Notes to Consolidated Financial Statements
(Unaudited)
Note 1 – General, Description of Business, and Basis of Presentation
General
Our accompanying interim consolidated financial statements do not include all the notes in our annual financial statements and, therefore, should be read in conjunction with the consolidated financial statements and notes thereto for the year ended December 31, 2017, in our Annual Report on Form 10-K. The accompanying unaudited financial statements include all normal recurring adjustments and others that, in the opinion of management, are necessary to present fairly our interim financial statements.
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.
Unless the context clearly indicates otherwise, references in this report to “we,” “our,” “us,” or like terms refer to Williams Partners L.P. (WPZ) and its subsidiaries. Unless the context clearly indicates otherwise, references to “we,” “our,” and “us” include the operations in which we own interests accounted for as equity-method investments that are not consolidated in our financial statements. When we refer to our equity investees by name, we are referring exclusively to their businesses and operations.
We are a Delaware limited partnership whose common units are listed and traded on the New York Stock Exchange. WPZ GP LLC, a Delaware limited liability company wholly owned by The Williams Companies, Inc. (Williams), serves as our general partner. As of
March 31, 2018
, Williams owns a
74 percent
limited partner interest in us. Our operations are located in the United States.
Financial Repositioning
In January 2017, we entered into agreements with Williams, wherein Williams permanently waived the general partner’s incentive distribution rights and converted its
2 percent
general partner interest in us to a noneconomic interest in exchange for
289 million
newly issued common units. Pursuant to this agreement, Williams also purchased approximately
277 thousand
common units for
$10 million
. Additionally, Williams purchased approximately
59 million
common units at a price of
$36.08586
per unit in a private placement transaction. According to the terms of this agreement, concurrent with our quarterly distributions in February 2017 and May 2017, Williams paid additional consideration totaling
$56 million
to us for these units.
Description of Business
Consistent with the manner in which our chief operating decision maker evaluates performance and allocates resources, our operations are organized into the following reportable segments: Northeast G&P, Atlantic-Gulf, West, and NGL & Petchem Services. Certain other corporate activities are included in Other.
Northeast G&P is comprised of our midstream gathering and processing businesses in the Marcellus Shale region primarily in Pennsylvania, New York, and West Virginia and the Utica Shale region of eastern Ohio, as well as a
66 percent
interest in Cardinal Gas Services, L.L.C. (Cardinal) (a consolidated entity), a
62 percent
equity-method investment in Utica East Ohio Midstream, LLC, a
69 percent
equity-method investment in Laurel Mountain Midstream, LLC, a
58 percent
equity-method investment in Caiman Energy II, LLC, and Appalachia Midstream Services, LLC, which owns equity-method investments with an approximate average
66 percent
interest in multiple gathering systems in the Marcellus Shale (Appalachia Midstream Investments).
Atlantic-Gulf is comprised of our interstate natural gas pipeline, Transcontinental Gas Pipe Line Company, LLC (Transco), and significant natural gas gathering and processing and crude oil production handling and transportation
assets in the Gulf Coast region, including a
51 percent
interest in Gulfstar One LLC (Gulfstar One) (a consolidated entity), which is a proprietary floating production system, and various petrochemical and feedstock pipelines in the Gulf Coast region, as well as a
50 percent
equity-method investment in Gulfstream Natural Gas System, L.L.C., a
41 percent
interest in Constitution Pipeline Company, LLC (Constitution) (a consolidated entity), which is developing a pipeline project (see
Note 3 – Variable Interest Entities
), and a
60 percent
equity-method investment in Discovery Producer Services LLC.
West is comprised of our interstate natural gas pipeline, Northwest Pipeline LLC (Northwest Pipeline), and our gathering, processing, and treating operations in New Mexico, Colorado, and Wyoming, as well as the Barnett Shale region of north-central Texas, the Eagle Ford Shale region of south Texas, the Haynesville Shale region of northwest Louisiana, and the Mid-Continent region which includes the Anadarko, Arkoma, Delaware, and Permian basins. This segment also includes our natural gas liquid (NGL) and natural gas marketing business, storage facilities, an undivided
50 percent
interest in an NGL fractionator near Conway, Kansas, and a
50 percent
equity-method investment in Overland Pass Pipeline, LLC, as well as our previously owned
50 percent
equity-method investment in the Delaware basin gas gathering system (DBJV) in the Mid-Continent region (see
Note 4 – Investing Activities
).
NGL & Petchem Services is comprised of previously owned operations, including an
88.5 percent
undivided interest in an olefins production facility in Geismar, Louisiana, which was sold in July 2017, and a refinery grade propylene splitter in the Gulf region, which was sold in June 2017.
Basis of Presentation
Significant risks and uncertainties
We may monetize assets that are not core to our strategy which could result in impairments of certain equity-method investments, property, plant, and equipment, and intangible assets. Such impairments could potentially be caused by indications of fair value implied through the monetization process or, in the case of asset dispositions that are part of a broader asset group, the impact of the loss of future estimated cash flows.
On March 15, 2018, the Federal Energy Regulatory Commission (FERC) issued a policy statement regarding the recovery of income tax costs in rates of natural gas pipelines. The FERC found that an impermissible double recovery results from granting a Master Limited Partnership (MLP) pipeline both an income tax allowance and a return on equity pursuant to the discounted cash flow methodology. The FERC will no longer permit an MLP pipeline to recover an income tax allowance in its cost of service. The FERC further stated it will address the application of this policy to non-MLP partnership forms as those issues arise in subsequent proceedings. The FERC also issued a Notice of Proposed Rulemaking proposing a process that will allow it to determine which natural gas pipelines may be collecting unjust and unreasonable rates in light of the recent reduction in the corporate income tax rate in the Tax Cuts and Jobs Act (Tax Reform) and this policy statement. Furthermore, the FERC issued a Notice of Inquiry seeking comments on the additional impacts of Tax Reform on jurisdictional rates, particularly whether, and if so how, the FERC should address changes relating to accumulated deferred income tax amounts after the corporate income tax rate reduction and bonus depreciation rules, as well as whether other features of Tax Reform require FERC action. We are evaluating the impact of these developments on our interstate natural gas pipelines and currently expect any associated impacts would be prospective and determined through subsequent rate proceedings. We also continue to monitor developments that may impact our regulatory liabilities resulting from Tax Reform. It is reasonably possible that future tariff-based rates collected by our interstate natural gas pipelines may be adversely impacted.
Accounting standards issued and adopted
Effective January 1, 2018, we adopted Accounting Standards Update (ASU) 2017-12 “Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities” (ASU 2017-12). ASU 2017-12 applies to entities that elect hedge accounting in accordance with Accounting Standards Codification (ASC) 815. The ASU affects both the designation and measurement guidance for hedging relationships and the presentation of hedging results. ASU 2017-12 was applied using a modified retrospective approach for cash flow and net investment hedges existing at the date of adoption and prospectively for the presentation and disclosure guidance. The adoption of ASU 2017-12 did not have a significant impact on our consolidated financial statements.
Effective January 1, 2018, we adopted ASU 2016-15 “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments” (ASU 2016-15). Among other things, ASU 2016-15 permits an accounting policy election to classify distributions received from equity-method investees using either the cumulative earnings approach or the nature of distribution approach. We have elected to apply the nature of distribution approach and have retrospectively conformed the prior year presentation within the
Consolidated Statement of Cash Flows
in accordance with ASU 2016-15. For the period ended March 31, 2017, amounts previously presented as
Distributions from unconsolidated affiliates in excess of cumulative earnings
within
Investing Activities
are now presented as part of
Distributions from unconsolidated affiliates
within
Operating Activities
, resulting in an increase to
Net cash provided (used) by operating activities
of $121 million with a corresponding reduction in
Net cash provided (used) by investing activities
.
In May 2014, the Financial Accounting Standards Board (FASB) issued ASU 2014-09 establishing ASC Topic 606, “Revenue from Contracts with Customers” (ASC 606). ASC 606 establishes a comprehensive new revenue recognition model designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to be entitled to receive in exchange for those goods or services and requires significantly enhanced revenue disclosures. In August 2015, the FASB issued ASU 2015-14 “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date” (ASU 2015-14). Per ASU 2015-14, the standard became effective for interim and annual reporting periods beginning after December 15, 2017.
We adopted the provisions of ASC 606 effective January 1, 2018, utilizing the modified retrospective transition method for all contracts with customers, which included applying the provisions of ASC 606 beginning January 1, 2018, to all contracts not completed as of that date with the cumulative effect of applying the standard for periods prior to January 1, 2018, as an adjustment to
Total equity
upon adoption. As a result of our adoption, the cumulative impact to our
Total equity
at January 1, 2018, was a decrease of
$148 million
in the
Consolidated Balance Sheet
.
For each revenue contract type, we conducted a formal contract review process to evaluate the impact of ASC 606. The adjustment to
Total equity
upon adoption of ASC 606 is primarily comprised of the impact to the timing of recognition of deferred revenue (contract liabilities) associated with certain contracts which underwent modifications in periods prior to January 1, 2018. Under the provisions of ASC 606, when a contract modification does not increase both the scope and price of the contract, and the remaining goods and services are distinct from the goods and services transferred prior to the modification, the modification is treated as a termination of the existing contract and the creation of a new contract. ASC 606 requires that the transaction price, including any remaining contract liabilities from the old contract, be allocated to the performance obligations over the term of the new contract. The contract modification adjustments are partially offset by the impact of changes to the timing of recognizing revenue which is subject to the constraint on estimates of variable consideration of certain contracts. The constraint of variable consideration will result in the acceleration of revenue recognition and corresponding de-recognition of contract liabilities for certain contracts (as compared to the previous revenue recognition model) as a result of our assessment that it is probable such recognition would not result in a significant revenue reversal in the future. Additionally, under ASC 606, our revenues will increase in situations where we receive noncash consideration, which exists primarily in certain of our gas processing contracts where we receive commodities as full or partial consideration for services provided. This increase in revenues will be offset by a similar increase in costs and expenses when the commodities received are subsequently sold. Financial systems and internal controls necessary for adoption were implemented effective January 1, 2018. (See
Note 2 – Revenue Recognition
.)
Accounting standards issued but not yet adopted
In June 2016, the FASB issued ASU 2016-13 “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” (ASU 2016-13). ASU 2016-13 changes the impairment model for most financial assets and certain other instruments. For trade and other receivables, held-to-maturity debt securities, loans, and other instruments, entities will be required to use a new forward-looking “expected loss” model that generally will result in the earlier recognition of allowances for losses. The guidance also requires increased disclosures. ASU 2016-13 is effective for interim and annual periods beginning after December 15, 2019. Early adoption is permitted. The standard requires varying transition methods for the different categories of amendments. Although we do not expect ASU 2016-13 to have a significant impact, it will impact our trade receivables as the related allowance for credit losses will be recognized earlier under the expected loss model.
In February 2016, the FASB issued ASU 2016-02 “Leases (Topic 842)” (ASU 2016-02). ASU 2016-02 establishes a comprehensive new lease accounting model. ASU 2016-02 modifies the definition of a lease, requires a dual approach to lease classification similar to current lease accounting, and causes lessees to recognize operating leases on the balance sheet as a lease liability measured as the present value of the future lease payments with a corresponding right-of-use asset, with an exception for leases with a term of one year or less. Additional disclosures will also be required regarding the amount, timing, and uncertainty of cash flows arising from leases. In January 2018, the FASB issued ASU 2018-01 “Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842” (ASU 2018-01). Per ASU 2018-01, land easements and rights-of-way are required to be assessed under ASU 2016-02 to determine whether the arrangements are or contain a lease. ASU 2018-01 permits an entity to elect a transition practical expedient to not apply ASU 2016-02 to land easements that exist or expired before the effective date of ASU 2016-02 and that were not previously assessed under the previous lease guidance in ASC Topic 840 “Leases.” ASU 2016-02 is effective for interim and annual periods beginning after December 15, 2018. Early adoption is permitted. We expect to adopt ASU 2016-02 effective January 1, 2019. ASU 2016-02 currently requires a modified retrospective transition for financing or operating leases existing at or entered into after the beginning of the earliest comparative period presented in the financial statements.
In January 2018, the FASB proposed an ASU titled “Leases (Topic 842): Targeted Improvements,” which is an update to ASU 2016-02 allowing entities an additional transition method to the existing requirements whereby an entity could adopt the provisions of ASU 2016-02 by recognizing a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption without adjustment to the financial statements for periods prior to adoption.
We are in the process of reviewing contracts to identify leases based on the modified definition of a lease, implementing a financial lease accounting system, and evaluating internal control changes to support management in the accounting for and disclosure of leasing activities. While we are still in the process of completing our implementation evaluation of ASU 2016-02, we currently believe the most significant changes to our financial statements relate to the recognition of a lease liability and offsetting right-of-use asset in our consolidated balance sheet for operating leases. We are also evaluating ASU 2016-02’s currently available and proposed practical expedients on adoption.
Note 2 – Revenue Recognition
Customers in our gas pipeline businesses are comprised of public utilities, municipalities, gas marketers and producers, intrastate pipelines, direct industrial users, and electrical generators. Customers in our midstream businesses are comprised of oil and natural gas producer counterparties. Customers for our product sales are comprised of public utilities, gas marketers, and direct industrial users.
A performance obligation is a promise in a contract to transfer a distinct good or service (or integrated package of goods or services) to the customer. A contract’s transaction price is allocated to each distinct performance obligation and recognized as revenue, when, or as, the performance obligation is satisfied. A performance obligation is distinct if the service is separately identifiable from other items in the integrated package of services and if a customer can benefit from it on its own or with other resources that are readily available to the customer. An integrated package of services typically represents a single performance obligation if the services are contained within the same contract or within multiple contracts entered into in contemplation with one another that are highly interdependent or highly interrelated, meaning each of the services is significantly affected by one or more of the other services in the contract. Service revenue contracts related to our gas pipeline and midstream businesses contain a series of distinct services, with the majority of our contracts having a single performance obligation that is satisfied over time as the customer simultaneously receives and consumes the benefits provided by our performance. Most of our product sales contracts have a single performance obligation with revenue recognized at a point in time when the products have been sold and delivered to the customer.
Certain customers reimburse us for costs we incur associated with construction of property, plant, and equipment utilized in our operations. For our rate-regulated gas pipeline businesses that apply ASC 980. "Regulated Operations" (Topic 980), we follow FERC guidelines with respect to reimbursement of construction costs. FERC tariffs only allow for cost reimbursement and are non-negotiable in nature; thus, the construction activities do not represent an ongoing major and central operation of our gas pipelines business and are not within the scope of ASC 606. Accordingly, cost reimbursements are treated as a reduction to the cost of the constructed asset. For our midstream businesses, reimbursement and service contracts with customers are viewed together as providing the same commercial
objective, as we have the ability to negotiate the mix of consideration between reimbursements and amounts billed over time. Accordingly, we generally recognize reimbursements of construction costs from customers on a gross basis as a contract liability separate from the associated costs included within property, plant, and equipment. The contract liability is recognized into service revenues as the underlying performance obligations are satisfied.
Service Revenues
Gas pipeline businesses
Revenues from our interstate natural gas pipeline businesses, which are included within the caption “Regulated interstate natural gas transportation and storage” in the revenue by category table below and are subject to regulation by certain state and federal authorities, including the FERC, include both firm and interruptible transportation and storage contracts. Firm transportation and storage agreements provide for a reservation charge based on the pipeline or storage capacity reserved, and a commodity charge based on the volume of natural gas delivered/stored, each at rates specified in our FERC tariffs or based on negotiated contractual rates, with contract terms that are generally long-term in nature. Most of our long-term contracts contain an evergreen provision, which allows the contracts to be extended for periods primarily up to one year in length an indefinite number of times following the specified contract term and until terminated generally by either us or the customer. Interruptible transportation and storage agreements provide for a volumetric charge based on actual commodity transportation or storage utilized in the period in which those services are provided, and the contracts are generally limited to one month periods or less. Our performance obligations related to our interstate natural gas pipeline businesses include the following:
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•
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Guaranteed transportation or storage under firm transportation and storage contracts—an integrated package of services typically constituting a single performance obligation, which includes standing ready to provide such services and receiving, transporting or storing (as applicable), and redelivering commodities;
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•
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Interruptible transportation and storage under interruptible transportation and storage contracts—an integrated package of services typically constituting a single performance obligation, which includes receiving, transporting or storing (as applicable), and redelivering commodities upon nomination by the customer.
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In situations where we consider an integrated package of services a single performance obligation, which represents a majority of our interstate natural gas pipeline contracts with customers, we do not consider there to be multiple performance obligations because the nature of the overall promise in the contract is to stand ready (with regard to firm transportation and storage contracts), receive, transport or store, and redeliver natural gas to the customer; therefore, revenue is recognized at the completion of the integrated package of services and represents a single performance obligation.
We recognize revenues for reservation charges over the performance obligation period, which is the contract term, regardless of the volume of natural gas that is transported or stored. Revenues for commodity charges from both firm and interruptible transportation services and storage services are recognized when natural gas is delivered at the agreed upon delivery point or when natural gas is injected or withdrawn from the storage facility because they specifically relate to our efforts to transfer these distinct services. Generally, reservation charges and commodity charges in our interstate natural gas pipeline businesses are recognized as revenue in the same period they are invoiced to our customers. As a result of the ratemaking process, certain amounts collected by us may be subject to refunds upon the issuance of final orders by the FERC in pending rate proceedings. We record estimates of rate refund liabilities considering our and other third-party regulatory proceedings, advice of counsel, and other risks.
Midstream businesses
Revenues from our midstream businesses, which are included in the caption titled “Non-regulated gathering, processing, transportation, and storage” in the revenue by category table below, include contracts for natural gas gathering, processing, treating, compression, transportation, and other related services with contract terms that are generally long-term in nature and may extend up to the production life of the associated reservoir. Additionally, our midstream businesses generate revenues from fees charged for storing customers’ NGLs, generally under prepaid contracted storage capacity contracts. In situations where we provide an integrated package of services combined into
a single performance obligation, which represents a majority of this class of contracts with customers, we do not consider there to be multiple performance obligations because the nature of the overall promise in the contract is to provide gathering, processing, transportation, storage, and related services resulting in the delivery, or redelivery in the context of storage services, of pipeline-quality natural gas and NGLs to the customer. As such, revenue is recognized at the daily completion of the integrated package of services as the integrated package represents a single performance obligation. Additionally, certain contracts in our midstream businesses contain fixed or upfront payment terms that result in the deferral of revenues until such services have been performed or such capacity has been made available.
We also earn revenues from offshore crude oil and natural gas gathering and transportation and offshore production handling. These services represent an integrated package of services and are considered a single distinct performance obligation for which we recognize revenues as the services are provided to the customer.
We generally earn a contractually-stated fee per unit for the volume of product transported, gathered, processed, or stored. The rate is generally fixed; however, certain contracts contain variable rates that are subject to change based on commodity prices, levels of throughput, or an annual adjustment based on a formulaic cost of service calculation. In addition, we have contracts with contractually-stated fees that decline over the contract term, such as declines based on the passage of time periods or achievement of cumulative throughput amounts. For all of our contracts, we allocate the transaction price to each performance obligation based on the relative standalone selling price. The excess of consideration received over revenue recognized results in the deferral of those amounts until future periods based on a units of production or straight-line methodology. Certain of our gas gathering and processing agreements have minimum volume commitments (MVC). If a customer under such an agreement fails to meet its MVC for a specified period (thus not exercising all the contractual rights to gathering and processing services within the specified period, herein referred to as “breakage”), it is obligated to pay a contractually determined fee based upon the shortfall between the actual gathered or processed volumes and the MVC for the period contained in the contract. When we conclude it is probable that the customer will not exercise all or a portion of its remaining rights, we recognize revenue associated with such breakage amount in proportion to the pattern of exercised rights within the respective MVC period.
Under keep-whole and percent-of-liquids processing contracts, we receive commodity consideration in the form of NGLs and take title to the NGLs at the tailgate of the plant. We recognize such commodity consideration as service revenue based on the market value of the NGLs retained at the time the processing is provided. The current market value, as opposed to the market value at the contract inception date, is used due to a combination of factors, including the fact that the volume, mix, and market price of NGL consideration to be received is unknown at the time of contract execution and is not specified in our contracts with customers. Additionally, product sales revenue (discussed below) is recognized upon the sale of the NGLs to a third party based on the sales price at the time of sale. As a result, revenue is recognized both at the time the processing service is provided in
Service revenues – commodity consideration
and at the time the NGLs retained as part of the processing service are sold in
Product sales
. The recognition of revenue related to commodity consideration has the impact of increasing the book value of NGL inventory, resulting in higher cost of goods sold at the time of sale. Given that most inventory is sold in the same period that it is generated, the impact of these transactions is expected to have little impact to operating income.
Product Sales
In the course of providing transportation services to customers of our gas pipeline businesses and gathering and processing services to customers of our midstream businesses, we may receive different quantities of natural gas from customers than the quantities delivered on behalf of those customers. The resulting imbalances are primarily settled through the purchase or sale of natural gas with each customer under terms provided for in our FERC tariffs or gathering and processing agreements, respectively. Revenue is recognized from the sale of natural gas upon settlement of imbalances.
In certain instances, we purchase NGLs, crude oil, and natural gas from our oil and natural gas producer customers. In addition, we retain NGLs as consideration in certain processing arrangements, as discussed above in the Service Revenues - Midstream businesses section. We recognize revenue from the sale of these commodities when the products have been sold and delivered. Our product sales contracts are primarily short-term contracts based on prevailing market rates at the time of the transaction.
Revenue by Category
The following table presents our revenue disaggregated by major service line:
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Northeast
Midstream
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Atlantic-
Gulf Midstream
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West Midstream
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Transco
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Northwest Pipeline
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Intercompany Eliminations
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Total
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(Millions)
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Three Months Ended March 31, 2018
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Revenues from contracts with customers:
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Service revenues:
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Non-regulated gathering, processing, transportation, and storage:
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Monetary consideration
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$
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202
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$
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137
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$
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408
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$
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—
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$
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—
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$
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(18
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)
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$
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729
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Commodity consideration
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4
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15
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82
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—
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—
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—
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101
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Regulated interstate natural gas transportation and storage
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—
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—
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—
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461
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112
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(1
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)
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572
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Other
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21
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6
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11
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—
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—
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(3
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)
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35
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Total service revenues
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227
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158
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501
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461
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112
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(22
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)
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1,437
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Product Sales:
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NGL and natural gas
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98
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68
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521
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25
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—
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(85
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)
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627
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Other
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—
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—
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4
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—
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—
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—
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4
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Total product sales
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98
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68
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525
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25
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—
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(85
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)
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631
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Total revenues from contracts with customers
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325
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226
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1,026
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486
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112
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(107
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)
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2,068
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Other revenues (1)
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5
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2
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5
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3
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—
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—
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15
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Total revenues
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$
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330
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$
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228
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$
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1,031
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$
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489
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$
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112
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$
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(107
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)
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$
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2,083
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(1)
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We provide management services to operated joint ventures and other investments for which we receive a management fee that is categorized as
Service revenues
in our Consolidated Statement of Comprehensive Income. These management fees do not constitute revenue from contracts with customers.
Product sales
in our Consolidated Statement of Comprehensive Income include amounts associated with our derivative contracts that are not within the scope of ASC 606.
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Contract Assets
Our contract assets primarily consist of revenue recognized under contracts containing MVC features whereby management has concluded it is probable there will be a short-fall payment at the end of the current MVC period, which typically follows the calendar year, and that a significant reversal of revenue recognized currently for the future MVC payment will not occur. As a result, our contract assets related to our future MVC payments are generally expected to be collected within the next 12 months and are included within
Other current assets and deferred charges
in our Consolidated Balance Sheet until such time as the MVC short-fall payments are invoiced to the customer.
The following table presents a reconciliation of the beginning and ending balances of our contract assets for the period ended March 31, 2018:
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2018
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(Millions)
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Balance at January 1
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$
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4
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Revenue recognized in excess of cash received
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20
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Minimum volume commitments invoiced
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—
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Balance at March 31
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$
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24
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Contract Liabilities
Our contract liabilities consist of advance payments primarily from midstream business customers which include construction reimbursements, prepayments, and other billings for which future services are to be provided under the contract. These amounts are deferred until recognized in revenue when the associated performance obligation has been satisfied, which is primarily based on a units of production methodology over the remaining contractual service periods, and are classified as current or noncurrent according to when such amounts are expected to be recognized. Current and noncurrent contract liabilities are included within
Other accrued liabilities
and
Regulatory liabilities, deferred income, and other
, respectively, in our Consolidated Balance Sheet.
Contracts requiring advance payments and the recognition of contract liabilities are evaluated to determine whether the advance payments provide us with a significant financing benefit. This determination is based on the combined effect of the expected length of time between when we transfer the promised good or service to the customer, when the customer pays for those goods or services, and the prevailing interest rates. We have assessed our contracts for significant financing components and determined that one group of contracts entered into in contemplation of one another for certain capital reimbursements contains a significant financing component. As a result, we recognize noncash interest expense based on the effective interest method and revenue (noncash) is recognized when the underlying asset is placed into service utilizing a units of production or straight-line methodology over the life of the corresponding customer contract.
The following table presents a reconciliation of the beginning and ending balances of our contract liabilities for the period ended March 31, 2018:
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|
|
|
|
2018
|
|
|
(Millions)
|
|
Balance at January 1
|
$
|
1,596
|
|
|
Payments received and deferred
|
92
|
|
|
Recognized in revenue
|
(114
|
)
|
|
Balance at March 31
|
$
|
1,574
|
|
The following table presents the amount of the contract liabilities balance as of March 31, 2018, expected to be recognized as revenue in each of the next five years as performance obligations are expected to be satisfied:
|
|
|
|
|
|
|
|
|
(Millions)
|
|
2018 (remainder)
|
$
|
251
|
|
|
2019
|
252
|
|
|
2020
|
120
|
|
|
2021
|
100
|
|
|
2022
|
94
|
|
|
2023
|
88
|
|
|
Thereafter
|
669
|
|
Remaining Performance Obligations
The following table presents the transaction price allocated to the remaining performance obligations under certain contracts as of March 31, 2018. These primarily include long-term contracts containing MVCs associated with our midstream businesses, fixed payments associated with offshore production handling, and reservation charges on contracted capacity on our gas pipeline firm transportation contracts with customers, as well as storage capacity contracts. Amounts included in the table below for our interstate natural gas pipeline businesses reflect the rates for such services in our current FERC tariffs for the life of the related contracts; however, these rates may change based on future tariffs approved by the FERC and the amount and timing of these changes is not currently known. As a practical expedient permitted by ASC 606, this table excludes variable consideration as well as consideration in contracts that is recognized in revenue as billed. It also excludes consideration received prior to March 31, 2018, that will be recognized in future periods (see above for Contract Liabilities and the expected recognition of those amounts within
revenue). As noted above, certain of our contracts contain evergreen and other renewal provisions for periods beyond the initial term of the contract. The remaining performance obligation as of March 31, 2018, does not consider potential future performance obligations for which the renewal has not been exercised. The table below also does not include contracts with customers for which the underlying facilities have not received FERC authorization to be placed into service.
|
|
|
|
|
|
|
|
|
(Millions)
|
|
2018 (remainder)
|
$
|
1,917
|
|
|
2019
|
2,399
|
|
|
2020
|
2,199
|
|
|
2021
|
1,881
|
|
|
2022
|
1,749
|
|
|
2023
|
1,559
|
|
|
Thereafter
|
11,636
|
|
|
Total
|
$
|
23,340
|
|
Accounts Receivable
We do not offer extended payment terms and typically receive payment within one month. We consider receivables past due if full payment is not received by the contractual due date. Interest income related to past due accounts receivable is generally recognized at the time full payment is received or collectability is assured.
The following is a summary of our
Trade accounts and other receivables
as it relates to contracts with customers:
|
|
|
|
|
|
|
|
|
March 31, 2018
|
|
|
(Millions)
|
|
Accounts receivable related to revenues from contracts with customers
|
$
|
701
|
|
|
Other accounts receivable
|
17
|
|
|
Total reflected in
Trade accounts and other receivables
|
$
|
718
|
|
Impact of Adoption of ASC 606
The following table depicts the impact of the adoption of ASC 606 on our 2018 financial statements. The adjustment to
Intangible assets – net of accumulated amortization
in the table below relates to the recognition under ASC 606 of contract assets for MVC-related contracts associated with a 2014 acquisition. The recognition of these contract assets resulted in a lower purchase price allocation to intangible assets. The adoption of ASC 606 did not result in adjustments to total operating, investing, or financing cash flows.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As Reported
|
|
Adjustments resulting from adoption of ASC 606
|
|
Balance without adoption of ASC 606
|
|
|
(Millions, except per unit amounts)
|
|
Consolidated Statement of Comprehensive Income
|
|
Three Months Ended March 31, 2018
|
|
|
|
|
|
|
Service revenues
|
$
|
1,346
|
|
|
$
|
5
|
|
|
$
|
1,351
|
|
|
Service revenues - commodity consideration
|
101
|
|
|
(101
|
)
|
|
—
|
|
|
Product sales
|
636
|
|
|
10
|
|
|
646
|
|
|
Total revenues
|
2,083
|
|
|
(86
|
)
|
|
1,997
|
|
|
Product costs
|
613
|
|
|
(55
|
)
|
|
558
|
|
|
Processing commodity expenses
|
35
|
|
|
(35
|
)
|
|
—
|
|
|
Operating and maintenance expenses
|
351
|
|
|
(1
|
)
|
|
350
|
|
|
Depreciation and amortization expenses
|
423
|
|
|
1
|
|
|
424
|
|
|
Total costs and expenses
|
1,591
|
|
|
(90
|
)
|
|
1,501
|
|
|
Operating income (loss)
|
492
|
|
|
4
|
|
|
496
|
|
|
Interest incurred
|
(218
|
)
|
|
3
|
|
|
(215
|
)
|
|
Interest capitalized
|
9
|
|
|
(2
|
)
|
|
7
|
|
|
Income (loss) before income taxes
|
384
|
|
|
5
|
|
|
389
|
|
|
Net income (loss)
|
384
|
|
|
5
|
|
|
389
|
|
|
Less: Net income (loss) attributable to noncontrolling interests
|
24
|
|
|
(1
|
)
|
|
23
|
|
|
Net income (loss) attributable to controlling interests
|
360
|
|
|
6
|
|
|
366
|
|
|
Allocation of net income (loss) to common units
|
353
|
|
|
6
|
|
|
359
|
|
|
Basic earnings (loss) per common unit
|
0.37
|
|
|
0.01
|
|
|
0.38
|
|
|
Diluted earnings (loss) per common unit
|
0.37
|
|
|
0.01
|
|
|
0.38
|
|
|
Comprehensive income (loss)
|
386
|
|
|
5
|
|
|
391
|
|
|
Less: Comprehensive income attributable to noncontrolling interests
|
24
|
|
|
(1
|
)
|
|
23
|
|
|
Comprehensive income (loss) attributable to controlling interests
|
362
|
|
|
6
|
|
|
368
|
|
|
|
|
|
|
|
|
|
Consolidated Balance Sheet
|
|
March 31, 2018
|
|
|
|
|
|
|
Inventories
|
$
|
160
|
|
|
$
|
(8
|
)
|
|
$
|
152
|
|
|
Other current assets and deferred charges
|
198
|
|
|
(20
|
)
|
|
178
|
|
|
Total current assets
|
2,344
|
|
|
(28
|
)
|
|
2,316
|
|
|
Investments
|
6,513
|
|
|
(1
|
)
|
|
6,512
|
|
|
Property, plant and equipment
|
39,876
|
|
|
(2
|
)
|
|
39,874
|
|
|
Property, plant, and equipment – net
|
28,547
|
|
|
(2
|
)
|
|
28,545
|
|
|
Intangible assets – net of accumulated amortization
|
8,643
|
|
|
63
|
|
|
8,706
|
|
|
Regulatory assets, deferred charges, and other
|
528
|
|
|
(4
|
)
|
|
524
|
|
|
Total assets
|
46,575
|
|
|
28
|
|
|
46,603
|
|
|
Regulatory liabilities, deferred income, and other
|
3,221
|
|
|
(125
|
)
|
|
3,096
|
|
|
Common and Class B units
|
21,694
|
|
|
157
|
|
|
21,851
|
|
|
Total partners’ equity
|
21,691
|
|
|
157
|
|
|
21,848
|
|
|
Noncontrolling interests in consolidated subsidiaries
|
1,654
|
|
|
(4
|
)
|
|
1,650
|
|
|
Total equity
|
23,345
|
|
|
153
|
|
|
23,498
|
|
|
Total liabilities and equity
|
46,575
|
|
|
28
|
|
|
46,603
|
|
|
|
|
|
|
|
|
|
Consolidated Statement of Changes in Equity
|
|
|
|
|
|
|
March 31, 2018
|
|
|
|
|
|
|
Adoption of ASC 606
|
$
|
(148
|
)
|
|
$
|
148
|
|
|
$
|
—
|
|
|
Net income (loss)
|
384
|
|
|
5
|
|
|
389
|
|
|
Net increase (decrease) in equity
|
(344
|
)
|
|
153
|
|
|
(191
|
)
|
|
Balance - March 31, 2018
|
23,345
|
|
|
153
|
|
|
23,498
|
|
Note 3 – Variable Interest Entities
As of
March 31, 2018
, we consolidate the following variable interest entities (VIEs):
Gulfstar One
We own a
51 percent
interest in Gulfstar One, a subsidiary that, due to certain risk-sharing provisions in its customer contracts, is a VIE. Gulfstar One includes a proprietary floating-production system, Gulfstar FPS, and associated pipelines which provide production handling and gathering services in the eastern deepwater Gulf of Mexico. We are
the primary beneficiary because we have the power to direct the activities that most significantly impact Gulfstar One’s economic performance.
Constitution
We own a
41 percent
interest in Constitution, a subsidiary that, due to shipper fixed-payment commitments under its long-term firm transportation contracts, is a VIE. We are the primary beneficiary because we have the power to direct the activities that most significantly impact Constitution’s economic performance. We, as operator of Constitution, are responsible for constructing the proposed pipeline connecting our gathering system in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and the Tennessee Gas Pipeline systems. The total remaining cost of the project is estimated to be approximately
$740 million
, which would be funded with capital contributions from us and the other equity partners on a proportional basis.
In December 2014, Constitution received approval from the FERC to construct and operate its proposed pipeline. However, in April 2016, the New York State Department of Environmental Conservation (NYSDEC) denied the necessary water quality certification under Section 401 of the Clean Water Act for the New York portion of the pipeline. In May 2016, Constitution appealed the NYSDEC’s denial of the Section 401 certification to the United States Court of Appeals for the Second Circuit, and in August 2017 the court issued a decision denying in part and dismissing in part Constitution’s appeal. The court expressly declined to rule on Constitution’s argument that the delay in the NYSDEC’s decision on Constitution’s Section 401 application constitutes a waiver of the certification requirement. The court determined that it lacked jurisdiction to address that contention, and found that jurisdiction over the waiver issue lies exclusively with the United States Court of Appeals for the District of Columbia Circuit. As to the denial itself, the court determined that NYSDEC’s action was not arbitrary or capricious. Constitution filed a petition for rehearing with the Second Circuit Court of Appeals, but in October the court denied our petition.
In October 2017, we filed a petition for declaratory order requesting the FERC to find that, by operation of law, the Section 401 certification requirement for the New York State portion of Constitution’s pipeline project was waived due to the failure by the NYSDEC to act on Constitution’s Section 401 application within a reasonable period of time as required by the express terms of such statute. In January 2018, the FERC denied our petition, finding that Section 401 provides that a state waives certification only when it does not act on an application within one year from the date of the application.
The project’s sponsors remain committed to the project. In February 2018, we filed a request with the FERC for rehearing of its finding that the NYSDEC did not waive the Section 401 certification requirement. If the FERC denies such request, we will file a petition for review with the D.C. Circuit Court of Appeals. In January 2018, we filed a petition with the United States Supreme Court to review the decision of the Second Circuit Court of Appeals that upheld the merits of the NYSDEC’s denial of the Section 401 certification. However, on April 30, 2018, the Court denied our petition. This decision is separate and independent from (and thus has no impact on) our request for rehearing (or appeal) of the FERC’s decision that the NYSDEC did not waive the Section 401 certification requirement.
Should any court or FERC decision determine that the NYSDEC waived the Section 401 certification requirement, we estimate that the target in-service date for the project would be approximately 10 to 12 months following any such determination. An unfavorable resolution could result in the impairment of a significant portion of the capitalized project costs, which total
$379 million
on a consolidated basis at
March 31, 2018
, and are included within
Property, plant, and equipment
in the
Consolidated Balance Sheet
. Beginning in April 2016, we discontinued capitalization of development costs related to this project. It is also possible that we could incur certain supplier-related costs in the event of a prolonged delay or termination of the project.
Cardinal
We own a
66 percent
interest in Cardinal, a subsidiary that provides gathering services for the Utica Shale region and is a VIE due to certain risks shared with customers. We are the primary beneficiary because we have the power to direct the activities that most significantly impact Cardinal’s economic performance. We expect to fund future expansion activity with capital contributions from us and the other equity partner on a proportional basis.
Jackalope
We own a
50 percent
interest in Jackalope Gas Gathering Services, L.L.C. (Jackalope), a subsidiary that provides gathering and processing services for the Powder River basin and is a VIE due to certain risks shared with customers. We are the primary beneficiary because we have the power to direct the activities that most significantly impact Jackalope’s economic performance. We expect to fund future expansion activity with capital contributions from us and the other equity partner on a proportional basis.
The following table presents amounts included in our
Consolidated Balance Sheet
that are for the use or obligation of our consolidated VIEs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31,
2018
|
|
December 31,
2017
|
|
Classification
|
|
|
(Millions)
|
|
|
|
Assets (liabilities):
|
|
|
|
|
|
|
Cash and cash equivalents
|
$
|
54
|
|
|
$
|
35
|
|
|
Cash and cash equivalents
|
|
Accounts receivable
|
66
|
|
|
76
|
|
|
Trade accounts and other receivables
|
|
Prepaid assets
|
2
|
|
|
2
|
|
|
Other current assets and deferred charges
|
|
Property, plant, and equipment – net
|
2,852
|
|
|
2,887
|
|
|
Property, plant, and equipment – net
|
|
Intangible assets
–
net
|
1,369
|
|
|
1,381
|
|
|
Intangible assets – net of accumulated amortization
|
|
Accounts payable
|
(15
|
)
|
|
(28
|
)
|
|
Accounts payable – trade
|
|
Accrued liabilities
|
(1
|
)
|
|
(1
|
)
|
|
Other accrued liabilities
|
|
Current deferred revenue
|
(57
|
)
|
|
(57
|
)
|
|
Other accrued liabilities
|
|
Noncurrent asset retirement obligations
|
(105
|
)
|
|
(103
|
)
|
|
Asset retirement obligations
|
|
Noncurrent deferred revenue associated with customer advance payments
|
(293
|
)
|
|
(305
|
)
|
|
Regulatory liabilities, deferred income, and other
|
Note 4 – Investing Activities
Acquisition of Additional Interests in Appalachia Midstream Investments
During the first quarter of 2017, we exchanged all of our
50 percent
interest in DBJV for an increased interest in two natural gas gathering systems that are part of the Appalachia Midstream Investments and
$155 million
in cash. This transaction was recorded based on our estimate of the fair value of the interests received as we have more insight to this value as we operate the underlying assets. Following this exchange, we have an approximate average
66 percent
interest in the Appalachia Midstream Investments. We continue to account for this investment under the equity-method due to the significant participatory rights of our partners such that we do not exercise control. We also sold all of our interest in Ranch Westex JV LLC for
$45 million
. These transactions resulted in a total gain of
$269 million
reflected in
Other investing income (loss) – net
in the
Consolidated Statement of Comprehensive Income
.
The fair value of the increased interests in the Appalachia Midstream Investments received as consideration was estimated to be
$1.1 billion
using an income approach based on expected cash flows and an appropriate discount rate (a Level 3 measurement within the fair value hierarchy). The determination of estimated future cash flows involved significant assumptions regarding gathering volumes, rates, and related capital spending. A
9.5 percent
discount rate was utilized and reflected our estimate of the cost of capital as impacted by market conditions and risks associated with the underlying business.
Note 5 – Other Income and Expenses
The following table presents certain gains or losses reflected in
Other (income) expense – net
within
Costs and expenses
in our
Consolidated Statement of Comprehensive Income
:
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
March 31,
|
|
|
2018
|
|
2017
|
|
|
(Millions)
|
|
West
|
|
|
|
|
Gains on contract settlements and terminations
|
$
|
—
|
|
|
$
|
(13
|
)
|
Additional Items
Certain additional items included in the Consolidated Statement of Comprehensive Income are as follows:
|
|
|
|
•
|
Other income (expense) – net
below
Operating income (loss)
includes income of
$20 million
and
$18 million
for the
three
months ended
March 31, 2018
and 2017, respectively, related to allowance for equity funds used during construction within the Atlantic-Gulf segment.
|
|
|
|
|
•
|
Other income (expense) – net
below
Operating income (loss)
for the
three
months ended March 31, 2018, includes a
$7 million
net loss associated with the March 28, 2018, early retirement of
$750 million
of
4.875 percent
senior unsecured notes that were due in 2024. The net loss within the Other segment reflects
$34 million
in premiums paid, partially offset by
$27 million
of unamortized premium. For the three months ended March 31, 2017,
Other income (expense) – net
below
Operating income (loss)
includes a
$30 million
net gain associated with the February 23, 2017, early retirement of
$750 million
of
6.125 percent
senior unsecured notes that were due in 2022. The net gain within the Other segment reflects
$53 million
of unamortized premium, partially offset by
$23 million
in premiums paid. (See
Note 6 – Debt and Banking Arrangements
.)
|
Note 6 – Debt and Banking Arrangements
Long-Term Debt
Issuances and retirements
On March 5, 2018, we completed a public offering of
$800 million
of
4.85 percent
senior unsecured notes due 2048. We used the net proceeds for general partnership purposes, primarily the March 28, 2018, repayment of
$750 million
of
4.875 percent
senior unsecured notes that were due in 2024.
On March 15, 2018, Transco issued
$400 million
of
4.0 percent
senior unsecured notes due 2028 and
$600 million
of
4.6 percent
senior unsecured notes due 2048 to investors in a private debt placement. Transco intends to use the net proceeds to retire
$250 million
of
6.05 percent
senior unsecured notes due June 2018, and for general corporate purposes, including the funding of capital expenditures. As part of the issuance, Transco entered into a registration rights agreement with the initial purchasers of the unsecured notes. Transco is obligated to file and consummate a registration statement for an offer to exchange the notes for a new issue of substantially identical notes registered under the Securities Act of 1933, as amended, within 365 days from closing and to use commercially reasonable efforts to complete the exchange offer. Transco is required to provide a shelf registration statement to cover resales of the notes under certain circumstances. If Transco fails to fulfill these obligations, additional interest will accrue on the affected securities. The rate of additional interest will be
0.25 percent
per annum on the principal amount of the affected securities for the first 90-day period immediately following the occurrence of a registration default, increasing by an additional
0.25 percent
per annum with respect to each subsequent 90-day period thereafter, up to a maximum amount for all such registration defaults of
0.5 percent
annually. Following the cure of any registration defaults, the accrual of additional interest will cease.
Other financing obligation
During the first quarter of 2018, Transco received an additional
$19 million
of funding from a co-owner related to the construction of the Dalton expansion project. This additional funding is reflected as
Long-term debt
in the
Consolidated Balance Sheet
.
Commercial Paper Program
As of March 31, 2018, no commercial paper was outstanding under our
$3 billion
commercial paper program.
Credit Facilities
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2018
|
|
|
Stated Capacity
|
|
Outstanding
|
|
|
(Millions)
|
|
Long-term credit facility (1)
|
$
|
3,500
|
|
|
$
|
—
|
|
|
Letters of credit under certain bilateral bank agreements
|
|
|
1
|
|
|
|
|
|
(1)
|
In managing our available liquidity, we do not expect a maximum outstanding amount in excess of the capacity of our credit facility inclusive of any outstanding amounts under our commercial paper program.
|
Note 7 – Partners’ Capital
Distribution Reinvestment Program
The February 2018 distribution resulted in
576,923
common units issued to the public at a discounted average price of
$38.83
per unit associated with the reinvested distributions of
$22 million
.
Common Units
The Board of Directors of our general partner declared a cash distribution of
$0.614
per common unit on
April 23, 2018
, to be paid on
May 11, 2018
, to unitholders of record at the close of business on
May 4, 2018
.
Class B Units
The Class B units are not entitled to cash distributions. Instead, prior to conversion into common units, the Class B units receive quarterly distributions of additional paid-in-kind Class B units. Effective February 10, 2015, each Class B unit became convertible at the election of either us or the holders of such Class B unit into a common unit on a one-for-one basis. The Board of Directors of our general partner has authorized the issuance of
318,553
Class B units associated with the first-quarter distribution, to be issued on
May 11, 2018
.
Note 8 – Fair Value Measurements and Guarantees
The following table presents, by level within the fair value hierarchy, certain of our financial assets and liabilities. The carrying values of cash and cash equivalents, accounts receivable, and accounts payable approximate fair value because of the short-term nature of these instruments. Therefore, these assets and liabilities are not presented in the following table.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using
|
|
|
Carrying
Amount
|
|
Fair
Value
|
|
Quoted
Prices In
Active
Markets for
Identical
Assets
(Level 1)
|
|
Significant
Other
Observable
Inputs
(Level 2)
|
|
Significant
Unobservable
Inputs
(Level 3)
|
|
|
(Millions)
|
|
Assets (liabilities) at March 31, 2018:
|
|
|
|
|
|
|
|
|
|
|
Measured on a recurring basis:
|
|
|
|
|
|
|
|
|
|
|
ARO Trust investments
|
$
|
145
|
|
|
$
|
145
|
|
|
$
|
145
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Energy derivatives assets designated as hedging instruments
|
2
|
|
|
2
|
|
|
2
|
|
|
—
|
|
|
—
|
|
|
Energy derivatives assets not designated as hedging instruments
|
4
|
|
|
4
|
|
|
4
|
|
|
—
|
|
|
—
|
|
|
Energy derivatives liabilities designated as hedging instruments
|
(3
|
)
|
|
(3
|
)
|
|
(3
|
)
|
|
—
|
|
|
—
|
|
|
Energy derivatives liabilities not designated as hedging instruments
|
(4
|
)
|
|
(4
|
)
|
|
(1
|
)
|
|
—
|
|
|
(3
|
)
|
|
Additional disclosures:
|
|
|
|
|
|
|
|
|
|
|
Other receivables
|
7
|
|
|
7
|
|
|
7
|
|
|
—
|
|
|
—
|
|
|
Long-term debt, including current portion
|
(17,512
|
)
|
|
(18,307
|
)
|
|
—
|
|
|
(18,307
|
)
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets (liabilities) at December 31, 2017:
|
|
|
|
|
|
|
|
|
|
|
Measured on a recurring basis:
|
|
|
|
|
|
|
|
|
|
|
ARO Trust investments
|
$
|
135
|
|
|
$
|
135
|
|
|
$
|
135
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Energy derivatives liabilities designated as hedging instruments
|
(3
|
)
|
|
(3
|
)
|
|
(2
|
)
|
|
(1
|
)
|
|
—
|
|
|
Energy derivatives liabilities not designated as hedging instruments
|
(3
|
)
|
|
(3
|
)
|
|
—
|
|
|
—
|
|
|
(3
|
)
|
|
Additional disclosures:
|
|
|
|
|
|
|
|
|
|
|
Other receivables
|
7
|
|
|
7
|
|
|
7
|
|
|
—
|
|
|
—
|
|
|
Long-term debt, including current portion
|
(16,497
|
)
|
|
(18,112
|
)
|
|
—
|
|
|
(18,112
|
)
|
|
—
|
|
Fair Value Methods
We use the following methods and assumptions in estimating the fair value of our financial instruments:
Assets and liabilities measured at fair value on a recurring basis
ARO Trust investments
:
Transco deposits a portion of its collected rates, pursuant to its rate case settlement, into an external trust (ARO Trust) that is specifically designated to fund future asset retirement obligations (ARO). The ARO Trust invests in a portfolio of actively traded mutual funds that are measured at fair value on a recurring basis based on quoted prices in an active market and is reported in
Regulatory assets, deferred charges, and other
in the Consolidated Balance Sheet. Both realized and unrealized gains and losses are ultimately recorded as regulatory assets or liabilities.
Energy derivatives
:
Energy derivatives include commodity-based exchange-traded contracts and over-the-counter contracts, which consist of physical forwards, futures, and swaps that are measured at fair value on a recurring basis. The fair value amounts are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under the terms of our master netting arrangements. Further, the amounts do not include cash held on deposit in margin
accounts that we have received or remitted to collateralize certain derivative positions. Energy derivatives assets are reported in
Other current assets and deferred charges
and
Regulatory assets, deferred charges, and other
in the Consolidated Balance Sheet. Energy derivatives liabilities are reported in
Other accrued liabilities
and
Regulatory liabilities, deferred income, and other
in the Consolidated Balance Sheet.
Reclassifications of fair value between Level 1, Level 2, and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. No transfers between Level 1 and Level 2 occurred during the
three
months ended
March 31, 2018
or
2017
.
Additional fair value disclosures
Other receivables:
Other receivables consist of margin deposits, which are reported in
Other current assets and deferred charges
in the Consolidated Balance Sheet. The disclosed fair value of our margin deposits is considered to approximate the carrying value generally due to the short-term nature of these items.
Long-term debt, including current portion
:
The disclosed fair value of our long-term debt is determined primarily by a market approach using broker quoted indicative period-end bond prices. The quoted prices are based on observable transactions in less active markets for our debt or similar instruments.
Guarantees
We are required by our revolving credit agreement to indemnify lenders for certain taxes required to be withheld from payments due to the lenders and for certain tax payments made by the lenders. The maximum potential amount of future payments under these indemnifications is based on the related borrowings and such future payments cannot currently be determined. These indemnifications generally continue indefinitely unless limited by the underlying tax regulations and have no carrying value. We have never been called upon to perform under these indemnifications and have no current expectation of a future claim.
Note 9 – Contingent Liabilities
Environmental Matters
We are a participant in certain environmental activities in various stages including assessment studies, cleanup operations, and/or remedial processes at certain sites, some of which we currently do not own. We are monitoring these sites in a coordinated effort with other potentially responsible parties, the U.S. Environmental Protection Agency (EPA), or other governmental authorities. We are jointly and severally liable along with unrelated third parties in some of these activities and solely responsible in others. Certain of our subsidiaries have been identified as potentially responsible parties at various Superfund and state waste disposal sites. In addition, these subsidiaries have incurred, or are alleged to have incurred, various other hazardous materials removal or remediation obligations under environmental laws. As of
March 31, 2018
, we have accrued liabilities totaling
$17 million
for these matters, as discussed below. Estimates of the most likely costs of cleanup are generally based on completed assessment studies, preliminary results of studies, or our experience with other similar cleanup operations. At
March 31, 2018
, certain assessment studies were still in process for which the ultimate outcome may yield different estimates of most likely costs. Therefore, the actual costs incurred will depend on the final amount, type, and extent of contamination discovered at these sites, the final cleanup standards mandated by the EPA or other governmental authorities, and other factors.
The EPA and various state regulatory agencies routinely promulgate and propose new rules, and issue updated guidance to existing rules. More recent rules and rulemakings include, but are not limited to, rules for reciprocating internal combustion engine maximum achievable control technology, air quality standards for one hour nitrogen dioxide emissions, and volatile organic compound and methane new source performance standards impacting design and operation of storage vessels, pressure valves, and compressors. On October 1, 2015, the EPA issued its rule regarding National Ambient Air Quality Standards for ground-level ozone, setting a stricter standard of
70 parts per billion
. We are monitoring the rule’s implementation as the reduction will trigger additional federal and state regulatory actions that may impact our operations. Implementation of the regulations is expected to result in impacts to our operations and increase the cost of additions to
Property, plant, and equipment – net
in the
Consolidated Balance Sheet
for both new and existing facilities in affected areas. We are unable to reasonably estimate the cost of additions that may be
required to meet the regulations at this time due to uncertainty created by various legal challenges to these regulations and the need for further specific regulatory guidance.
Our interstate gas pipelines are involved in remediation activities related to certain facilities and locations for polychlorinated biphenyls, mercury, and other hazardous substances. These activities have involved the EPA and various state environmental authorities, resulting in our identification as a potentially responsible party at various Superfund waste sites. At
March 31, 2018
, we have accrued liabilities of
$7 million
for these costs. We expect that these costs will be recoverable through rates.
We also accrue environmental remediation costs for natural gas underground storage facilities, primarily related to soil and groundwater contamination. At
March 31, 2018
, we have accrued liabilities totaling
$10 million
for these costs.
Royalty Matters
Certain of our customers, including one major customer, have been named in various lawsuits alleging underpayment of royalties and claiming, among other things, violations of anti-trust laws and the Racketeer Influenced and Corrupt Organizations Act. We have also been named as a defendant in certain of these cases filed in Pennsylvania based on allegations that we improperly participated with that major customer in causing the alleged royalty underpayments. We believe that the claims asserted are subject to indemnity obligations owed to us by that major customer. Due to the preliminary status of the cases, we are unable to estimate a range of potential loss at this time.
Unitholder Litigation
On March 7, 2016, a purported unitholder of us filed a putative class action on behalf of certain purchasers of our units in U.S. District Court in Oklahoma. The action names as defendants us, Williams, Williams Partners GP LLC, Alan S. Armstrong, and former Chief Financial Officer Donald R. Chappel and alleges violations of certain federal securities laws for failure to disclose Energy Transfer Equity, L.P.’s intention to pursue a purchase of Williams conditioned on Williams not closing the May 2015 agreement for a unit-for-stock transaction whereby Williams would have acquired all of our publicly held outstanding common units in exchange for shares of Williams’ common stock (WPZ Public Unit Exchange) when announcing the WPZ Public Unit Exchange. The complaint seeks, among other things, damages and an award of costs and attorneys’ fees. The plaintiff filed an amended complaint on August 31, 2016. On October 17, 2016, we requested the court dismiss the action, and on March 8, 2017, the court dismissed the complaint with prejudice. On April 7, 2017, the plaintiff filed a notice of appeal. We cannot reasonably estimate a range of potential loss at this time.
Other
In addition to the foregoing, various other proceedings are pending against us which are incidental to our operations, none of which are expected to be material to our expected future annual results of operations, liquidity, and financial position.
Summary
We have disclosed all significant matters for which we are unable to reasonably estimate a range of possible loss. We estimate that for all other matters for which we are able to reasonably estimate a range of loss, our aggregate reasonably possible losses beyond amounts accrued are immaterial to our expected future annual results of operations, liquidity, and financial position. These calculations have been made without consideration of any potential recovery from third parties.
Note 10 – Segment Disclosures
Our reportable segments are Northeast G&P, Atlantic-Gulf, West, and NGL & Petchem Services. (See
Note 1 – General, Description of Business, and Basis of Presentation
.) Certain other corporate activities are included in Other.
Performance Measurement
We evaluate segment operating performance based upon
Modified EBITDA
(earnings before interest, taxes, depreciation, and amortization). This measure represents the basis of our internal financial reporting and is the primary performance measure used by our chief operating decision maker in measuring performance and allocating resources among our reportable segments. Intersegment revenues primarily represent the sale of NGLs from our natural gas processing plants to our marketing business.
We define
Modified EBITDA
as follows:
|
|
|
|
•
|
Net income (loss) before:
|
|
|
|
|
◦
|
Provision (benefit) for income taxes;
|
|
|
|
|
◦
|
Interest incurred, net of interest capitalized;
|
|
|
|
|
◦
|
Equity earnings (losses);
|
|
|
|
|
◦
|
Impairment of equity-method investments;
|
|
|
|
|
◦
|
Other investing income (loss)
–
net;
|
|
|
|
|
◦
|
Impairment of goodwill;
|
|
|
|
|
◦
|
Depreciation and amortization expenses;
|
|
|
|
|
◦
|
Accretion expense associated with asset retirement obligations for nonregulated operations.
|
|
|
|
|
•
|
This measure is further adjusted to include our proportionate share (based on ownership interest) of
Modified EBITDA
from our equity-method investments calculated consistently with the definition described above.
|
The following table reflects the reconciliation of
Segment revenues
to
Total
revenues
as reported in the
Consolidated Statement of Comprehensive Income
.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Northeast
G&P
|
|
Atlantic-
Gulf
|
|
West
|
|
NGL &
Petchem
Services
|
|
Eliminations
|
|
Total
|
|
|
(Millions)
|
|
Three Months Ended March 31, 2018
|
|
Segment revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Service revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
External
|
$
|
219
|
|
|
$
|
596
|
|
|
$
|
531
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1,346
|
|
|
Internal
|
9
|
|
|
13
|
|
|
—
|
|
|
—
|
|
|
(22
|
)
|
|
—
|
|
|
Total service revenues
|
228
|
|
|
609
|
|
|
531
|
|
|
—
|
|
|
(22
|
)
|
|
1,346
|
|
|
Total service revenues
–
commodity consideration (external only)
|
4
|
|
|
15
|
|
|
82
|
|
|
—
|
|
|
—
|
|
|
101
|
|
|
Product sales
|
|
|
|
|
|
|
|
|
|
|
|
|
External
|
89
|
|
|
35
|
|
|
512
|
|
|
—
|
|
|
—
|
|
|
636
|
|
|
Internal
|
9
|
|
|
58
|
|
|
18
|
|
|
—
|
|
|
(85
|
)
|
|
—
|
|
|
Total product sales
|
98
|
|
|
93
|
|
|
530
|
|
|
—
|
|
|
(85
|
)
|
|
636
|
|
|
Total revenues
|
$
|
330
|
|
|
$
|
717
|
|
|
$
|
1,143
|
|
|
$
|
—
|
|
|
$
|
(107
|
)
|
|
$
|
2,083
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2017
|
|
Segment revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Service revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
External
|
$
|
208
|
|
|
$
|
527
|
|
|
$
|
518
|
|
|
$
|
3
|
|
|
$
|
—
|
|
|
$
|
1,256
|
|
|
Internal
|
9
|
|
|
9
|
|
|
—
|
|
|
—
|
|
|
(18
|
)
|
|
—
|
|
|
Total service revenues
|
217
|
|
|
536
|
|
|
518
|
|
|
3
|
|
|
(18
|
)
|
|
1,256
|
|
|
Product sales
|
|
|
|
|
|
|
|
|
|
|
|
|
External
|
60
|
|
|
69
|
|
|
405
|
|
|
193
|
|
|
—
|
|
|
727
|
|
|
Internal
|
8
|
|
|
65
|
|
|
51
|
|
|
6
|
|
|
(130
|
)
|
|
—
|
|
|
Total product sales
|
68
|
|
|
134
|
|
|
456
|
|
|
199
|
|
|
(130
|
)
|
|
727
|
|
|
Total revenues
|
$
|
285
|
|
|
$
|
670
|
|
|
$
|
974
|
|
|
$
|
202
|
|
|
$
|
(148
|
)
|
|
$
|
1,983
|
|
The following table reflects the reconciliation of
Modified EBITDA
to
Net income (loss)
as reported in the
Consolidated Statement of Comprehensive Income
.
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
March 31,
|
|
|
2018
|
|
2017
|
|
|
(Millions)
|
|
Modified EBITDA by segment:
|
|
|
|
|
Northeast G&P
|
$
|
250
|
|
|
$
|
226
|
|
|
Atlantic-Gulf
|
451
|
|
|
450
|
|
|
West
|
413
|
|
|
385
|
|
|
NGL & Petchem Services
|
—
|
|
|
51
|
|
|
Other
|
(7
|
)
|
|
20
|
|
|
|
1,107
|
|
|
1,132
|
|
|
Accretion expense associated with asset retirement obligations for nonregulated operations
|
(8
|
)
|
|
(6
|
)
|
|
Depreciation and amortization expenses
|
(423
|
)
|
|
(433
|
)
|
|
Equity earnings (losses)
|
82
|
|
|
107
|
|
|
Other investing income (loss) – net
|
4
|
|
|
271
|
|
|
Proportional Modified EBITDA of equity-method investments
|
(169
|
)
|
|
(194
|
)
|
|
Interest expense
|
(209
|
)
|
|
(214
|
)
|
|
(Provision) benefit for income taxes
|
—
|
|
|
(3
|
)
|
|
Net income (loss)
|
$
|
384
|
|
|
$
|
660
|
|
The following table reflects
Total assets
by reportable segment.
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Assets
|
|
|
March 31,
2018
|
|
December 31,
2017
|
|
|
(Millions)
|
|
Northeast G&P
|
$
|
14,388
|
|
|
$
|
14,397
|
|
|
Atlantic-Gulf
|
16,806
|
|
|
15,230
|
|
|
West
|
15,802
|
|
|
16,144
|
|
|
NGL & Petchem Services
|
2
|
|
|
3
|
|
|
Other (1)
|
1,366
|
|
|
936
|
|
|
Eliminations (2)
|
(1,789
|
)
|
|
(807
|
)
|
|
Total
|
$
|
46,575
|
|
|
$
|
45,903
|
|
|
|
|
|
(1)
|
Increase in Other due primarily to increased cash balance.
|
|
|
|
|
(2)
|
Eliminations primarily relate to the intercompany accounts receivable generated by our cash management program.
|
Item 2
