available to our noteholders for actions that, without the limitations, might constitute breaches of such fiduciary duty; |
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• | except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval; |
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• | disputes may arise under our commercial agreements or acquisition agreements with these affiliates of ArcLight; |
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• | our general partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities and the creation, reduction or increase of reserves, each of which can affect the amount of cash that is distributed to our unitholders; |
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• | our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and to our general partner as well as the conversion of the Convertible Preferred Units into common units; |
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• | our general partner determines which costs incurred by it are reimbursable by us; |
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• | our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the Convertible Preferred Units, to make incentive distributions or to accelerate the expiration of a subordination period; |
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• | our Partnership Agreement permits us to classify up to $11.5 million as operating surplus, even if it is generated from asset sales, nonworking capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions on our Convertible Preferred Units or to our general partner in respect of the general partner interest or the incentive distribution rights; |
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• | our Partnership Agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf; |
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• | our general partner intends to limit its liability regarding our contractual and other obligations; |
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• | our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if they own more than 80% of the common units; |
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• | our general partner controls the enforcement of the obligations that it and its affiliates owe to us; |
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• | our general partner decides whether to retain separate counsel, accountants or others to perform services for us; |
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• | our general partner may transfer its IDRs without unitholder approval; and |
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• | our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the Conflicts Committee of the Board of Directors of our general partner (“Conflicts Committee”) or our unitholders. This election may result in lower distributions to our common unitholders in certain situations. |
The affiliates of ArcLight that own our general partner are not limited in their ability to compete with us and are not obligated to offer us the opportunity to acquire additional assets or businesses, which could limit our ability to grow and could adversely affect our results of operations and cash available for distribution to our unitholders.
The affiliates of ArcLight that own our general partner are not prohibited from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, in the future, affiliates of our general partner and the entities owned or controlled by affiliates of our general partner, including these affiliates of ArcLight may acquire, construct or dispose of additional midstream or other assets and may be presented with new business opportunities, without any obligation to offer us the opportunity to purchase or construct such assets or to engage in such business opportunities. Moreover, while these affiliates of ArcLight may offer us the opportunity to buy additional assets from them, they are under no contractual obligation to do so and we are unable to predict whether or when such acquisitions might be completed. This may create actual and potential conflicts of interest between us and affiliates of our general partner, and result in less than favorable treatment of us and our unitholders.
The New York Stock Exchange (“NYSE”) does not require a publicly traded partnership like us to comply with certain of its corporate governance requirements.
Our common units are listed on the NYSE. Because we are a publicly traded partnership, the NYSE does not require us to have a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. Additionally, any future issuance of additional common units or other securities, including to affiliates, will not be subject to the NYSE’s shareholder approval rules. Accordingly, unitholders will not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements.
If you are not an eligible holder, you may not receive distributions or allocations of income or loss on your common units and your common units will be subject to redemption.
We have adopted certain requirements regarding those investors who may own our units. Eligible holders are U.S. individuals or entities subject to U.S. federal income taxation on the income generated by us or entities not subject to U.S. federal income taxation on the income generated by us, so long as all of the entity’s owners are U.S. individuals or entities subject to such taxation. If you are not an eligible holder, our General Partner may elect not to make distributions or allocate net
income or loss on your units, and you run the risk of having your units redeemed by us at the lower of your purchase price for the units and the then-current market price. The redemption price may be paid in cash or by delivery of a promissory note, as determined by our General Partner.
Common units held by persons who are non-taxpaying assignees will be subject to the possibility of redemption.
Our Partnership Agreement gives our General Partner the power to amend the agreement to avoid any adverse effect on the maximum applicable rates chargeable to customers by us under FERC regulations or to reverse an adverse determination that has occurred regarding such maximum rate. If our General Partner determines that our not being treated as an association taxable as a corporation or otherwise taxable as an entity for U.S. federal income tax purposes, coupled with the tax status (or lack of proof thereof) of one or more of our limited partners, has, or is reasonably likely to have, a material adverse effect on the maximum applicable rates chargeable to customers by us, then our General Partner may adopt such amendments to our Partnership Agreement as it determines are necessary or advisable to obtain proof of the U.S. federal income tax status of our limited partners (and their owners, to the extent relevant) and permit us to redeem the units held by any person whose tax status has or is reasonably likely to have a material adverse effect on the maximum applicable rates or who fails to comply with the procedures instituted by our General Partner to obtain proof of the U.S. federal income tax status.
Our partnership agreement requires that we distribute our available cash, which could limit our ability to grow and make acquisitions.
Our partnership agreement requires us to distribute our available cash to our unitholders. Accordingly, we will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. As a result, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow.
In addition, because we intend to distribute our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement, or in our revolving credit facility, on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other indebtedness to finance our growth strategy would result in increased interest expense, which in turn may impact the available cash that we have to distribute to our unitholders.
Our general partner may limit its liability regarding our obligations.
Our general partner may limit its liability under contractual arrangements so that the counterparties to such arrangements have recourse only against our assets, and not against our general partner or its assets. Our general partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our general partner. Our partnership agreement permits our general partner to limit its liability, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce our ability to make cash distributions to our unitholders.
Our Partnership Agreement limits our General Partner’s fiduciary duties to us and the holders of our common units.
Our Partnership Agreement contains provisions that modify and reduce the fiduciary duties to which our General Partner would otherwise be held by state fiduciary duty law. For example, our Partnership Agreement permits our General Partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our General Partner or otherwise, free of fiduciary duties to us and our unitholders. This entitles our General Partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our General Partner may make in its individual capacity include:
•how to allocate corporate opportunities among us and its affiliates;
•whether to exercise its limited call right;
•how to exercise its voting rights with respect to the units it owns;
•whether to elect to reset target distribution levels; and
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• | whether or not to consent to any merger or consolidation of the partnership or amendment to the Partnership Agreement. |
By purchasing a common unit, a common unitholder agrees to become bound by the provisions in the Partnership Agreement, including the provisions discussed above.
Our Partnership Agreement restricts the remedies available to holders of our common units for actions taken by our General Partner that might otherwise constitute breaches of fiduciary duty.
Our Partnership Agreement contains provisions that restrict the remedies available to unitholders for actions taken by our General Partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our Partnership Agreement:
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• | provides that whenever our General Partner makes a determination or takes, or declines to take, any other action in its capacity as our General Partner, our General Partner is required to make such determination, or take or decline to take such other action, in good faith, and will not be subject to any other or different standard imposed by our Partnership Agreement, Delaware law, or any other law, rule or regulation, or at equity; |
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• | provides that our General Partner will not have any liability to us or our unitholders for decisions made in its capacity as a General Partner so long as such decisions are made in good faith, meaning that it believed that the decision was in, or not opposed to, the best interest of our partnership; |
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• | provides that our General Partner and its officers and directors will not be liable for monetary damages to us, our limited partners or their assignees resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our General Partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and |
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• | provides that our General Partner will not be in breach of its obligations under the Partnership Agreement or its fiduciary duties to us or our unitholders if a transaction with an affiliate or the resolution of a conflict of interest is: |
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a. | approved by the Conflicts Committee of the Board of Directors of our General Partner, although our General Partner is not obligated to seek such approval; |
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b. | approved by the vote of a majority of the outstanding common units, excluding any common units owned by our General Partner and its affiliates; |
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c. | on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or |
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d. | fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us. |
In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by our General Partner must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the Conflicts Committee, and the Board of Directors of our General Partner determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest satisfies either of the standards set forth in subclauses (c) and (d) above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the Partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.
Our General Partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our General Partner’s incentive distribution rights without the approval of the Conflicts Committee of our General Partner’s board or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.
Our General Partner has the right, at any time it has received incentive distributions exceeding the target distribution described in our Partnership Agreement for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our cash distribution at the time of the exercise of the reset election. Following a reset election by our General Partner, the minimum quarterly distribution will be reset to an amount equal to the average cash distribution per unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the “reset minimum quarterly distribution”), and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.
We anticipate that our General Partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion; however, it is possible that our General Partner could exercise this reset election at a time when we are experiencing declines in our aggregate cash distributions or at a time when our General Partner expects that we will experience declines in our aggregate cash distributions
in the foreseeable future. In such situations, our General Partner may be experiencing, or may expect to experience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to be issued common units, which are entitled to specified priorities with respect to our distributions and which therefore may be more advantageous for the General Partner to own in lieu of the right to receive incentive distribution payments based on target distribution levels that are less certain to be achieved in the then current business environment. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued common units to our General Partner in connection with resetting the target distribution levels related to our General Partner’s incentive distribution rights.
Holders of our common units have limited voting rights and are not entitled to elect our General Partner or its directors.
Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will have no right on an annual or ongoing basis to elect our General Partner or its board of directors. The Board of Directors of our General Partner will be chosen by HPIP. Furthermore, if the unitholders are dissatisfied with the performance of our General Partner, they will have little ability to remove our General Partner. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price. Our Partnership Agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.
Even if holders of our common units are dissatisfied, they cannot currently remove our General Partner without its consent.
Our unitholders are unable to remove our General Partner without its consent because our General Partner and its affiliates own sufficient units to be able to prevent its removal. The vote of the holders of at least 66 2/3% of all outstanding limited partner units voting together as a single class is required to remove our General Partner. As of March 20, 2017, ArcLight indirectly held common units or convertible preferred units representing 49.2% of our then-outstanding common units.
Our Partnership Agreement restricts the voting rights of unitholders owning 20% or more of our common units.
Unitholders’ voting rights are further restricted by a provision of our Partnership Agreement providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our General Partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the Board of Directors of our General Partner, cannot vote on any matter.
Our General Partner interest or the control of our General Partner may be transferred to a third party without unitholder consent.
Our General Partner may transfer its General Partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our Partnership Agreement does not restrict the ability of HPIP to transfer all or a portion of their ownership interest in our General Partner to a third party. The new owner of our General Partner would then be in a position to replace the board of directors and officers of our General Partner with its own designees and thereby exert significant control over the decisions made by the board of directors and officers.
We may issue additional units without your approval, which would dilute your existing ownership interests.
Our Partnership Agreement does not limit the number of additional limited partner interests that we may issue at any time without the approval of our unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:
•our existing unitholders’ proportionate ownership interest in us will decrease;
•the amount of cash available for distribution on each unit may decrease;
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• | because of the Series A Units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase; |
•the ratio of taxable income to distributions may increase;
•the relative voting strength of each previously outstanding unit may be diminished; and
•the market price of the common units may decline.
ArcLight may sell units in the public or private markets, and such sales could have an adverse impact on the trading price of the common units.
As of March 20, 2017, ArcLight held 7,187,358 Series A-1 Units, 3,079,284 Series A-2 Units, 8,792,205 Series C Units and 2,333,333 Series D Units through its affiliates. The Series A-1, A-2, C and D Units are all convertible into common units at the election of ArcLight at any time. In addition, as of March 20, 2017, ArcLight indirectly held 13,977,709 common units, including 1,349,609 common units held by our General Partner, which ArcLight controls. The sale of these units in the public or private markets could have an adverse impact on the price of the common units or on any trading market that may develop.
Our General Partner has a limited call right that may require you to sell your units at an undesirable time or price.
If at any time our General Partner and its affiliates own more than 80% of our common units, our General Partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price that is not less than their then-current market price, as calculated pursuant to the terms of our Partnership Agreement. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units.
Your liability may not be limited if a court finds that unitholder action constitutes control of our business.
A General Partner of a partnership generally has unlimited liability for the obligations of the Partnership, except for those contractual obligations of the Partnership that are expressly made without recourse to the General Partner. Our partnership is organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. You could be liable for any and all of our obligations as if you were a General Partner if a court or government agency were to determine that:
•we were conducting business in a state but had not complied with that particular state’s partnership statute; or
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• | your right to act with other unitholders to remove or replace our General Partner, to approve some amendments to our Partnership Agreement or to take other actions under our Partnership Agreement constitute “control” of our business. |
Unitholders may have liability to repay distributions that were wrongfully distributed to them.
Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable both for the obligations of the assignor to make contributions to the Partnership that were known to the substituted limited partner at the time it became a limited partner and for those obligations that were unknown if the liabilities could have been determined from the Partnership Agreement. Neither liabilities to partners on account of their partnership interest nor liabilities that are non-recourse to the Partnership are counted for purposes of determining whether a distribution is permitted.
If we are deemed an “investment company” under the Investment Company Act of 1940, it would adversely affect the price of our common units and could have a material adverse effect on our business.
Our assets include 20.1% non-operated interest in Delta House Class A Units, a 16.7% non-operated interest in Tri- States, a 25.3% non-operated interest in Wilprise, a non-operated interest in Mesquite and a 26.3% non- operated interest in Pinto, any of which may be deemed to be an “investment security” within the meaning of the Investment Company Act of 1940, as amended (the “Investment Company Act”). In the future, we may acquire additional minority owned interests that could be deemed “investment securities.” If a sufficient amount of our assets are deemed to be “investment securities” within the meaning of the Investment Company Act, we would either have to register as an investment company under the Investment Company Act, obtain exemptive relief from the SEC or modify our organizational structure or our contract rights to fall outside the definition of an investment company. Registering as an investment company could, among other things, materially limit our ability to engage in transactions with affiliates, including the purchase and sale of certain securities or other property to or from our affiliates, restrict our ability to borrow funds or engage in other transactions involving leverage and require us to add additional directors who are independent of us or our affiliates. The occurrence of some or all of these events may have a material adverse effect on our business. Moreover, treatment of us as an investment company would prevent our qualification as a partnership for U.S. federal income tax purposes in which case we would be treated as a corporation for U.S. federal income tax purposes, and be subject to U.S. federal income tax at the corporate tax rate, significantly reducing the cash available for distributions.
Additionally, distributions to our unitholders would be taxed again as corporate distributions and none of our income, gains, losses or deductions would flow through to our unitholders.
Additionally, as a result of our desire to avoid having to register as an investment company under the Investment Company Act, we may have to forego potential future acquisitions of interests in companies that may be deemed to be investment securities within the meaning of the Investment Company Act or dispose of our current interests in any of our assets that are deemed to be “investment securities.”
Tax Risks to Common Unitholders
Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service (“IRS”) treats us as a corporation for U.S. federal income tax purposes or we become subject to material additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution to the unitholders would be substantially reduced.
The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for U.S. federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter affecting us.
Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a publicly traded partnership such as ours to be treated as a corporation rather than a partnership for U.S. federal income tax purposes. Although we do not believe based upon our current operations that we are so treated, the IRS could disagree with the positions we take or a change in our business (or a change in current law) could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation as an entity.
If we were treated as a corporation for U.S. federal income tax purposes, we would pay U.S. federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state income tax at varying rates. Distributions to a unitholder would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions, or credits would flow through to the unitholder. Because a tax would be imposed upon us as a corporation, our cash available for distribution to unitholders would be substantially reduced. Therefore, treatment of us as a corporation for U.S. federal income tax purposes would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.
Our Partnership Agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.
The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. From time to time, members of the U.S. Congress propose and consider such substantive changes to the existing U.S. federal income tax laws that affect publicly traded partnerships. If successful, such proposals or other similar proposals could eliminate the qualifying income exception to the treatment of all publicly traded partnerships as corporations upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted, but it is possible that a change in law could affect us and may, if enacted, be applied retroactively. Any such changes could negatively impact the value of an investment in our common units.
On January 24, 2017, the U.S. Treasury Department and the IRS published final regulations (the “Final Regulations”) regarding qualifying income under Section 7704(d)(1)(E) of the Code. The Final Regulations treat as qualifying income the income earned from retail sales of propane. We do not believe the Final Regulations adversely affect our ability to qualify as a
partnership for U.S. federal income tax purposes.
Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. For example, we are required to pay the State of Texas a margin tax that is assessed at 0.75% of taxable margin apportioned to Texas. Imposition of such a tax
on us by any state will reduce the cash available for distribution to unitholders. The Partnership Agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution levels will be adjusted to reflect the impact of that law on us.
Compliance with and changes in tax laws could adversely affect our performance.
We are subject to extensive tax laws and regulations, including federal and state income tax laws and transactional tax laws such as excise, sales/use, payroll, franchise and ad valorem tax laws. New tax laws and regulations and changes in existing tax laws and regulations are continuously being enacted that could result in increased tax expenditures in the future. Further, taxing authorities may change their application of existing taxes, so that additional entities or transactions may become subject to an existing tax. Many of these tax liabilities are subject to audits by the respective taxing authority. These audits may result in additional tax payments, as well as interest and penalties. The costs of these audits are borne indirectly by the unitholders and our General Partner because such costs reduce our cash available for distribution.
If the IRS contests the U.S. federal income tax positions we take, the market for our common units may be adversely impacted, and the cost of any IRS contest will reduce our cash available for distribution to the unitholders.
We have not requested a ruling from the IRS with respect to our treatment as a partnership for U.S. federal income tax purposes. The IRS may adopt positions that differ from the conclusions of our counsel expressed in a prospectus or from the positions we take, and the IRS’s positions may ultimately be sustained. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take. A court may not agree with some or all of our counsel’s conclusions or positions we take. Any contest with the IRS, and the outcome of any such contest, may increase a unitholder’s tax liability and result in adjustment to items unrelated to us and could materially and adversely impact the market for our common units and the price at which they trade. The rights of a unitholder owning less than a 1% profits interest in us to participate in the U.S. federal income tax audit process are very limited. In addition, our costs of any contest with the IRS will be borne indirectly by the unitholders and our General Partner because such costs will reduce our cash available for distribution.
If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it may collect any resulting taxes (including any applicable penalties and interest) directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced.
Pursuant to the Bipartisan Budget Act of 2015, if the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it may collect any resulting taxes (including any applicable penalties and interest) directly from us. We will generally have the ability to shift any such tax liability to our General Partner and our unitholders in accordance with their interests in us during the year under audit, but there can be no assurance that we will be able to (or will choose to) do so under all circumstances, or that we will be able to (or will choose to) effect corresponding shifts in state income or similar tax liability resulting from the IRS adjustment in states in which we do business in the year under audit or in the adjustment year. If we are required to make payments of taxes, penalties and interest resulting from audit adjustments, our cash available for distribution to our unitholders might be substantially reduced.
The unitholders' share of our income will be taxable to them for U.S. federal income tax purposes even if the unitholders do not receive any cash distributions from us.
Because a unitholder will be treated as a partner to whom we will allocate taxable income, which could be different in amount than the cash we distribute, a unitholder's allocable share of our taxable income will be taxable to it, which may require the payment of U.S. federal income taxes and, in some cases, state and local income taxes on its share of our taxable income even if it receives no cash distributions from us. The unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the tax liability that results from that income.
Certain actions that we may take, such as issuing additional units, may increase the U.S. federal income tax liability of unitholders.
In the event we issue additional units or engage in certain other transactions in the future, the allocable share of nonrecourse liabilities allocated to the unitholders will be recalculated to take into account our issuance of any additional units. Any reduction in a unitholder's share of our nonrecourse liabilities will be treated as a distribution of cash to that unitholder and will result in a corresponding tax basis reduction in a unitholder's units. A deemed cash distribution may, under certain circumstances, result in the recognition of taxable gain by a unitholder, to the extent that the deemed cash distribution exceeds such unitholder's tax basis in its units.
In addition, the U.S. federal income tax liability of a unitholder could be increased if we dispose of assets or make a future offering of units and use the proceeds in a manner that does not produce substantial additional deductions, such as to repay indebtedness currently outstanding or to acquire property that is not eligible for depreciation or amortization for U.S. federal income tax purposes or that is depreciable or amortizable at a rate significantly slower than the rate currently applicable to the our assets.
There are limits on the deductibility of losses that may adversely affect unitholders.
In the case of taxpayers subject to the passive loss rules (generally, individuals, closely-held corporations and regulated investment companies), any losses generated by us will only be available to offset our future income and cannot be used to offset income from other activities, including other passive activities or investments. Unused losses may be deducted when the unitholder disposes of the unitholder’s entire investment in us in a fully taxable transaction with an unrelated party. A unitholder’s share of our net passive income may be offset by unused losses from us carried over from prior years, but not by losses from other passive activities, including losses from other publicly traded partnerships.
Tax gain or loss on the disposition of our common units could be more or less than expected.
If a unitholder sells its common units, the unitholder will recognize a gain or loss equal to the difference between the amount realized and the unitholder's tax basis in those common units. Because distributions to a unitholder in excess of the total net taxable income allocated to the unitholder decrease the unitholder's tax basis in the unitholder's common units, the amount, if any, of such prior excess distributions with respect to the units sold will, in effect, become taxable income to the unitholder if the unitholder sells the common units at a price greater than the unitholder's tax basis in those common units, even if the price received by the unitholder is less than the original cost. Furthermore, a substantial portion of the amount realized on any sale of a unitholder's common units, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder's share of our nonrecourse liabilities, if the unitholder sells its common units, the unitholder may incur a tax liability in excess of the amount of cash the unitholder receives from the sale.
Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.
Investment in common units by tax-exempt entities, such as individual retirement accounts, or IRAs, other retirement plans and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from U.S. federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income, which may be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or a non-U.S. person, you should consult a tax advisor before investing in our common units.
We treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.
Because we cannot match transferors and transferees of common units and because of other reasons, we have adopted depreciation and amortization positions that may not conform to all aspects of existing Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to the unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to the unitholders' tax returns.
We prorate our items of income, gain, loss and deduction for U.S. federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among the unitholders.
We prorate our items of income, gain, loss and deduction for U.S. federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. Treasury recently adopted final regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders to ours. These regulations apply to certain publicly-traded partnerships, including us, for taxable years beginning on
or after August 3, 2015. However, these regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among the unitholders.
A unitholder whose common units are loaned to a “short seller” to cover a short sale of common units may be considered as having disposed of those common units. If so, the unitholder would no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.
Because a unitholder whose common units are loaned to a “short seller” to cover a short sale of common units may be considered as having disposed of the loaned common units, the unitholder may no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan to the short seller and such unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing and lending their common units.
We have adopted certain valuation methodologies for tax purposes that may result in a shift of income, gain, loss and deduction between our General Partner and the unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.
When we issue additional units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and the General Partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and our General Partner, which may be unfavorable to such unitholders. Moreover, subsequent purchasers of common units may have a greater portion of the Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Code Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between our General Partner and certain of the unitholders.
A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to the unitholders. It also could affect the amount of gain from the unitholders' sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to the unitholders’ tax returns without the benefit of additional deductions.
The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for U.S. federal income tax purposes.
We will be considered to have terminated as a partnership for U.S. federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. Our termination, among other things, would result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1 if relief from the IRS were not granted, as described below) for one fiscal year and could also result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a calendar year, the closing of our taxable year may result in more than twelve months of our taxable income or loss being includable in such unitholder’s taxable income for the year of termination. Under current law, such a termination would not affect our classification as a partnership for U.S. federal income tax purposes, but instead, after our termination, we would be treated as a new partnership for tax purposes. If treated as a new partnership, we would be required to make new tax elections and could be subject to penalties if we were unable to determine that a termination occurred. The IRS has announced a relief procedure for publicly traded partnerships that terminate in this manner, whereby, if a publicly traded partnership that has terminated requests and the IRS grants special relief, among other things, such partnership would only have to provide one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years resulting from the termination.
Unitholders may be subject to state and local taxes and return filing requirements in states and jurisdictions where they do not reside as a result of investing in our units.
In addition to U.S. federal income taxes, unitholders may be subject to other taxes, including foreign, state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property, even if the unitholders do not live in any of those jurisdictions. Unitholders may be required
to file foreign, state and local income tax returns and pay state and local income taxes in some or all of these jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. As we make acquisitions or expand our business, we may own assets or do business in additional states that impose a personal income tax or an entity level tax. It is each unitholder's responsibility to file all U.S. federal, foreign, state, local and non-U.S. tax returns.
Some of the states in which we do business or own property may require us to, or we may elect to, withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the state. Withholding, the amount of which may be greater or less than a particular unitholder's income tax liability to the state, generally does not relieve the nonresident unitholder from the obligation to file an income tax return. Amounts withheld may be treated as if distributed to unitholders for purposes of determining the amounts distributed by us.
Item 1B. Unresolved Staff Comments
Not applicable.
Item 2. Properties
A description of our properties is contained in "Item 1. Business" of this Annual Report and is incorporated into this Item 2. by reference.
Our principal executive offices are located at 2103 CityWest Blvd., Bldg. 4, Suite 800, Houston, Texas 77042 and our telephone number is 346-241-3400.
Item 3. Legal Proceedings
We are not currently party to any pending litigation or governmental proceedings, other than ordinary routine litigation incidental to our business. While the ultimate impact of any proceedings cannot be predicted with certainly, our management believes that the resolution of any of our pending proceeds will not have a material adverse effect on our financial condition or results of operations.
Item 4. Mine Safety Disclosures
Not applicable.
PART II
Item 5. Market for Registrant's Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities
Market Information
Our common units have been listed on the New York Stock Exchange ("NYSE") since July 27, 2011, under the symbol "AMID." The following table sets forth the high and low sales prices of our common units, as reported by the NYSE for each quarter during 2016 and 2015, together with distributions paid subsequent to such quarter for that quarter through December 31, 2016:
|
| | | | | | | | | | | | | | | |
Period Ended | Fourth Quarter | | Third Quarter | | Second Quarter | | First Quarter |
2016 | | | | | | | |
High Price | $ | 18.30 |
| | $ | 15.19 |
| | $ | 14.00 |
| | $ | 8.49 |
|
Low Price | $ | 13.06 |
| | $ | 10.39 |
| | $ | 6.18 |
| | $ | 4.03 |
|
Distribution per common unit | $ | 0.4125 |
| | $ | 0.4125 |
| | $ | 0.4125 |
| | $ | 0.4125 |
|
2015 | | | | | | | |
High Price | $ | 12.70 |
| | $ | 16.71 |
| | $ | 19.42 |
| | $ | 21.17 |
|
Low Price | $ | 3.80 |
| | $ | 9.01 |
| | $ | 15.75 |
| | $ | 15.71 |
|
Distribution per common unit | $ | 0.4725 |
| | $ | 0.4725 |
| | $ | 0.4725 |
| | $ | 0.4725 |
|
As of March 20, 2017, there were 206 unitholders of record of our common units. This number does not include unitholders whose units are held in trust by other entities. The actual number of unitholders is greater than the number of holders of record. We have also issued approximately 10,266,642 Series A Units, 8,792,205 Series C Units, 2,333,333 Series D Units and 933,435 General Partner units, for which there is no established trading market. Our General Partner and its affiliates receive quarterly distributions on the General Partner units only after the requisite distributions have been paid on the common units and Series A Units, Series C Units, and Series D Units.
Our Distribution Policy
Our Partnership Agreement requires us to distribute all of our available cash quarterly. Our cash distribution policy reflects our belief that our unitholders will be better served if we distribute rather than retain our available cash. Generally, our available cash is the sum of our i) cash on hand at the end of a quarter after the payment of our expenses and the establishment of cash reserves and ii) cash on hand resulting from working capital borrowings made after the end of the quarter. We pay the cash dividend in one payment to those unitholders of record on the applicable record date, as determined by the General Partner.
The following table sets forth the number of units at December 31, 2016 and 2015 (in thousands):
|
| | | | | | |
| | December 31, |
| | 2016 | | 2015 |
Series A convertible preferred units | | 10,107 |
| | 9,210 |
|
Series B convertible units (1) | | — |
| | 1,350 |
|
Series C convertible preferred units | | 8,792 |
| | — |
|
Series D convertible preferred units | | 2,333 |
| | — |
|
Limited partner common units | | 31,237 |
| | 30,427 |
|
General Partner units | | 680 |
| | 536 |
|
(1) Our General Partner held 1,349,609 Series B convertible units ("Series B Units"), which converted into common units on a one-for-one basis on February 1, 2016.
Our General Partner's initial 2.0% interest in distributions has been reduced to 1.3% due to the issuance of additional units and the General Partner has not contributed a proportionate amount of capital to us to maintain its initial 2.0% General Partner notional interest.
Our cash distribution policy, as expressed in our Partnership Agreement, may not be modified or repealed without amending our Partnership Agreement. The actual amount of our cash distributions for any quarter is subject to fluctuations based on the amount
of cash we generate from our business and the amount of reserves our General Partner establishes in accordance with our Partnership Agreement as described above. We will pay our distributions on or about the 15th of each February, May, August and November to holders of record on or about the 5th of each such month. If the distribution date does not fall on a business day, we will make the distribution on the business day immediately preceding the indicated distribution date.
Series A Units
Distributions on Series A Units can be made with paid-in-kind Series A Units, cash or a combination thereof, at the discretion of the Board of Directors, which began with the distribution for the three months ended June 30, 2014 and continued through the distribution for the quarter ended March 31, 2016. At December 31, 2016, we accrued $2.5 million of contractual cash distributions on the Series A Units which were paid in February 2017.
Series C Units
Distributions on Series C Units can be made with paid-in-kind Series C Units, cash or a combination thereof, at the discretion of the Board of Directors. At December 31, 2016, we accrued $3.6 million of contractual cash distributions on the Series C Units which were paid in February 2017.
Series D Units
Distributions on Series D Units are equal to the greater of $0.4125 and the cash distribution that the Series D Units would have received if they had been converted to common units immediately prior to the beginning of the quarter. At December 31, 2016, we accrued $1.0 million of contractual cash distributions on the Series D Units which were paid in February 2017.
Securities Authorized for Issuance Under Equity Compensation Plans
The following table summarizes information about our equity compensation plans as of December 31, 2016:
|
| | | | | | | | | |
Plan Category | Number of securities to be issued upon exercise of outstanding options, warrants and rights | | Weighted-average exercise price of outstanding options, warrants and rights | | Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) |
Equity compensation plans approved by security holders | 275,000 |
| | $ | 9.03 |
| | 5,017,528 |
|
Total | 275,000 |
| | 9.03 |
| | 5,017,528 |
|
Item 6. Selected Historical Financial and Operating Data
The following table presents selected historical consolidated financial and operating data for the periods and as of the dates indicated. We derived this information from our historical consolidated financial statements and accompanying notes. This information should be read together with, and is qualified in its entirety, by reference to those consolidated financial statements and notes, which for the years 2016, 2015, and 2014 begin on F-1 to this Annual Report.
For a detailed discussion of the following table, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations."
|
| | | | | | | | | | | | | | | | | | | | |
| | Years ended December 31, |
| | 2016 (1) | | 2015 (1) | | 2014 (1) | | 2013 (1) | | 2012 |
| | (in thousands, except per unit and operating data) |
Statements of Operations Data: | | | | | | | | | | |
Revenues: | | | | | | | | | | |
Sales of natural gas, NGLs and condensate | | $ | 160,950 |
| | $ | 179,818 |
| | $ | 255,025 |
| | $ | 241,401 |
| | $ | 192,968 |
|
Services | | 72,572 |
| | 55,216 |
| | 52,284 |
| | 52,650 |
| | 14,308 |
|
Gain (loss) on commodity derivatives, net | | (840 | ) | | 1,324 |
| | 1,091 |
| | 28 |
| | 992 |
|
Total revenue | | 232,682 |
| | 236,358 |
| | 308,400 |
| | 294,079 |
| | 208,268 |
|
Operating expenses: | | | | | | | | | | |
Purchases of natural gas, NGLs and condensate | | 92,556 |
| | 105,883 |
| | 197,952 |
| | 215,053 |
| | 154,472 |
|
Direct operating expenses | | 61,861 |
| | 60,737 |
| | 45,919 |
| | 32,275 |
| | 17,223 |
|
Corporate expenses | | 54,223 |
| | 29,818 |
| | 24,422 |
| | 21,134 |
| | 16,052 |
|
Depreciation, amortization and accretion expense | | 46,022 |
| | 38,014 |
| | 28,832 |
| | 30,002 |
| | 21,287 |
|
(Gain) loss on involuntary conversion of property, plant and equipment | | — |
| | — |
| | — |
| | (343 | ) | | 1,021 |
|
(Gain) loss on sale of assets, net | | 591 |
| | 3,011 |
| | 122 |
| | — |
| | (123 | ) |
Loss on impairment of property, plant and equipment | | 697 |
| | — |
| | 99,892 |
| | 18,155 |
| | — |
|
Loss on impairment of goodwill | | — |
| | 118,592 |
| | — |
| | — |
| | — |
|
Total operating expenses | | 255,950 |
|
| 356,055 |
|
| 397,139 |
|
| 316,276 |
|
| 209,932 |
|
Operating loss | | (23,268 | ) | | (119,697 | ) |
| (88,739 | ) |
| (22,197 | ) |
| (1,664 | ) |
Other income (expense): | | | | | | | | | | |
Interest expense | | (15,499 | ) | | (14,745 | ) | | (7,577 | ) | | (9,291 | ) | | (4,570 | ) |
Other expense | | — |
| | — |
| | (670 | ) | | — |
| | — |
|
Earnings in unconsolidated affiliates | | 40,158 |
| | 8,201 |
| | 348 |
| | — |
| | — |
|
Income (loss) from continuing operations before income taxes | | 1,391 |
| | (126,241 | ) | | (96,638 | ) | | (31,488 | ) | | (6,234 | ) |
Income tax (expense) benefit | | (2,057 | ) | | (1,134 | ) | | (557 | ) | | 495 |
| | — |
|
Income (loss) from continuing operations | | (666 | ) | | (127,375 | ) | | (97,195 | ) | | (30,993 | ) | | (6,234 | ) |
Discontinued operations: | | | | | | | | | | |
Loss from discontinued operations, net of tax | | — |
| | (80 | ) | | (611 | ) | | (2,413 | ) | | (18 | ) |
Net loss | | (666 | ) | | (127,455 | ) | | (97,806 | ) | | (33,406 | ) | | (6,252 | ) |
Net income attributable to non-controlling interests | | 2,804 |
| | 25 |
| | 214 |
| | 633 |
| | 256 |
|
Net loss attributable to the Partnership | | $ | (3,470 | ) | | $ | (127,480 | ) | | $ | (98,020 | ) | | $ | (34,039 | ) | | $ | (6,508 | ) |
General Partner's Interest in net loss | | $ | (48 | ) | | $ | (1,645 | ) | | $ | (1,279 | ) | | $ | (1,405 | ) | | $ | (129 | ) |
Limited Partners' Interest in net loss | | $ | (3,422 | ) | | $ | (125,835 | ) | | $ | (96,741 | ) | | $ | (32,634 | ) | | $ | (6,379 | ) |
| | | | | | | | | | |
Limited Partners' net (loss) per common unit: | | | | | | |
Basic and diluted: | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | |
Loss from continuing operations | | $ | (1.11 | ) | | $ | (6.00 | ) | | $ | (8.54 | ) | | $ | (7.15 | ) | | $ | (0.70 | ) |
Loss from discontinued operations | | — |
| | — |
| | (0.04 | ) | | (0.27 | ) | | — |
|
Net loss | | $ | (1.11 | ) | | $ | (6.00 | ) | | $ | (8.58 | ) | | $ | (7.42 | ) | | $ | (0.70 | ) |
Weighted average number of common units outstanding: | | | | | | | | | | |
Basic and diluted (2) | | 31,043 |
| | 24,983 |
| | 13,472 |
| | 7,525 |
| | 9,113 |
|
Statement of Cash Flow Data: | | | | | | | | | | |
Net cash provided by (used in): | | | | | | | | | | |
Operating activities | | $ | 45,362 |
| | $ | 40,937 |
| | $ | 21,478 |
| | $ | 17,223 |
| | $ | 18,348 |
|
Investing activities | | (551,441 | ) | | (171,692 | ) | | (471,870 | ) | | (28,214 | ) | | (62,427 | ) |
Financing activities | | 509,018 |
| | 130,256 |
| | 450,490 |
| | 10,816 |
| | 43,784 |
|
Other Financial Data: | | | | | | | | | | |
Adjusted EBITDA (3) | | $ | 132,023 |
| | $ | 66,311 |
| | $ | 45,551 |
| | $ | 31,907 |
| | $ | 18,850 |
|
Gross margin (4) | | 130,065 |
| | 122,201 |
| | 102,655 |
| | 74,821 |
| | 49,431 |
|
Cash distribution declared per common unit | | 1.71 |
| | 1.89 |
| | 1.85 |
| | 1.75 |
| | 1.73 |
|
Segment gross margin: | | | | | | | | | | |
Gathering and Processing | | 74,582 |
| | 76,865 |
| | 50,817 |
| | 36,985 |
| | 36,118 |
|
Transmission | | 41,233 |
| | 35,301 |
| | 42,828 |
| | 32,408 |
| | 13,313 |
|
Terminals | | 14,250 |
| | 10,035 |
| | 9,010 |
| | 5,428 |
| | — |
|
Balance Sheet Data (at period end): | | | | | | | | | | |
Cash and cash equivalents | | $ | 2,939 |
| | $ | — |
| | $ | 499 |
| | $ | 393 |
| | $ | 576 |
|
Accounts receivable and unbilled revenue | | 29,322 |
| | 18,740 |
| | 29,543 |
| | 29,823 |
| | 23,470 |
|
Property, plant and equipment, net | | 755,457 |
| | 655,310 |
| | 582,182 |
| | 312,701 |
| | 223,819 |
|
Investments in unconsolidated affiliates | | 291,987 |
| | 63,704 |
| | 22,252 |
| | — |
| | — |
|
Restricted cash | | 323,564 |
| | 5,037 |
| | 5,037 |
| | 3,000 |
| | — |
|
Total assets | | 1,563,495 |
| | 891,880 |
| | 913,558 |
| | 382,075 |
| | 256,696 |
|
Current portion of long-term debt | | 4,458 |
| | 2,338 |
| | 2,908 |
| | 2,048 |
| | — |
|
Long-term debt | | 711,250 |
| | 525,100 |
| | 372,950 |
| | 130,735 |
| | 128,285 |
|
Operating Data: | | | | | | | | | | |
Gathering and processing segment: | | | | | | | | | | |
Average throughput (MMcf/d) | | 393.7 |
| | 338.2 |
| | 274.8 |
| | 277.2 |
| | 291.2 |
|
Average plant inlet volume (MMcf/d) (5) | | 102.1 |
| | 120.9 |
| | 89.1 |
| | 117.3 |
| | 116.1 |
|
Average gross NGL production (Mgal/d) (5) | | 192.9 |
| | 231.1 |
| | 64.2 |
| | 52.0 |
| | 49.9 |
|
Average gross condensate production (Mgal/d) (5) | | 86.6 |
| | 99.8 |
| | 75.2 |
| | 46.2 |
| | 22.6 |
|
Transmission segment: | | | | | | | | | | |
Average throughput (MMcf/d) | | 683.2 |
| | 708.6 |
| | 778.9 |
| | 644.7 |
| | 398.5 |
|
Average firm transportation - capacity reservation (MMcf/d) | | 688.1 |
| | 653.7 |
| | 577.9 |
| | 640.7 |
| | 703.6 |
|
Average interruptible transportation - throughput (MMcf/d) | | 354.0 |
| | 410.3 |
| | 468.9 |
| | 389.2 |
| | 86.6 |
|
Terminals segment: | | | | | | | | | | |
Storage utilization | | 92.5 | % | | 88.1 | % | | 91.4 | % | | 95.6 | % | | — | % |
| |
(1) | During these years, we had the following transactions that affect comparability: i) in October 2016 and April 2016 we acquired a 6.2% and a 1% non-operated interest in Delta House Class A Units, respectively; ii) in April 2016, we acquired |
membership interests in Destin (49.7%), Tri-States (16.7%), Okeanos (66.7%), and Wilprise (25.3%), which we account for as equity method investments; iii) in April 2016 we acquired a 60% interest in American Panther which we consolidate for financial reporting purposes; iv) in September 2015, we acquired a non-operated 12.9% indirect interest in Delta House Class A Units, which we account for as an equity method investment; and v) in October 2014 and January 2014, we acquired the Costar and Lavaca systems, respectively, both of which are included in our Gathering and Processing segment. vi) in December 2013, we acquired Blackwater, which is included in our Terminals segment; and vii) in April 2013, we acquired the High Point System, which is included in Transmission segment.
| |
(2) | Includes unvested phantom units with distribution equivalent rights ("DERs"), which are considered participating securities, of 200,000 at December 31, 2016 and 2015. |
| |
(3) | For a definition of Adjusted EBITDA and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP and a discussion of how we use Adjusted EBITDA to evaluate our operating performance, p |