| Organization, Basis of Presentation and Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
| Dec. 31, 2018 |
| Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
| Nature of business | Nature of business We provide critical midstream infrastructure that links producers of natural gas, crude oil, NGLs, condensate and specialty chemicals to numerous intermediate and end-use markets. During 2018, we operated through five reportable segments: (i) Gas Gathering and Processing Services, (ii) Liquid Pipelines and Services, (iii) Natural Gas Transportation Services, (iv) Offshore Pipelines and Services and (v) Terminalling Services. For further discussion of our reporting segments see Note 23. Reportable Segments . Our primary assets are strategically located in some of the most prolific onshore and offshore producing regions and key demand markets in the United States. Our gathering and processing assets are primarily located in (i) the Permian Basin of West Texas, (ii) the Cotton Valley/Haynesville Shale of East Texas, (iii) the Eagle Ford Shale of South Texas, (iv) the Bakken Shale of North Dakota and (v) offshore in the Gulf of Mexico. Our transmission assets are in key demand markets in Oklahoma, Alabama, Arkansas, Louisiana, Mississippi and Tennessee. |
| Basis of presentation | Basis of presentation As discussed in Note 4. Acquisitions , we acquired JP Energy Partners LP ("JPE") in a unit-for-unit exchange on March 8, 2017. As both the Partnership and JPE were controlled by ArcLight affiliates, the acquisition represented a transaction among entities under common control. Although the Partnership was the legal acquirer, JPE was considered the acquirer for accounting purposes as ArcLight obtained control of JPE on April 15, 2013 before it obtained control of the Partnership. The accompanying consolidated financial statements represent the JPE historical cost basis consolidated financial statements retrospectively adjusted to reflect its acquisition of the Partnership at ArcLight's historical cost bases effective April 15, 2013, the date on which ArcLight obtained control of the Partnership. |
| Transactions between entities under common control | Transactions between entities under common control We may enter into transactions with ArcLight affiliates whereby we receive midstream assets or other businesses in exchange for cash or Partnership equity. As the transactions are between entities under common control we account for the net assets acquired at the affiliate's historical cost basis, whether the transactions are considered assets or business acquisitions. In certain cases, our historical consolidated financial statements will be revised to include the results attributable to the assets acquired from the later of April 15, 2013 (the date Arclight affiliates obtained control of our General Partner) or the date the ArcLight affiliates obtained control of the assets or business acquired. |
| Consolidation policy | Consolidation policy The accompanying consolidated financial statements include accounts of American Midstream Partners, LP, and its controlled subsidiaries. All significant inter-company accounts and transactions have been eliminated in the preparation of the accompanying consolidated financial statements. |
| Going concern assessment and management's plans | Going Concern Assessment and Management’s Plans Pursuant to FASB ASC 205-40, Presentation of Financial Statements – Going Concern (Subtopic 205-40): Disclosure of Uncertainties About an Entity's Ability to Continue as a Going Concern , we are required to assess our ability to continue as a going concern for a period of one year from the date of the issuance of these consolidated financial statements. Substantial doubt about an entity’s ability to continue as a going concern exists when relevant conditions and events, considered in the aggregate, indicate that it is probable that the entity will be unable to meet its obligations as they become due within one year from the financial statement issuance date. As discussed in Note 14. Debt Obligations , our Credit Agreement matures on September 5, 2019 and has not been renewed as of the date of the issuance of these consolidated financial statements. As discussed in Note 21. Related Party Transactions , the Board received a non-binding proposal from Magnolia, an affiliate of ArcLight to acquire the common units that it does not already own. On March 17, 2019, we entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Anchor Midstream Acquisition, LLC, a Delaware limited liability company (“Proposed Parent”), Anchor Midstream Merger Sub, LLC, a Delaware limited liability company (“Proposed Merger Sub”), and High Point Infrastructure Partners, LLC, a Delaware limited liability company (“HPIP”), pursuant to which Proposed Merger Sub will merge with and into the Partnership, with the Partnership surviving as a direct wholly owned subsidiary of our General Partner and Proposed Parent (the “Pending Merger”). We expect the Pending Merger to close in the second quarter of 2019. As the Merger Agreement is subject to customary closing conditions and because the Pending Merger may affect how, or if, the Partnership elects to obtain a maturity extension, management has deferred finalization of a renewal of the Credit Agreement. While we intend to renew or extend the terms of our Credit Agreement, until such time as we have executed an agreement to refinance or extend the maturity of our Credit Agreement, we cannot conclude that it is probable we will do so, and accordingly, this raises substantial doubt about our ability to continue as a going concern. As the renewal or refinance of the Credit Agreement remains uncertain, the audited financial statements contained in this Form 10-K include a note regarding our ability to continue as a going concern. Prior to our entry into the Waiver, the existence of this going concern qualification in our audited financial statements would have constituted an event of default under the Credit Agreement. Pursuant to the Waiver, the administrative agent and certain lenders (as required by the Credit Agreement) have waived the Financial Statements Audit Requirement for the fiscal year ended December 31, 2018. Although we entered into the Waiver to address the event of default otherwise arising pursuant to the existence of a going concern note and material weakness exception in our audited financial statements contained in this Form 10-K, there is no guarantee that our lenders will agree to waive events of default or potential events of default in the future. |
| Use of estimates | Use of estimates When preparing consolidated financial statements in conformity with U.S. GAAP, management must make estimates and assumptions based on information available at the time. These estimates and assumptions affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosures of contingent assets and liabilities as of the date of the consolidated financial statements. Estimates and assumptions are based on information available at the time such estimates and assumptions are made. Adjustments made with respect to the use of these estimates and assumptions often relate to information not previously available. Uncertainties with respect to such estimates and assumptions are inherent in the preparation of consolidated financial statements. Estimates and assumptions are used in, among other things, i) estimating unbilled revenues, product purchases and operating and general and administrative costs, ii) developing fair value assumptions, including estimates of future cash flows and discount rates, iii) analyzing long-lived assets, goodwill and intangible assets for possible impairment, iv) estimating the useful lives of assets and v) determining amounts to accrue for contingencies, guarantees and indemnifications. Actual results, therefore, could differ materially from estimated amounts. |
| Cash, cash equivalents and restricted cash | Cash, cash equivalents and restricted cash We consider all highly liquid investments with an original maturity of three months or less at the date of purchase to be cash equivalents. The carrying value of cash and cash equivalents approximates fair value because of the short term to maturity for these investments. From time to time we are required to maintain cash in separate accounts the use of which is restricted by the terms of our debt agreements or asset retirement obligations. Such amounts are included in Restricted cash in our Consolidated Balance Sheets. |
| Inventory | Inventory Inventory, which is mainly comprised of crude oil, refined products and NGLs, is stated at the lower of cost or net realizable value. Cost of refined products and NGLs inventory is determined using the first-in, first-out (FIFO) method and the cost of crude oil inventory is determined using the weighted-average method. |
| Allowance for doubtful accounts | Allowance for doubtful accounts We establish provisions for losses on accounts receivable when we determine that we will not collect all or part of an outstanding balance. Collectability is reviewed regularly and an allowance is established or adjusted, as necessary, using the specific identification method. |
| Derivative financial instruments | Derivative financial instruments Our net income (loss) and cash flows are subject to volatility stemming from changes in interest rates on our variable rate debt, commodity prices and fractionation margins (the relative difference between the price we receive from NGL sales and the corresponding cost of natural gas purchases). In an effort to manage the risks to unitholders, we may use a variety of derivative financial instruments such as swaps, collars, interest rate caps or forward contracts to create offsetting positions to specific commodity or interest rate exposures. We record all derivative financial instruments in our Consolidated Balance Sheets at fair value as current and long-term assets or liabilities on a net basis by counterparty. We record changes in the fair value of our commodity derivatives in Gains (losses) on commodity derivatives, net while changes in the fair value of our interest rate swaps are included in Interest expense, net of capitalized interest in our Consolidated Statements of Operations. Our hedging program provides a control structure and governance for our hedging activities specific to identified risks and time periods, which are subject to the approval and monitoring by the board of directors of our General Partner ("the Board"). We employ derivative financial instruments in connection with an underlying asset, liability or anticipated transaction, and we do not use derivative financial instruments for speculative or trading purposes. The price assumptions we use to value our derivative financial instruments can affect our net income (loss) each period. We use published market price information where available, or quotations from over-the-counter, market makers to find executable bids and offers. The valuations also reflect the potential impact of related conditions, including credit risk of our counterparties. The amounts reported in our consolidated financial statements change quarterly as these valuations are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond our control. We are also a party to a number of contracts that have elements of a derivative instrument. These contracts are primarily forward purchase and sales contracts with counterparties. Although many of these contracts have the requisite elements of a derivative instrument, these contracts qualify for the normal purchase and normal sales exception because they provide for the delivery of products or services in quantities that are expected to be used in the normal course of operating our business and the price in the contract is directly associated with the price of the product or service being purchased or sold. As a result, these contracts are not recorded in our consolidated financial statements until they are settled. |
| Fair value measurements | Fair value measurements We apply the authoritative accounting provisions for measuring the fair value of our derivative financial instruments and disclosures associated with our outstanding indebtedness. We define fair value as an exit price representing the expected amount we would receive when selling an asset or pay to transfer a liability in an orderly transaction with market participants at the measurement date. We use various assumptions and methods in estimating the fair values of our financial instruments. The carrying value of all non-derivative financial instruments included in current assets (including cash, cash equivalents, restricted cash and accounts receivable) and current liabilities (including accounts payable but excluding short-term debt) approximates the applicable fair value due to the short maturity of those instruments. We employ a hierarchy which prioritizes the inputs we use to measure recurring fair value into three distinct categories based upon whether such inputs are observable in active markets or unobservable. We classify assets and liabilities in their entirety based on the lowest level of input that is significant to their fair value measurement. Our methodology for categorizing assets and liabilities that are measured at fair value pursuant to this hierarchy gives the highest priority to unadjusted quoted prices in active markets and the lowest level to unobservable inputs as outlined below: • Level 1 – Inputs represent unadjusted quoted prices in active markets for identical assets or liabilities; • Level 2 – Inputs include quoted prices for similar assets and liabilities in active markets that are either directly or indirectly observable; and • Level 3 – Inputs are unobservable and considered significant to fair value measurement. We utilize a mid-market pricing convention, or the "market approach," for valuation for assigning fair value to our derivative assets and liabilities. Our credit exposure for over-the-counter derivatives is directly tied to our counterparty and continues until the maturity or termination of the contracts. As appropriate, valuations are adjusted for various factors such as credit and liquidity considerations. |
| Property, plant and equipment | Property, plant and equipment We capitalize expenditures related to property, plant and equipment that have a useful life greater than one year. We also capitalize expenditures that improve or extend the useful life of an asset. Maintenance and repair costs, including any planned major maintenance activities, are expensed as incurred. We record property, plant and equipment at cost and recognize depreciation expense on a straight-line basis over the related estimated useful lives of the assets which range from 3 to 40 years. Our determination of the useful lives of property, plant and equipment requires us to make various assumptions, including the supply of and demand for hydrocarbons in the markets served by our assets, normal wear and tear of the facilities and the extent and frequency of maintenance programs. We classify long-lived assets to be disposed of through sales that meet specific criteria as held for sale. We cease depreciating those assets effective on the date the asset is classified as held for sale. We record those assets at the lower of their carrying value or the estimated fair value less the cost to sell. Until the assets are disposed of, our estimate of fair value is re-determined when related events or circumstances change. |
| Impairment of long lived Assets | Impairment of long lived assets We evaluate the recoverability of our property, plant and equipment and intangible assets with definite lives when events or circumstances indicate we may not recover the carrying amount of the assets. We continually monitor our operations, the market and business environment to identify indicators that could suggest an asset or asset group may not be recoverable. We evaluate the asset or asset group for recoverability by estimating the undiscounted future cash flows expected to be derived from their use and disposition. These cash flow estimates require us to make projections and assumptions for many years into the future for pricing, demand, competition, operating cost, contract renewals and other factors. An asset or asset group is considered impaired when the estimated undiscounted cash flows are less than the carrying amount. In that event, an impairment loss is recognized to the extent that the carrying amount of the asset or asset group exceeds its fair value as determined by quoted market prices in active markets or present value techniques. The determination of fair values using present value techniques requires us to make projections and assumptions regarding future cash flows and weighted average cost of capital. Any changes we make to these projections and assumptions could result in significant revisions to our evaluation of the recoverability of our property, plant and equipment and the recognition of an impairment loss in our consolidated statements of operations. |
| Goodwill impairment and intangible assets | Goodwill impairment We record goodwill for the excess of the cost of an acquisition over the fair value of the net assets of the acquired business. Goodwill is reviewed for impairment at least annually, as of October 1st of each year, or more frequently if an event or change in circumstance indicates that an impairment may have occurred. We first assess qualitative factors to evaluate whether it is more likely than not that an impairment has occurred, and it is therefore necessary to perform the one-step quantitative goodwill impairment test. If the one-step quantitative goodwill impairment test indicates that the goodwill is impaired, an impairment loss is recorded, which is the difference between the carrying value of the reporting unit to its fair value, with the impairment loss not to exceed the amount of goodwill recorded. When performing a quantitative impairment test, we generally determine the fair value of our reporting units ("RU") using a discounted cash flow method. In the event we enter into an agreement to sell all or substantially all of an RU, we will utilize such information. While using the discounted cash flow method, we must make estimates of projected cash flows related to assets, which include, but are not limited to, assumptions about revenue growth rates, operating margins, weighted average costs of capital and future market conditions, the use or disposition of assets, estimated remaining life of assets and future expenditures necessary to maintain current operations. We also must make certain estimates and assumptions, including, among other things, changes in general economic conditions in regions in which our markets are located, the availability and prices of energy commodities (such as natural gas, crude oil and refined products), our ability to negotiate favorable sales agreements, the risks that natural gas exploration and production activities will not occur or be successful, our dependence on certain significant customers and producers of natural gas and competition from other companies. The fair value is estimated using the income approach based on significant inputs not observable in the market and thus represent a Level 3 measurement. Under the discounted cash flow method, we determine fair value based on estimated future cash flows and earnings before interest, income tax, depreciation and amortization (“EBITDA”) of each RU including estimates for capital expenditures, discounted to present value using the risk-adjusted industry rate, which reflects the overall level of inherent risk of an RU. Cash flow projections are derived from one-year budgeted amounts and five-year operating forecasts plus an estimate of later period cash flows, all of which are evaluated by management. Subsequent period cash flows are developed for each RU using growth rates that management believes are reasonably likely to occur. The annual budget process is typically completed near the annual goodwill impairment testing date, and management uses the most recent information for the annual impairment tests. The forecast is also subjected to a comprehensive update annually in conjunction with the annual budget process and is revised periodically to reflect new information and revised expectations. The estimates of future cash flows and EBITDA are subjective in nature and are subject to impacts from our business risks. While we believe we have made reasonable estimates and assumptions based on available information to calculate the fair value, if future results are not consistent with our estimates, changes in fair value estimates could result in additional impairments in future periods that could be material to our results of operations. Intangible assets We record the estimated fair value of acquired customer contracts, relationships and dedicated acreage agreements as intangible assets. These intangible assets have definite lives and are subject to amortization on a straight-line basis over their economic lives, currently ranging between 5 and 30 years. We assess intangible assets for impairment together with related underlying long-lived assets whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. |
| Investment in unconsolidated affiliates | Investment in unconsolidated affiliates We hold membership interests in entities that own and operate natural gas pipeline systems and NGL and crude oil pipelines in and around Louisiana, Alabama, Mississippi and the Gulf of Mexico. While we have significant influence over these entities, we do not control them and therefore, they are accounted for using the equity method and are reported in Investment in unconsolidated affiliates in our Consolidated Balance Sheets. We evaluate the recoverability of these investments on a regular basis and recognize impairment write downs if we determine a loss in value represents an other-than-temporary-decline. The unconsolidated affiliates that were determined to be variable interest entities (“VIE”) due to disproportionate economic interests and decision making rights were further evaluated under the VIE method of consolidation. In each case, we lack the power to direct the activities that most significantly impact the unconsolidated affiliate’s economic performance. Therefore, as we do not hold a controlling financial interest in these affiliates, we account for our related investments using the equity method. In each case, we are not obligated to absorb losses greater than our proportional ownership percentages. We have joint venture arrangements in which we and our partners share proportional ownership and responsibilities and receive returns in accordance with our ownership percentage. |
| Deferred financing costs | Deferred financing costs Costs incurred in connection with our revolving credit facilities are deferred and charged to interest expense over the term of the related credit agreement. Such amounts are included in Other assets, net in our Consolidated Balance Sheets. Costs incurred in connection with our long-term debt such as the 8.50% Senior Notes and 3.77% Senior Notes are also deferred and charged to interest expense over the respective term of the agreements; however, these amounts are reflected as a reduction of the related obligation. Gains or losses on debt repurchases or extinguishment include any associated unamortized deferred financing costs. |
| Asset retirement obligations | Asset retirement obligations Asset retirement obligations ("ARO") are legal obligations associated with the retirement of tangible long-lived assets that result from the asset's acquisition, construction, development and operation. An ARO is initially measured at its estimated fair value. Upon initial recognition, we also record an increase to the carrying amount of the related long-lived asset. We depreciate the asset using the straight-line method over the period during which it is expected to provide benefits. After initial recognition, we revise the ARO to reflect the passage of time and for changes in the estimated amount or timing of cash flows. We have legal obligations requiring us to decommission our offshore pipeline systems at retirement. In certain rate jurisdictions, we are permitted to include annual charges for removal costs in the regulated cost of service rates we charge our customers. Additionally, legal obligations exist for certain of our onshore right-of-way agreements due to requirements or landowner options to compel us to remove the pipe at final abandonment. Sufficient data exists with certain onshore pipeline systems to reasonably estimate the cost of abandoning or retiring a pipeline system. However, in some cases, there is insufficient information to reasonably determine the timing and/or method of settlement for purposes of estimating the fair value of the ARO. In these cases, the ARO cost is considered indeterminate because there is no data or information that can be derived from past practice, industry practice, management's experience or the asset's estimated economic life. The useful lives of most pipeline systems are primarily derived from available supply resources and ultimate consumption of those resources by end users. Variables can affect the remaining lives of the assets which preclude us from making a reasonable estimate of the ARO. Indeterminate ARO costs will be recognized in the period in which sufficient information exists to reasonably estimate potential settlement dates and methods. |
| Commitments, contingencies and environmental liabilities | Commitments, contingencies and environmental liabilities We expense or capitalize, as appropriate, expenditures for ongoing compliance with environmental regulations that relate to past or current operations. We expense amounts we incur from the remediation of existing environmental contamination caused by past operations that do not benefit future periods by preventing or eliminating future contamination. We record liabilities for environmental matters when assessments indicate that remediation efforts are probable and the costs can be reasonably estimated. Estimates of environmental liabilities are based on currently available facts, existing technology and presently enacted laws and regulation taking into consideration the likely effects of inflation and other factors. These amounts also take into account our prior experience in remediating contaminated sites, other companies' clean-up experience and data released by government organizations. Our estimates are subject to revision in future periods based on actual cost or new information. We evaluate recoveries from insurance coverage separately from the liability and, when recovery is probable, we record an asset separately from the associated liability in our consolidated financial statements. We recognize liabilities for other commitments and contingencies when, after fully analyzing the available information, we determine it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. When a range of probable loss can be estimated, we accrue the most likely amount, or if no amount is more likely than another, we accrue the minimum of the range of probable loss. We expense legal costs associated with loss contingencies as such costs are incurred. |
| Noncontrolling interests | Noncontrolling interests Noncontrolling interests represent the minority interest holders' proportionate share of the equity in certain of our consolidated subsidiaries and are adjusted for the minority interest holders' proportionate share of the subsidiaries' earnings or losses each period. |
| Revenue recognition | Revenue recognition Our revenue is derived from the provision of gathering, processing, transportation, terminalling and storage services and the sale of commodities primarily to marketers and brokers, refiners and chemical manufacturers, utilities and power generation customers, industrial users and local distribution companies. Services revenue also includes revenues generated through operating lease arrangements. Beginning on January 1, 2018, we account for revenue from contracts with customers in accordance with Topic 606. The unit of account in Topic 606 is a performance obligation, which is a promise in a contract to transfer to a customer either a distinct good or service (or bundle of goods or services) or a series of distinct goods or services provided at a point in time or over a period of time. Topic 606 requires that a contract’s transaction price, which is the amount of consideration to which an entity expects to be entitled in exchange for transferring promised goods or services to a customer, is to be allocated to each performance obligation in the contract based on relative standalone selling prices and recognized as revenue when (point in time) or as (over time) the performance obligation is satisfied. See Note 2. Recent Accounting Pronouncements, for further discussion regarding our January 1, 2018 implementation of the new Revenue Recognition guidance. Cost of sales Cost of sales represent the cost of commodities purchased for resale or obtained in connection with certain of our customer revenue arrangements. These costs do not include an allocation of depreciation expense or direct operating costs. |
| Corporate expenses | Corporate expenses Corporate expenses include compensation costs for executives and administrative personnel, professional service fees, rent expense and other general and administrative expenses and are recognized as incurred. |
| Operational balancing agreements and natural gas imbalances | Operational balancing agreements and natural gas imbalances To facilitate deliveries of natural gas and provide for operational flexibility, we have operational balancing agreements in place with other interconnecting pipelines. These agreements ensure that the volume of natural gas a shipper schedules for transportation between two interconnecting pipelines equals the volume actually delivered. If natural gas moves between pipelines in volumes that are more or less than the volumes the shipper previously scheduled, a natural gas imbalance is created. The imbalances are settled through periodic cash payments or repaid in-kind through future receipt or delivery of natural gas. Natural gas imbalances are recorded in Other current assets or Accrued expenses and other current liabilities in our Consolidated Balance Sheets at cost which approximates fair value. |
| Equity-based compensation | Equity-based compensation We award equity-based compensation to management, non-management employees and directors under our long-term incentive plans, which provide for the issuance of options, unit appreciation rights, restricted units, phantom units, other unit-based awards, unit awards or replacement awards, as well as tandem Distribution Equivalent Rights ("DERs"). Compensation expense is measured by the fair value of the award at the date of grant as determined by management. Compensation expense is recognized in Corporate expenses and Direct operating expenses i n our Consolidated Statements of Operations over the requisite service period of each award. |
| Income taxes | Income taxes The Partnership is not a taxable entity for U.S. federal income tax purposes or for the majority of states that impose an income tax. Taxes on our net income are generally borne by our unitholders through the allocation of taxable income. Prior to the disposition of Marine Products in July 2018 (as discussed in Note 5. Dispositions ), we owned American Midstream Blackwater, LLC, which owned a subsidiary that had operations which were subject to both U.S. federal and state income taxes. We accounted for income taxes of that subsidiary using the asset and liability approach. If it was more than likely that a deferred tax asset would not be realized, a valuation allowance was recognized. Margin tax expense results from the enactment of laws by the state of Texas that apply to entities organized as partnerships and is included in Income tax expense in our Consolidated Statements of Operations. The Texas margin tax is computed on the portion of our taxable margin which is apportioned to Texas. Net income (loss) for financial statement purposes may differ significantly from taxable income (loss) allocable to unitholders as a result of differences between the financial reporting and income tax bases of our assets and liabilities and the taxable income allocation requirement under our Partnership Agreement. The aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined because information regarding each partner's tax attributes in us is not available. |
| Accumulated other comprehensive income (loss) | Accumulated other comprehensive income (loss) Accumulated other comprehensive income (loss) is comprised solely of adjustments related to the Partnership's postretirement benefit plan. |
| Limited partners' net income (loss) per unit | Limited partners' net income (loss) per unit We compute earnings per unit using the two-class method. The two-class method requires that securities which meet the definition of a participating security should be considered in the computation of basic earnings per unit. Under the two-class method, earnings per unit is calculated as if all of the earnings for the period were distributed under the terms of the Partnership Agreement, regardless of whether the General Partner has discretion over the amount of distributions to be made in any particular period, whether those earnings would actually be distributed during a particular period from an economic or practical perspective or whether the General Partner has other legal or contractual limitations on its ability to pay distributions that would prevent it from distributing all of the earnings for a particular period. The two-class method does not impact our overall net income or other financial results; we make distributions on the basis of available cash and not earnings. However, if a distribution exceeds the Minimum Quarterly Distribution it will have the impact of reducing net income per limited partner unit. This result occurs as a larger portion of the excess would be allocated to the incentive distribution rights of the General Partner. In periods in which our aggregate net income does not exceed our aggregate distributions for such period, the two-class method does not have any impact on our calculation of earnings per limited partner unit. As our preferred units participate in distributions to our common unitholders, in periods in which our aggregate net income exceeds our aggregate distributions for such period, the two-class method will have the impact of reducing net income per limited partner unit. |
| New accounting pronouncements | New Accounting Pronouncements Standards Adopted in 2018 Revenue from Contracts with Customers (Topic 606 ) - In May 2014, the Financial Accounting Standards Board (the “FASB”) issued a new standard related to revenue recognition which supersedes most of the existing revenue recognition requirements in GAAP and requires entities to recognize revenue at an amount that reflects the consideration to which an entity expects to be entitled in exchange for transferring goods or services to a customer. It also requires significantly expanded disclosures regarding the qualitative and quantitative information of an entity’s nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The FASB has issued several amendments to the standard since its issuance, including clarification on accounting for licenses of intellectual property, identifying performance obligations, reporting gross versus net revenue and narrow-scope revisions and practical expedients. We adopted the new standard on January 1, 2018 (the “initial application” date): • using the modified retrospective application, with no restatement of the comparative periods presented and a cumulative effect adjustment to retained earnings as of the date of adoption, and • disclosing the impact of the new standard in our consolidated financial statements included in this 2018 Form 10-K. Our revenue is derived from the provision of gathering, processing, transportation, terminalling and storage services and the sale of commodities primarily to marketers and brokers, refiners and chemical manufacturers, utilities and power generation customers, industrial users and local distribution companies. Beginning on January 1, 2018, we account for revenue from contracts with customers in accordance with Topic 606. The unit of account in Topic 606 is a performance obligation, which is a promise in a contract to transfer to a customer either a distinct good or service (or bundle of goods or services) or a series of distinct goods or services provided at a point in time or over a period of time. Topic 606 requires that a contract’s transaction price, which is the amount of consideration to which an entity expects to be entitled in exchange for transferring promised goods or services to a customer, is to be allocated to each performance obligation in the contract based on relative standalone selling prices and recognized as revenue when (point in time) or as (over time) the performance obligation is satisfied. Commodity Sales - For the majority of our commodity sales contracts: (i) each unit of product is a separate performance obligation, since our promise is to sell multiple distinct units of product at a point in time, (ii) the transaction price principally consists of variable consideration, which is determinable on commodity index prices for the volume of the product sold to the customer that month and (iii) the transaction price is allocated to each performance obligation based on the product’s standalone selling price. Revenues from sales of commodities are recognized at the point in time when control of the commodity transfers to the customer, which generally occurs upon delivery of the product to the customer or its designee. Payment is generally received from the customer in the month following delivery. Contracts with customers have varying terms, including spot sales, month-to-month contracts and multi-year agreements. In our Liquid Pipelines and Services segment, we enter into purchase and sale contracts as well as buy/sell contracts with counterparties, under which we gather and transport different types of crude oil and eventually sell the crude oil to either the same counterparty or different counterparties. For each of these arrangements, the Partnership assesses if control of the underlying commodity volumes transfers to the Partnership. Generally, the Partnership is unable to direct the use of the commodity volumes it purchases from the supplier because the Partnership is contractually required to redeliver an equivalent volume of the commodity back to the supplier or to a specified customer, therefore these arrangements are recorded on a net basis. Occasionally, we enter into crude oil inventory exchange arrangements with the same counterparty where the purchase and sale of inventory are considered in contemplation of each other. These types of arrangements are accounted for as inventory exchanges and are recorded on a net basis. Services - The Partnership provides gathering, processing, transportation, terminalling and storage services pursuant to a variety of contracts. Generally, for the majority of these contracts: (i) our promise is to transfer (or stand ready to transfer) a series of distinct integrated services over a period of time, which is a single performance obligation and (ii) the transaction price includes fixed or variable consideration, or both fixed and variable consideration. The amount of consideration is determinable at contract inception or at each month’s end based on our right to invoice at month end for the value of services provided to the customer in that month. Revenue is recognized over the service period specified in the contract as the services are rendered using a time-based (passage of time) or units-based (units of service transferred) method for measuring provision of the services. Progress towards satisfying our performance obligation is based on the firm or interruptible nature of the promised service and the terms and conditions of the contract (such as contracts with or without makeup rights). Payment is generally received from the customer in the month of service or the month following the service. Contracts with customers generally are a combination of month-to-month and multi-year agreements. Firm Services - Firm services are services that are promised to be available to the customer at all times during the term of the contract with limited exceptions. These agreements require customers to deliver, transport or throughput a minimum volume over an agreed upon period. Substantially all of such agreements are entered into with customers to economically support the return on our capital expenditure necessary to construct the related asset. Our firm service contracts are typically structured with take-or-pay or minimum volume provisions, which specify minimum service quantities a customer will pay for even if it chooses not to receive or use them in the specified service period (referred to as “deficiency quantities”). Under firm service contracts, we record a receivable from the customer in the period that services are provided or when the transaction occurs, including amounts for deficiency quantities from customers associated with minimum volume commitments. If a customer has a make-up right associated with a deficiency, we defer the revenue attributable to the counterparty’s make-up right and subsequently recognize the revenue at the earlier of when the deficiency volume is delivered or shipped, when the make-up right expires or when it is determined that the customer’s ability to utilize the make-up right is remote. Interruptible Services - Interruptible services are services provided to the extent that we have available capacity. Generally, we do not have an obligation to perform these services until we accept a customer’s periodic request for service. For the majority of these contracts, the customer will pay only for the actual quantities of services it chooses to receive or use and we typically recognize the transaction price as revenue as those units of service are transferred to the customer in the specified service period. Gathering and Processing - Our Gas Gathering and Processing Services segment provides “wellhead-to-market” services to producers of natural gas and NGLs, which include transporting raw natural gas from various receipt points through gathering systems, treating the raw natural gas, processing raw natural gas to separate the NGLs from the natural gas, fractionating NGLs and selling or delivering pipeline-quality natural gas and NGLs to various markets and pipeline systems. Services can be firm if subject to a minimum volume commitment or acreage dedication or interruptible when offered on an as requested, non-guaranteed basis. Revenue for fee-based gathering and processing services is valued based on the rate in effect for the month of service and is recognized in the month of service based on the volumes of natural gas we gather, process and fractionate. Under these arrangements, we may take control of: (i) none of the commodities we sell (i.e., residue gas or NGLs), (ii) a portion of the commodities we sell or (iii) all of the commodities we sell. In those instances where we purchase and obtain control of the entire natural gas stream in our producer arrangements, we have determined these are contracts with suppliers rather than contracts with customers and therefore, these arrangements are not included in the scope of Topic 606. These supplier arrangements are subject to updated guidance in Accounting Standards Codification (“ASC”) 705, Cost of Sales and Services , whereby any embedded fees within such contracts, which historically have been reported as services revenue, are now reported as a reduction to cost of sales upon adoption of Topic 606. In those instances where we remit all of the cash proceeds received from third parties for selling the extracted commodities to the producer, less the fees attributable to these arrangements, we have determined that the producer has control over these commodities. Upon adoption of Topic 606, we eliminated recording both sales revenue (natural gas and products) and cost of sales amounts and now only record fees attributable to these arrangements as service revenues. In other instances where we do not obtain control of the extracted commodities we sell, we are acting as an agent for the producer and, upon adoption of Topic 606, we have continued to recognize services revenue for the net amount of consideration we retain in exchange for our service. The Partnership may charge additional service fees to customers for a portion of the contract term (i.e., for the first year of a contract or until reaching a volume threshold) due to the significant upfront capital investment, and these fees are initially deferred and recognized to revenue over the expected period of customer benefit, generally the lesser of the expected contract term or the life of the related properties. Transportation - Our transportation operations generally consist of fee-based activities associated with transporting crude oil, natural gas and NGL on pipelines, gathering systems and trucks. Revenues from pipeline tariffs and fees are associated with the transportation at a published tariff, as well as revenues associated with agreements for committed capacity on various assets. We primarily recognize pipeline tariff and fee revenues over time based on the volumes delivered and invoiced. The majority of our pipeline tariff and fee revenues are based on actual volumes and rates. As is common in the pipeline transportation industry, our tariffs incorporate a loss allowance factor. The intent of the allowance in arrangements for the transportation of natural gas is to approximate the natural shrink that occurs when transporting gas. For crude oil transportation arrangements, loss allowance provisions are immaterial to the Partnership. In the event the Partnership retains excess natural gas and crude oil and subsequently sells the commodity to a third party, the sale is recorded at that point in time as a commodity sale. Terminalling and Storage - In our Terminalling Services segment, we generally received fee-based compensation on guaranteed firm storage contracts, throughput fees charged to our customers when their products are either received or disbursed and other operational charges associated with ancillary services provided to our customers, such as excess throughput and steam heating. Storage fees resulting from short-term and long-term contracts are typically recognized in revenue ratably over the term of the contract regardless of the actual storage capacity utilized. Substantially all of our Terminalling Services segment assets were sold in 2018, see Note 5. Dispositions for more information. Adoption of the new revenue standard resulted in changes to the timing of revenue recognition and in the reclassification between financial statement line items. See Note 3. Revenue Recognition , for further discussion . Statement of Cash Flows - In August 2016, the FASB issued Accounting Standards Update (“ASU”) No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15”). ASU 2016-15 provides specific guidance on cash flow classification issues to reduce diversity in practice. In connection with the January 1, 2018 retrospective adoption of this ASU, for the year ended December 31, 2017, we reclassified $2.8 million in distributions received from unconsolidated affiliates from operating cash inflows to investing cash inflows and reclassified $2.5 million of transaction costs associated with the disposal of our Propane Business from an investing cash outflow to an operating cash outflow in our Consolidated Statement of Cash Flows. Transaction costs for the year ended December 31, 2016 were not material. In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (“ASU 2016-18”), which requires amounts described as restricted cash and restricted cash equivalents to be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. A reconciliation between the balance sheet and the statement of cash flows must be disclosed when the balance sheet includes more than one line item for cash, cash equivalents, restricted cash and restricted cash equivalents. We retrospectively adopted ASU 2016-18 as of January 1, 2018. For the year ended December 31, 2017, cash flows from investing activities were adjusted to remove the impact of $298.2 million in restricted cash inflows and for December 31, 2016, cash flows from investing activities were adjusted to remove the impact of $318.5 million in restricted cash outflows. Stock Compensation - In May 2017, the FASB issued ASU No. 2017-09, Compensation - Stock Compensation (Topic 718): Scope of Modification Accounting (“ASU 2017-09”). ASU 2017-09 was issued with the intent to clarify the scope of modification accounting and when it should be applied to a change to the terms or conditions of a share-based payment award. Under the new guidance, modification accounting is required for all changes to share-based payment awards, unless all the following conditions are met: (i) there is no change to the fair value of the award, (ii) the vesting conditions have not changed and (iii) the classification of the award as an equity instrument or a debt instrument has not changed. We adopted ASU 2017-09 on its effective date of January 1, 2018, and the adoption did not have a material impact on our consolidated financial statements. Standards Not Yet Adopted Leases (Topic 842) - In February 2016, the FASB issued ASU No. 2016-02 (“Topic 842”) Leases , which supersedes the lease recognition requirements in ASC 840, Leases . Under the new guidance, for leases with a term longer than 12 months, a lessee should recognize a lease liability and a right-of-use (“ROU”) asset representing its right to use the underlying asset for the lease term. Topic 842 retains a classification distinction between finance leases and operating leases, with the classification affecting the pattern of expense recognition in the income statement. This ASU also requires enhanced disclosures. In 2018, the FASB issued ASU No. 2018-01, Land Easement Practical Expedient for Transition to Topic 842 and ASU No. 2018-11, Targeted Improvements . Under these updates, optional transition practical expedients are available (1) whereby existing or expired land easements that were not previously accounted for as leases under Topic 840 are not required to be evaluated under Topic 842 and (2) lease and associated non-lease components are not required to be separated within lessor arrangements if certain criteria are met. The FASB also issued ASUs 2018-10 and 2018-20, Codification Improvements to Topic 842 and Narrow Scope Improvements for Lessors , respectively, to alleviate unintended consequences from applying Topic 842. The amendments do not make substantive changes to the core provisions or principles of Topic 842 and are not expected to significantly impact our implementation process. We adopted the new standard on its effective date, January 1, 2019, using the modified retrospective application. We have also elected the package of practical expedients permitted under the transition guidance within Topic 842 which, among other things, allows us to carry forward the historical lease classification. As such, we did not reassess (1) whether any expired or existing contracts are or contain leases, (2) the lease classification for any expired or existing leases, and (3) any initial direct costs for any existing leases as of the effective date. We did not elect the hindsight practical expedient which permits entities to use hindsight in determining the lease term and assessing impairment of ROU assets. Additionally, we elected certain practical expedients on an ongoing basis, including the practical expedient for short-term leases pursuant to which a lessee is permitted to make an accounting policy election by class of underlying asset not to recognize a lease liability and ROU asset for leases (1) with a term of 12 months or less and (2) that do not include an option to purchase the underlying asset that the lessee is reasonably certain to exercise. Instead, we will recognize the lease payments for short-term leases within profit and loss on a straight-line basis over the lease term and variable lease payments in the period in which the obligation for those payments is incurred. We selected a third-party consulting firm to assist us with the adoption of the new guidance. We are implementing specialized software and developing policies based on reviews of existing arrangements. We intend to complete any required changes to our systems, software applications and processes, including training personnel and updating our internal controls, during the first quarter 2019. While we continue to evaluate certain aspects of Topic 842, the application will have an effect on our consolidated financial statements from a lessee perspective, with the most significant effects relating to (1) the recognition of new ROU assets and lease liabilities on our balance sheet and (2) significant new disclosures about our leasing activities. We believe substantially all leases where we are a lessee will continue to be classified as operating leases under Topic 842. We do not expect Topic 842 to have a material effect on our consolidated financial statements from a lessor perspective. On adoption, we expect to recognize additional lease liabilities ranging from $28 million to $32 million , with corresponding ROU assets of approximately the same amount. This estimate could change as the Partnership continues to finalize the implementation. Management does not expect a material impact to the Partnership’s Consolidated Statements of Operations or Cash Flows. Financial Instruments - In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments (“ASU 2016-13”). This guidance will become effective for interim and annual periods beginning after December 15, 2019. We expect to adopt ASU 2016-13 on January 1, 2020, and we are currently evaluating the effect that adopting this guidance will have on our consolidated financial position, results of operations and cash flows. Fair Value Measurement - In August 2018, the FASB issued ASU No. 2018-13, Fair Value Measurements (Topic 820): Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement (“ASU 2018-13”). This guidance eliminates certain disclosure requirements for fair value measurements for all entities, requires public entities to disclose certain new information and modifies certain disclosure requirements. The FASB developed the amendments to Topic 820 as part of its broader disclosure framework project, which aims to improve the effectiveness of disclosures in the notes to consolidated financial statements by focusing on requirements that clearly communicate the most important information to users of the consolidated financial statements. This guidance will become effective for interim and annual periods beginning after December 15, 2019. We expect to adopt ASU 2018-13 on January 1, 2020, and we are currently evaluating the impact, if any, that adopting this guidance will have on our disclosures. Cloud Computing Arrangements - In August 2018, the FASB issued ASU No. 2018-15, Customer's Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement that is a Service Contract ("ASU 2018-15"). The ASU aligns the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. The capitalized implementation costs of a hosting arrangement that is a service contract will be expensed over the term of the hosting arrangement. ASU 2018-15 is effective for annual and interim periods beginning after December 15, 2019. Early adoption is permitted, including adoption in any interim period. The amendments can be applied either retrospectively or prospectively to all implementation costs incurred after the adoption date. We expect to adopt ASU 2018-15 on January 1, 2020, and we are currently evaluating the impact, if any, that adopting this guidance will have on our accounting and disclosures. |
