UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
x | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 2017 | |
OR
¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to | |
(Exact name of registrant as specified in its charter) | Commission file number | State or other jurisdiction of incorporation or organization | (I.R.S. Employer Identification No.) |
Crestwood Equity Partners LP | 001-34664 | Delaware | 43-1918951 |
Crestwood Midstream Partners LP | 001-35377 | Delaware | 20-1647837 |
811 Main Street, Suite 3400 Houston, Texas | 77002 | |
(Address of principal executive offices) | (Zip code) | |
(832) 519-2200
(Registrant’s telephone number, including area code)
___________________________________________
Securities registered pursuant to Section 12(b) of the Act:
Crestwood Equity Partners LP | Common Units representing limited partnership interests, listed on the New York Stock Exchange | |
Crestwood Midstream Partners LP | None | |
Securities registered pursuant to Section 12(g) of the Act:
Crestwood Equity Partners LP | None | |
Crestwood Midstream Partners LP | None | |
Indicate by check mark if registrant is a well-known seasoned issuer, as defined by Rule 405 of the Securities Act.
Crestwood Equity Partners LP | Yes x No ¨ | |
Crestwood Midstream Partners LP | Yes ¨ No x | |
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act.
Crestwood Equity Partners LP | Yes ¨ No x | |
Crestwood Midstream Partners LP | Yes ¨ 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.
Crestwood Equity Partners LP | Yes x No ¨ | |
Crestwood Midstream Partners LP | Yes x No ¨ | |
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, 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).
Crestwood Equity Partners LP | Yes x No ¨ | |
Crestwood Midstream Partners LP | Yes x No ¨ | |
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of 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.
Crestwood Equity Partners LP | x | |
Crestwood Midstream Partners LP | x | |
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 definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Crestwood Equity Partners LP | Large accelerated filer x | Accelerated filer ¨ | Non-accelerated filer ¨ | Smaller reporting company ¨ | Emerging growth company ¨ |
Crestwood Midstream Partners LP | Large accelerated filer ¨ | Accelerated filer ¨ | Non-accelerated filer x | Smaller reporting company ¨ | Emerging growth company ¨ |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange act.
Crestwood Equity Partners LP | o | |
Crestwood Midstream Partners LP | o | |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).
Crestwood Equity Partners LP | Yes ¨ No x | |
Crestwood Midstream Partners LP | Yes ¨ No x | |
State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter (June 30, 2017).
Crestwood Equity Partners LP | $1.1 billion | |
Crestwood Midstream Partners LP | None | |
Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date (February 12, 2018).
Crestwood Equity Partners LP | $26.95 per common unit | 71,231,599 | |
Crestwood Midstream Partners LP | None | None | |
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the following documents are incorporated by reference into the indicated parts of this report:
Crestwood Equity Partners LP | None | |
Crestwood Midstream Partners LP | None | |
Crestwood Midstream Partners LP, as a wholly-owned subsidiary of a reporting company, meets the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K and is therefore filing this report with the reduced disclosure format as permitted by such instruction.
FILING FORMAT
This Annual Report on Form 10-K is a combined report being filed by two separate registrants: Crestwood Equity Partners LP and Crestwood Midstream Partners LP. Crestwood Midstream Partners LP is a wholly-owned subsidiary of Crestwood Equity Partners LP. Information contained herein related to any individual registrant is filed by such registrant solely on its own behalf. Each registrant makes no representation as to information relating exclusively to the other registrant.
Item 15 of Part IV of this Annual Report includes separate financial statements (i.e., balance sheets, statements of operations, statements of comprehensive income, statements of partners’ capital and statements of cash flows, as applicable) for Crestwood Equity Partners LP and Crestwood Midstream Partners LP. The notes accompanying the financial statements are presented on a combined basis for each registrant. Management’s Discussion and Analysis of Financial Condition and Results of Operations included under Item 7 of Part II is presented for each registrant.
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CRESTWOOD EQUITY PARTNERS LP
CRESTWOOD MIDSTREAM PARTNERS LP
INDEX TO ANNUAL REPORT ON FORM 10-K
Page | ||
Mine Safety Disclosures | ||
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GLOSSARY
The terms below are common to our industry and used throughout this report.
/d | per day |
AOD | Area of dedication, which means the acreage dedicated to a company by an oil and/or natural gas producer under one or more contracts. |
ASC | Accounting Standards Codification. |
ASU | Accounting Standards Update. |
Barrels (Bbls) | One barrel of petroleum products equal to 42 U.S. gallons. |
Base gas | A quantity of natural gas held within the confines of the natural gas storage facility and used for pressure support and to maintain a minimum facility pressure. May consist of injected base gas or native base gas. Also known as cushion gas. |
Bcf | One billion cubic feet of natural gas. A standard volume measure of natural gas products. |
Cycle | A complete withdrawal and injection of working gas. Cycling refers to the process of completing one cycle. |
EPA | Environmental Protection Agency. |
FASB | Financial Accounting Standards Board. |
FERC | Federal Energy Regulatory Commission. |
Firm service | Services pursuant to which customers receive an assured or firm right to (i) in the context of storage service, store product in the storage facility or (ii) in the context of transportation service, transport product through a pipeline, over a defined period of time. |
GAAP | Generally Accepted Accounting Principles. |
Gas storage capacity | The maximum volume of natural gas that can be cost-effectively injected into a storage facility and extracted during the normal operation of the storage facility. Gas storage capacity excludes base gas. |
HP | Horsepower. |
Hub | Geographic location of a storage facility and multiple pipeline interconnections. |
Hub services | With respect to our natural gas storage and transportation operations, the following services: (i) interruptible storage services, (ii) firm and interruptible park and loan services, (iii) interruptible wheeling services, and (iv) balancing services. |
Injection rate | The rate at which a customer is permitted to inject natural gas into a natural gas storage facility. |
Interruptible service | Services pursuant to which customers receive only limited assurances regarding the availability of (i) with respect to storage services, capacity and deliverability in storage facilities or (ii) with respect to transportation services, capacity and deliverability from receipt points to delivery points. Customers pay fees for interruptible services based on their actual utilization of the storage or transportation assets. |
MMBbls | One million barrels. |
MMcf | One million cubic feet of natural gas. |
Natural gas | A gaseous mixture of hydrocarbon compounds, primarily methane together with varying quantities of ethane, propane, butane and other gases. |
Natural Gas Act | Federal law enacted in 1938 that established the FERC’s authority to regulate interstate pipelines. |
Natural gas liquids (NGLs) | Those hydrocarbons in natural gas that are separated from the natural gas as liquids through the process of absorption, condensation, adsorption or other methods in natural gas processing or cycling plants. NGLs include natural gas plant liquids (primarily ethane, propane, butane and isobutane) and lease condensate (primarily pentanes produced from natural gas at lease separators and field facilities). |
NYPSC | New York State Public Service Commission. |
NYSE | New York Stock Exchange. |
Salt cavern | A man-made cavern developed in a salt dome or salt beds by leaching or mining of the salt. |
SEC | Securities and Exchange Commission. |
Withdrawal rate | The rate at which a customer is permitted to withdraw gas from a natural gas storage facility. |
Working gas | Natural gas in a storage facility in excess of base gas. Working gas may or may not be completely withdrawn during any particular withdrawal season. |
Working gas storage capacity | See gas storage capacity (above). |
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PART I
Item 1. Business
Unless the context requires otherwise, references to (i) “we,” “us,” “our,” “ours,” “our company,” the “Company,” the “Partnership,” “Crestwood Equity,” “CEQP,” and similar terms refer to either Crestwood Equity Partners LP itself or Crestwood Equity Partners LP and its consolidated subsidiaries, as the context requires, and (ii) “Crestwood Midstream” and “CMLP” refers to Crestwood Midstream Partners LP and its consolidated subsidiaries Unless otherwise indicated, information contained herein is reported as of December 31, 2017.
Introduction
Crestwood Equity, a Delaware limited partnership formed in March 2001, is a master limited partnership (MLP) that develops, acquires, owns or controls, and operates primarily fee-based assets and operations within the energy midstream sector. Headquartered in Houston, Texas, we provide broad-ranging infrastructure solutions across the value chain to service premier liquids-rich natural gas and crude oil shale plays across the United States. We own and operate a diversified portfolio of crude oil and natural gas gathering, processing, storage and transportation assets that connect fundamental energy supply with energy demand across North America. Crestwood Equity’s common units representing limited partner interests are listed on the NYSE under the symbol “CEQP.”
Crestwood Equity is a holding company. All of our consolidated operating assets are owned by or through our wholly-owned subsidiary, Crestwood Midstream, a Delaware limited partnership. Our consolidated operating assets primarily include:
• | natural gas facilities with approximately 2.4 Bcf/d of gathering capacity and 0.5 Bcf/d of processing capacity; |
• | NGL facilities with approximately 20,000 Bbls/d of fractionation capacity and 3.1 MMBbls of storage capacity, as well as our portfolio of transportation assets (consisting of truck and rail terminals, truck/trailer units and rail cars) capable of transporting approximately 195,000 Bbls/d of NGLs; and |
• | crude oil facilities with approximately 125,000 Bbls/d of gathering capacity, 1.5 MMBbls of storage capacity, 20,000 Bbls/d of transportation capacity and 160,000 Bbls/d of rail loading capacity. |
In addition, through our equity investments in joint ventures, we have ownership interests in:
• | natural gas facilities with approximately 0.3 Bcf/d of gathering capacity, 0.2 Bcf/d of processing capacity, 75.8 Bcf of certificated working storage capacity, and 1.5 Bcf/d of transportation capacity; and |
• | crude oil facilities with approximately 20,000 Bbls/d of rail loading capacity and 380,000 Bbls of working storage capacity. |
Our primary business objective is to maximize the value of Crestwood for our unitholders.
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Ownership Structure
The diagram below reflects a simplified version of our ownership structure as of December 31, 2017:
Crestwood Equity. Crestwood Equity GP LLC, which is indirectly owned by Crestwood Holdings LLC (Crestwood Holdings), owns our non-economic general partnership interest. Crestwood Holdings, which is substantially owned and controlled by First Reserve Management, L.P. (First Reserve), also owns approximately 25% of Crestwood Equity’s common units and all of its subordinated units as of December 31, 2017.
Crestwood Midstream. Crestwood Equity owns a 99.9% limited partnership interest in Crestwood Midstream and Crestwood Gas Services GP LLC (CGS GP), a wholly-owned subsidiary of Crestwood Equity, owns a 0.1% limited partnership interest in
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Crestwood Midstream. Crestwood Midstream GP LLC, a wholly-owned subsidiary of Crestwood Equity, owns the non-economic general partnership interest of Crestwood Midstream.
Simplification Merger (2015). On September 30, 2015, Crestwood Midstream merged with a wholly-owned subsidiary of Crestwood Equity, with Crestwood Midstream surviving as a wholly-owned subsidiary of Crestwood Equity (the Simplification Merger). Prior to the Simplification Merger, Crestwood Equity indirectly owned a non-economic general partnership interest in Crestwood Midstream and 100% of its incentive distribution rights (IDRs), which entitled Crestwood Equity to receive 50% of all distributions paid to Crestwood Midstream’s common unit holders in excess of its initial quarterly distribution of $0.37 per common unit. Crestwood Midstream’s common units were also listed on the NYSE under the listing symbol “CMLP”. Upon becoming a wholly-owned subsidiary of Crestwood Equity as a result of the Simplification Merger, Crestwood Midstream’s IDRs were eliminated and its common units ceased to be listed on the NYSE.
Prior to the Simplification Merger, Crestwood Midstream owned all of our operating assets other than the assets comprising our NGL marketing business. Crestwood Operations LLC (Crestwood Operations), a wholly-owned subsidiary of Crestwood Equity, owned and operated the assets comprising our NGL marketing business, consisting mainly of our West Coast NGL assets, our Seymour NGL storage facility, and our NGL transportation terminals and fleet. Upon the closing of the Simplification Merger, Crestwood Equity contributed 100% of its interests in Crestwood Operations to Crestwood Midstream. As a result of this contribution, all of the Company’s assets are owned by or through Crestwood Midstream. See Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 2 for a further discussion of the Simplification Merger.
Our Assets
Our financial statements reflect three operating and reporting segments: (i) gathering and processing (G&P) operations; (ii) storage and transportation (S&T) operations; and (iii) marketing, supply and logistics (MS&L) operations. Below is a description of our operating and reporting segments.
Gathering and Processing
Our G&P operations provide gathering and transportation services (natural gas, crude oil and produced water) and processing, treating and compression services (natural gas) to producers in unconventional shale plays and tight-gas plays in North Dakota, West Virginia, Texas, New Mexico, Wyoming and Arkansas. This segment primarily includes our operations and investments that own (i) our crude oil, gas and produced water gathering systems in the Bakken Shale play; (ii) rich gas gathering systems and processing plants in the Bakken, Marcellus, Barnett, Delaware Permian and Powder River Basin Shale plays; and (iii) dry gas gathering systems in the Barnett, Fayetteville and Delaware Permian Shale plays.
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The table below summarizes certain information about our G&P systems (including our equity investments) as of December 31, 2017:
Shale Play (State) | Counties / Parishes | Pipeline (Miles) | Gathering Capacity | 2017 Average Gathering Volumes | Compression (HP) | Number of In-Service Processing Plants | Processing Capacity (MMcf/d) | Gross Acreage Dedication |
Bakken North Dakota | McKenzie and Dunn | 640 (1) | 100 MMcf/d - natural gas gathering 125 MBbls/d - crude oil gathering 40 MBbls/d - water gathering | 48 MMcf/d - natural gas gathering 80 MBbls/d - crude oil gathering 35 MBbls/d - water gathering | 18,000 | 1 | 30 | 150,000 |
Marcellus West Virginia | Harrison, Barbour and Doddridge | 80 | 875 MMcf/d | 423 MMcf/d | 131,380 | — | — | 140,000 |
Barnett Texas | Hood, Somervell, Tarrant, Johnson and Denton | 507 | 925 MMcf/d | 319 MMcf/d | 153,465 | 1 | 425 | 140,000 |
Fayetteville Arkansas | Conway, Faulkner, Van Buren, and White | 173 | 510 MMcf/d | 46 MMcf/d | 18,670 | — | — | 143,000 |
Granite Wash Texas | Roberts | 36 | 36 MMcf/d | 10 MMcf/d | 10,400 | 1 | 36 | 22,000 |
Delaware Permian(2) New Mexico/Texas | Eddy (New Mexico) Loving, Reeves, Ward, Culberson (Texas) | 189 | 165 MMcf/d | 74 MMcf/d | 33,310 (3) | 2 | 75 | 214,000 |
Powder River Basin (3) Wyoming | Converse | 211 | 140 MMcf/d | 60 MMcf/d | 50,895 | 1 | 120 | 358,000 |
(1) | Consists of 262 miles of natural gas gathering pipeline, 183 miles of crude oil gathering pipeline, and 195 miles of produced water gathering pipeline. |
(2) | Our Delaware Permian assets in New Mexico and Texas are owned by Crestwood Permian Basin Holdings LLC (Crestwood Permian), our 50% equity method investment. |
(3) | Includes 16,800 HP that is owned and operated by a third party under a compression services agreement. |
(4) | Our Powder River Basin assets are owned by Jackalope Gas Gathering Services, L.L.C. (Jackalope), our 50% equity method investment. |
We generate G&P revenues predominantly under fee-based contracts, which minimizes our commodity price exposure and provides less volatile operating performance and cash flows. Our principal G&P systems are described below.
Bakken
Our Arrow system gathers crude oil, rich gas and produced water from wells operating on the Fort Berthold Indian Reservation in the core of the Bakken Shale in McKenzie and Dunn Counties, North Dakota. Located approximately 60 miles southeast of the COLT Hub, the Arrow system connects to our COLT Hub through Hiland Partners, LP (Hiland) and Andeavor crude oil pipeline systems. The Arrow system includes approximately 640 miles of gathering lines, a 23-acre central delivery point with 266,000 Bbls of crude oil working storage capacity and multiple pipeline take-away outlets, and salt water disposal wells. We are completing construction of a 30 MMcf/d natural gas processing facility (Bear Den) and associated pipelines that began receiving gas in late 2017. Our operations are anchored by long-term gathering contracts with producers who have dedicated over 150,000 acres to the Arrow system, and our underlying contracts largely provide for fixed-fee gathering services with annual escalators for crude oil, natural gas and produced water gathering services.
Marcellus
We own and operate natural gas gathering and compression systems in Harrison, Doddridge and Barbour Counties, West Virginia. These systems consist of 80 miles of low pressure gathering lines and nine compression and dehydrations stations with 131,380 horsepower. Through these systems, we provide midstream services, primarily to Antero Resources Corporation (Antero), under long-term, fixed-fee contracts across two operating areas: our eastern area of operation (East AOD), where we are the exclusive gatherer, and our western area of operation (Western Area), where we provide compression services.
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In the East AOD, we provide gathering, dehydration and compression services, on a fixed-fee basis, to Antero on approximately 140,000 gross acres dedicated pursuant to a 20-year gathering and compression agreement. Under the gathering agreement, Antero provides for an annual minimum volume commitment of 450 MMcf/d in 2018. We gather and ultimately redeliver Antero’s production to MarkWest Energy Partners, L.P.’s Sherwood gas processing plant and various regional pipeline systems.
In the Western Area, we provide compression and dehydration services, on a fixed-fee basis, to Antero’s gathering facilities predominantly with our West Union and Victoria compressor stations, each with a maximum capacity of 120 MMcf/d. The agreement runs through 2021, subject to Antero’s right to extend the contract term for an additional three years, and provides for a minimum volume commitment of approximately 50% of the throughput capacity of each compressor station.
Barnett
We own and operate three systems in the Barnett Shale, including the Cowtown, Lake Arlington and the Alliance systems.
Our Cowtown system, which is located principally in the southern portion of the Fort Worth Basin, consists of pipelines that gather rich gas produced by customers and deliver the volumes to our plants for processing and the Cowtown plant, which includes two natural gas processing units that extract NGLs from the natural gas stream and deliver customers’ residue gas and extracted NGLs to unaffiliated pipelines for sale downstream. For the year ended December 31, 2017, our processing plant had a total average throughput of 114 MMcf/d of natural gas with an average NGL recovery of 9,541 Bbls/d. In June 2015, we diverted processing volumes from our Corvette plant to the Cowtown plant but we continue to use the compression facilities at the Corvette plant.
Our Lake Arlington system, which is located in eastern Tarrant County, Texas, consists of a dry gas gathering system and related dehydration and compression facilities. Our Alliance system, which is located in northern Tarrant and southern Denton Counties, Texas, consists of a dry gas gathering system and a related dehydration, compression and amine treating facility.
Fayetteville
We own and operate five systems in the Fayetteville Shale, including the Twin Groves, Prairie Creek, Woolly Hollow, Wilson Creek, and Rose Bud systems. Our Twin Groves, Prairie Creek, and Woolly Hollow systems (Conway and Faulkner Counties) consist of three gas gathering, compression, dehydration and treating facilities. Our Wilson Creek system (Van Buren County) consists of a gas gathering system and related dehydration and compression facilities. Our Rose Bud system (White County) consists of a gas gathering system. All of our systems gather natural gas produced by customers and deliver customers’ gas to unaffiliated pipelines for sale downstream.
Equity Investments
Delaware Permian
In October 2016, Crestwood Infrastructure Holdings LLC (Crestwood Infrastructure), our wholly-owned subsidiary, and an affiliate of First Reserve formed a joint venture, Crestwood Permian, to fund and own a natural gas gathering system (the Nautilus gathering system) and other potential investments in the Delaware Permian. As part of this transaction, we transferred to the Crestwood Permian joint venture 100% of the equity interest of Crestwood Permian Basin LLC (Crestwood Permian Basin), which owns the Nautilus gathering system. We manage the joint venture under a long-term management agreement and we account for our 50% ownership interest in Crestwood Permian under the equity method of accounting.
Crestwood Permian Basin has a long-term agreement with SWEPI LP (SWEPI), a subsidiary of Royal Dutch Shell plc, to construct, own and operate the Nautilus gathering system in SWEPI’s operated position in the Delaware Permian. SWEPI has dedicated to Crestwood Permian Basin approximately 100,000 acres and gathering rights for SWEPI’s gas production across a large acreage position in Loving, Reeves and Ward Counties, Texas. The initial build-out of the Nautilus gathering system was completed on June 6, 2017, and includes 20 receipt point meters, 60 miles of pipeline, a 24-mile high pressure header system, 10,080 horsepower of compression and a high pressure delivery point. From the date it was placed into service to December 31, 2017, the Nautilus gathering system had an average throughput of 35 MMcf/d. Crestwood Permian Basin provides gathering, dehydration, compression and liquids handling services to SWEPI under a 20-year fixed-fee gathering agreement. In October 2017, Shell Midstream Partners L.P. (Shell Midstream), a subsidiary of Royal Dutch Shell plc, purchased a 50% equity interest in Crestwood Permian Basin.
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On June 21, 2017, we contributed to Crestwood Permian 100% of the equity interest of Crestwood New Mexico Pipeline LLC
(Crestwood New Mexico), our wholly-owned subsidiary that owns our Delaware Basin assets located in Eddy County, New
Mexico. These assets consist of two dry gas gathering systems (Las Animas systems) and one rich gas gathering system and processing plant (Willow Lake system). Our Willow Lake system includes two plants with a combined capacity of 75MMcf/d processing plant, which are supported by a 10-year fixed-fee agreement with Concho Resources Inc. (Concho) and a seven year contract with Mewbourne Oil Co. (Mewbourne). We deconsolidated Crestwood New Mexico as a result of the contribution. In conjunction with this contribution, First Reserve has agreed to contribute to Crestwood Permian the first $151 million of capital cost required to fund the expansion of the Delaware Basin assets, which includes a new processing plant located in Orla, Texas and associated pipelines (Orla processing plant). See Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 6 for a further discussion of our investment in Crestwood Permian.
Powder River Basin
Our G&P segment includes our 50% equity interest in the Jackalope joint venture with Williams Partners LP (Williams), which we account for under the equity method of accounting. The joint venture, operated by Williams, owns the Jackalope gas gathering system, which serves a 358,000 gross acre dedication operated by Chesapeake Energy Corporation (Chesapeake) in Converse County, Wyoming. The Jackalope system consists of approximately 211 miles of gathering pipelines, 50,895 horsepower of compression and a 120 MMcf/d processing plant (Bucking Horse). The system connects to 100 well pads and is supported by a 10-year gathering and processing agreement with Chesapeake that includes minimum revenue guarantees for a five to seven year period. See Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 6 for a further discussion of our investment in Jackalope.
The table below summarizes certain contract information of our G&P operations (including our equity investments) as of December 31, 2017:
Shale Play | Type of Services | Type of Contracts(1) | Gross Acreage Dedication | Major Customers | Weighted Average Remaining Contract Terms (in years) |
Bakken | Gathering - crude oil, natural gas and water | Mixed | 150,000 | WPX, Bruin E&P Partners, LLC, Rimrock Energy Partners, LLC, XTO Energy, QEP Resources, Inc., Enerplus | 8 |
Marcellus | Gathering | Fixed-fee | 140,000 | Antero | 14 |
Compression | Fixed-fee | — | Antero | 2 | |
Barnett | Gathering | Mixed | 140,000 | BlueStone, Devon Energy, Tokyo Gas America Ltd. (Tokyo Gas) | 7 |
Processing | Mixed | — | BlueStone, Devon Energy, Tokyo Gas | 9 | |
Compression | Mixed | — | BlueStone, Devon Energy, Tokyo Gas | 7 | |
Fayetteville | Gathering | Fixed-fee | 143,000 | BHP Billiton Petroleum (BHP) | 7 |
Treating | Fixed-fee | — | BHP | 7 | |
Granite Wash | Gathering | Fixed-fee | 22,000 | Sabine Oil and Gas | 7 |
Processing | Mixed | — | Sabine Oil and Gas | 7 | |
Permian | Gathering | Fixed-fee | 214,000 | Mewbourne, Concho, Marathon Oil Corp, SWEPI | 7 |
Processing | Mixed | — | Mewbourne, Matador | 4 | |
Powder River Basin | Gathering | Fixed-fee | 358,000 | Chesapeake | 10 |
Processing | Fixed-fee | — | Chesapeake | 10 | |
(1) | Fixed-fee contracts represent contracts in which our customers agree to pay a flat rate based on the amount of gas delivered. Mixed contracts include percent-of-proceeds and fixed-fee arrangements. |
Storage and Transportation
Our S&T operations include our COLT Hub, one of the largest crude-by-rail terminals serving Bakken crude oil production, and our equity investments in three joint ventures that own five high-performance natural gas storage facilities with an aggregate certificated working gas storage capacity of approximately 75.8 Bcf, three natural gas pipeline systems with an aggregate firm transportation capacity of 1.5 Bcf/d, and crude oil facilities with approximately 380,000 Bbls of crude oil working storage capacity and 20,000 Bbls/d of rail loading capacity.
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COLT Hub
The COLT Hub consists of our integrated crude oil loading, storage and pipeline terminal located in the heart of the Bakken and Three Forks Shale oil-producing areas in Williams County, North Dakota. It has approximately 1.2 MMBbls of crude oil storage capacity and is capable of loading up to 160,000 Bbls/d. Customers can source crude oil for rail loading through interconnected gathering systems, a twelve-bay truck unloading rack and the COLT Connector, a 21-mile 10-inch bi-directional proprietary pipeline that connects the COLT terminal to our storage tank at Dry Fork (Beaver Lodge/Ramberg junction). The COLT Hub is connected to the Meadowlark Midstream Company, LLC and Hiland crude oil gathering systems and the Dakota Access Pipeline (DAPL) interstate pipeline system at the COLT terminal, and the Enbridge Energy Partners, L.P. and Andeavor interstate pipeline systems at Dry Fork. The gathering systems connected to the COLT Hub can deliver up to approximately 350,000 Bbls/d of crude oil to our terminal.
Equity Investments
Below is a description of the S&T assets owned by our joint ventures.
Northeast Storage Facilities. Our storage and transportation segment includes our 50% equity interest in Stagecoach Gas Services LLC (Stagecoach Gas), which we account for under the equity method of accounting. On June 3, 2016, our wholly-owned subsidiary, Crestwood Pipeline and Storage Northeast LLC (Crestwood Northeast) and Con Edison Gas Pipeline and Storage Northeast, LLC (CEGP), a wholly-owned subsidiary of Consolidated Edison, Inc. (Consolidated Edison), formed Stagecoach Gas to own and further develop our natural gas natural gas storage and transportation business located in the Northeast (the NE S&T assets). During 2016, we contributed to the joint venture the entities owning the NE S&T assets, CEGP contributed to the joint venture $975 million in exchange for a 50% equity interest in Stagecoach Gas, and Stagecoach Gas distributed to us the net cash proceeds received from CEGP. We manage the joint venture’s operations under a long-term management agreement. We deconsolidated the NE S&T assets as a result of the contribution of these assets to Stagecoach Gas as described above. See Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 6 for a further discussion of our investment in Stagecoach Gas.
The Stagecoach Gas joint venture owns and operates four natural gas storage facilities located in New York and Pennsylvania. The facilities are located near major shale plays and demand markets, have low maintenance costs and long useful lives. They have comparatively high cycling capabilities, and their interconnectivity with interstate pipelines offers significant flexibility to customers. These natural gas storage facilities, each of which generates fee-based revenues as of December 31, 2017, include:
• | Stagecoach - a FERC certificated 26.2 Bcf multi-cycle, depleted reservoir storage facility owned and operated by a subsidiary of Stagecoach Gas. A 21-mile, 30-inch diameter south pipeline lateral connects the storage facility to Tennessee Gas Pipeline Company, LLC’s (TGP) 300 Line, and a 10-mile, 20-inch diameter north pipeline lateral connects to Millennium Pipeline Company’s (Millennium) system. |
• | Thomas Corners - a FERC-certificated 7.0 Bcf multi-cycle, depleted reservoir storage facility owned and operated by a subsidiary of Stagecoach Gas. An 8-mile, 12-inch diameter pipeline lateral connects the storage facility to TGP’s 200 Line, and an 8-mile, 8-inch diameter pipeline lateral connects to Millennium. Thomas Corners is also connected to Dominion Transmission Inc.’s (Dominion) system through the Steuben facility discussed below. |
• | Seneca Lake - a FERC-certificated 1.5 Bcf multi-cycle, bedded salt storage facility owned and operated by a subsidiary of Stagecoach Gas. A 20-mile, 16-inch diameter pipeline lateral connects the storage facility to the Millennium and Dominion systems. |
• | Steuben - a FERC-certificated 6.2 Bcf single-cycle, depleted reservoir storage facility owned and operated by a subsidiary of Stagecoach Gas. A 15-mile, 12-inch diameter pipeline lateral connects the storage facility to the Dominion system, and a 6-inch diameter pipeline measuring less than one mile connects the Steuben and Thomas Corners storage facilities. |
Tres Palacios Storage Facility. Our storage and transportation segment includes our 50.01% equity interest in Tres Palacios Holdings LLC (Tres Holdings), which we account for under the equity method of accounting. Tres Palacios Gas Storage LLC (Tres Palacios), a wholly-owned subsidiary of Tres Holdings, owns a FERC-certificated 34.9 Bcf multi-cycle salt dome natural gas storage facility located in Texas. We manage the joint venture’s operations under a long-term management agreement.
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The Tres Palacios natural gas storage facility’s 63-mile, dual 24-inch diameter header system (including a 52-mile north pipeline lateral and an approximate 11-mile south pipeline lateral) interconnects with 11 pipeline systems and can receive residue gas from the tailgate of Kinder Morgan Inc.’s (Kinder Morgan) Houston Central processing plant. The certificated maximum injection rate of the Tres Palacios storage facility is 1,000 MMcf/d and the certificated maximum withdrawal rate is 2,500 MMcf/d. See Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 6 for a further discussion of our ownership interest in Tres Palacios.
The following provides additional information about the natural gas storage facilities of our S&T equity investments as of December 31, 2017:
Storage Facility / Location | Certificated Working Gas Storage Capacity (Bcf) | Certificated Maximum Injection Rate (MMcf/d) | Certificated Maximum Withdrawal Rate (MMcf/d) | Pipeline Connections | ||||||
Stagecoach Tioga County, NY; Bradford County, PA | 26.2 | 250 | 500 | TGP’s 300 Line; Millennium; UGI’s Sunbury Pipeline,(1) Transco’s Leidy Line(1) | ||||||
Thomas Corners Steuben County, NY | 7.0 | 70 | 140 | TGP’s 200 Line; Millennium; Dominion | ||||||
Seneca Lake Schuyler County, NY | 1.5 | (2) | 73 | 145 | Dominion; Millennium | |||||
Steuben Steuben County, NY | 6.2 | 30 | 60 | TGP’s 200 Line; Millennium; Dominion | ||||||
Northeast Storage Total | 40.9 | 423 | 845 | |||||||
Tres Palacios | 34.9 | 1,000 | 2,500 | Multiple(3) | ||||||
Total | 75.8 | 1,423 | 3,345 | |||||||
(1) | Stagecoach is connected to UGI Energy Services, LLC’s (UGI) Sunbury Pipeline and Transcontinental Gas Pipe Line Corporation’s (Transco) Leidy Line through the MARC I Pipeline. |
(2) | Stagecoach Gas has been authorized by the FERC to expand the facility’s working gas storage capacity to 2 Bcf. |
(3) | Tres Palacios is interconnected to Florida Gas Transmission Company, LLC, Kinder Morgan Tejas Pipeline, L.P., Houston Pipe Line Company LP, Central Texas Gathering System, Natural Gas Pipeline Company of America, Transco, TGP, Gulf South Pipeline, Valero Natural Gas Pipeline Company, Channel Pipeline Company, and Texas Eastern Transmission, L.P. |
Transportation Facilities. Stagecoach Gas owns three natural gas pipeline systems located in New York and Pennsylvania. These natural gas transportation facilities include:
• | North-South Facilities - include compression and appurtenant facilities installed to expand transportation capacity on the Stagecoach north and south pipeline laterals. The bi-directional interstate facilities provide more than 538 MMcf/d of firm interstate transportation capacity to shippers. The North-South Facilities generate fee-based revenues under a negotiated rate structure authorized by the FERC. |
• | MARC I Pipeline - a 39-mile, 30-inch diameter interstate natural gas pipeline that connects the North-South Facilities and TGP’s 300 Line in Bradford County, Pennsylvania, with UGI’s Sunbury Pipeline and Transco’s Leidy Line, both in Lycoming County, Pennsylvania. The bi-directional pipeline provides more than 925 MMcf/d of firm interstate transportation capacity to shippers. The MARC I Pipeline generates fee-based revenues under a negotiated rate structure authorized by the FERC. |
• | East Pipeline - a 37.5 mile, 12-inch diameter intrastate natural gas pipeline located in New York, which transports 30 MMcf/d of natural gas from Dominion to the Binghamton, New York city gate. The pipeline runs within three miles of the North-South Facilities’ point of interconnection with Millennium. The East Pipeline generates fee-based revenues under a negotiated rate structure authorized by the NYPSC. |
Rail Loading Facility. Crestwood Crude Logistics LLC, our wholly-owned subsidiary, has a 50.01% equity interest in Powder River Basin Industrial Complex, LLC (PRBIC), which owns an integrated crude oil loading, storage and pipeline terminal located in Douglas County, Wyoming. PRBIC provides a market for crude oil production from the Powder River Basin. The joint venture, which is operated by our joint venture partner, Twin Eagle Resource Management, LLC (Twin Eagle), sources crude oil production from Chesapeake and other Powder River Basin producers. PRBIC includes 20,000 Bbls/d of rail loading capacity and 380,000 Bbls of crude oil working storage capacity. PRBIC expanded its pipeline terminal to include connections to Kinder Morgan’s Double H Pipeline system in July 2015 and Plains All American Pipeline’s Rocky Mountain Pipeline system in March 2016. See Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 6 for a further discussion of our investment in PRBIC.
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The table below summarizes certain contract information associated with the COLT Hub and the assets of our S&T equity investments as of December 31, 2017:
Facility | Type of Services | Type of Contracts(1)(2) | Contract Volumes | Major Customers | Weighted Average Remaining Contract Terms (in years) |
COLT | Rail Loading and Transportation | Mixed | 31 MBbl/d | U.S. Oil, Flint Hills Resources, Sunoco Logistics | 2 |
NE S&T Joint Venture: | |||||
North-South Facilities | Transportation | Firm | 538 MMcf/d | Southwestern Energy, Consolidated Edison, Anadarko Energy Services Company (Anadarko) | 2 |
MARC I Pipeline | Transportation | Firm | 925 MMcf/d | Chesapeake, Anadarko, Chief Oil and Gas | 3 |
East Pipeline | Transportation | Firm | 30 MMcf/d | NY State Electric & Gas Corp | 3 |
Stagecoach | Storage | Firm | 26.3 Bcf | Consolidated Edison, Merrill Lynch Commodities Inc (Merrill Lynch), New Jersey Natural Gas, Repsol Energy North America Corporation (Repsol), Sequent Energy Management | 2 |
Thomas Corners | Storage | Firm | 13.0 Bcf | Repsol, Tenaska Gas Storage, LLC | 1 |
Seneca Lake | Storage | Firm | 1.5 Bcf | Dominion, NY State Electric & Gas Corp, DTE Energy Trading | 2 |
Steuben | Storage | Firm | 9.3 Bcf | PSEG Energy Resources & Trade LLC, Repsol, Pivotal Utility Holdings | 1 |
Tres Palacios Joint Venture | Storage | Firm | 28.5 Bcf | Brookfield Infrastructure Group, Anadarko, Exelon, Merrill Lynch, NJR Energy, Repsol | 1 |
PRBIC Joint Venture | Rail Loading | Fixed-fee | 10 MBbl/d | Chesapeake | 1 |
(1) | Firm contracts represent take-or-pay contracts whereby our customers agree to pay for a specified amount of storage or transportation capacity, whether or not the capacity is utilized. Fixed-fee contracts represent contracts in which our customers agree to pay a flat rate based on the amount of commodity delivered. |
(2) | Mixed contracts include both firm and fixed-fee arrangements. |
Marketing, Supply and Logistics
Our MS&L segment includes our supply and logistics business, our storage and terminals business, our West Coast operations and our crude oil, NGL and produced water trucking operations.
Supply and Logistics. Our Supply and Logistics operations are supported by (i) our fleet of rail and rolling stock with 75,000 Bbls/d of NGL transportation capacity, which also includes our rail-to-truck terminals located in Florida, New Jersey, New York, Rhode Island and North Carolina; and (ii) NGL pipeline and storage capacity leased from third parties, including more than 500,000 Bbls of NGL working storage capacity at major hubs in Mt. Belvieu, Texas and Conway, Kansas.
Storage and Terminals. Our NGL Storage and Terminals operations include our Seymour and Bath storage facilities. The Seymour storage facility is located in Seymour, Indiana, and has 500,000 Bbls of underground NGL storage capacity and 29,000 Bbls of aboveground “bullet” storage capacity. The Seymour facility’s receipts and deliveries are supported by Enterprise’s TEPPCO pipeline, allowing pipeline and truck access. The Bath storage facility is located in Bath, New York and has approximately 2.0 MMBbls of underground NGL storage capacity and is supported by rail and truck terminal facilities capable of loading and unloading 23 rail cars per day and approximately 100 truck transports per day.
West Coast. Our West Coast NGL operations provide processing, fractionation, storage, transportation and marketing services to producers, refiners and other customers. Our facilities located near Bakersfield, California include 24 million gallons of aboveground NGL storage capacity, 25 MMcf/d of natural gas processing capacity, 12,000 Bbls/d of NGL fractionation capacity, 8,000 Bbls/d of butane isomerization capacity, and NGL rail and truck receipt and take-away options. We separate NGLs from natural gas, deliver to local natural gas pipelines, retain NGLs for further processing at our fractionation facility, provide butane isomerization and refrigerated storage services, as well as provide to Western US refineries for motor fuel production. Our isomerization facility chemically changes normal butane to isobutane, which we provide to refineries for motor fuel production. Our operations also consist of wholesale propane assets, primarily including three rail-to-truck terminals located in Hazen, Nevada, Carlin, Nevada, and Shoshoni, Wyoming and a truck terminal located in Salt Lake City, Utah. These terminals are used to provide supply, transportation and storage services to wholesale customers in the western and north central regions of the United States.
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Trucking. Our Trucking operations consist of a fleet of owned and leased trucks with 20,000 Bbls/d of crude oil and produced water transportation capacity and 120,000 Bbls/d of NGL transportation capacity. We provide hauling services to customers in North Dakota, Montana, Wyoming, Texas, New Mexico, Indiana, Mississippi, New Jersey, Ohio, Utah and California.
Customers
For the years ended December 31, 2017, 2016 and 2015, no customer accounted for more than 10% of our total consolidated revenues.
Industry Background
The midstream sector of the energy industry provides the link between exploration and production and the delivery of crude oil, natural gas and their components to end-use markets. The midstream sector consists generally of gathering, processing, storage, and transportation activities. We, through our consolidated operations and our equity investments, gather crude oil and natural gas; process natural gas; fractionate NGLs; store crude oil, NGLs and natural gas; and transport crude oil, NGLs and natural gas.
The diagram below depicts the main segments of the midstream sector value chain:
Crude Oil
Pipelines typically provide the most cost-effective option for shipping crude oil. Crude oil gathering systems normally comprise a network of small-diameter pipelines connected directly to the well head that transport crude oil to central receipt points or interconnecting pipelines through larger diameter trunk lines. Common carrier pipelines frequently transport crude oil from central delivery points to logistics hubs or refineries under tariffs regulated by the FERC or state authorities. Logistic hubs provide storage and connections to other pipeline systems and modes of transportation, such as railroads and trucks. Pipelines not engaged in the interstate transportation of crude may also be proprietary or leased entirely to a single customer.
Trucking complements pipeline gathering systems by gathering crude oil from operators at remote wellhead locations not served by pipeline gathering systems. Trucking is generally limited to low volume, short haul movements because trucking costs escalate sharply with distance, making trucking the most expensive mode of crude oil transportation. Railroads provide additional transportation capabilities for shipping crude oil between gathering storage systems, pipelines, terminals and storage centers and end-users.
Natural Gas
Midstream companies within the natural gas industry create value at various stages along the value chain by gathering natural gas from producers at the wellhead, processing and separating the hydrocarbons from impurities and into lean gas (primarily methane) and NGLs, and then routing the separated lean gas and NGL streams for delivery to end-markets or to the next stage of the value chain.
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A significant portion of natural gas produced at the wellhead contains NGLs. Natural gas produced in association with crude oil typically contains higher concentrations of NGLs than natural gas produced from gas wells. This rich natural gas is generally not acceptable for transportation in the nation’s transmission pipeline system or for residential or commercial use. Processing plants extract the NGLs, leaving residual lean gas that meets transmission pipeline quality specifications for ultimate consumption. Processing plants also produce marketable NGLs, which, on an energy equivalent basis, typically have a greater economic value as a raw material for petrochemicals and motor gasolines than as a component of the natural gas stream.
Gathering. At the earliest stage of the midstream value chain, a network of typically small diameter pipelines known as gathering systems directly connect to wellheads or pad sites in the production area. Gathering systems transport gas from the wellhead to downstream pipelines or a central location for treating and processing. Gathering systems are often designed to be highly flexible to allow gathering of natural gas at different pressures and scalable to allow for additional production and well connections without significant incremental capital expenditures. A byproduct of the gathering process is the recovery of condensate liquids, which are sold on the open market.
Compression. Gathering systems are operated at pressures intended to enable the maximum amount of production to be gathered from connected wells. Through a mechanical process known as compression, volumes of natural gas at a given pressure are compressed to a sufficiently higher pressure, thereby allowing those volumes to be delivered into a higher pressure downstream pipeline to be shipped to market. Because wells produce at progressively lower field pressures as they age, it becomes necessary to add additional compression over time to maintain throughput across the gathering system.
Treating and Dehydration. Treating and dehydration involves the removal of impurities such as water, carbon dioxide, nitrogen and hydrogen sulfide that may be present when natural gas is produced at the wellhead. Impurities must be removed for the natural gas to meet the quality specifications for pipeline transportation, and end users normally cannot consume (and will not purchase) natural gas with a high level of impurities. Therefore, to meet downstream pipeline and end user natural gas quality standards, the natural gas is dehydrated to remove water and is chemically treated to separate the impurities from the natural gas stream.
Processing. Once impurities are removed, pipeline-quality residue gas is separated from NGLs. Most rich natural gas is not suitable for long-haul pipeline transportation or commercial use and must be processed to remove the heavier hydrocarbon components. The removal and separation of hydrocarbons during processing is possible because of the differences in physical properties between the components of the raw gas stream. There are four basic types of natural gas processing methods: cryogenic expansion, lean oil absorption, straight refrigeration and dry bed absorption. Cryogenic expansion represents the latest generation of processing, incorporating extremely low temperatures and high pressures to provide the best processing and most economical extraction.
Natural gas is processed not only to remove heavier hydrocarbon components that would interfere with pipeline transportation or the end use of the natural gas, but also to separate from the natural gas those hydrocarbon liquids that could have a higher value as NGLs than as natural gas. The principal component of residue gas is methane, although some lesser amount of entrained ethane typically remains. In some cases, processors have the option to leave ethane in the gas stream or to recover ethane from the gas stream, depending on ethane’s value relative to natural gas. The processor’s ability to “reject” ethane varies depending on the downstream pipeline’s quality specifications. The residue gas is sold to industrial, commercial and residential customers and electric utilities.
Fractionation. Once NGLs have been removed from the natural gas stream, they can be broken down into their base components to be useful to commercial customers. Mixed NGL streams can be further separated into purity NGL products, including ethane, propane, normal butane, isobutane, and natural gasoline. Fractionation works based on the different boiling points of the different hydrocarbons in the NGL stream, and essentially occurs in stages consisting of the boiling off of hydrocarbons one by one. The entire fractionation process is broken down into steps, starting with the removal of the lighter NGLs from the stream. In general, fractionators are used in the following order: (i) deethanizer, which separates ethane from the NGL stream, (ii) depropanizer, which separates propane, (iii) debutanizer, which boils off the butanes and leaves the pentanes and heavier hydrocarbons in the NGL stream, and (iv) butane splitter (or deisobutanizer), which separates isobutanes and normal butanes.
Transportation and Storage. Once raw natural gas has been treated or processed and the raw NGL mix fractionated into individual NGL components, the natural gas and NGL components are stored, transported and marketed to end-use markets. The natural gas pipeline grid in the United States transports natural gas from producing regions to customers, such as LDCs, industrial users and electric generation facilities.
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Historically, the concentration of natural gas production in a few regions of the United States generally required transportation pipelines to transport gas not only within a state but also across state borders to meet national demand. However, a recent shift in supply sources, from conventional to unconventional, has affected the supply patterns, the flows and the rates that can be charged on pipeline systems. The impacts vary among pipelines according to the location and the number of competitors attached to these new supply sources. These changing market dynamics are prompting midstream companies to evaluate the construction of short-haul pipelines as a means of providing demand markets with cost-effective access to newly-developed production regions, as compared to relying on higher-cost, long-haul pipelines that were originally designed to transport natural gas greater distances across the country.
Natural gas storage plays a vital role in maintaining the reliability of gas available for deliveries. Natural gas is typically stored in underground storage facilities, including salt dome caverns, bedded salt caverns and depleted reservoirs. Storage facilities are most often utilized by pipeline companies to manage temporary imbalances in operations; natural gas end-users, such as LDCs, to manage the seasonality and variability of demand and to satisfy future natural gas needs; and, independent natural gas marketing and trading companies in connection with the execution of their trading strategies.
Competition
Our G&P operations compete for customers based on reputation, operating reliability and flexibility, price, creditworthiness, and service offerings, including interconnectivity to producer-desired takeaway options (i.e., processing facilities and pipelines). We face strong competition in acquiring new supplies in the production basins in which we operate, and competition customarily is impacted by the level of drilling activity in a particular geographic region and fluctuations in commodity prices. Our primary competitors include other midstream companies with G&P operations and producer-owned systems, and certain competitors enjoy first-mover advantages over us and may offer producers greater gathering and processing efficiencies, lower operating costs and more flexible commercial terms.
Our NGL supply and logistics business competes primarily with integrated major oil companies, refiners and processors, and other energy companies that own or control transportation and storage assets that can be optimized for supply, marketing and logistics services.
Natural gas storage and pipeline operators compete for customers primarily based on geographic location, which determines connectivity and proximity to supply sources and end-users, as well as price, operating reliability and flexibility, available capacity and service offerings. Our primary competitors in our natural gas storage market include other independent storage providers and major natural gas pipelines with storage capabilities embedded within their transmission systems. Our primary competitors in the natural gas transportation market include major natural gas pipelines and intrastate pipelines that can transport natural gas volumes between interstate systems. Long-haul pipelines often enjoy cost advantages over new pipeline projects with respect to options for delivering greater volumes to existing demand centers, and new projects and expansions proposed from time to time may serve the markets we serve and effectively displace the service we provide to customers.
Our crude oil rail terminals primarily compete with crude oil pipelines and other midstream companies that own and operate rail terminals in the markets we serve. The crude oil logistics business is characterized by strong competition for supplies, and competition is based largely on customer service quality, pricing, and geographic proximity to customers and other market hubs.
Regulation
Our operations and investments are subject to extensive regulation by federal, state and local authorities. The regulatory burden on our operations increases our cost of doing business and, in turn, impacts our profitability. In general, midstream companies have experienced increased regulatory oversight over the past few years. We cannot predict the extent to which this trend will continue in the foreseeable future or in the long term.
Pipeline and Underground Storage Safety
We are subject to pipeline safety regulations imposed by the U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA). PHMSA regulates safety requirements in the design, construction, operation and maintenance of jurisdictional natural gas and hazardous liquid pipeline and storage facilities. All of our natural gas pipelines used in gathering, storage and transportation activities are subject to regulation by PHMSA under the Natural Gas Pipeline Safety Act of 1968, as amended (NGPSA), and all of our NGL and crude oil pipelines used in gathering, storage and
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transportation activities are subject to regulation by PHMSA as hazardous liquids pipelines under the Hazardous Liquid Pipeline Safety Act of 1979, as amended (HLPSA).
These federal statutes and PHMSA implementing regulations collectively impose numerous safety requirements on pipeline operators, such as the development of a written qualification program for individuals performing covered tasks on pipeline facilities and the implementation of pipeline integrity management programs. For example, pursuant to the authority under the NGPSA and HLPSA, PHMSA has promulgated regulations requiring pipeline operators to develop and implement integrity management programs for certain gas and hazardous liquid pipelines. The integrity management programs govern pipeline operators’ actions in high-consequence areas, such as areas of high population and areas unusually sensitive to environmental damage. Specifically, integrity management programs require more frequent inspections and other preventative measures to ensure pipeline safety in high consequence areas.
We plan to continue testing under our pipeline integrity management programs to assess and maintain the integrity of our pipelines in accordance with PHMSA regulations. Notwithstanding our preventive and investigatory maintenance efforts, we may incur significant expenses if anomalous pipeline conditions are discovered or due to the implementation of more stringent pipeline safety standards resulting from new or amended legislation. For example, the NGPSA and HLPSA were amended by the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (2011 Pipeline Safety Act), which requires increased safety measures for gas and hazardous liquids transportation pipelines. Among other things, the 2011 Pipeline Safety Act increased the penalties for safety violations, established additional safety requirements for newly constructed pipelines and required studies of safety issues that could result in the adoption of new regulatory requirements by PHMSA for existing pipelines. More recently, in June 2016, the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (2016 Pipeline Safety Act) was passed, extending PHMSA’s statutory mandate through 2019 and, among other things, requiring PHMSA to complete certain of its outstanding mandates under the 2011 Pipeline Safety Act and developing new safety standards for natural gas storage facilities by June 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. PHMSA issued interim regulations in October 2016, to implement the agency's expanded authority to address unsafe pipeline conditions or practices that pose an imminent hazard to life, property, or the environment. The safety enhancement requirements and other provisions of the 2011 Pipeline Safety Act and the 2016 Pipeline Safety Act, as well as any implementation of PHMSA regulations thereunder, or any issuance or reinterpretation of guidance by PHMSA or any state agencies with respect thereto, could require us to install new or modified safety controls, pursue additional capital projects or conduct maintenance programs on an accelerated basis, any or all of which tasks could result in our incurring increased operating costs that could have a material adverse effect on our results of operations or financial position.
Furthermore, PHMSA is considering changes to its natural gas pipeline regulations to, among other things: (i) expand the scope of high consequence areas; (ii) strengthen integrity management requirements applicable to existing operators; (iii) strengthen or expand non-integrity pipeline management standards relating to such matters as valve spacing, automatic or remotely-controlled valves, corrosion protection, and gathering lines; and (iv) add new regulations to govern underground facilities that are not currently subject to federal regulation. See “We may incur higher costs as a result of pipeline integrity management program testing and additional safety legislation,” under Item 1A. Risk Factors for further discussion on PHMSA rulemaking. We cannot predict the final outcome of these legislative or regulatory efforts or the precise impact that compliance with any resulting new safety requirements may have on our business and investments.
Future environmental regulatory developments, such as more strict environmental laws or regulations, or more stringent enforcement of the existing regulatory requirements could also directly affect our operations and investments. For example, in June 2016, the EPA published a final rule establishing new emissions standards for methane and additional standards for volatile organic compounds from certain new, modified, and reconstructed equipment and processes in the oil and natural gas source category, including production, processing, transmission and storage facilities. These standards will require the use of certain specific emissions control practices, thereby requiring additional controls for pneumatic controllers and pumps, as well as compressors, and imposing leak detection and repair requirements for natural gas compressor and booster stations. However, in June 2017, the EPA published a proposed rule to stay certain portions of these 2016 standards for two years and reconsider the entirety of the 2016 standards but has not yet published a final rule and, as a result, the 2016 standards are currently in effect.
States are also expected to implement their own rules, which could be more stringent than federal requirements. In matters that could have an indirect adverse effect on our business by decreasing demand for the services that we offer, the EPA has completed a study of potential adverse impacts that certain drilling methods (including hydraulic fracturing) may have on water quality and public health, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain circumstances. Congress has also considered but not adopted, and several states have
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proposed or enacted, legislation or regulations imposing more stringent or costly requirements for exploration and production companies to develop and produce hydrocarbons.
States are largely preempted by federal law from regulating pipeline safety for interstate pipelines, but most states are certified by the Department of Transportation 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 pipelines, states vary considerably in their authority and capacity to address pipeline safety. Our pipelines have operations and maintenance plans designed to keep the facilities in compliance with pipeline safety requirements, and we do not anticipate any significant difficulty in complying with applicable state laws and regulations.
Natural Gas Gathering
Natural gas gathering facilities are exempt from FERC jurisdiction under Section 1(b) of the Natural Gas Act. Although the FERC has not made formal determinations with respect to all of our facilities we consider to be gathering facilities, we believe that our natural gas pipelines meet the traditional tests that the FERC has used to determine whether a pipeline is a gathering pipeline, and not subject to FERC jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services, however, has been the subject of substantial litigation. The FERC determines whether facilities are gathering facilities on a case-by-case basis, so the classification and regulation of our gathering facilities is subject to change based on future determinations by the FERC, the courts or Congress. If the FERC were to consider the status of an individual facility and determine that the facility and/or services provided are not exempt from FERC regulation under the Natural Gas Act and the facility provides interstate service, the rates for, and terms and conditions of, the services provided by such facility would be subject to FERC. Such regulation could decrease revenue, increase operating costs, and, depending upon the facility in question, 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 Natural Gas Act or the Natural Gas Policy Act, 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 rate established by the FERC.
States may regulate gathering pipelines. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, requirements prohibiting undue discrimination, and complaint-based rate regulation. Our natural gas gathering operations may be subject to ratable take and common purchaser statutes in the states in which we operate. 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, and generally require our gathering pipelines to take natural gas without undue discrimination as to source of supply or producer. These statutes have the effect of restricting our right as an owner of gathering facilities to decide with whom we contract to purchase or transport natural gas.
The states in which we operate gathering systems have adopted a form of complaint-based regulation, 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. To date, these regulations have not had an adverse effect on our systems. We cannot predict whether such a complaint will be filed against us in the future, however, a failure to comply with state regulations can result in the imposition of administrative, civil and criminal remedies.
In Texas, we have filed with the Texas Railroad Commission (TRRC) to establish rates and terms of service for certain of our pipelines. Our assets in Texas include intrastate common carrier NGL pipelines subject to the regulation of the TRRC, which requires that our NGL pipelines file tariff publications containing all the rules and the regulations governing the rates and charges for services we perform. NGL pipeline rates may be limited to provide no more than a fair return on the aggregate value of the pipeline property used to render services.
NGL Storage
Our NGL storage terminals are subject primarily to state and local regulation. For example, the Indiana Department of Natural Resources (INDNR) and the New York State Department of Environmental Conservation (NYSDEC) have jurisdiction over the underground storage of NGLs and NGL related well drilling, well conversions and well plugging in Indiana and New York, respectively. Thus, the INDNR regulates aspects of our Seymour facility, and the NYSDEC regulates aspects of the Bath facility, as well as our proposed storage facility near Watkins Glen.
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We filed an application with the NYSDEC in October 2009, for an underground storage permit for our Watkins Glen NGL storage development project. The agency issued a Positive Declaration for the project in November 2010, and determined in August 2011 that the Draft Supplemental Environmental Impact Statement we submitted for the project was complete. In 2012, we modified our brine pond designs in response to local concerns and submitted to the NYSDEC final drawings and plans for our revised project design. The NYSDEC published a draft storage permit in October 2014, and held an issues conference in February 2015, to determine if any significant issues remained that would require an adjudicatory hearing. In September 2016, we further modified our project design (i.e., reduced storage capacity, eliminated truck and rail transportation options, and eliminated brine pond capacity) in response to local concerns and perceptions. In September 2017, the Chief Administrative Law Judge ruled that the opponents of the project failed to raise any issues requiring adjudication. This ruling has been appealed to the NYSDEC Commissioner. As part of the US Salt divestiture, we retained all surface and sub-surface rights necessary to place the Watkins Glen NGL storage development project into service once we receive all required regulatory approvals. We cannot predict with certainty if and when the permitting process will be concluded.
Crude Oil Transportation
The transportation of crude oil by common carrier pipelines on an interstate basis is subject to regulation by the FERC under the Interstate Commerce Act (ICA), the Energy Policy Act of 1992, and the rules and regulations promulgated under those laws. FERC regulations require interstate common carrier petroleum pipelines to file with the FERC and publicly post tariffs stating their interstate transportation rates and terms and conditions of service. The ICA and FERC regulations also require that such rates be just and reasonable, and to be applied in a non-discriminatory manner so as to not confer undue preference upon any shipper. The transportation of crude oil by common carrier pipelines on an intrastate basis is subject to regulation by state regulatory commissions. The basis for intrastate crude oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate crude oil pipeline rates, varies from state to state. Intrastate common carriers must also offer service to all shippers requesting service on the same terms and under the same rates. Our crude oil pipelines in North Dakota are not common carrier pipelines and, therefore, are not subject to rate regulation by the FERC or any state regulatory commission. We cannot, however, provide assurance that the FERC will not, at some point, either at the request of other entities or on its own initiative, assert that some or all of our crude oil pipelines are subject to FERC requirements for common carrier pipelines, or are otherwise not exempt from the FERC’s filing or reporting requirements, or that such an assertion would not adversely affect our results of operations. In the event the FERC were to determine that these crude oil pipelines are subject to FERC requirements for common carrier pipelines, or otherwise would not qualify for a waiver from the FERC’s applicable regulatory requirements, we would likely be required to (i) file a tariff with the FERC; (ii) provide a cost justification for the transportation charge; (iii) provide service to all potential shippers without undue discrimination; and (iv) potentially be subject to fines, penalties or other sanctions.
Certain of our crude oil operations located in North Dakota are subject to state regulation by the North Dakota Industrial Commission (NDIC). For example, gas conditioning requirements established by the NDIC recently will require operators of crude by rail terminals to report to the NDIC any crude volumes received for loading that exceed federal vapor pressure limits. State legislation has been proposed that, if passed, would authorize and require the NDIC to promulgate regulations under which produced water pipelines would be required to, among other things, install leak detection facilities and post bonds to cover potential remediation costs associated with releases. Moreover, the regulation of our customers’ production activities by the NDIC impacts our operations. For example, during 2016, the NDIC approved additional requirements relating to site construction, underground gathering pipelines and spill containment that became effective on October 1, 2016, while other requirements relating to bonding for underground gathering pipelines, and construction of berms around facilities became effective on January 1, 2017. Additionally, on July 1, 2014, the NDIC issued an order pursuant to which the agency adopted legally enforceable “gas capture percentage goals” targeting the capture of certain percentages of natural gas produced in the state by specified dates, and subsequently modified that order in late 2015. Exploration and production operators in the state may be required to install new equipment to satisfy these goals, and any failure by operators to meet these gas capture percentage goals would subject those operators to production restrictions, which could reduce the amount of commodities we gather on the Arrow system from our customers, and have a corresponding adverse impact on our business and results of operations.
Portions of our Arrow gathering system, which is located on the Fort Berthold Indian Reservation, may be subject to applicable regulation by the Mandan, Hidatsa & Arikara Nation (MHA Nation). An entirely separate and distinct set of laws and regulations may apply to operators and other parties within the boundaries of the Fort Berthold Indian Reservation. Various federal agencies within the U.S. Department of the Interior, particularly the Bureau of Indian Affairs, the Office of Natural Resources Revenue and the Bureau of Land Management (BLM) promulgate and enforce regulations pertaining to oil and gas operations on Native American lands. These regulations include lease provisions, environmental standards, tribal employment preferences and numerous other matters.
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Native American tribes are subject to various federal statutes and oversight by the Bureau of Indian Affairs and BLM. However, Native American tribes possess certain inherent authorities to enact and enforce their own internal laws and regulations as long as such laws and regulations do not supersede or conflict with such federal statutes. These tribal laws and regulations may include various fees, taxes, and requirements to extend preference in employment to tribal members or Indian owned businesses. Further, lessees and operators within a Native American reservation may be subject to the pertinent Native American judiciary system, or barred from litigating matters adverse to the pertinent tribe unless there is a specific waiver of the tribe’s sovereign immunity. Therefore, we may be subject to various applicable laws and regulations pertaining to Native American oil and gas leases, fees, taxes and other burdens, obligations and issues unique to oil and gas operations within Native American reservations. One or more of these applicable regulatory requirements, or delays in obtaining necessary approvals or permits necessary to operate on tribal lands, may increase our costs of doing business on Native American tribal lands and have an impact on the economic viability of any well or project with a Native American reservation. Additionally, we cannot guarantee that we will always be able to renew existing rights-of-way or obtain new rights-of-way in Native American lands without experiencing significant costs. For example, following a recent decision issued in May 2017 by the Federal Tenth Circuit Court of Appeals that relied, in part, on a previous Federal Eighth Circuit Court of Appeals decision, tribal ownership of even a very small fractional interest in an allotted land, that is, tribal land owned or at one time owned by an individual Native American landowner, bars condemnation of any interest in the allotment. Consequently, the inability to condemn such allotted lands under circumstances where an existing pipeline rights-of-way may soon lapse or terminate serves as an additional impediment for pipeline operators.
In recent years, PHMSA and other federal agencies have reviewed the adequacy of transporting Bakken crude oil by rail transport and, as necessary have pursued rules to better assure the safe transport of Bakken crude oil by rail. For example, in May 2015, PHMSA adopted a final rule that includes, among other things, providing new sampling and testing requirements to improve classification of Bakken crude oil transported. Additional proposed and final rules issued by PHMSA in July 2016 and August 2016, respectively, mandate a phase-out schedule for all DOT-111 tank cars used to transport Class 3 flammable liquids, including crude oil and ethanol, between 2018 and 2029, and may expand the applicability of comprehensive oil spill response plans so that any railroad transporting a single train carrying 20 or more loaded tanks of liquid petroleum oil in a continuous block or a single train carrying 35 or more loaded tank cars of liquid petroleum oil throughout the train will have to have a current, comprehensive, written plan. We, as the owner of a Bakken crude loading terminal, may be adversely affected to the extent more stringent rail transport rules result in more significant operating costs in the shipment of Bakken crude oil by rail or as a result of delays or limitations of such shipments.
Natural Gas Storage and Transportation
Our equity investments’ natural gas pipelines used in gathering, storage and transportation activities are subject to regulation under NGPSA, and all of our equity investments’ crude oil pipelines used in gathering, storage and transportation activities are subject to regulation under HLPSA. On December 14, 2016, PHMSA issued final interim rules that impose new safety related requirements on downhole facilities (including wells, wellbore tubing and casing) of new and existing underground natural gas storage facilities. The final interim rules adopt and make mandatory two American Petroleum Institute Recommend Practices that, among other things, address construction, maintenance, risk-management and integrity-management procedures. PHMSA indicated when it issued the interim final rule that the adoption of these safety standards for natural gas storage facilities represent a first step in a multi-phase process to enhance the safety of underground natural gas storage, with more standards likely forthcoming. Most recently, in response to a petition for reconsideration of the interim final rule received in January 2017, PHMSA published a notice in June 2017, advising that the agency intends to consider the issues raised by the petitioners in a final rule, which it currently expects to issue in 2018. At this time, we cannot predict the impact of any future regulatory actions in this area. To the extent we operate or manage natural gas storage facilities owned by our equity investments, we are evaluating the final interim rules and their potential impact on our equity investments. PHMSA’s interim final rules could significantly increase the costs of operating and maintaining natural gas storage facilities.
The interstate natural gas storage and transportation operations of our equity investments are subject to regulation by the FERC under the Natural Gas Act. Subsidiaries of our Stagecoach Gas and Tres Holdings joint ventures are regulated by the FERC as natural gas companies. Under the Natural Gas Act, the FERC has authority to regulate gas transportation services in interstate commerce, which includes natural gas storage services. The FERC exercises jurisdiction over (i) rates charged for services and the terms and conditions of service; (ii) the certification and construction of new facilities; (iii) the extension or abandonment of services and facilities; (iv) the maintenance of accounts and records; (v) the acquisition and disposition of facilities; (vi) standards of conduct between affiliated entities; and (vii) various other matters. Regulated natural gas companies are prohibited from charging rates determined by the FERC to be unjust, unreasonable, or unduly discriminatory, and both the existing tariff rates and the proposed rates of regulated natural gas companies are subject to challenge.
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The rates and terms and conditions of our natural gas storage and transportation equity investments are found in the FERC-approved tariffs of (i) Stagecoach Pipeline & Storage Company LLC (Stagecoach Pipeline), a wholly-owned subsidiary of Stagecoach Gas that owns the Stagecoach natural gas storage facility, the North-South Facilities and the MARC I Pipeline, (ii) Arlington Storage Company, LLC (Arlington Storage), a wholly-owned subsidiary of Stagecoach Gas that owns the Thomas Corners, Seneca Lake and Steuben natural gas storage facilities, and (iii) Tres Palacios, a wholly-owned subsidiary of Tres Holdings that owns the Tres Palacios natural gas storage facility. Stagecoach Pipeline, Arlington Storage and Tres Palacios are authorized to charge and collect market-based rates for storage services, and Stagecoach Pipeline is authorized to charge and collect negotiated rates for transportation services. Market-based and negotiated rate authority allows our equity investments to negotiate rates with individual customers based on market demand. A loss of market-based or negotiated rate authority or any successful complaint or protest against the rates charged or provided by our equity investments could have an adverse impact on our results of operations.
In addition, the Energy Policy Act of 2005 amended the Natural Gas Act to (i) prohibit market manipulation by any entity; (ii) direct the FERC to facilitate market transparency in the market for sale or transportation of physical natural gas in interstate commerce; and (iii) significantly increase the penalties for violations of the Natural Gas Act, the Natural Gas Policy Act of 1978, and FERC rules, regulations or orders thereunder. As a result of the Energy Policy Act of 2005, the FERC has the authority to impose civil penalties for violations of these statutes and FERC rules, regulations and orders, up to approximately $1.2 million per day per violation.
The interstate natural gas storage operations of our equity investments are also subject to non-rate regulation by various state agencies. For example, the NYSDEC has jurisdiction over well drilling, conversion and plugging in New York. The NYSDEC, therefore, regulates aspects of the Stagecoach, Thomas Corners, Seneca Lake and Steuben natural gas storage facilities.
Supply and Logistics
The transportation of crude oil, water and NGLs by truck is subject to regulations promulgated under the Federal Motor Carrier Safety Act. These regulations, which are administered by the United States Department of Transportation, cover the transportation of hazardous materials.
Environmental and Occupational Safety and Health Matters
Our operations and investments are subject to stringent federal, state, regional and local laws and regulations governing the discharge and emission of pollutants into the environment, environmental protection, or occupational health and safety. These laws and regulations may impose significant obligations on our operations, including (i) the need to obtain permits to conduct regulated activities; (ii) restrict the types, quantities and concentration of materials that can be released into the environment; (iii) apply workplace health and safety standards for the benefit of employees; (iv) require remedial activities or corrective actions to mitigate pollution from former or current operations; and (v) impose substantial liabilities on us for pollution resulting from our operations. Failure to comply with these laws and regulations may result in the (i) assessment of sanctions, including administrative, civil and criminal penalties; (ii) imposition of investigatory, remedial and corrective action obligations or the incurrence of capital expenditures; (iii) occurrence of delays in permitting or the development of projects; and (iv) issuance of injunctions restricting or prohibiting some or all of the activities in a particular area.
The following is a summary of the more significant existing federal environmental laws and regulations, each as amended from time to time, to which our business operations and investments are subject:
• | The Comprehensive Environmental Response, Compensation and Liability Act, a remedial statute that imposes strict liability on generators, transporters and arrangers of hazardous substances at sites where hazardous substance releases have occurred or are threatening to occur; |
• | The Resource Conservation and Recovery Act, which governs the treatment, storage and disposal of non-hazardous and hazardous wastes; |
• | The Clean Air Act, which restricts the emission of air pollutants from many sources and imposes various pre-construction, monitoring and reporting requirements and which serves as a legal basis for the EPA to adopt climate change regulatory initiatives relating to greenhouse gas (GHG) emissions; |
• | The Water Pollution Control Act, also known as the federal Clean Water Act, which regulates discharges of pollutants from facilities to state and federal waters; |
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• | The Safe Drinking Water Act, which ensures the quality of the nation’s public drinking water through adoption of drinking water standards and controlling the injection of substances into below-ground formations that may adversely affect drinking water sources; |
• | The National Environmental Policy Act, which requires federal agencies to evaluate major agency actions having the potential to significantly impact the environment and which may require the preparation of Environmental Assessments or the more detailed Environmental Impact Statements, may be made available for public review and comment; |
• | The Endangered Species Act, which restricts activities that may affect federally identified endangered or threatened species, or their habitats through the implementation of operating restrictions or a temporary, seasonal, or permanent ban in affected areas; and |
• | The Occupational Safety and Health Act, which establishes 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. |
Certain of these federal environmental laws, as well as their state counterparts, impose strict, joint and several liability for costs required to clean up and restore properties where pollutants have been released regardless of whom may have caused the harm or whether the activity was performed in compliance with all applicable laws. In the course of our operations, generated materials or wastes may have been spilled or released from properties owned or leased by us or on or under other locations where these materials or wastes have been taken for recycling or disposal. In addition, many of the properties owned or leased by us were previously operated by third parties whose management, disposal or release of materials and wastes was not under our control. Accordingly, we may be liable for the costs of cleaning up or remediating contamination arising out of our operations or as a result of activities by others who previously occupied or operated on properties now owned or leased by us. Private parties, including the owners of properties that we lease and facilities where our materials or wastes are taken for recycling 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 damages. We may not be able to recover some or any of these additional costs from insurance.
During 2014, we experienced three releases on our Arrow produced water gathering system that resulted in approximately 28,000 barrels of produced water being released on lands within the boundaries of the Fort Berthold Indian Reservation. In May 2015, we experienced another release of approximately 5,200 barrels of produced water. We have substantially completed our remediation efforts for the spills, and we believe our remediation costs will be recoverable under our insurance policies.
In April 2015, the EPA issued a Notice of Potential Violation (NOPV) under the Clean Water Act relating to the largest of the 2014 water releases. We responded to the NOPV in May 2015, and in April 2017, we entered into an Administrative Order on Consent (the Order) with the EPA. The Order requires us to continue to remediate and monitor the impacted area for no less than four years unless all goals of the Order are satisfied earlier. On December 13, 2017, the EPA and Crestwood signed a Combined Complaint and Consent Agreement (CCCA) whereby we agreed to pay a civil penalty of $49,000 to the EPA and purchase emergency response equipment at an estimated cost of approximately $173,000 for the Three Affiliated Tribes as a Supplemental Environmental Project (SEP). The CCCA and SEP concludes the EPA’s penalty phase related to this matter.
In March 2015, we received a grand jury subpoena from the United States Attorney’s Office in Bismarck, North Dakota, seeking documents and information relating to the largest of the three 2014 water releases. In September 2017, we received a notice from the United States Department of Justice that it completed the investigation with no charges being filed against us.
In August 2015, we received a notice of violation from the Three Affiliated Tribes’ Environmental Division related to our 2014 produced water releases on the Fort Berthold Indian Reservation. The notice of violation imposes fines and requests reimbursements exceeding $1.1 million; however, the notice of violation was stayed in September 2015, upon our posting of a performance bond for the amount contemplated by the notice and pending the outcome of settlement discussions with the EPA related to the NOPV. Although we continue to have productive settlement conversations with the Tribe, we cannot predict if or when we will be able to settle the dispute.
Employees
As of February 9, 2018, we had 954 full-time employees, 298 of which were general and administrative employees and 656 of which were operational. We believe that our relationship with our employees is satisfactory.
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Available Information
Our website is located at www.crestwoodlp.com. We make available, free of charge, on or through our website our annual reports on Form 10-K, which include our audited financial statements, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as we electronically file such material with the SEC. These documents are also available, free of charge, at the SEC’s website at www.sec.gov. In addition, copies of these documents, excluding exhibits, may be requested at no cost by contacting Investor Relations, Crestwood Equity Partners LP or Crestwood Midstream Partners LP, 811 Main Street, Suite 3400, Houston, Texas 77002, and our telephone number is (832) 519-2200.
We also make available within the “Corporate Governance” section of our website our corporate governance guidelines, the charter of our Audit Committee and our Code of Business Conduct and Ethics. Requests for copies may be directed in writing to Crestwood Equity Partners LP, 811 Main Street, Suite 3400, Houston, Texas 77002, Attention: General Counsel. Interested parties may contact the chairperson of any of our Board committees, our Board’s independent directors as a group or our full Board in writing by mail to Crestwood Equity Partners LP, 811 Main Street, Suite 3400, Houston, Texas 77002, Attention: General Counsel. All such communications will be delivered to the director or directors to whom they are addressed.
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Item 1A. Risk Factors
Risks Inherent in Our Business
Our business depends on hydrocarbon supply and demand fundamentals, which can be adversely affected by numerous factors outside of our control.
Our success depends on the supply and demand for natural gas, NGLs and crude oil, which has historically generated the need for new or expanded midstream infrastructure. The degree to which our business is impacted by changes in supply or demand varies. Our business can be negatively impacted by sustained downturns in supply and demand for one or more commodities, including reductions in our ability to renew contracts on favorable terms and to construct new infrastructure. For example, although capital investment in certain areas may have increased as crude oil prices improved in throughout 2017 and early 2018, significantly lower commodity prices during the past few years have resulted in an industry-wide reduction in capital expenditures by producers and a slowdown in drilling, completion and supply development efforts. Notwithstanding this market downturn, production volumes of crude oil, natural gas and NGLs have continued to grow (or decline at a slower rate than expected). Similarly major factors that will impact natural gas demand domestically will be the realization of potential liquefied natural gas exports and demand growth within the power generation market. Factors expected to impact crude oil demand include the lifting of the United States’ crude oil export ban and production cuts and freezes implemented by Organization of the Petroleum Exporting Countries (OPEC) members and Russia. In addition, the supply and demand for natural gas, NGLs and crude oil for our business will depend on many other factors outside of our control, some of which include:
• | adverse changes in general global economic conditions; |
• | adverse changes in domestic regulations that could impact the supply or demand for oil and gas; |
• | technological advancements that may drive further increases in production and reduction in costs of developing shale plays; |
• | competition from imported supplies and alternate fuels; |
• | commodity price changes, including the recent decline in crude oil and natural gas prices, that could negatively impact the supply of, or the demand for these products; |
• | increased costs to explore for, develop, produce, gather, process or transport commodities; |
• | shareholder activism and activities by non-governmental organizations to limit sources of funding for the energy sector or restrict the exploration, development and production of oil and gas: |
• | adoption of various energy efficiency and conservation measures; and |
• | perceptions of customers on the availability and price volatility of our services, particularly customers’ perceptions on the volatility of commodity prices over the longer-term. |
If volatility and seasonality in the oil and gas industry decrease, because of increased production capacity or otherwise, the demand for our services and the prices that we will be able to charge for those services may decline. In addition to volatility and seasonality, an extended period of low commodity prices, as the industry is currently experiencing, could adversely impact storage and transportation values for some period of time until market conditions adjust. With West Texas Intermediate crude oil prices ranging from $42.53 to $60.42 per barrel in 2017, the sustainability of recent prices improvements and longer-term oil prices cannot be predicted. These commodity price impacts could have a negative impact on our business, financial condition, and results of operations.
Our future growth may be limited if commodity prices remain low, resulting in a prolonged period of reduced midstream infrastructure development and service requirements to customers.
Our business strategy depends on our ability to provide increased services to our customers and develop growth projects that can be financed appropriately. We may be unable to complete successful, accretive growth projects for any of the following reasons, among others:
• | we fail to identify (or we are outbid for) attractive expansion or development projects or acquisition candidates that satisfy our economic and other criteria; |
• | we fail to secure adequate customer commitments to use the facilities to be developed, expanded or acquired; or |
• | we cannot obtain governmental approvals or other rights, licenses or consents needed to complete such projects or acquisitions on time or on budget, if at all. |
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The development and construction of gathering, processing, storage and transportation facilities involves numerous regulatory, environmental, safety, political and legal uncertainties beyond our control and may require the expenditure of significant amounts of capital. When we undertake these projects, they may not be completed on schedule, at the budgeted cost or at all. Moreover, our revenues may not increase immediately upon the expenditure of funds on a particular growth project. For instance, if we build a new gathering system, processing plant or transmission pipeline, the construction may occur over an extended period of time and we will not receive material increases in revenues until the project is placed in service. Accordingly, if we do pursue growth projects, we can provide no assurances that our efforts will provide a platform for additional growth for our company.
Our ability to finance new growth projects and make capital expenditures may be limited by our access to the capital markets or ability to raise investment capital at a cost of capital that allows for accretive midstream investments.
The significant decline in energy commodity prices in recent years has led to an increased concern by energy investors regarding the future outlook for the industry. This has resulted in a historic decline in equity and debt valuations in the publicly traded capital markets as well as increased trading volatility. As a result, our publicly traded common units experienced a decrease in value, primarily during 2015 and 2016, with a corresponding increase in yield resulting in a higher cost of capital than we have historically experienced. Our growth strategy depends on our ability to identify, develop and contract for new growth projects and raise the investment capital, at a reasonable cost of capital, required to generate accretive returns from the growth project. This trend may continue and could negatively impact our ability to grow for any of the following reasons:
• | access to the public equity and debt markets for partnerships of similar size to us may limit our ability to raise new equity and debt capital to finance new growth projects; |
• | if market conditions deteriorate below current levels, it is unlikely that we could issue equity at costs of capital that would enable us to invest in new growth projects on an accretive basis; or |
• | we cannot raise financing for such projects or acquisitions on economically acceptable terms. |
The growth projects we complete may not perform as anticipated.
Even if we complete growth projects that we believe will be strategic and accretive, such projects may nevertheless reduce our cash available for distribution due to the following factors, among others:
• | mistaken assumptions about capacity, revenues, synergies, costs (including operating and administrative, capital, debt and equity costs), customer demand, growth potential, assumed liabilities and other factors; |
• | the failure to receive cash flows from a growth project or newly acquired asset due to delays in the commencement of operations for any reason; |
• | unforeseen operational issues or the realization of liabilities that were not known to us at the time the acquisition or growth project was completed; |
• | the inability to attract new customers or retain acquired customers to the extent assumed in connection with an acquisition or growth project; |
• | the failure to successfully integrate growth projects or acquired assets or businesses into our operations and/or the loss of key employees; or |
• | the impact of regulatory, environmental, political and legal uncertainties that are beyond our control. |
In particular, we may construct facilities to capture anticipated future growth in production and/or demand in a region in which such growth does not materialize. As a result, new facilities may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our business, financial condition, results of operations and ability to make distributions.
If we complete future growth projects, our capitalization and results of operations may change significantly, and you 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. If any growth projects we ultimately complete are not accretive to our cash available for distribution, our ability to make distributions may be reduced.
We may rely upon third-party assets to operate our facilities, and we could be negatively impacted by circumstances beyond our control that temporarily or permanently interrupt the operation of such third-party assets.
Certain of our operations and investments depend on assets owned and controlled by third parties to operate effectively. For example, (i) certain of our “rich gas” gathering systems depend on interconnections, compression facilities and processing plants owned by third parties for us to move gas off our systems; (ii) our crude oil gathering systems depend on third-party
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pipelines to move crude to demand markets or rail terminals and our crude oil rail terminals depend on railroad companies to move our customers’ crude oil to market; and (iii) our natural gas storage facilities rely on third-party interconnections and pipelines to receive and deliver natural gas. Since we do not own or operate these third-party facilities, their continuing operation is outside of our control. If third-party facilities become unavailable or constrained, or other downstream facilities utilized to move our customers’ product to their end destination become unavailable, it could have a material adverse effect on our business, financial condition, results of operations, and ability to make distributions.
In addition, the rates charged by processing plants, pipelines and other facilities interconnected to our assets affect the utilization and value of our services. Significant changes in the rates charged by these third parties, or the rates charged by the third parties that own “downstream” assets required to move commodities to their final destinations, could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions.
We depend on a limited number of customers for a substantial portion of our revenues.
We generate a substantial portion of our gathering revenues from a limited number of oil and gas producers. If as a result of market conditions, certain of our producer customers levered to shale production reduce capital spending (or continue capital spending levels lower than historical levels) and/or shut in production for economic reasons, this could result in lower revenues for us. In the event that market conditions deteriorate, this could lead to the loss of a significant customer, which could also cause a significant decline in our revenues. In addition, to the extent our producer customers have weathered the challenges of lower commodity prices over the past few years, we cannot provide any assurance that they will remain viable over a longer period of lower commodity prices.
Declines in natural gas, NGL or crude prices could adversely affect our business.
Energy commodity prices have declined substantially since 2014 due to a wide range of factors, including a continuing growth of supply, slowdown or decline in demand, and challenges in economic, financial and monetary markets. Sustained low natural gas, NGL and crude oil prices have recently negatively impacted natural gas and oil exploration and production activity levels industry-wide and in the areas we operate. A continued slowdown in activity can result in a decline in the production of hydrocarbons over time, resulting in reduced throughput on our systems, plants, trucks and terminals. Such a decline could also potentially affect the ability of our customers to continue their operations. As a result, sustained low natural gas and crude oil prices could have a material adverse effect on our business, results of operations, and financial condition. In general, the prices of natural gas, oil, condensate, NGLs and other hydrocarbon products fluctuate in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control.
Our gathering and processing operations depend, in part, on drilling and production decisions of others.
Our gathering and processing operations are dependent on the continued availability of natural gas and crude oil production. 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. Our gathering systems are connected to wells whose production will naturally decline over time, which means that our cash flows associated with these wells will decline over time. To maintain or increase throughput levels on our gathering systems and utilization rates at our natural gas processing plants, we must continually obtain new natural gas and crude oil supplies. Our ability to obtain additional sources of natural gas and crude oil primarily depends on the level of successful drilling activity near our systems, our ability to compete for volumes from successful new wells, and our ability to expand our system capacity as needed. If we are not able to obtain new supplies of natural gas and crude oil to replace the natural decline in volumes from existing wells, throughput on our gathering and processing facilities would decline, which could have a material adverse effect on our results of operations and distributable cash flow.
Although we have acreage dedications from customers that include certain producing and non-producing oil and gas properties, our customers are not contractually required to develop the reserves and or properties they have dedicated to us. We have no control over producers or their drilling and production decisions in our areas of operations, which are affected by, among other things, (i) the availability and cost of capital; (ii) prevailing and projected commodity prices; (iii) demand for natural gas, NGLs and crude oil; (iv) levels of reserves and geological considerations; (v) governmental regulations, including the availability of drilling permits and the regulation of hydraulic fracturing; and (vi) the availability of drilling rigs and other development services. Fluctuations in energy prices can also greatly affect the development of oil and gas reserves. Drilling and production activity generally decreases as commodity prices decrease, and sustained declines in commodity prices could lead to a material decrease in such activity. Because of these factors, even if oil and gas reserves are known to exist in areas served by our assets, producers may choose not to develop those reserves. Reductions in exploration or production activity in our areas of operations could lead to reduced utilization of our systems.
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Estimates of oil and gas reserves depend on many assumptions that may turn out to be inaccurate, and future volumes on our gathering systems may be less than anticipated.
We normally do not obtain independent evaluations of natural gas or crude oil reserves connected to our gathering systems. We therefore do not have independent estimates of total reserves dedicated to our systems or the anticipated life of such reserves. It often takes producers longer periods of time to determine how to efficiently develop and produce hydrocarbons from unconventional shale plays than conventional basins, which can result in lower volumes becoming available as soon as expected in the shale plays in which we operate. If the total reserves or estimated life of the reserves connected to our gathering systems is less than anticipated and we are unable to secure additional sources of natural gas or crude oil, it could have a material adverse effect on our business, results of operations and financial condition.
We are exposed to credit risks of our customers, and any material nonpayment or nonperformance by our key customers could adversely affect our cash flows and results of operations.
Many of our customers may experience financial problems that could have a significant effect on their creditworthiness. Severe financial problems encountered by our customers could limit our ability to collect amounts owed to us, or to enforce performance of obligations under contractual arrangements. In addition, many of our customers finance their activities through cash flows from operations, the incurrence of debt or the issuance of equity. The combination of the reduction of cash flows resulting from declines in commodity prices, a reduction in borrowing bases under reserve-based credit facility and the lack of availability of debt or equity financing may result in a significant reduction of customers’ liquidity and limit their ability to make payments or perform on their obligations to us. Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to us. Financial problems experienced by our customers could result in the impairment of our assets, reduction of our operating cash flows and may also reduce or curtail their future use of our products and services, which could reduce our revenues.
Our marketing, supply and logistics operations are seasonal and generally have lower cash flows in certain periods during the year, which may require us to borrow money to fund our working capital needs of these businesses.
The natural gas liquids inventory we pre-sell to our customers is higher during the second and third quarters of a given year, and our cash receipts during that period are lower. As a result, we may have to borrow money to fund the working capital needs of our marketing, supply and logistics operations during those periods. Any restrictions on our ability to borrow money could impact our ability to pay quarterly distributions to our unitholders.
Counterparties to our commodity derivative and physical purchase and sale contracts in our marketing, supply and logistics operations may not be able to perform their obligations to us, which could materially affect our cash flows and results of operations.
We encounter risk of counterparty non-performance in our marketing, supply and logistics operations. Disruptions in the price or supply of NGLs for an extended or near term period of time could result in counterparty defaults on our derivative and physical purchase and sale contracts. This could impair our expected earnings from the derivative or physical sales contracts, our ability to obtain supply to fulfill our sales delivery commitments or our ability to obtain supply at reasonable prices, which could result adversely affect our financial condition and results of operations.
Our marketing, supply and logistics operations are subject to commodity risk, basis risk, or risk of adverse market conditions, which can adversely affect our financial condition and results of operations.
We attempt to lock in a margin for a portion of the commodities we purchase by selling such commodities for physical delivery to our customers or by entering into future delivery obligations under contracts for forward sale. Through these transactions, we seek to maintain a position that is substantially balanced between purchases, and sales or future delivery obligations. Any event that disrupts our anticipated physical supply of commodities could expose us to risk of loss resulting from the need to fulfill our obligations required under contracts for forward sale. Basis risk describes the inherent market price risk created when a commodity of certain grade or location is purchased, sold or exchanged as compared to a purchase, sale or exchange of a like commodity at a different time or place. Transportation costs and timing differentials are components of basis risk. In a backwardated market (when prices for future deliveries are lower than current prices), basis risk is created with respect to timing. In these instances, physical inventory generally loses value as the price of such physical inventory declines over time. Basis risk cannot be entirely eliminated, and basis exposure, particularly in backwardated or other adverse market conditions, can adversely affect our financial condition and results of operations.
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Changes in future business conditions could cause recorded long-lived assets and goodwill to become further impaired, and our financial condition and results of operations could suffer if there is an additional impairment of long-lived assets and goodwill.
We continually monitor our business, the business environment and the performance of our operations to determine if an event has occurred that indicates that a long-lived asset may be impaired. If an event occurs, which is a determination that involves judgment, we may be required to utilize cash flow projections to assess our ability to recover the carrying value of our assets based on our long-lived assets’ ability to generate future cash flows on an undiscounted basis. This differs from our evaluation of goodwill, which is evaluated for impairment annually on December 31, and whenever events indicate that it is more likely than not that the fair value of a reporting unit could be less than the carrying amount. This evaluation requires us to compare the fair value of each of our reporting units primarily utilizing discounted cash flows, to its carrying value (including goodwill). If the fair value exceeds the carrying value amount, goodwill of the reporting unit is not considered impaired.
Under GAAP, during the years ended December 31, 2017, 2016 and 2015, we were required to record $121.0 million, $194.0 million and $2,223.8 million of long-lived asset and goodwill impairments related to certain of our reporting units because changes in circumstances or events (of which one of the several indicators of impairment was considered jointly is a significant and other than temporary decrease in our market capitalization) indicated that the carrying values of such assets exceeded their fair value and were not recoverable.
Our long-lived assets and goodwill impairment analyses are sensitive to changes in key assumptions used in our analysis, such as expected future cash flows, the degree of volatility in equity and debt markets and our unit price. If the assumptions used in our analysis are not realized, it is possible a material impairment charge may need to be recorded in the future. We cannot accurately predict the amount and timing of any impairment of long-lived assets or goodwill. Further, as we work toward a turnaround of our business, we will need to continue to evaluate the carrying value of our goodwill. Any additional impairment charges that we may take in the future could be material to our results of operations and financial condition. For a further discussion of our long-lived assets and goodwill impairments, see Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 2.
Our industry is highly competitive, and increased competitive pressure could adversely affect our ability to execute our growth strategy.
We compete with other energy midstream enterprises, some of which are much larger and have significantly greater financial resources or operating experience, in our areas of operation. Our competitors may expand or construct infrastructure that creates additional competition for the services we provide to customers. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenues 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 distributions.
Our level of indebtedness could adversely affect our ability to raise additional capital to fund operations, limit our ability to react to changes in our business or industry, and place us at a competitive disadvantage.
We had approximately $1.5 billion of long-term debt outstanding as of December 31, 2017. Our inability to generate sufficient cash flow to satisfy debt obligations or to obtain alternative financing could materially and adversely affect our business, results of operations, financial condition and business prospects.
Our substantial debt could have important consequences to our unitholders. For example, it could:
• | increase our vulnerability to general adverse economic and industry conditions; |
• | limit our ability to fund future capital expenditures and working capital, to engage in development activities, or to otherwise realize the value of our assets and opportunities fully because of the need to dedicate a substantial portion of our cash flow from operations to payments of interest and principal on our debt or to comply with any restrictive covenants or terms of our debt; |
• | result in an event of default if we fail to satisfy debt obligations or fail to comply with the financial and other restrictive covenants contained in the agreements governing our indebtedness, which event of default could result in all of our debt becoming immediately due and payable and could permit our lenders to foreclose on any of the collateral securing such debt; |
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• | require a substantial portion of cash flow from operations to be dedicated to the payment of principal and interest on our indebtedness, therefore reducing our ability to use cash flow to fund operations, capital expenditures and future business opportunities; |
• | increase our cost of borrowing; |
• | restrict us from making strategic acquisitions or investments, or cause us to make non-strategic divestitures; |
• | limit our flexibility in planning for, or reacting to, changes in our business or industry in which we operate, placing us at a competitive disadvantage compared to our peers who are less highly leveraged and who therefore may be able to take advantage of opportunities that our leverage prevents us from exploring; and |
• | impair our ability to obtain additional financing in the future. |
Realization of any of these factors could adversely affect our financial condition, results of operations and cash flows.
Restrictions in our revolving credit facility and indentures governing our senior notes could adversely affect our business, financial condition, results of operations and ability to make distributions.
Our revolving credit facility and indentures governing our senior notes contain various covenants and restrictive provisions that will limit our ability to, among other things:
• | incur additional debt; |
• | make distributions on or redeem or repurchase units; |
• | make investments and acquisitions; |
• | incur or permit certain liens to exist; |
• | enter into certain types of transactions with affiliates; |
• | merge, consolidate or amalgamate with another company; and |
• | transfer or otherwise dispose of assets. |
Furthermore, our revolving credit facility contains covenants which requires us to maintain certain financial ratios such as (i) a net debt to consolidated EBITDA ratio (as defined in the credit agreement) of not more than 5.50 to 1.0; (ii) a consolidated EBITDA to consolidated interest expense ratio (as defined in our credit agreement) of not less than 2.50 to 1.0, and (iii) a senior secured leverage ratio (as defined in its credit agreement) of not more than 3.75 to 1.0.
Borrowings under our revolving credit facility are secured by pledges of the equity interests of, and guarantees by, substantially all of our restricted domestic subsidiaries, and liens on substantially all of our real property (outside of New York) and personal property. None of our equity investments have guaranteed, and none of the assets of our equity investments secure, our obligations under our revolving credit facility.
The provisions of our credit agreement and indentures governing our senior notes may affect our ability to obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of our revolving credit facility or indentures governing our senior notes could result in events of default, which could enable our lenders or holders of our senior notes, subject to the terms and conditions of our credit agreement or indentures, as applicable, to declare any outstanding principal of that debt, together with accrued interest, to be immediately due and payable. If the payment of any such debt is accelerated, our assets may be insufficient to repay such debt in full, and the holders of our common units could experience a partial or total loss of their investment.
A change of control could result in us facing substantial repayment obligations under our revolving credit facility and indentures governing our senior notes.
Our credit agreement and indentures governing our senior notes contain provisions relating to change of control of Crestwood Equity’s general partner. If these provisions are triggered, our outstanding indebtedness may become due. In such an event, there is no assurance that we would be able to pay the indebtedness, in which case the lenders under the revolving credit facility would have the right to foreclose on our assets and holders of our senior notes would be entitled to require us to repurchase all or a portion of our notes at a purchase price equal to 101% of the principal amount thereof, plus accrued and unpaid interest, if any, to the date of such repurchase, which would have a material adverse effect on us. There is no restriction on our ability or the ability of Crestwood Equity’s general partner or its parent companies to enter into a transaction which would trigger the change of control provision. In certain circumstances, the control of our general partner may be transferred to a third party without unitholder consent, and this may be considered a change in control under our revolving credit facility and senior notes. Please read “The control of our general partner may be transferred to a third party without unitholder consent.”
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Our ability to make cash distributions may be diminished, and our financial leverage could increase, if we are not able to obtain needed capital or financing on satisfactory terms.
Historically, we have used cash flow from operations, borrowings under our revolving credit facilities and issuances of debt or equity to fund our capital programs, working capital needs and acquisitions. Our capital program may require additional financing above the level of cash generated by our operations to fund growth. If our cash flow from operations decreases or distributions from our equity investments decrease as a result of lower throughput volumes on our systems or otherwise, our ability to expend the capital necessary to expand our business or increase our future cash distributions may be limited. If our cash flow from operations and the distributions we receive from subsidiaries are insufficient to satisfy our financing needs, we cannot be certain that additional financing will be available to us on acceptable terms, if at all. Our ability to obtain bank financing or to access the capital markets for future equity or debt offerings may be limited by our financial condition or general economic conditions at the time of any such financing or offering. Even if we are successful in obtaining the necessary funds, the terms of such financings could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders. Further, incurring additional debt may significantly increase our interest expense and financial leverage and issuing additional limited partner interests may result in significant unitholder dilution and would increase the aggregate amount of cash required to maintain the cash distribution rate which could materially decrease our ability to pay distributions. If additional capital resources are unavailable, we may curtail our activities or be forced to sell some of our assets on an untimely or unfavorable basis.
Increases in interest rates could adversely impact our unit price, ability to issue equity or incur debt for acquisitions or other purposes, and ability to make payments on our debt obligations.
Interest rates may 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. 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 and our ability to issue equity or incur debt for acquisitions or other purposes and to make payments on our debt obligations.
The loss of key personnel could adversely affect our ability to operate.
Our success is dependent upon the efforts of our senior management team, as well as on our ability to attract and retain both executives and employees for our field operations. Our senior executives have significant experience in the oil and gas industry and have developed strong relationships with a broad range of industry participants. The loss of these executives, or the loss of key field employees operating in competitive markets, could prevent us from implementing our business strategy and could have a material adverse effect on our customer relationships, results of operations and ability to make distributions.
We operate joint ventures that may limit our operational flexibility.
We conduct a meaningful portion of our operations through joint ventures (including our Crestwood Permian, Jackalope, PRBIC, Stagecoach Gas and Tres Palacios joint ventures), and we may enter into additional joint ventures in the future. In a joint venture arrangement, we could have less operational flexibility, as actions must be taken in accordance with the applicable governing provisions of the joint venture. In certain cases, we:
• | could have limited ability to influence or control certain day to day activities affecting the operations; |
• | could have limited control on the amount of capital expenditures that we are required to fund with respect to these operations; |
• | could be dependent on third parties to fund their required share of capital expenditures; |
• | may be subject to restrictions or limitations on our ability to sell or transfer our interests in the jointly owned assets; and |
• | may be required to offer business opportunities to the joint venture, or rights of participation to other joint venture members, participants in certain areas of mutual interest. |
In addition, joint venture participants may have obligations that are important to the success of the joint venture, such as the obligation to pay substantial carried costs pertaining to the joint venture. The performance and ability of our joint venture partners to satisfy their obligations under joint venture arrangements is outside of our control. If these parties do not satisfy their obligations, our business may be adversely affected. Our joint venture partners may be in a position to take actions contrary to our instructions or requests or contrary to our policies or objectives, and disputes between us and our joint venture partners may result in delays, litigation or operational impasses. The risks described above or the failure to continue our joint
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ventures or to resolve disagreements with our joint venture partners could adversely affect our ability to conduct business that is the subject of a joint venture, which could in turn negatively affect our financial condition and results of operations.
Moreover, our decision to operate aspects of our business through joint ventures could limit our ability to consummate strategic transactions. Similarly, due to the perceived challenges of existing joint ventures, companies like ours that fund a considerable portion of their operations through joint ventures may be less attractive merger or take-over candidates. We cannot provide any assurance that our operating model will not negatively affect the value of our common units.
We may not be able to renew or replace expiring contracts.
Our primary exposure to market risk occurs at the time contracts expire and are subject to renegotiation and renewal. As of December 31, 2017, the weighted average remaining term of our consolidated portfolio of natural gas gathering contracts is approximately 10 years, and our consolidated portfolio of crude oil gathering contracts is approximately nine years. The extension or replacement of existing contracts depends on a number of factors beyond our control, including:
• | the macroeconomic factors affecting natural gas, NGL and crude economics for our current and potential customers; |
• | the level of existing and new competition to provide services to our markets; |
• | the balance of supply and demand, on a short-term, seasonal and long-term basis, in our markets; |
• | the extent to which the customers in our markets are willing to contract on a long-term basis; and |
• | the effects of federal, state or local regulations on the contracting practices of our customers. |
Any failure to extend or replace a significant portion of our existing contracts, or extending or replacing them at unfavorable or lower rates, could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions.
The fees we charge to customers under our contracts may not escalate sufficiently to cover our cost increases, and those contracts may be suspended in some circumstances.
Our costs may increase at a rate greater than the rate that the fees we charge to third parties increase pursuant to our contracts with them. In addition, some third parties’ obligations under their agreements with us may be permanently or temporarily reduced upon the occurrence of certain events, some of which are beyond our control, including force majeure events wherein the supply of natural gas or crude oil is curtailed or cut off. Force majeure events generally include, without limitation, revolutions, wars, acts of enemies, embargoes, import or export restrictions, strikes, lockouts, fires, storms, floods, acts of God, explosions, mechanical or physical failures of our equipment or facilities or those of third parties. If our escalation of fees is insufficient to cover increased costs or if any third party suspends or terminates its contracts with us, our business, financial condition, results of operations and ability to make distributions could be materially adversely affected.
Our operations are subject to extensive regulation, and regulatory measures adopted by regulatory authorities could have a material adverse effect on our business, financial condition and results of operations.
Our operations, including our joint ventures, are subject to extensive regulation by federal, state and local regulatory authorities. For example, because Stagecoach Gas transports natural gas in interstate commerce and stores natural gas that is transported in interstate commerce, Stagecoach Gas’ natural gas storage and transportation facilities are subject to comprehensive regulation by the FERC under the Natural Gas Act. Federal regulation under the Natural Gas Act extends to such matters as:
•rates, operating terms and conditions of service;
• | the form of tariffs governing service; |
• | the types of services we may offer to our customers; |
• | the certification and construction of new, or the expansion of existing, facilities; |
• | the acquisition, extension, disposition or abandonment of facilities; |
• | contracts for service between storage and transportation providers and their customers; |
• | creditworthiness and credit support requirements; |
• | the maintenance of accounts and records; |
• | relationships among affiliated companies involved in certain aspects of the natural gas business; |
• | the initiation and discontinuation of services; and |
• | various other matters. |
Natural gas companies may not charge rates that, upon review by the FERC, are found to be unjust and unreasonable or unduly discriminatory. Existing interstate transportation and storage rates may be challenged by complaint and are subject to prospective change by the FERC. Additionally, rate increases proposed by a regulated pipeline or storage provider may be
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challenged and such increases may ultimately be rejected by the FERC. Stagecoach Gas has authority from the FERC to charge and collect (i) market-based rates for interstate storage services provided at the Stagecoach, Thomas Corners, Seneca Lake and Steuben facilities and (ii) negotiated rates for interstate transportation services provided by the North-South Facilities and MARC I Pipeline. The FERC has authorized Tres Palacios to charge and collect market-based rates for interstate storage services provided by its natural gas facilities. The FERC’s “market-based rate” policy allows regulated entities to charge rates different from, and in some cases, less than, those which would be permitted under traditional cost-of-service regulation. Among the sorts of changes in circumstances that could raise market power concerns would be an expansion of capacity, acquisitions or other changes in market dynamics. There can be no guarantee that our joint ventures will be allowed to continue to operate under such rate structures for the remainder of their assets’ operating lives. Any successful challenge against rates charged for their storage and transportation services, or their loss of market-based rate authority or negotiated rate authority, could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions.
There can be no assurance that the FERC will continue to pursue its approach of pro-competitive policies as it considers matters such as pipeline rates and rules and policies that may affect rights of access to natural gas transportation capacity and transportation and storage facilities. Failure to comply with applicable regulations under the Natural Gas Act, the Natural Gas Policy Act of 1978, the Pipeline Safety Act of 1968 and certain other laws, and with implementing regulations associated with these laws, could result in the imposition of administrative and criminal remedies and civil penalties of up to approximately $1.2 million per day, per violation.
A change in the jurisdictional characterization of our gathering assets may result in increased regulation, which could cause our revenues to decline and operating expenses to increase.
Our natural gas and crude oil gathering operations are generally exempt from the jurisdiction and regulation of the FERC, except for certain anti-market manipulation provisions. FERC regulation nonetheless affects our businesses and the markets for products derived from our gathering businesses. The FERC’s policies and practices across the range of its oil and gas regulatory activities, including, for example, its policies on open access transportation, rate making, capacity release and market center promotion, indirectly affect intrastate markets. In recent years, the FERC has pursued pro-competitive policies in its regulation of interstate oil and natural gas pipelines. However, we have no assurance that the FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to oil and natural gas transportation capacity. In addition, the distinction between FERC-regulated transmission services and federally unregulated gathering services has regularly been the subject of substantial, on-going litigation. Consequently, the classification and regulation of some of our pipelines could change based on future determinations by the FERC, the courts or Congress. If our gathering operations become subject to FERC jurisdiction, the result may adversely affect the rates we are able to charge and the services we currently provide, and may include the potential for a termination of certain gathering agreements.
State and municipal regulations also impact our business. Common purchaser statutes generally require gatherers to gather or provide services without undue discrimination as to source of supply or producer; as a result, these statutes restrict our right to decide whose production we gather or transport. Federal law leaves any economic regulation of natural gas gathering to the states. The states in which we currently operate have adopted complaint-based regulation of gathering activities, which allows oil and gas producers and shippers to file complaints with state regulators in an effort to resolve access and rate grievances. Other state and municipal regulations may not directly regulate our gathering business, but may nonetheless affect the availability of natural gas for purchase, processing and sale, including state regulation of production rates and maximum daily production allowable from gas wells. While our gathering lines currently are subject to limited state regulation, there is a risk that state laws will be changed, which may give producers a stronger basis to challenge the rates, terms and conditions of its gathering lines.
Our operations are subject to compliance with environmental and operational health and safety laws and regulations that may expose us to significant costs and liabilities.
Our operations are subject to stringent federal, regional, state and local laws and regulations governing worker health and safety aspects of our operations, the discharge of materials into the environment and otherwise relating to environmental protection. Such environmental laws and regulations impose numerous obligations that are applicable to our operations, including the acquisition of permits to conduct regulated activities, the incurrence of capital expenditures to comply with applicable legal requirements, the application of specific health and safety criteria addressing worker protections and the imposition of restrictions on the generation, handling, treatment, storage, disposal and transportation of materials and wastes. Failure to comply with such environmental laws and regulations can result in the assessment of substantial administrative, civil and criminal penalties, the imposition of remedial liabilities, the occurrence of delays in permitting or development of projects and the issuance of injunctions restricting or prohibiting some or all of our activities. Certain environmental laws impose strict, joint and several liability for costs required to clean up and restore sites where materials or wastes have been disposed or
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otherwise released. In the course of our operations, generated materials or wastes may have been spilled or released from properties owned or leased by us or on or under other locations where these materials or wastes have been taken for recycling or disposal.
It is also possible that adoption of stricter environmental laws and regulations or more stringent interpretation of existing environmental laws and regulations in the future could result in additional costs or liabilities to us as well as the industry in general or otherwise adversely affect demand for our services. For example, in October 2015, the EPA issued a final rule under the federal Clean Air Act lowering the United States NAAQS for ground-level ozone to 70 parts per billion for the 8-hour primary and secondary ozone standards. The EPA published a final rule in November 2017 that issued area designations with respect to ground-level ozone for approximately 85% of the U.S. counties as either “attainment/unclassifiable” or “unclassifiable” but has not yet issued non-attainment designations for the remaining areas of the U.S. not addressed under the November 2017 final rule. States are also expected to adopt regulations implementing the NAAQS rule that may be more stringent than the federal standards. In another example, the EPA and U.S. Army of Corps of Engineers (Corp) published a final rule in June 2015 that attempted to clarify federal jurisdiction under the Clean Water Act over waters of the United States, but legal challenges to this rule followed and the rule has been stayed nationwide, with the U.S. Supreme Court accepting review of this rule in January 2017 to determine whether jurisdiction resides with the federal district or appellate courts. Subsequently, the EPA and the Corps have proposed a rulemaking in June 2017 to repeal the June 2015 rule, announced their intent to issue a new rule defining the Clean Water Act’s jurisdiction, and published a proposed rule in November 2017 specifying that the contested May 2015 rule would not take effect until two years after the November 2017 proposed rule is finalized and published in the Federal Registrar. As a result, future implementation of the June 2015 rule is uncertain at this time but to the extent any rule expands the scope of the Clean Water Act’s jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. Our compliance with these or other new or amended legal requirements could result in our incurring significant additional expense and operating delays or restrictions with respect to our operations, which may not be fully recoverable from customers and, thus, could reduce net income. Our customers may similarly incur increased costs or restrictions that may limit or decrease those customers’ operations and have an indirect material adverse effect on our business.
Climate change legislation or regulations restricting emissions of GHGs could result in increased operating and capital costs and reduced demand for our services.
Climate change continues to attract considerable public and scientific attention. As a result, numerous proposals have been made and could continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs. These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources. At the federal level, no comprehensive climate change legislation has been implemented to date. However, the EPA has adopted regulations to restrict emissions of GHGs under existing provisions of the Clean Air Act that, among other things, establish Prevention of Significant Deterioration (PSD) construction and Title V operating permit reviews for GHGs from certain large stationary sources that are already potential major sources of principal, or criteria, pollutant emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet best available control technology standards that typically will be established by the states. The EPA has also adopted regulations requiring the annual reporting of GHG emissions from specified large GHG emission sources in the United States including certain oil and natural gas production, processing, transmission, storage and distribution facilities as well as certain onshore gathering and boosting systems consisting primarily of gathering pipelines, compressors and process equipment used to perform natural gas compression, dehydration and acid gas removal.
Federal agencies also have begun directly regulating emissions of methane, a GHG, from oil and natural gas operations. In June 2016, the EPA published a final rule establishing new emissions standards for methane and additional standards for volatile organic compounds from certain new, modified, and reconstructed equipment and processes in the oil and natural gas source category, including production, processing, transmission and storage facilities. These standards require the use of certain equipment specific emissions control practices, require additional controls for pneumatic controllers and pumps as well as compressors, and impose leak detection and repair requirements for natural gas compressor and booster stations. However, in June 2017, the EPA published a proposed rule to stay certain portions of the June 2016 standards for two years and re-evaluate the entirety of the 2016 standards but the EPA has not yet published a final rule and, as a result, future implementation of the 2016 standards is uncertain at this time. In another example, the BLM published a final rule in November 2016 that imposes requirements to reduce methane emissions from venting, flaring, and leaking on public lands. However, in October 2017, the BLM published a proposed rule that would temporarily suspend or delay certain requirements contained in the November 2016 final rule until January 17, 2019. These rules and any other new methane emission standards imposed on the oil and gas sector could result in increased costs to our and our customers’ operations and could delay or curtail our customers’ activities, which could adversely affect our business. On an international level, the United States is one of numerous nations that prepared an international climate change agreement in Paris, France in December 2015, requiring member countries to
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review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals every five years beginning in 2020. This “Paris agreement” was signed by the United States in April 2016 and became effective in November 2016; however, this agreement does not create any binding obligations for nations to limit their GHG emissions, but does include pledges to voluntarily limit or reduce future emissions. However, in August 2017, the U.S. State Department officially informed the United Nations of the intent of the United States to withdraw from the Paris Agreement. The Paris Agreement provides for a four year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process and/or the terms on which the United States may re-enter the Paris Agreement or a separately negotiated agreement are unclear at this time.
The adoption of legislation or regulatory programs to reduce emissions of GHGs could require us and our customers to incur increased compliance and operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas that is produced, which may decrease demand for our midstream services. Moreover, any such future laws and regulations that limit emissions of GHGs or that otherwise promote the use of renewable fuels could adversely affect demand for the natural gas our customers produce, which could thereby reduce demand for our services and adversely affect our business. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations. In addition, recent non-governmental activism directed at shifting funding away from companies with energy-related assets could result in limitations or restrictions on certain sources of funding for the energy sector.
We may incur higher costs as a result of pipeline integrity management program testing and additional safety legislation.
Pursuant to authority under the NGPSA and HLPSA, PHMSA requires pipeline operators to develop integrity management programs for pipelines located where a leak or rupture could harm “high consequence areas”. The regulations require operators like 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. |
We estimate that the total future costs to complete the testing required by existing PHMSA regulations will not have a material impact to our results. 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 itself.
Moreover, new legislation or regulations adopted by PHMSA may impose more stringent requirements applicable to integrity management programs and other pipeline safety aspects of our operations, which could cause us to incur increased capital costs, operational delays and costs of operations. For example, the 2011 Pipeline Safety Act increased the penalties for safety violations, established additional safety requirements for newly constructed pipelines and required studies of safety issues that could result in the adoption of new regulatory requirements by PHMSA for existing pipelines. More recently, in June 2016, the 2016 Pipeline Safety Act was passed, extending PHMSA’s statutory mandate through 2019 and, among other things, requiring PHMSA to complete certain of its outstanding mandates under the 2011 Pipeline Safety Act and developing new safety standards for natural gas storage facilities by June 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. PHMSA issued interim regulations in October 2016 to implement the agency’s expanded authority to address unsafe pipeline conditions or practices that pose an imminent hazard to life, property, or the environment.
With regard to storage facilities, following the leak at a natural gas storage facility, in February 2016, PHMSA issued an advisory bulletin for natural gas storage facility operators, recommending that they review operations to identify the potential leaks and failures caused by corrosion, chemical or mechanical damage, or other material deficiencies in equipment; review storage facility locations and operations of shut-off and isolation systems, and comply with state regulations governing the permitting, drilling, completion, and operation of storage wells, and recommending the voluntary implementation of certain industry recognized recommended practices for natural gas storage facilities. Further in December 2016, PHMSA issued final interim rules that impose new safety-related requirements on downhole facilities (including wells, wellbore tubing and casing) of new and existing underground natural gas storage facilities. The final interim rules adopt and make mandatory two American Petroleum Institute Recommend Practices (API RP 1170 and 1171) that, among other things, address construction, maintenance, risk-management and integrity-management procedures. PHMSA indicated when it issued the interim final rule
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that the adoption of these safety standards for natural gas storage facilities represent a first step in a multi-phase process to enhance the safety of underground natural gas storage, with more standards likely forthcoming. Most recently, in response to a petition for reconsideration of the interim final rule received in January 2017, PHMSA published a notice on June 20, 2017, advising that the agency intends to consider the issues raised by the petitioners in a final rule, which it currently expects to issue in 2018. At this time, we cannot predict the impact of any future regulatory actions in this area.
In January 2017, PHMSA issued a final rule that amends its pipeline safety regulations for the design, construction, testing, operation and maintenance of hazardous liquids pipelines. The final rule imposes more stringent standards that determine how operators repair aging and high-risk infrastructure, increase the frequency of tests that assess pipeline conditions, and require operators to report more operating and safety data. Among other things, the final rule: (i) extends an operator’s reporting requirements to gravity and hazardous liquids gathering pipelines; (ii) requires operators to inspect pipelines in areas affected by extreme weather and similar events within a certain timeframe; (iii) impose new requirements to periodically “pig” transmission pipelines in areas outside of high consequence areas; (iv) broadens the requirement for the use of leak detection systems; and (v) increases the use of inline inspection tools. However, the date of implementation of this final rule by publication in the Federal Registrar remains uncertain following the January 2017 change in Presidential administrations.
We are evaluating PHMSA’s new rules, and we cannot predict the precise impact that compliance with the new rules will have on our business. The new rules may, among other things, require us or our joint ventures to install new or modified safety controls, undertake additional capital projects or conduct maintenance programs on an expedited basis. The costs of complying with the new PHMSA rules, as well as other rules under consideration by PHMSA or other agencies, could have a material adverse effect on our cash flows and results of operations.
Our business involves many hazards and risks, some of which may not be fully covered by insurance.
Our operations are subject to many risks inherent in gathering, processing, storage and transportation segments of the energy midstream industry, such as:
• | damage to pipelines and plants, related equipment and surrounding properties caused by natural disasters and acts of terrorism; |
• | subsidence of the geological structures where we store NGLs, or storage cavern collapses; |
• | operator error; |
• | inadvertent damage from construction, farm and utility equipment; |
• | leaks, migrations or losses of natural gas, NGLs or crude oil; |
• | fires and explosions; |
• | cyber intrusions; and |
• | other hazards that could also result in personal injury, including loss of life, property and natural resources damage, pollution of the environmental or suspension of operations. |
These risks could result in substantial losses due to breaches of contractual commitments, personal injury and/or loss of life, damage to and destruction of property and equipment and pollution or other environmental damage. For example, we have experienced releases on our Arrow water gathering system on the Fort Berthold Indian Reservation in North Dakota, the remediation and repair costs of which we believe are covered by insurance, but nonetheless potentially subjects us to substantial penalties, fines and damages from regulatory agencies and individual landowners. These risks may also result in curtailment or suspension of our operations. 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 property insurance on any of our underground pipeline systems that would cover damage to the pipelines. We are also not insured against all environmental accidents that might occur, some of which may result in toxic tort claims. If a significant accident or event occurs for which we are not fully insured, it could result in a material adverse effect on our business, financial condition, results of operations and ability to make distributions.
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 indemnification rights, for potential environmental liabilities. Although we maintain insurance policies with insurers in such amounts and with such coverages and deductibles as we believe are reasonable and prudent, our insurance may not be adequate to protect us from all material expenses related to potential future claims for personal injury and property damage.
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We do not own all of the land on which our pipelines and facilities are located, which could disrupt our operations.
We do not own all of the land on which our pipelines and facilities (particularly our G&P facilities) have been constructed, which subjects us to the possibility of more onerous terms or increased costs to obtain and maintain valid easements and rights-of-way. We obtain standard easement rights to construct and operate pipelines on land owned by third parties, and our rights frequently revert back to the landowner after we stop using the easement for its specified purpose.
Therefore, these easements exist for varying periods of time. Our loss of easement rights could have a material adverse effect on our ability to operate our business, thereby resulting in a material reduction in our revenue, earnings and ability to make distributions.
Terrorist attacks or “cyber security” events, or the threat of them, may adversely affect our business.
The U.S. government has issued public warnings that indicate that pipelines and other assets might be specific targets of terrorist organizations or “cyber security” events. These potential targets might include our pipeline systems or operating systems and may affect our ability to operate or control our pipeline assets, our operations could be disrupted and/or customer information could be stolen. The occurrence of one of these events could cause a substantial decrease in revenues, increased costs to respond or other financial loss, damage to reputation, increased regulation or litigation and or inaccurate information reported from our operations. These developments may subject our operations to increased risks, as well as increased costs, and, depending on their ultimate magnitude, could have a material adverse effect on our business, results of operations and financial condition.
Risks Inherent in an Investment in Us
We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses to enable us to pay quarterly distributions to our common and preferred unitholders.
We may not have sufficient cash each quarter to pay quarterly distributions to our common unitholders or, alternatively, we may reallocate a portion of our available cash to debt repayment or capital investment. The amount of cash we can distribute on our common units principally depends upon the amount of cash we generate from our operations, distributions received from our joint ventures, and payments of fees and expenses as well as decisions the board of directors makes regarding acceptable levels of debt or the desire to invest in new growth projects. Our board typically reviews these factors on a quarterly basis. Before we pay any cash distributions on our preferred and common units, we will establish reserves and pay fees and expenses, including reimbursements to our general partner and its affiliates, for all expenses they incur and payments they make on our behalf. These costs will reduce the amount of cash available to pay distributions to our common unitholders and, to the extent we are unable to declare and pay fixed cash distributions on our preferred units, we cannot make cash distributions to our common unitholders until all payments accruing on the preferred units have been repaid.
The amount of cash we have available to distribute on our preferred and common units will fluctuate from quarter to quarter based on, among other things:
• | the rates charged for services and the amount of services customers purchase, which will be affected by, among other things, the overall balance between the supply of and demand for commodities, governmental regulation of our rates and services, and our ability to obtain permits for growth projects; |
• | force majeure events that damage our or third-party pipelines, facilities, related equipment and surrounding properties; |
• | prevailing economic and market conditions; |
• | governmental regulation, including changes in governmental regulation in our industry; |
• | changes in tax laws; |
• | the level of competition from other midstream companies; |
• | the level of our operating and maintenance and general administrative costs; |
• | the level of capital expenditures we make; |
• | our ability to make borrowings under our revolving credit facility; |
• | our ability to access the capital markets for additional investment capital; and |
• | acceptable levels of debt, liquidity and/or leverage. |
In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including: the level and timing of capital expenditures we make; our debt service requirements and other liabilities; fluctuations in our working capital needs; our ability to borrow funds and access capital markets; restrictions contained in our debt agreements; and the amount of cash reserves established by our general partner.
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Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow given the current trends existing in the capital markets.
Since 2014, the dramatic decrease in commodity prices has negatively impacted the equity and debt markets resulting in limitations on our ability to access the capital markets for new growth capital at a reasonable cost of capital. Historically, we have distributed all of our available cash to our preferred and common unitholders on a quarterly basis and relied upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. If the current capital market trends persist, we may be unable to finance growth externally by accessing the capital markets, and may have to depend on a reallocation of our cash distributions to reduce debt and/or invest in new growth projects. In addition, we may dispose of assets to reduce debt and/or invest in new growth projects, which can impact the level of our cash distributions.
In the event we continue to distribute all of our available cash or decide to reallocate cash to debt reduction, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we decide to reallocate cash to debt reduction or invest in new capital projects, we may be unable to maintain or increase our per unit distribution level. Subject to certain restrictions that apply if we are not able to pay cash distributions to our preferred unitholders, there are no limitations in our partnership agreement on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt 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 unit holders.
We may issue additional common units without common unitholder approval, which would dilute existing common unit holder ownership interests.
Our partnership agreement does not limit the number of additional limited partner interests we may issue at any time without the approval of our existing common unitholders. The issuance of additional common units or other equity interests of equal or senior rank will have the following effects:
• | our existing common unitholders’ proportionate ownership interest in us will decrease; |
• | the amount of cash available for distribution on each common unit may decrease; |
• | the ratio of taxable income to distributions may increase; |
• | the relative voting strength of each previously outstanding common unit may be diminished; and |
• | the market price of the common units may decline. |
Unitholders have less ability to elect or remove management than holders of common stock in a corporation.
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 did not elect, and do not have the right to elect, our general partner or its board of directors on an annual or other continuing basis. The board of directors of our general partner is effectively chosen by Crestwood Holdings, the general partner and only voting member of Holdings LP, the sole member of our general partner. Although our general partner has a fiduciary duty to manage our partnership in a manner beneficial to us and our unitholders, the directors of our general partner also have a fiduciary duty to manage our general partner in a manner beneficial to its sole member, Holdings LP.
If unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. Our general partner generally may not be removed except upon the vote of the holders of 66⅔% of the outstanding units voting together as a single class.
Our unitholders’ voting rights are further restricted by a provision in 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 and its affiliates, cannot be voted on any matter.
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Common unitholders may have liability to repay distributions and in certain circumstances may be personally liable for the obligations of the partnership.
Under certain circumstances, common unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act (the Delaware Act), we may not make a distribution to our common unitholders 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 the 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. A purchaser of units who becomes a limited partner is liable for the obligations of the transferring limited partner to make contributions to the partnership that are known to the purchaser of units at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.
It may be determined that the right, or the exercise of the right by the limited partners as a group, to (i) remove or replace our general partner; (ii) approve some amendments to our partnership agreement; or (iii) take other action under our partnership agreement constitutes “participation in the control” of our business. A limited partner that participates in the control of our business within the meaning of the Delaware Act may be held personally liable for our obligations under the laws of Delaware to the same extent as our general partner. This liability would extend to persons who transact business with us under the reasonable belief that the limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our general partner.
The amount of cash we have available for distribution to common unitholders depends primarily on our cash flow (including distributions from joint ventures) and not solely on profitability, which may prevent us from making cash distributions during periods when we record net income.
The amount of cash we have available for distribution depends primarily upon our cash flow, including cash flow from reserves and working capital or other borrowings and cash distributions received from our joint ventures, and not solely on profitability, which will be affected by non-cash items. As a result, we may pay cash distributions during periods when we record net losses for financial accounting purposes and may not pay cash distributions during periods when we record net income.
Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.
Our partnership agreement restricts unitholders’ voting rights by providing that any units held by a person or group that owns 20% or more of any class of units then outstanding, other than our general partner and 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.
Crestwood Holdings and its affiliates may sell its common units in the public or private markets, and such sales could have an adverse impact on the trading price of the common units. Additionally, Crestwood Holdings may pledge or hypothecate its common units or is interest in Crestwood Holdings LP.
As of December 31, 2017, Crestwood Holdings and its affiliates beneficially held an aggregate of 17,908,700 limited partner units. The sale of any or all 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 on which the common units are traded. Additionally, Crestwood Holdings may pledge or hypothecate its common units or its interest in Crestwood Holdings LP (Holdings LP), the sole member of our general partner, or its subsidiaries. Such pledge or hypothecation may include terms and conditions that might result in an adverse impact on the trading price of our common units.
Our preferred units contain covenants that may limit our business flexibility.
Our preferred units contain covenants preventing us from taking certain actions without the approval of the holders of a majority or a super-majority of the preferred units, depending on the action as described below. The need to obtain the approval of holders of the preferred units before taking these actions could impede our ability to take certain actions that management or our board of directors may consider to be in the best interests of its unit holders. The affirmative vote of the then-applicable voting threshold of the outstanding preferred units, voting separately as a class with one vote per preferred unit, shall be necessary to amend our partnership agreement in any manner that (i) alters or changes the rights, powers, privileges or preferences or duties and obligations of the preferred units in any material respect; (ii) except as contemplated in the
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partnership agreement, increases or decreases the authorized number of preferred units; or (iii) otherwise adversely affects the preferred units, including without limitation the creation (by reclassification or otherwise) of any class of senior securities (or amending the provisions of any existing class of partnership interests to make such class of partnership interests a class of senior securities). In addition, our partnership agreement provides certain rights to the preferred unit holders that could impair our ability to consummate (or increase the cost of consummating) a change-in-control transaction, which could result in less economic benefits accruing to our common unit holders.
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 our unitholders. Furthermore, there is no restriction in our partnership agreement on the ability of the owner of our general partner, Holdings LP, from transferring its ownership interest in our general partner to a third party. Additionally, Holdings LP’s general partner interest in our general partner is pledged as collateral under a Credit Agreement between Crestwood Holdings and various lenders (Holdings Credit Agreement). In the event of a default by Crestwood Holdings under the Holdings Credit Agreement, the lenders may foreclose on the pledged general partner interest and take or transfer control of our general partner without unitholder consent. 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 choices and to control the decisions taken by our board of directors and officers. This effectively permits a “change of control” without the vote or consent of the common unitholders. In addition, such a change of control could result in our indebtedness becoming due. Please read “A change of control could result in us facing substantial repayment obligations under our revolving credit facility and senior notes.”
Potential conflicts of interest may arise among our general partner, its affiliates and us. Our general partner and its affiliates have limited fiduciary duties to us, which may permit them to favor their own interests to the detriment of us.
Conflicts of interest may arise among our general partner and its affiliates, on the one hand, and us, on the other hand. As a result of these conflicts, our general partner may favor its own interests and the interests of its affiliates over our interests. These conflicts include, among others, the following:
• | Our general partner is allowed to take into account the interests of parties other than us in resolving conflicts of interest, which has the effect of limiting its fiduciary duties to us. |
• | Our general partner has limited its liability and reduced its fiduciary duties under the terms of our partnership agreement, while also restricting the remedies available for actions that, without these limitations, might constitute breaches of fiduciary duty. As a result of purchasing our units, unitholders consent to various actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law. |
• | Our general partner determines the amount and timing of our investment transactions, borrowings, issuances of additional partnership securities and reserves, each of which can affect the amount of cash that is available for distribution. |
• | Our general partner determines which costs it and its affiliates have incurred are reimbursable by us. |
• | Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered, or from entering into additional contractual arrangements with any of these entities on our behalf, so long as the terms of any such payments or additional contractual arrangements are fair and reasonable to us. |
• | Our general partner controls the enforcement of obligations owed to us by it and its affiliates. |
• | Our general partner decides whether to retain separate counsel, accountants or others to perform services for us. |
Our partnership agreement limits our general partner’s fiduciary duties to us and restricts the remedies available for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement:
• | provides that our general partner is entitled to make decisions in “good faith” if it reasonably believes that the decisions are in our best interests; |
• | generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the Conflicts Committee of the board of directors of our general partner and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to us and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships among the parties involved, including other transactions that may be particularly advantageous or beneficial to us; and |
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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 assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or engaged in fraud, willful misconduct or gross negligence. |
Our general partner has a limited call right that may require unitholders to sell their units at an undesirable time or price.
If at any time our general partner and its affiliates own more than 80% of our outstanding units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the units held by unaffiliated persons at a price not less than their then-current market price. As a result, unitholders may be required to sell their units at an undesirable time or price and may not receive any return on their investment. Unitholders may also incur a tax liability upon a sale of their units. As of December 31, 2017, the directors and executive officers of our general partner owned approximately 6% of our common units.
Tax Risks to Common Unitholders
Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes. If the IRS were to treat us as a corporation for federal income tax purposes, or we were to become subject to material additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution to unitholders would be substantially reduced.
The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for U.S. federal income tax purposes.
Despite the fact that we are organized as a limited partnership under Delaware law, we would be treated as a corporation for U.S. federal income tax purposes unless we satisfy a “qualifying income” requirement. Based upon our current operations, we believe we satisfy the qualifying income requirement. However, no ruling has been or will be requested regarding our treatment as a partnership for U.S. federal income tax purposes.
Failing to meet the qualifying income requirement 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 federal income tax on our taxable income at the corporate tax rate. Distributions to our unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to our unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our common 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. At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise, or other forms of taxation. Imposition of a similar tax on us in the jurisdictions in which we operate or in other jurisdictions to which we may expand could substantially reduce our cash available for distribution to our unitholders.
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 applied 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 changes or differing interpretations at any time. From time to time, members of Congress propose and consider substantive changes to the existing U.S. federal income tax laws that affect publicly traded partnerships. Although there is no current legislative proposal, a prior legislative proposal would have eliminated 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.
In addition, in January 2017, final regulations regarding which activities give rise to qualifying income within the meaning of Section 7704 of the Internal Revenue Code were published in the Federal Registrar. The final regulations are effective as of January 19, 2017, and apply to taxable years beginning on or after January 19, 2017. We do not believe the final regulations affect our ability to be treated as a partnership for U.S. federal income tax purposes.
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Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.
If the IRS were to contest the federal income tax positions we take, it may adversely impact the market for our common units, and the costs of any such contest would reduce our cash available for distribution to our unitholders.
We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, the costs of any contest with the IRS will be borne indirectly by you and our general partner because the 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 (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced and our current and former unitholders may be required to indemnify us for any taxes (including any applicable penalties and interest) resulting from such audit adjustments that were paid on such unitholders behalf.
Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us. To the extent possible under the new rules, our general partner may elect to either pay the taxes (including any applicable penalties and interest) directly to the IRS or, if we are eligible, issue a revised information statement to each unitholder with respect to an audited and adjusted return. Although our general partner may elect to have our unitholders take such audit adjustment into account in accordance with their interests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible or effective in all circumstances. As a result, our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own units in us during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties and interest, our cash available for distribution to our unitholders might be substantially reduced and our current and former unitholders may be required to indemnify us for any taxes (including any applicable penalties and interest) resulting from such audit adjustments that were paid on such unitholders behalf.
Our unitholders are required to pay taxes on their share of our income even if they do not receive any cash distributions from us.
Our unitholders are required to pay any U.S. federal income taxes and, in some cases, state and local income taxes on their share of our taxable income whether or not they receive cash distributions from us. For example, if we sell assets and use the proceeds to repay existing debt or fund capital expenditures, a unitholder may be allocated taxable income and gain resulting from the sale and our cash available for distribution would not increase. Similarly, taking advantage of opportunities to reduce our existing debt, such as debt exchanges, debt repurchases, or modifications of our existing debt could result in “cancellation of indebtedness income” being allocated to our unitholders as taxable income without any increase in our cash available for distribution. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.
Tax gain or loss on the disposition of our common units could be more or less than expected.
If you sell your common units, you will recognize a gain or loss equal to the difference between your amount realized and your tax basis in those common units. Because distributions in excess of your allocable share of our total net taxable income result in a reduction in your tax basis in your common units, the amount, if any, of such prior excess distributions with respect to the units you sell will, in effect, become taxable income to you if you sell such units at a price greater than your tax basis in those common units, even if the price you receive is less than your original cost. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if you sell your units you may incur a tax liability in excess of the amount of cash you receive from the sale.
Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture of depreciation deductions. Thus, you may recognize both ordinary income and capital loss from the sale of your units if the amount realized on a sale of your units is less than your adjusted basis in the units. Net capital loss may
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only offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per year. In the taxable period in which you sell your units, you may recognize ordinary income from our allocations of income and gain to you prior to the sale and from recapture items that generally cannot be offset by any capital loss recognized upon the sale of units.
Unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.
In general, we are entitled to a deduction for interest paid or accrued on indebtedness properly allocable to our trade or business during our taxable year. However, under the Tax Cuts and Jobs Act, for taxable years beginning after December 31, 2017, our deduction for business interest is limited to the sum our business interest income and 30% of our adjusted taxable income. For the purposes of this limitation, our adjusted taxable income is computed without regard to any business interest expense or business interest income, and in the case of taxable years beginning before January 1, 2022, any deduction allowable for depreciation, amortization, or depletion.
Tax-exempt entities face unique tax issues from our owning common units that may result in adverse tax consequences to them.
Investment in our common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs) 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 and will be taxable to them. Further, with respect to taxable years beginning after December 31, 2017, a tax-exempt entity with more than one unrelated trade or business (including by attribution from investment in a partnership such as ours that is engaged in one or more unrelated trade or business) is required to compute the unrelated business taxable income of such tax-exempt entity separately with respect to each such trade or business (including for purposes of determining any net operating loss deduction). As a result, for years beginning after December 31, 2017, it may not be possible for tax-exempt entities to utilize losses from an investment in our partnership to offset unrelated business taxable income from another unrelated trade or business and vice versa. Tax-exempt entities should consult a tax advisor before investing in our common units.
Non-U.S. unitholders will be subject to U.S. taxes and withholding with respect to their income and gain from owning our units.
Non-U.S. unitholders are generally taxed and subject to income tax filing requirements by the United States on income effectively connected with a U.S. trade or business (“effectively connected income”). Income allocated to our unitholders and any gain from the sale of our units will generally be considered to be “effectively connected” with a U.S. trade or business. As a result, distributions to a Non-U.S. unitholder will be subject to withholding at the highest applicable effective tax rate and a Non-U.S. unitholder who sells or otherwise disposes of a unit will also be subject to U.S. federal income tax on the gain realized from the sale or disposition of that unit.
The Tax Cut and Jobs Act imposes a withholding obligation of 10% of the amount realized upon a Non-U.S. unitholder’s sale or exchange of an interest in a partnership that is engaged in a U.S. trade or business. However, due to challenges of administering a withholding obligation applicable to open market trading and other complications, the IRS has temporarily suspended the application of this withholding rule to open market transfers of interest in publicly traded partnerships pending promulgation of regulations or other guidance that resolves the challenges. It is not clear if or when such regulations or other guidance will be issued. Non-U.S. unitholders should consult a tax advisor before investing in our common units.
We will treat each purchaser of our common units as having the same tax benefits without regard to the specific common units purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units.
Because we cannot match transferors and transferees of common units and because of other reasons, we will adopt 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 you. It also could affect the timing of these tax benefits or the amount of gain from the sale of our common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of 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 our unitholders.
We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month (the Allocation Date), instead of on the basis of the date a particular unit is transferred. Similarly, we generally allocate certain deductions for depreciation of capital additions, gain or loss realized on a sale or other disposition of our assets and, in the discretion of the general partner, any other extraordinary
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item of income, gain, loss or deduction based upon ownership on the Allocation Date. Treasury Regulations allow a similar monthly simplifying convention, but such regulations do not specifically authorize all aspects of our proration method. 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 our unitholders.
A unitholder whose common units are the subject of a securities loan (i.e., a loan to a “short seller” to cover a short sale of common units) may be considered as having disposed of those common units. If so, he 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 there are no specific rules governing the U.S. federal income tax consequences of loaning a partnership interest, a unitholder whose common units are the subject of a securities loan may be considered as having disposed of the loaned units. In that case, he may no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, 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. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller should modify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units.
Our unitholders will likely be subject to state and local taxes and return filing requirements in jurisdictions where they do not live as a result of investing in our common units.
In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes, estate, inheritance or intangible taxes and foreign taxes that are imposed by the various jurisdictions in which we do business or own property and in which they do not reside. We own property and conduct business in various parts of the United States. Unitholders may be required to file state and local income tax returns in many or all of the jurisdictions in which we do business or own property. Further, unitholders may be subject to penalties for failure to comply with those requirements. It is our unitholders’ responsibility to file all required U. S. federal, state, local and foreign tax returns.
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Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
A description of our properties is included in Item 1. Business, and is incorporated herein by reference. We also lease office space for our corporate offices in Houston, Texas and Kansas City, Missouri.
We lease and rely upon our customers’ property rights to conduct a substantial part of our operations, and we own or lease the property rights necessary to conduct our storage and transportation operations. We believe that we have satisfactory title to our assets. Title to property may be subject to encumbrances. For example, we have granted to the lenders of our revolving credit facility security interests in substantially all of our real property interests. We believe that none of these encumbrances will materially detract from the value of our properties or from our interest in these properties, nor will they materially interfere with their use in the operation of our business.
Item 3. Legal Proceedings
A description of our legal proceedings is included in Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 15, and is incorporated herein by reference.
Item 4. Mine Safety Disclosures
Not applicable.
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PART II
Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities
Crestwood Equity. Crestwood Equity’s common units representing limited partner interests are traded on the NYSE under the symbol “CEQP.” The following table sets forth the range of high and low sales prices of the common units, as reported by the NYSE, as well as the amount of cash distributions declared per common unit for the periods indicated.
Quarters Ended: | Low | High | Cash Distribution Per Unit | ||||||||
2017 | |||||||||||
December 31, 2017 | $ | 22.15 | $ | 26.10 | $ | 0.600 | |||||
September 30, 2017 | 22.30 | 26.65 | 0.600 | ||||||||
June 30, 2017 | 20.00 | 27.35 | 0.600 | ||||||||
March 31, 2017 | 24.35 | 28.30 | 0.600 | ||||||||
2016 | |||||||||||
December 31, 2016 | $ | 18.51 | $ | 25.70 | $ | 0.600 | |||||
September 30, 2016 | 18.67 | 22.22 | 0.600 | ||||||||
June 30, 2016 | 10.40 | 23.59 | 0.600 | ||||||||
March 31, 2016 | 7.90 | 21.56 | 0.600 | ||||||||
The last reported sale price of Crestwood Equity’s common units on the NYSE on February 12, 2018, was $26.95. As of that date, Crestwood Equity had 71,231,599 common units issued and outstanding, which were held by 259 unitholders of record.
Distribution Policy
Preferred Units. We are required to make quarterly distributions to our preferred unitholders. The holders of the Preferred Units are entitled to receive fixed quarterly distributions of $0.2111 per unit. Through the quarter ending September 30, 2017 (the Initial Distribution Period), distributions on the Preferred Units could be made in additional Preferred Units, cash, or a combination thereof, at our election. Through and for the quarter ended June 30, 2017, we paid distributions on our Preferred Units through the issuance of additional Preferred Units. The number of units distributed was calculated as the fixed quarterly distribution of $0.2111 per unit divided by the cash purchase price of $9.13 per unit. We accrued the fair value of such distribution at the end of the quarterly period and adjusted the fair value of the distribution on the date the additional Preferred Units were distributed. Distributions on the Preferred Units following the Initial Distribution Period will be paid in in cash unless, subject to certain exceptions, (i) there is no distribution being paid on our common units; and (ii) our available cash (as defined in our partnership agreement) is insufficient to make a cash distribution to our Preferred Unit holders. If we fail to pay the full amount payable to our Preferred Unit holders in cash following the Initial Distribution Period, then (x) the fixed quarterly distribution on the Preferred Units will increase to $0.2567 per unit, and (y) we will not be permitted to declare or make any distributions to our common unitholders until such time as all accrued and unpaid distributions on the Preferred Units have been paid in full in cash. In addition, if we fail to pay in full any Preferred Distribution (as defined in our partnership agreement), the amount of such unpaid distribution will accrue and accumulate from the last day of the quarter for which such distribution is due until paid in full, and any accrued and unpaid distributions will be increased at a rate of 2.8125% per quarter.
Common Units. Crestwood Equity makes quarterly distributions to its partners within approximately 45 days after the end of each fiscal quarter in an aggregate amount equal to our available cash for such quarter. Available cash generally means, with respect to each fiscal quarter, all cash on hand at the end of the quarter less the amount of cash that the general partner determines in its reasonable discretion is necessary or appropriate to:
• | provide for the proper conduct of our business, including but not limited to, debt repayments, unit buybacks or capital investment; |
• | comply with applicable law, any of our debt instruments, or other agreements; or |
• | provide funds for distributions to unitholders for any one or more of the next four quarters; |
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plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made subsequent to the end of the quarter. Working capital borrowings are generally borrowings that are made under our revolving credit facility and in all cases are used solely for working capital purposes or to pay distributions to its partners.
On February 14, 2018, Crestwood Equity paid a distribution of $0.60 per limited partner unit ($2.40 per limited partner unit on an annualized basis) to its unitholders of record on February 7, 2018.
Issuer Purchases of Equity Securities
For the year ended December 31, 2017, we relinquished 206,600 common units to cover payroll taxes upon the vesting of restricted units.
Equity Compensation Plan Information
The following table sets forth in tabular format, a summary of the Crestwood Equity equity compensation plan information as of December 31, 2017:
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)) | ||||||
(a) | (b) | (c) | |||||||
Equity compensation plans approved by security holders | — | $ | — | — | |||||
Equity compensation plans not approved by security holders | — | $ | — | 4,157,742 | |||||
Total | — | $ | — | 4,157,742 | |||||
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Item 6. Selected Financial Data
Crestwood Midstream. This information has been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.
Crestwood Equity. Crestwood Equity’s consolidated financial statements were originally the financial statements of Legacy Crestwood GP prior to being acquired by us on June 19, 2013. Our acquisition of Legacy Crestwood GP was accounted for as a reverse acquisition under the purchase method of accounting in accordance with the accounting standards for business combinations. The accounting for a reverse acquisition results in the legal acquiree (Legacy Crestwood GP) being the acquirer for accounting purposes. Although Legacy Crestwood GP was the acquirer for accounting purposes, we were the acquirer for legal purposes; consequently, we changed our name from Crestwood Gas Services GP, LLC to Crestwood Equity Partners LP.
The income statement and cash flow data for each of the three years ended December 31, 2017 and balance sheet data as of December 31, 2017 and 2016 were derived from our audited financial statements. We derived the income statement and cash flow data for each of the two years ended December 31, 2014 and the balance sheet data as of December 31, 2015, 2014 and 2013 from our accounting records. The selected financial data is not necessarily indicative of results to be expected in future periods and should be read together with Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Part IV, Item 15. Exhibits and Financial Statement Schedules included elsewhere in this report.
EBITDA and Adjusted EBITDA - We believe that EBITDA and Adjusted EBITDA are widely accepted financial indicators of a company’s operational performance and its ability to incur and service debt, fund capital expenditures and make distributions. We believe that EBITDA and Adjusted EBITDA are useful to our investors because it allows them to use the same performance measure analyzed internally by our management to evaluate the performance of our businesses and investments without regard to the manner in which they are financed or our capital structure. EBITDA is defined as income before income taxes, plus debt-related costs (interest and debt expense, net, and gain (loss) on modification/extinguishment of debt) and depreciation, amortization and accretion expense. Adjusted EBITDA considers the adjusted earnings impact of our unconsolidated affiliates by adjusting our equity earnings or losses from our unconsolidated affiliates to reflect our proportionate share (based on the distribution percentage) of their EBITDA, excluding impairments. Adjusted EBITDA also considers the impact of certain significant items, such as unit-based compensation charges, gains and losses on long-lived assets, impairments of long-lived assets and goodwill, gains and losses on acquisition-related contingencies, third party costs incurred related to potential and completed acquisitions, certain environmental remediation costs, certain costs related to our historical cost saving initiatives, the change in fair value of commodity inventory-related derivative contracts, costs associated with our 2017 realignment of our Marketing, Supply and Logistics operations and related consolidation and relocation of our corporate offices, and other transactions identified in a specific reporting period. The change in fair value of commodity inventory-related derivative contracts is considered in determining Adjusted EBITDA given that the timing of recognizing gains and losses on these derivative contracts differs from the recognition of revenue for the related underlying sale of inventory to which these derivatives relate. Changes in the fair value of other derivative contracts is not considered in determining Adjusted EBITDA given the relatively short-term nature of those derivative contracts. EBITDA and Adjusted EBITDA are not measures calculated in accordance with GAAP, as they do not include deductions for items such as depreciation, amortization and accretion, interest and income taxes, which are necessary to maintain our business. EBITDA and Adjusted EBITDA should not be considered as alternatives to net income, operating cash flow or any other measure of financial performance presented in accordance with GAAP. EBITDA and Adjusted EBITDA calculations may vary among entities, so our computation may not be comparable to measures used by other companies.
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Crestwood Equity Partners LP | ||||||||||||||||||||
Year Ended December 31, | ||||||||||||||||||||
2017 | 2016 | 2015 | 2014 | 2013 (1) | ||||||||||||||||
(in million, except per unit data) | ||||||||||||||||||||
Statement of Income Data: | ||||||||||||||||||||
Revenues | $ | 3,880.9 | $ | 2,520.5 | $ | 2,632.8 | $ | 3,931.3 | $ | 1,426.7 | ||||||||||
Operating income (loss) | (79.4 | ) | (108.7 | ) | (2,084.8 | ) | 117.9 | 28.2 | ||||||||||||
Loss before income taxes | (167.4 | ) | (191.8 | ) | (2,305.1 | ) | (9.3 | ) | (49.6 | ) | ||||||||||
Net loss | (166.6 | ) | (192.1 | ) | (2,303.7 | ) | (10.4 | ) | (50.6 | ) | ||||||||||
Net income (loss) attributable to Crestwood Equity Partners LP | (191.9 | ) | (216.3 | ) | (1,666.9 | ) | 56.4 | 6.7 | ||||||||||||
Performance Measures: | ||||||||||||||||||||
Diluted net income (loss) per limited partner unit: (2) | $ | (3.64 | ) | $ | (3.55 | ) | $ | (54.00 | ) | $ | 3.30 | $ | 0.59 | |||||||
Distributions declared per limited partner unit(3) | $ | 2.40 | $ | 3.175 | $ | 5.50 | $ | 5.50 | $ | 6.925 | ||||||||||
Other Financial Data: | ||||||||||||||||||||
EBITDA (unaudited) | $ | 161.4 | $ | 152.9 | $ | (1,844.9 | ) | $ | 403.1 | $ | 196.2 | |||||||||
Adjusted EBITDA (unaudited) | 395.4 | 455.6 | 527.4 | 495.9 | 297.7 | |||||||||||||||
Net cash provided by operating activities | 255.9 | 346.1 | 440.7 | 283.0 | 188.3 | |||||||||||||||
Net cash provided by (used in) investing activities | 38.7 | 867.2 | (212.7 | ) | (483.0 | ) | (1,042.9 | ) | ||||||||||||
Net cash provided by (used in) financing activities | (294.9 | ) | (1,212.2 | ) | (236.3 | ) | 203.6 | 859.7 | ||||||||||||
Balance Sheet Data: | ||||||||||||||||||||
Property, plant and equipment, net | $ | 1,820.8 | $ | 2,097.6 | $ | 3,310.8 | $ | 3,893.8 | $ | 3,905.3 | ||||||||||
Total assets | 4,284.9 | 4,448.9 | 5,762.8 | 8,421.7 | 8,476.0 | |||||||||||||||
Total debt, including current portion | 1,492.2 | 1,523.7 | 2,502.9 | 2,356.8 | 2,218.8 | |||||||||||||||
Other long-term liabilities(4) | 104.7 | 44.6 | 47.5 | 47.2 | 140.4 | |||||||||||||||
Partners’ capital | 2,180.5 | 2,539.0 | 2,946.9 | 5,584.5 | 5,508.6 | |||||||||||||||
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Crestwood Equity Partners LP | ||||||||||||||||||||
Year Ended December 31, | ||||||||||||||||||||
2017 | 2016 | 2015 | 2014 | 2013 (1) | ||||||||||||||||
(in millions) | ||||||||||||||||||||
Reconciliation of Net Income to EBITDA and Adjusted EBITDA: | ||||||||||||||||||||
Net loss | $ | (166.6 | ) | $ | (192.1 | ) | $ | (2,303.7 | ) | $ | (10.4 | ) | $ | (50.6 | ) | |||||
Depreciation, amortization and accretion | 191.7 | 229.6 | 300.1 | 285.3 | 167.9 | |||||||||||||||
Interest and debt expense, net | 99.4 | 125.1 | 140.1 | 127.1 | 77.9 | |||||||||||||||
(Gain) loss on modification/extinguishment of debt | 37.7 | (10.0 | ) | 20.0 | — | — | ||||||||||||||
Provision (benefit) for income taxes | (0.8 | ) | 0.3 | (1.4 | ) | 1.1 | 1.0 | |||||||||||||
EBITDA | 161.4 | 152.9 | (1,844.9 | ) | 403.1 | 196.2 | ||||||||||||||
Unit-based compensation charges | 25.5 | 19.2 | 19.7 | 21.3 | 17.4 | |||||||||||||||
(Gain) loss on long-lived assets, net(5) | 65.6 | 65.6 | 821.2 | 1.9 | (5.3 | ) | ||||||||||||||
Goodwill impairment(6) | 38.8 | 162.6 | 1,406.3 | 48.8 | 4.1 | |||||||||||||||
Loss on contingent consideration(7) | 57.0 | — | — | 8.6 | 31.4 | |||||||||||||||
(Earnings) loss from unconsolidated affiliates, net(8) | (47.8 | ) | (31.5 | ) | 60.8 | 0.7 | 0.1 | |||||||||||||
Adjusted EBITDA from unconsolidated affiliates, net | 80.3 | 61.1 | 25.3 | 6.9 | 2.5 | |||||||||||||||
Change in fair value of commodity inventory-related derivative contracts | 2.2 | 14.1 | 5.4 | (10.3 | ) | 10.7 | ||||||||||||||
Significant transaction and environmental-related costs and other items(9) | 12.4 | 11.6 | 33.6 | 14.9 | 40.6 | |||||||||||||||
Adjusted EBITDA | $ | 395.4 | $ | 455.6 | $ | 527.4 | $ | 495.9 | $ | 297.7 | ||||||||||
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Crestwood Equity Partners LP | ||||||||||||||||||||
Year Ended December 31, | ||||||||||||||||||||
2017 | 2016 | 2015 | 2014 | 2013 (1) | ||||||||||||||||
(in millions) | ||||||||||||||||||||
Reconciliation of Net Cash Provided by Operating Activities to EBITDA and Adjusted EBITDA: | ||||||||||||||||||||
Net cash provided by operating activities | $ | 255.9 | $ | 346.1 | $ | 440.7 | $ | 283.0 | $ | 188.3 | ||||||||||
Net changes in operating assets and liabilities | (0.3 | ) | (57.9 | ) | (98.0 | ) | 73.8 | (19.6 | ) | |||||||||||
Amortization of debt-related deferred costs, discounts and premiums | (7.2 | ) | (6.9 | ) | (8.9 | ) | (8.5 | ) | (9.2 | ) | ||||||||||
Interest and debt expense, net | 99.4 | 125.1 | 140.1 | 127.1 | 77.9 | |||||||||||||||
Market adjustment on interest rate swaps | — | — | 0.5 | 2.7 | 1.7 | |||||||||||||||
Unit-based compensation charges | (25.5 | ) | (19.2 | ) | (19.7 | ) | (21.3 | ) | (17.4 | ) | ||||||||||
Gain (loss) on long-lived assets, net(5) | (65.6 | ) | (65.6 | ) | (821.2 | ) | (1.9 | ) | 5.3 | |||||||||||
Goodwill impairment(6) | (38.8 | ) | (162.6 | ) | (1,406.3 | ) | (48.8 | ) | (4.1 | ) | ||||||||||
Loss on contingent consideration(7) | (57.0 | ) | — | — | (8.6 | ) | (31.4 | ) | ||||||||||||
Earnings (loss) from unconsolidated affiliates, net, adjusted for cash distributions received | 0.1 | (7.6 | ) | (73.6 | ) | (0.7 | ) | (0.1 | ) | |||||||||||
Deferred income taxes | 2.1 | 3.1 | 3.6 | 5.2 | 2.8 | |||||||||||||||
Provision (benefit) for income taxes | (0.8 | ) | 0.3 | (1.4 | ) | 1.1 | 1.0 | |||||||||||||
Other non-cash income (expense) | (0.9 | ) | (1.9 | ) | (0.7 | ) | — | 1.0 | ||||||||||||
EBITDA | 161.4 | 152.9 | (1,844.9 | ) | 403.1 | 196.2 | ||||||||||||||
Unit-based compensation charges | 25.5 | 19.2 | 19.7 | 21.3 | 17.4 | |||||||||||||||
(Gain) loss on long-lived assets, net(5) | 65.6 | 65.6 | 821.2 | 1.9 | (5.3 | ) | ||||||||||||||
Goodwill impairment(6) | 38.8 | 162.6 | 1,406.3 | 48.8 | 4.1 | |||||||||||||||
Loss on contingent consideration(7) | 57.0 | — | — | 8.6 | 31.4 | |||||||||||||||
(Earnings) loss from unconsolidated affiliates, net(8) | (47.8 | ) | (31.5 | ) | 60.8 | 0.7 | 0.1 | |||||||||||||
Adjusted EBITDA from unconsolidated affiliates, net | 80.3 | 61.1 | 25.3 | 6.9 | 2.5 | |||||||||||||||
Change in fair value of commodity inventory-related derivative contracts | 2.2 | 14.1 | 5.4 | (10.3 | ) | 10.7 | ||||||||||||||
Significant transaction and environmental-related costs and other items(9) | 12.4 | 11.6 | 33.6 | 14.9 | 40.6 | |||||||||||||||
Adjusted EBITDA | $ | 395.4 | $ | 455.6 | $ | 527.4 | $ | 495.9 | $ | 297.7 | ||||||||||
(1) | Financial data presented for periods prior to June 19, 2013, solely reflect the operations of Legacy Crestwood GP. Financial data for periods subsequent to June 19, 2013, represent the consolidated operations of Crestwood Equity. |
(2) | The weighted average number of units outstanding is calculated based on the presumption that the common and subordinated units issued to acquire Legacy Crestwood GP (the accounting predecessor) were outstanding for the entire period prior to the June 19, 2013 acquisition. On the date of the acquisition, all of our limited partner units were considered outstanding. In addition, on November 23, 2015, CEQP completed a 1-for-10 reverse split of its common units. The accounting standards related to earnings per share requires an entity to restate earnings per share when a stock dividend or stock split occurs, and as such, the earnings per unit for the years ended December 31, 2014 and 2013, were restated to reflect the 1-for-10 reverse split. |
(3) | Reported amounts include the fourth quarter distributions, which are paid in the first quarter of the subsequent year. |
(4) | Other long-term liabilities primarily include our capital leases, asset retirement obligations, loss on contingent consideration, net and the fair value of unfavorable contracts recorded in purchase accounting. |
(5) | During 2017, we recognized a gain of approximately $33.6 million from the sale of US Salt. For a further discussion of this transaction, see Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 3. During 2016, we recorded a loss of approximately $32.4 million on the deconsolidation of our NE S&T assets. For a further discussion of this transaction, see Part IV, Item 15. Exhibits, Financial Statement Schedules, Notes 2 and 6. During 2014, we recorded a gain of approximately $30.6 million on the sale of our investment in Tres Palacios. In addition, during 2017, 2015 and 2014, we recorded property, plant and equipment impairments of approximately $81.4 million, $501.7 million and $13.2 million. During 2017, 2016, 2015 and 2014, we recorded intangible asset impairments of approximately $0.8 million, $31.4 million, $316.6 million and $21.3 million. For a further discussion, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - “Critical Accounting Estimates” and Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 2. |
(6) | For a further discussion of our goodwill impairments recorded during 2017, 2016, 2015 and 2014, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - “Critical Accounting Estimates” and Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 2. |
(7) | During 2017, the loss on contingent consideration related to our obligation to CEGP due to our expectation of certain criteria on growth capital projects not being met by Stagecoach Gas. For a further discussion, see Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 6. During 2014 and 2013, we recorded a loss on contingent consideration which reflects the fair value of an earn-out premium associated with the original acquisition of our Marcellus G&P assets from Antero in 2012. |
(8) | During 2015, we recorded impairments of our PRBIC and Jackalope equity investments of approximately $23.4 million and $51.4 million. For a further discussion of these impairments, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - “Critical Accounting Estimates” and Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 2. |
(9) | Significant transaction and environmental-related costs and other items primarily include costs incurred related to the Simplification Merger and other merger, acquisition and joint venture transactions, as well as costs associated with our historical cost savings initiatives and the realignment of our MS&L operations and related consolidation and relocation of our corporate offices. |
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Our Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with our consolidated financial statements and the accompanying footnotes.
This report, including information included or incorporated by reference herein, contains forward-looking statements concerning the financial condition, results of operations, plans, objectives, future performance and business of our company and its subsidiaries. These forward-looking statements include:
• | statements that are not historical in nature, including, but not limited to: (i) our belief that anticipated cash from operations, cash distributions from entities that we control, and borrowing capacity under our credit facility will be sufficient to meet our anticipated liquidity needs for the foreseeable future; (ii) our belief that we do not have material potential liability in connection with legal proceedings that would have a significant financial impact on our consolidated financial condition, results of operations or cash flows; and (iii) our belief that our assets will continue to benefit from the development of unconventional shale plays as significant supply basins; and |
• | statements preceded by, followed by or that contain forward-looking terminology including the words “believe,” “expect,” “may,” “will,” “should,” “could,” “anticipate,” “estimate,” “intend” or the negation thereof, or similar expressions. |
Forward-looking statements are not guarantees of future performance or results. They involve risks, uncertainties and assumptions. Actual results may differ materially from those contemplated by the forward-looking statements due to, among others, the following factors:
• | our ability to successfully implement our business plan for our assets and operations; |
• | governmental legislation and regulations; |
• | industry factors that influence the supply of and demand for crude oil, natural gas and NGLs; |
• | industry factors that influence the demand for services in the markets (particularly unconventional shale plays) in which we provide services; |
• | weather conditions; |
• | the availability of crude oil, natural gas and NGLs, and the price of those commodities, to consumers relative to the price of alternative and competing fuels; |
• | economic conditions; |
• | costs or difficulties related to the integration of acquisitions and success of our joint ventures’ operations; |
• | environmental claims; |
• | operating hazards and other risks incidental to the provision of midstream services, including gathering, compressing, treating, processing, fractionating, transporting and storing energy products (i.e., crude oil, NGLs and natural gas) and related products (i.e., produced water); |
• | interest rates; |
• | the price and availability of debt and equity financing, including our ability to raise capital through alternatives like joint ventures; and |
• | the ability to sell or monetize assets, to reduce indebtedness, to repurchase our equity securities, to make strategic investments, or for other general partnership purposes. |
We have described under Part I, Item 1A. Risk Factors, additional factors that could cause actual results to be materially different from those described in the forward-looking statements. Other factors that we have not identified in this report could also have this effect.
Overview
We own and operate crude oil, natural gas and NGL midstream assets and operations. Headquartered in Houston, Texas, we are a fully-integrated midstream solution provider that specializes in connecting shale-based energy supplies to key demand markets. We conduct our operations through our wholly-owned subsidiary, Crestwood Midstream, a limited partnership that owns and operates gathering, processing, storage, and transportation assets in the most prolific shale plays across the United States.
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Our Company
We provide broad-ranging services to customers across the crude oil, natural gas and NGL sector of the energy value chain. Our midstream infrastructure is geographically located in or near significant supply basins, especially developed and emerging liquids-rich and crude oil shale plays, across the United States. We own or control:
• | natural gas facilities with approximately 2.4 Bcf/d of gathering capacity and 0.5 Bcf/d of processing capacity; |
• | NGL facilities with approximately 20,000 Bbls/d of fractionation capacity and 3.1 MMBbls of storage capacity, as well as our portfolio of transportation assets (consisting of truck and rail terminals, truck/trailer units and rail cars) capable of transporting approximately 195,000 Bbls/d of NGLs; and |
• | crude oil facilities with approximately 125,000 Bbls/d of gathering capacity, 1.5 MMBbls of storage capacity, 20,000 Bbls/d of transportation capacity, and 160,000 Bbls/d of rail loading capacity. |
In addition, through our equity investments in joint ventures, we have ownership interests in:
• | natural gas facilities with approximately 0.3 Bcf/d of gathering capacity, 0.2 Bcf/d of processing capacity, 75.8 Bcf of certificated working storage capacity, and 1.5 Bcf/d of transportation capacity; and |
• | crude oil facilities with approximately 20,000 Bbls/d of rail loading capacity and 380,000 Bbls of working storage capacity. |
Our financial statements reflect three operating and reporting segments: (i) gathering and processing, which includes our natural gas, crude oil and produced water G&P operations; (ii) storage and transportation, which includes our natural gas and crude oil storage and transportation operations; and (iii) marketing, supply and logistics, which includes our NGL supply and logistics business, crude oil storage and rail loading facilities and fleet.
Gathering and Processing
Our G&P operations and investments provide gathering, compression, treating, and processing services to producers in multiple unconventional resource plays across the United States and we have established footprints in “core of the core” areas of many of the largest shale plays. We believe that our strategy of focusing on prolific, low-cost shale plays positions us well to (i) generate greater returns in varying commodity price environments, (ii) capture greater upside economics when development activity occurs, and (iii) in general, better manage through commodity price cycles and production changes associated therewith.
Our G&P operations primarily include:
• | Bakken. We own and operate an integrated crude oil, natural gas and produced water gathering system and processing facility (the Arrow system) in the core of the Bakken Shale in McKenzie and Dunn Counties, North Dakota, some of which is located on Fort Berthold Indian Reservation. The Arrow system consists of 640 miles of low-pressure gathering pipeline capable of gathering 100 MMcf/d of natural gas, 125 MBbls/d of crude oil, 40 MBbls/d of produced water, and the Bear Den processing plant includes approximately 30 MMcf/d of natural gas processing capacity. We also have approximately 266,000 Bbls of crude oil working storage capacity at the Arrow central delivery point; |
• | Marcellus. We own and operate natural gas gathering and compression systems in Harrison, Doddridge and Barbour Counties, West Virginia. These systems have a total gathering capacity of 875 MMcf/d and 131,380 horsepower of compression; |
• | Barnett. We own and operate (i) a low-pressure natural gas gathering system with a gathering capacity of approximately 425 MMcf/d of rich gas produced by our customers in Hood and Somervell Counties, Texas, which delivers the rich gas to our processing plant where NGLs are extracted from the natural gas stream; and (ii) low-pressure gathering systems with a gathering capacity of 500 MMcf/d of dry natural gas produced by our customers in Tarrant and Denton Counties, Texas; |
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• | Fayetteville. We own and operate five low-pressure gas gathering systems with a gathering capacity of approximately 510 MMcf/d of dry natural gas produced by our customers in Conway, Faulkner, Van Buren, and White Counties, Arkansas; |
• | Granite Wash. We own and operate a low-pressure natural gas gathering system with a gathering capacity of approximately 36 MMcf/d of rich gas produced by our customers in Roberts County, Texas, and a processing plant that extracts NGLs from the natural gas stream; |
• | Delaware Permian. We own a 50% equity interest in the Crestwood Permian joint venture with an affiliate of First Reserve. We operate the joint venture, which owns low-pressure dry gas and rich natural gas gathering systems with a primary focus on the Willow Lake system, which includes approximately 75 MMcf/d of processing capacity that serves our customers in Eddy County, New Mexico. The joint venture also owns a 50% equity interest in Crestwood Permian Basin. In October 2017, Shell Midstream purchased a 50% equity interest in Crestwood Permian Basin. Crestwood Permian Basin owns and operates the Nautilus gathering system for SWEPI’s gas production in an area of dedication (approximately 100,000 acres) in Loving, Reeves and Ward Counties, Texas. The initial build-out of the Nautilus gathering system was completed on June 6, 2017, and includes 20 receipt point meters, 60 miles of pipeline, a 24-mile high pressure header system, 10,800 horsepower of compression and a high pressure delivery point. The Nautilus gathering system is supported by a 20-year fixed-fee gathering agreement with SWEPI; and |
• | Powder River Basin. We own a 50% equity interest in the Jackalope joint venture with Williams. The joint venture, operated by Williams, owns the Jackalope gas gathering system and Bucking Horse processing plant. The Jackalope system is supported by a 10-year gathering and processing agreement with Chesapeake under an area of dedication of approximately 358,000 gross acres in the core of the Powder River Basin; |
Although the cash flows from our G&P operations are predominantly fee-based under contracts with original terms ranging from 5-20 years, the results of our G&P operations are significantly influenced by the volumes gathered and processed through our systems. For example, due to market conditions that ultimately resulted in 2015 bankruptcy filings of two of our G&P customers (Quicksilver and Sabine), we gathered significantly lower volumes for those customers during 2015 and 2016 as they continued to shut-in wells during their respective bankruptcy proceedings. In April 2016, BlueStone bought Quicksilver’s assets out of bankruptcy and thereafter returned to production wells that were previously shut-in by Quicksilver. We entered into new 10-year agreements with BlueStone to gather and process its production under fixed-fee and percent-of-proceeds fee structures, and pursuant to the agreements, BlueStone will not shut-in or choke back production for economic purposes through the end of 2018. As a result, the volumes we are now gathering and processing have returned to levels consistent with those preceding Quicksilver’s bankruptcy filing. In March 2017, the Sabine bankruptcy proceedings were settled by the district court for the Southern District of New York, and the outcome was not material to our G&P segment’s results of operations.
The cash flows from our G&P operations can also be impacted in the short term by changing commodity prices, seasonality and weather fluctuations. We gather, process, treat, compress, transport and sell crude oil and natural gas pursuant to a variety of contracts. These contracts include:
• | Fixed-fee contracts. Under these contracts, we do not take title to the underlying crude, natural gas or NGLs but charge our customers a fixed-fee per volume gathered, processed, treated, compressed and/or transported. Certain of these agreements can contain commitments for a minimum level of volumes or revenues; |
• | Percentage-of-proceeds service contracts. Under these contracts, we effectively take title to crude, natural gas or NGLs after the commodity leaves our gathering and processing facilities. We often market and sell those commodities to third parties after they leave our facilities and we will remit a portion of the sales proceeds to our producers; |
• | Percentage-of-proceeds product contracts. Under these contracts, we effectively take title to crude, natural gas or NGLs before the commodity enters our gathering and processing facilities. We market and sell those commodities to third parties and we will remit a portion of the sales proceeds to our producers; and |
• | Purchase and sale contracts. Under these contracts, we purchase crude, natural gas or NGLs before the commodity enters our gathering and processing facilities, and we market and sell those commodities to third parties. |
Our election to enter primarily into fixed-fee contracts minimizes our G&P segment’s commodity price exposure and provides us more stable operating performance and cash flows.
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Storage and Transportation
Our S&T operations and investments consist of our crude oil terminals in the Bakken and Powder River Basin and our natural gas storage and transportation assets in the Northeast and Texas Gulf Coast, including:
• | Bakken. We own and operate the COLT Hub, which is one of the largest crude oil rail terminals in the Bakken Shale based on actual throughput. Located approximately 60 miles from Arrow’s central delivery point, the COLT Hub interconnects with the Arrow system through the Hiland and Andeavor pipeline systems. The COLT Hub, which can receive approximately 350,000 Bbls/d from interconnected gathering systems, is capable of loading up to 160,000 Bbls/d and storing approximately 1.2 MMBbls of crude oil. Moreover, because the COLT Hub and our Arrow system each interconnect with the DAPL interstate system, our Bakken crude oil assets are integrated and offer customers multiple service options since the DAPL interstate pipeline system was placed in service in 2017; |
• | Powder River Basin. PRBIC, our 50% equity method investment, owns an integrated crude oil loading, storage and pipeline terminal, located in Douglas County, Wyoming, which provides a market for crude oil production from the Powder River Basin. The joint venture, which is operated by our joint venture partner, Twin Eagle, sources crude oil production from Chesapeake and other Powder River Basin producers. PRBIC includes 20,000 Bbls/d of rail loading capacity and 380,000 Bbls of crude oil working storage capacity. The terminal connects to Kinder Morgan’s Double H Pipeline system and Plains All American Pipeline’s Rocky Mountain Pipeline system; |
• | Marcellus. Stagecoach Gas, our 50% equity method investment, owns four natural gas storage facilities (Stagecoach, Thomas Corners, Steuben and Seneca Lake) and three transportation pipelines (North/South Facilities, MARC I and the East Pipeline) located in or near the dry portion of the Marcellus Shale. The natural gas storage facilities provide 40.9 Bcf of certificated firm storage capacity and 1.5 Bcf/d of firm transportation capacity to producers, utilities, marketers and other customers. The location of these assets relative to New York City and other premium demand markets along the East Coast, together with the formation of our joint venture with a subsidiary of Consolidated Edison, helps to insulate our operations from production and commodity price changes that can impact storage and transportation operators in other geographic regions; and |
• | Texas Gulf Coast. Tres Holdings, our 50.01% equity method investment owns a FERC-certificated 34.9 Bcf multi-cycle, salt dome natural gas storage facility. The Tres Palacios storage facility’s 63-mile, dual 24-inch diameter header system (including a 52-mile north pipeline lateral and an approximate 11-mile south pipeline lateral) interconnects with 11 pipeline systems and can receive residue gas from the tailgate of Kinder Morgan Inc.’s Houston central processing plant. |
The cash flows from our S&T operations are predominantly fee-based under contracts with an original term ranging from 1-10 years. Our current cash flows from crude-by-rail facilities are supported by take-or-pay contracts with refiners and marketers. The rates and durations of the contracts associated with our crude oil terminals have eroded as pipelines come on-line that make crude-by-rail options less economical, which impacts our cash flows from operations. Cash flows from interruptible and other hub services provided by the natural gas storage facilities and pipelines owned by our joint ventures tends to increase during the peak winter season.
Marketing, Supply and Logistics
Our MS&L segment consists of our supply and logistics business, our storage and terminals business, our West Coast operations, and our crude oil, NGL and produced water trucking business. We utilize our over-the-road and rail fleet, processing and storage facilities, and contracted storage and pipeline capacity on a portfolio basis to provide integrated supply and logistics solutions to producers, refiners and other customers. In December 2017, we sold 100% of our equity interests in US Salt, a solution-mining and salt production company located on the shores of Seneca Lake near Watkins Glen in Schuyler County, New York, to an affiliate of Kissner Group Holdings LP for net proceeds of approximately $223.6 million. As part of the US Salt divestiture, we retained all surface and sub-surface rights necessary to place the Watkins Glen NGL storage development project into service once we receive all required regulatory approvals.
Our MS&L operations primarily include:
• | Supply and Logistics. Our Supply and Logistics operations are supported by i) our fleet of rail and rolling stock with 75,000 Bbls/d of NGL transportation capacity, which also includes our rail-to-truck terminals located in Florida, New Jersey, New York, Rhode Island and North Carolina; and ii) NGL pipeline and storage capacity leased from third |
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parties, including more than 500,000 Bbls of NGL working storage capacity at major hubs in Mt. Belvieu, Texas and Conway, Kansas;
• | Storage and Terminals. Our NGL Storage and Terminals operations include our Seymour and Bath storage facilities, which are supported by third-party pipelines and/or rail and truck terminal facilities; |
• | West Coast. Our West Coast NGL operations provide processing, fractionation, storage, transportation and marketing services to producers, refiners and other customers. We separate NGLs from natural gas, deliver to local natural gas pipelines, retain NGLs for further processing at our fractionation facility, provide butane isomerization and refrigerated storage services, as well as provide to Western US refineries for motor fuel production. Our operations also consists of wholesale propane assets primarily including three rail-to-truck terminals located in Hazen, Nevada, Carlin, Nevada, and Shoshoni, Wyoming and a truck terminal located in Salt Lake City, Utah. These terminals are used to provide supply, transportation and storage services to wholesale customers in the western and north central regions of the United States; and |
• | Trucking. Our Trucking operations consist of a fleet of owned and leased trucks with 20,000 Bbls/d of crude oil and produced water transportation capacity and 120,000 Bbls/d of NGL transportation capacity. We provide hauling services to customers in North Dakota, Montana, Wyoming, Texas, New Mexico, Indiana, Mississippi, New Jersey, Ohio, Utah and California. |
The cash flows from our marketing, supply and logistics business represent sales to creditworthy customers typically under contracts with durations of one year or less, and tend to be seasonal in nature due to customer profiles and their tendencies to purchase NGLs during peak winter periods.
Outlook and Trends
Our business objective is to create long-term value for our unitholders. We expect to create long-term value by consistently generating stable operating margins and improved cash flows from operations by prudently financing our investments, maximizing throughput on our assets, and effectively controlling our operating and administrative costs. Our business strategy depends, in part, on our ability to provide increased services to our customers at competitive fees, including opportunities to expand our services resulting from expansions, organic growth projects and acquisitions that can be financed appropriately.
Through the challenging market environment from 2014 through 2017, we have taken a number of strategic steps to better position the Company as a stronger, better capitalized company that can over time accretively grow cash flows and sustainably resume growing our distributions. Those strategic steps included (i) simplifying our corporate structure to eliminate our incentive distribution rights (IDRs) and create better alignment of interests with our unitholders; (ii) divesting assets to reduce approximately $1 billion of long-term debt to ensure long-term balance sheet strength; (iii) realigning our operating structure to significantly reduce operating and administrative expenses; (iv) forming strategic joint ventures to enhance our competitive position around certain operating assets; and (v) focusing our growth capital expenditures on our highest return organic projects around our core growth assets in the Bakken Shale and Delaware Permian. We will remain focused on efficiently allocating capital expenditures by investing in accretive, organic growth projects, maintaining low-cost operations (through increased operating efficiencies and cost discipline) and maintaining our balance sheet strength through continued financial discipline. We expect to focus on expansion and greenfield opportunities in the Bakken Shale and Delaware Permian in the near term, while closely monitoring longer-term expansion opportunities in the Powder River Basin and northeast Marcellus. As a result, the Company is well positioned to execute its business plan and capitalize on the improving market conditions around many of our core assets.
While market conditions remain challenging around some of our assets, the Company continues to be positioned to generate consistent results in a low commodity price environment without sacrificing revenue upside as market conditions improve. For example, many of our more mature G&P assets are supported by long-term, core acreage dedications in shale plays that are economic to varying degrees based upon natural gas, NGL and crude oil prices, the availability of infrastructure to flow production to market, and the operational and financial condition of our diverse customer base. In addition, a substantial portion of our midstream investments are based on fixed-fee, take-or-pay or minimum volume commitment agreements that ensure a minimum level of cash flow regardless of actual commodity prices or volumetric throughput. Over time, we expect cash flows from our more mature, non-core, assets to stabilize and potentially increase with the improving commodity price environment, while the growth from our core assets in the Bakken Shale, Delaware Permian, Powder River Basin and northeast Marcellus drive significant growth to the Company.
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Below is a discussion of events that highlight our core business and financing activities. Through continued execution of our plan, we have materially improved the strategic and financial position of the Company and expect to capitalize on increasing opportunities in an improving but competitive market environment, which will position us to achieve our chief business objective to create long-term value for our unitholders.
Gathering and Processing
Bakken. In the Bakken, we are expanding and upgrading our Arrow system water handling facilities and increasing natural gas capacity on the system, which should allow for substantial growth in volumetric throughput across all of our crude oil, produced water and natural gas gathering systems. We are completing construction of a 30 MMcf/d natural gas processing facility and associated pipelines that began receiving gas in late 2017. In addition, we are constructing a 120 MMcf/d cryogenic plant that is designed to fulfill 100% of the processing requirements for producers on the Arrow system upon expiration of third-party processing contracts in the third quarter 2019. We expect to invest approximately $195 million on the expansion with a targeted in-service date in the second quarter 2019. Upon completion of the expansion, we expect to have a combined 150 MMcf/d of gas processing capacity in the Bakken. We believe the installation of a gas processing solution on the Arrow system will, among other things, spur greater development activity around the Arrow system, allow us to provide greater flow assurance to our producer customers and reduce flaring of natural gas, and reduce the downstream constraints currently experienced by producers on the Fort Berthold Indian Reservation.
Delaware Permian. In the Delaware Permian, we have identified gathering and processing and transportation opportunities in and around our existing assets, including our joint ventures. Through our Crestwood Permian joint venture, we are expanding our gathering and processing capacity in the region, which includes the construction of a 200 MMcf/d natural gas processing facility in Orla, Texas, and associated pipelines, as well as our interconnection capacity to accommodate greater takeaway options for residue gas and NGLs. The initial cost of the expansion project is expected to cost approximately $170 million with an in-service date in the second half of 2018. We are also evaluating expansion opportunities to provide midstream services for crude oil and produced water, including crude gathering, crude oil and condensate storage and terminalling, condensate stabilization, truck loading/unloading options and connections to third party pipelines and produced water gathering, disposal and recycling.
On June 21, 2017, we contributed to Crestwood Permian 100% of the equity interest of Crestwood New Mexico, our wholly-owned subsidiary that owns our Delaware Basin assets located in Eddy County, New Mexico. This contribution was treated as a transaction between entities under common control, and accordingly we deconsolidated Crestwood New Mexico and our investment in Crestwood Permian was increased by the historical book value of these assets of approximately $69.4 million. In conjunction with this contribution, First Reserve has agreed to contribute to Crestwood Permian the first $151 million of capital costs required to fund the expansion of the Delaware Basin assets, which includes the Orla processing plant and associated pipelines. In October 2017, CPB Subsidiary Holdings LLC, a wholly-subsidiary of Crestwood Permian, entered into a credit agreement with certain lenders. The five year term credit agreement allows for revolving loans, letters of credit and swingline loans in an aggregate principal amount of up to $150 million. Borrowings under the credit agreement will be used to fund expansion projects and for general corporate purposes.
Crestwood Permian Basin has a long-term agreement with SWEPI to construct, own and operate a natural gas gathering system in SWEPI's operated position in the Delaware Permian. SWEPI has dedicated to Crestwood Permian Basin approximately 100,000 acres and gathering rights for SWEPI's gas production across a large acreage position in Loving, Reeves, Ward and Culberson Counties, Texas. The Nautilus gathering system will be constructed to ultimately include 194 miles of low pressure gathering lines, 36 miles of high pressure trunklines and centralized compression facilities which are expandable over time as production increases, producing gas gathering capacity of approximately 250 MMcf/d. In addition, the Orla processing plant described above, will be further expanded and integrated to connect the Nautilus gas gathering system to the Orla plant. The initial build-out of the Nautilus gathering system was completed on June 6, 2017, and includes 20 receipt point meters, 60 miles of pipeline, a 24-mile high pressure header system, 10,800 horsepower of compression and a high pressure delivery point. Crestwood Permian Basin provides gathering, dehydration, compression and liquids handling services to SWEPI under a 20-year fixed-fee gathering agreement. In October 2017, Shell Midstream purchased a 50% equity interest in Crestwood Permian Basin for approximately $37.9 million in cash.
Marketing, Supply and Logistics
Our MS&L operations own NGL storage and terminalling assets in the Northeast U.S. and our West Coast processing facility. During 2017, we experienced NGL market headwinds in the Northeast, with our NGL exports and other market dynamics causing price differentials to narrow between purchasing NGLs in the summer (which are stored in our NGL facilities) and
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selling NGLs in the winter. These dynamics also caused the rates that we were able to charge for storing NGLs in our facilities to decline from their historical levels. Also during 2017, our West Coast customers also experienced headwinds, with both producers and refineries located in the Western U.S. experiencing regulatory challenges and an inflow of NGLs from the Eastern U.S. This caused demand for the gathering, processing and logistics services from our West Coast operations to remain relatively flat in 2017 compared to 2016.
In December 2017, we sold 100% of our equity interests in US Salt, a solution-mining and salt production company located on the shores of Seneca Lake near Watkins Glen in Schuyler County, New York, to an affiliate of Kissner Group Holdings LP for net proceeds of approximately $223.6 million.
Regulatory Matters
Many aspects of the energy midstream sector, such as crude-by-rail activities and pipeline integrity, have experienced increased regulatory oversight over the past few years. However, under the current Presidential Administration, we anticipate changes in policy that could lessen the degree of regulatory scrutiny we face in the near term.
In December 2017, the Tax Cuts and Jobs Act (the Tax Act) was passed by the U.S. Congress, which modified several aspects of the U.S. income tax code beginning in 2018. We are currently evaluating how many of these modifications will impact master limited partnerships such as CEQP and its unitholders. In particular, we are evaluating the impact that the Tax Act will have on our unitholders’ ability to deduct business interest from their taxable income, since the Tax Act requires that the business interest deduction be limited to the sum of business interest income and 30% of adjusted taxable income. For the purposes of this limitation, adjusted taxable income will be computed without regard to any business interest expense or business interest income, and in the case of taxable years beginning before January 1, 2022, any deduction allowable for depreciation, amortization, or depletion.
Critical Accounting Estimates and Policies
Our significant accounting policies are described in Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 2.
The preparation of financial statements in conformity with GAAP requires management to select appropriate accounting estimates and to make estimates and assumptions that affect the reported amount of assets, liabilities, revenues and expenses and the disclosures of contingent assets and liabilities. We consider our critical accounting estimates to be those that require difficult, complex, or subjective judgment necessary in accounting for inherently uncertain matters and those that could significantly influence our financial results based on changes in those judgments. Changes in facts and circumstances may result in revised estimates and actual results may differ materially from those estimates. We have discussed the development and selection of the following critical accounting estimates and related disclosures with the Audit Committee of the board of directors of our general partner.
Goodwill Impairment
Our goodwill represents the excess of the amount we paid for a business over the fair value of the net identifiable assets acquired. We evaluate goodwill for impairment annually on December 31, and whenever events indicate that it is more likely than not that the fair value of a reporting unit could be less than its carrying amount. This evaluation requires us to compare the fair value of each of our reporting units to its carrying value (including goodwill). If the fair value exceeds the carrying amount, goodwill of the reporting unit is not considered impaired.
We estimate the fair value of our reporting units based on a number of factors, including discount rates, projected cash flows and the potential value we would receive if we sold the reporting unit. We also compare the total fair value of our reporting units to our overall enterprise value, which considers the market value for our common and preferred units. Estimating projected cash flows requires us to make certain assumptions as it relates to the future operating performance of each of our reporting units (which includes assumptions, among others, about estimating future operating margins and related future growth in those margins, contracting efforts and the cost and timing of facility expansions) and assumptions related to our customers, such as their future capital and operating plans and their financial condition. When considering operating performance, various factors are considered such as current and changing economic conditions and the commodity price environment, among others. Due to the imprecise nature of these projections and assumptions, actual results can and often do, differ from our estimates. If the assumptions embodied in the projections prove inaccurate, we could incur a future impairment charge. In addition, the use of the income approach to determine the fair value of our reporting units (see further discussion of the income approach below) could result in a different fair value if we had utilized a market approach, or a combination thereof.
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We acquired substantially all of our reporting units in 2013, 2012 and 2011, which required us to record the assets, liabilities and goodwill of each of those reporting units at fair value on the date they were acquired. As a result, any level of decrease in the forecasted cash flows of these businesses or increases in the discount rates utilized to value those businesses from their respective acquisition dates would likely result in the fair value of the reporting unit falling below the carrying value of the reporting unit, and could result in an assessment of whether that reporting unit’s goodwill is impaired.
Current commodity prices are significantly lower compared to commodity prices during 2014, and that decrease has adversely impacted forecasted cash flows, discount rates and stock/unit prices for most companies in the midstream industry, including us. In light of these circumstances, we evaluated the carrying value of our reporting units and determined it was more likely than not that the goodwill associated with several of our reporting units was impaired and as a result, we recorded goodwill impairments on several of our reporting units during 2017, 2016 and 2015 as shown in the table below (in millions). During 2017, we adopted the provision of ASU 2017-04, Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment, which allows companies to apply a single test to determine if goodwill is impaired and the amount of any impairment, which is reflected in our 2017 goodwill impairments.
Goodwill Impairments during the Year Ended December 31, 2015 | Goodwill Impairments during the Year Ended December 31, 2016 | Goodwill Impairments during the Year Ended December 31, 2017 | Goodwill at December 31, 2017 | |||||||||||||
G&P | ||||||||||||||||
Fayetteville | $ | 72.5 | $ | — | $ | — | $ | — | ||||||||
Marcellus | — | 8.6 | — | — | ||||||||||||
Arrow | — | — | — | 45.9 | ||||||||||||
S&T | ||||||||||||||||
COLT | 623.4 | 44.9 | — | — | ||||||||||||
MS&L | ||||||||||||||||
West Coast | 85.9 | — | 2.4 | — | ||||||||||||
Supply and Logistics | 99.0 | 65.5 | — | 101.7 | ||||||||||||
Storage and Terminals | 53.7 | 14.1 | 36.4 | — | ||||||||||||
Trucking | 148.4 | 29.5 | — | — | ||||||||||||
Watkins Glen | 66.2 | — | — | — | ||||||||||||
Total Crestwood Midstream | $ | 1,149.1 | $ | 162.6 | $ | 38.8 | $ | 147.6 | ||||||||
Barnett (G&P) | 257.2 | — | — | — | ||||||||||||
Total Crestwood Equity | $ | 1,406.3 | $ | 162.6 | $ | 38.8 | $ | 147.6 | ||||||||
The goodwill impairments recorded during 2017 related to our MS&L West Coast and Storage and Terminals operations. The goodwill impairment related to our MS&L West Coast operations resulted from decreasing forecasted cash flows to be generated by those operations. Our West Coast customers experienced headwinds during 2017, with both producers and refineries located in the Western U.S. experiencing regulatory challenges and an inflow of NGLs from the Eastern U.S., which caused demand for gathering, processing and logistics services from our West Coast operations to remain relatively flat over the past several years. Although our West Coast operations’ results have been relatively consistent over the past several years, these operations have not experienced growth as fast or to the degree that we expected when we merged with Inergy, LP in 2013, and during 2017, we revised our forecasted cash flows to reflect current market dynamics, which we believe will continue for the foreseeable future. The goodwill impairment related to our MS&L Storage and Terminals operations resulted from decreasing forecasted cash flows to be generated by those operations. During 2017, we experienced NGL market headwinds in the Northeast with NGL exports and other market dynamics causing price differentials to narrow between purchasing NGLs in the summer (which are then stored in our NGL facilities) and selling NGLs in the winter. These dynamics also caused the rates that we are able to charge for storing NGLs in our facilities to decline from their historical levels. Although our MS&L Storage and Terminals operations’ results have been relatively consistent over the past several years, these operations have not experienced growth as fast or to the decrease that we expected when we merged with Inergy, LP in 2013, and during 2017, we revised our forecasted cash flows to reflect current market dynamics, which we believe will continue for the foreseeable future. We utilized the income approach to determine the fair value of our reporting units given the limited availability of comparable market-based transactions during 2017, and we utilized discount rates ranging from 10% to 12% in applying the income approach to determine the fair value of our reporting units with goodwill as of December 31, 2017, which is a Level 3 fair value measurement.
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As a result of these analyses and impairments, we only have two reporting units with goodwill associated with them at December 31, 2017 (Arrow and Supply and Logistics). We continue to monitor our remaining goodwill, and we could experience additional impairments of the remaining goodwill in the future if we experience a significant sustained decrease in the market value of our common or preferred units or if we receive additional negative information about market conditions or the intent of our customers on our remaining operations with goodwill, which could negatively impact the forecasted cash flows or discount rates utilized to determine the fair value of those businesses. In particular, a 5% decrease in the forecasted cash flows or a 1% increase in the discount rates utilized to determine the fair value of our business would not have resulted in goodwill impairments at our two remaining reporting units with goodwill associated with them.
Long-Lived Assets
Our long-lived assets consist of property, plant and equipment and intangible assets that have been obtained through multiple historical business combinations and property, plant and equipment that has been constructed in recent years. The initial recording of a majority of these long-lived assets was at fair value, which is estimated by management primarily utilizing market-related information and other projections on the performance of the assets acquired. Management reviews this information to determine its reasonableness in comparison to the assumptions utilized in determining the purchase price of the assets in addition to other market-based information that was received through the purchase process and other sources. These projections also include projections on potential and contractual obligations assumed in these acquisitions. Due to the imprecise nature of the projections and assumptions utilized in determining fair value, actual results can, and often do, differ from our estimates.
We utilize assumptions related to the useful lives and related salvage value of our property, plant and equipment in order to determine depreciation and amortization expense each period. Due to the imprecise nature of the projections and assumptions utilized in determining useful lives, actual results can, and often do, differ from our estimates.
To estimate the useful life of our finite lived intangible assets we utilize assumptions of the period over which the assets are expected to contribute directly or indirectly to our future cash flows. Generally this requires us to amortize our intangible assets based on the expected future cash flows (to the extent they are readily determinable) or on a straight-line basis (if they are not readily determinable) of the acquired contracts or customer relationships. Due to the imprecise nature of the projections and assumptions utilized determining future cash flows, actual results can, and often do, differ from our estimates.
We continually monitor our business, the business environment and the performance of our operations to determine if an event has occurred that indicates that a long-lived asset may be impaired. If an event occurs, which is a determination that involves judgment, we may be required to utilize cash flow projections to assess our ability to recover the carrying value of our assets based on our long-lived assets’ ability to generate future cash flows on an undiscounted basis. This differs from our evaluation of goodwill, for which we perform an assessment of the recoverability of goodwill utilizing fair value estimates that primarily utilize discounted cash flows in the estimation process (as described above), and accordingly a reporting unit that has experienced a goodwill impairment may not experience a similar impairment of the underlying long-lived assets included in that reporting unit. During 2017, 2016 and 2015, we recorded the following impairments of our intangible assets and property, plant and equipment:
• | During 2017, we incurred $82.2 million of impairments of our property, plant and equipment and intangible assets related to our MS&L West Coast operations, which resulted from decreasing forecasted cash flows to be generated by those operations. Our West Coast customers experienced headwinds during 2017, with both producers and refineries located in the Western U.S. experiencing regulatory challenges and an inflow of NGLs from the Eastern U.S., which caused demand for the gathering, processing and logistics services from our West Coast operations to remain relatively flat in 2017 compared to 2016. Although our West Coast operations’ results have been relatively consistent over the past several years, these operations have not experienced growth as fast or to the degree that we expected when we merged with Inergy, LP in 2013, and during 2017, we revised our forecasted cash flows to reflect current market dynamics, which we believe will continue for the foreseeable future. |
• | During 2016, we incurred a $31.4 million impairment of intangible assets related to our MS&L Trucking operations, which resulted from the impact of increased competition on our Trucking business and the loss of several key customer relationships that were acquired in 2013 to which the intangible assets related. |
• | During 2015, we incurred $8.5 million of impairments of our property, plant and equipment related to our Granite Wash gathering and processing operations, which resulted from decreases in forecasted cash flows for those operations given that our major customer of those assets has declared bankruptcy and has ceased any substantial drilling in the |
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Granite Wash in the near future given current and future anticipated market conditions related to natural gas and NGLs.
• | During 2015, we incurred $593.3 million of impairments of our intangible assets and property, plant and equipment related to our Barnett gathering and processing operations, which resulted from the recent actions of our primary customer in the Barnett Shale, Quicksilver, related to its filing for protection under Chapter 11 of the U.S. Bankruptcy Code in 2015. |
• | During 2015, we incurred $184.5 million of impairments of our intangible assets and property, plant and equipment related to our Fayetteville and Haynesville gathering and processing operations, which resulted from decreases in forecasted cash flows for those operations given that our customers for those assets have ceased any substantial drilling in the Fayetteville and Haynesville Shales in the near future given current and future anticipated market conditions related to natural gas. |
• | During 2015, we incurred $31.2 million of impairments of our property, plant and equipment related to our Watkins Glen marketing, supply and logistics segment development project, which resulted from continued delays and uncertainties in the permitting of our proposed NGL storage facility. |
Projected cash flows of our long-lived assets are generally based on current and anticipated future market conditions, which require significant judgment to make projections and assumptions about pricing, demand, competition, operating costs, construction costs, legal and regulatory issues and other factors that may extend many years into the future and are often outside of our control. If those cash flow projections indicate that the long-lived asset’s carrying value is not recoverable, we record an impairment charge for the excess of carrying value of the asset over its fair value. The estimate of fair value considers a number of factors, including the potential value we would receive if we sold the asset, discount rates and projected cash flows. Due to the imprecise nature of these projections and assumptions, actual results can and often do, differ from our estimates.
We continue to monitor our long-lived assets, and we could experience additional impairments of the remaining carrying value of these long-lived assets in the future if we receive additional negative information about market conditions or the intent of our long-lived assets’ customers, which could negatively impact the forecasted cash flows or discount rates utilized to determine the fair value of those investments.
Equity Method Investments
We evaluate our equity method investments for impairment when events or circumstances indicate that the carrying value of the equity method investment may be impaired and that impairment is other than temporary. If an event occurs, we evaluate the recoverability of our carrying value based on the fair value of the investment. If an impairment is indicated, we adjust the carrying values of the asset downward, if necessary, to their estimated fair values.
We estimate the fair value of our equity method investments based on a number of factors, including discount rates, projected cash flows, enterprise value and the potential value we would receive if we sold the equity method investment. Estimating projected cash flows requires us to make certain assumptions as it relates to the future operating performance of each of our equity method investments (which includes assumptions, among others, about estimating future operating margins and related future growth in those margins, contracting efforts and the cost and timing of facility expansions) and assumptions related to our equity method investments’ customers, such as their future capital and operating plans and their financial condition. When considering operating performance, various factors are considered such as current and changing economic conditions and the commodity price environment, among others. Due to the imprecise nature of these projections and assumptions, actual results can and often do, differ from our estimates.
Because our Jackalope and PRBIC equity method investments were acquired in 2013, any level of decrease in the forecasted cash flows of these investments or increases in the discount rates utilized to value those investments from their respective acquisition dates would likely result in the fair value of the equity method investment falling below their carrying value, and could result in an assessment of whether that investment is impaired.
During 2015, we recorded a $51.4 million and $23.4 million impairment of our Jackalope and PRBIC equity method investments, respectively, as a result of decreasing forecasted cash flows and increasing the discount rate utilized in determining the fair value of the equity method investment considering the continued decrease in commodity prices and its impact on the midstream industry and our equity method investments’ customers.
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We continue to monitor our equity method investments, and we could experience additional impairments of the remaining carrying value of these investments in the future if we receive additional negative information about market conditions or the intent of our equity method investments’ customers, which could negatively impact the forecasted cash flows or discount rates utilized to determine the fair value of those investments.
Variable Interest Entities
We evaluate all legal entities in which we hold an ownership interest to determine if the entity is a variable interest entity (VIE). Our interests in a VIE are referred to as variable interests. Variable interests can be contractual, ownership or other interests in an entity that change with changes in the fair value of the VIE’s assets. When we conclude that we hold an interest in a VIE we must determine if we are the entity’s primary beneficiary. A primary beneficiary is deemed to have a controlling financial interest in a VIE.
We consolidate any VIE when we determine that we are the primary beneficiary. We must disclose the nature of any interests in a VIE that is not consolidated. Significant judgment is exercised in determining that a legal entity is a VIE and in evaluating our interest in a VIE. We use primarily a qualitative analysis to determine if an entity is a VIE. We evaluate the entity’s need for continuing financial support; the equity holder’s lack of a controlling financial interest; and/or if an equity holder’s voting interests are disproportionate to its obligation to absorb expected losses or receive residual returns. We evaluate our interests in a VIE to determine whether we are the primary beneficiary. We use primarily a qualitative analysis to determine if we are deemed to have a controlling financial interest in the VIE, either on a standalone basis or as part of a related party group. We continually monitor our interests in legal entities for changes in the design or activities of an entity and changes in our interests, including our status as the primary beneficiary to determine if the changes require us to revise our previous conclusions. As a result of this analysis, we concluded that our investment in Crestwood Permian is a VIE that we are not the primary beneficiary of, and as a result, we account for our investment in Crestwood Permian as an equity method investment.
Our other equity investments are not considered to be VIEs. However, any future changes in the design or nature of the activities of these entities may require us to reconsider our conclusions associated with these entities. Such reconsideration would require the identification of the variable interests in the entity and a determination on which party is the entity’s primary beneficiary. If an equity investment were considered a VIE and we were determined to be the primary beneficiary, the change could cause us to consolidate the entity. The consolidation of an entity that is currently accounted for under the equity method could have a significant impact on our financial statements. See Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 6 for more information on our equity method investments.
How We Evaluate Our Operations
We evaluate our overall business performance based primarily on EBITDA and Adjusted EBITDA. We do not utilize depreciation, amortization and accretion expense in our key measures because we focus our performance management on cash flow generation and our assets have long useful lives.
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EBITDA and Adjusted EBITDA - We believe that EBITDA and Adjusted EBITDA are widely accepted financial indicators of a company’s operational performance and its ability to incur and service debt, fund capital expenditures and make distributions. We believe that EBITDA and Adjusted EBITDA are useful to our investors because it allows them to use the same performance measure analyzed internally by our management to evaluate the performance of our businesses and investments without regard to the manner in which they are financed or our capital structure. EBITDA is defined as income before income taxes, plus debt-related costs (interest and debt expense, net, and gain (loss) on modification/extinguishment of debt) and depreciation, amortization and accretion expense. Adjusted EBITDA considers the adjusted earnings impact of our unconsolidated affiliates by adjusting our equity earnings or losses from our unconsolidated affiliates to reflect our proportionate share (based on the distribution percentage) of their EBITDA, excluding impairments. Adjusted EBITDA also considers the impact of certain significant items, such as unit-based compensation charges, gains and losses on long-lived assets, impairments of long-lived assets and goodwill, third party costs incurred related to potential and completed acquisitions, certain environmental remediation costs, certain costs related to our historical cost saving initiatives, the change in fair value of commodity inventory-related derivative contracts, costs associated with our 2017 realignment of our Marketing, Supply and Logistics operations and related consolidation and relocation of our corporate offices, and other transactions identified in a specific reporting period. The change in fair value of commodity inventory-related derivative contracts is considered in determining Adjusted EBITDA given that the timing of recognizing gains and losses on these derivative contracts differs from the recognition of revenue for the related underlying sale of inventory to which these derivatives relate. Changes in the fair value of other derivative contracts is not considered in determining Adjusted EBITDA given the relatively short-term nature of those derivative contracts. EBITDA and Adjusted EBITDA are not measures calculated in accordance with GAAP, as they do not include deductions for items such as depreciation, amortization and accretion, interest and income taxes, which are necessary to maintain our business. EBITDA and Adjusted EBITDA should not be considered as alternatives to net income, operating cash flow or any other measure of financial performance presented in accordance with GAAP. EBITDA and Adjusted EBITDA calculations may vary among entities, so our computation may not be comparable to measures used by other companies.
See our reconciliation of net income to EBITDA and Adjusted EBITDA in Results of Operations below.
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Results of Operations
The following table summarizes our results of operations (in millions).
Crestwood Equity | Crestwood Midstream | ||||||||||||||||||
Year Ended December 31, | Year Ended December 31, | ||||||||||||||||||
2017 | 2016 | ||||||||||||||||||