Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
General
We are an energy infrastructure master limited partnership focused on connecting North America’s significant hydrocarbon resource plays to growing markets for natural gas, NGLs, and olefins through our gas pipeline and midstream businesses. WPZ GP LLC, a Delaware limited liability company wholly owned by Williams, is our general partner.
Our interstate natural gas pipeline strategy is to create value by maximizing the utilization of our pipeline capacity by providing high quality, low cost transportation of natural gas to large and growing markets. Our gas pipeline businesses’ interstate transmission and storage activities are subject to regulation by the FERC and as such, our rates and charges for the transportation of natural gas in interstate commerce, and the extension, expansion or abandonment of jurisdictional facilities and accounting, among other things, are subject to regulation. The rates are established through the FERC’s ratemaking process. Changes in commodity prices and volumes transported have limited near-term impact on these revenues because the majority of cost of service is recovered through firm capacity reservation charges in transportation rates.
The ongoing strategy of our midstream operations is to safely and reliably operate large-scale midstream infrastructure where our assets can be fully utilized and drive low per-unit costs. We focus on consistently attracting new business by providing highly reliable service to our customers. These services include natural gas gathering, processing, treating, and compression, NGL fractionation and transportation, crude oil production handling and transportation, olefin production, marketing services for NGL, oil and natural gas, as well as storage facilities.
Regarding our discussion in Item 7. Management’s Discussion and Analysis and Item 8. Financial Statements and Supplementary Data, effective January 1, 2016, businesses located in the Marcellus and Utica Shale plays within the former Access Midstream segment are now managed, and thus, presented within the Northeast G&P segment. The remaining Access Midstream businesses are now presented as the Central segment. Prior period segment disclosures have been recast for these segment changes. As a result, beginning with the reporting of first-quarter 2016, our reportable segments are Central, Northeast G&P, Atlantic-Gulf, West, and NGL & Petchem Services, which are comprised of the following businesses:
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Central provides domestic gathering, treating, and compression services to producers under long-term, fixed-fee contracts. Its primary operating areas are in 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. Central also includes a 50 percent equity-method investment in the Delaware basin gas gathering system (DBJV) in the Mid-Continent region.
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Northeast G&P is comprised of 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 (a consolidated entity), a 69 percent equity-method investment in Laurel Mountain and a 58 percent equity-method investment in Caiman II. Northeast G&P also includes a 62 percent equity-method investment in UEOM and Appalachia Midstream Services, LLC, which owns equity-method investments with an approximate average 41 percent interest in multiple gas gathering systems in the Marcellus Shale (Appalachia Midstream Investments).
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Atlantic-Gulf is comprised of our interstate natural gas pipeline, 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 (a consolidated entity), which is a proprietary floating production system, as well as a 50 percent equity-method investment in Gulfstream, a 60 percent equity-method investment in Discovery, and a
41 percent
interest in Constitution (a consolidated entity), which is under development.
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West is comprised of our gathering, processing and treating operations in New Mexico, Colorado, and Wyoming, and our interstate natural gas pipeline, Northwest Pipeline.
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NGL & Petchem Services is comprised of our
88.5 percent
undivided interest in an olefins production facility in Geismar, Louisiana, (see Geismar Olefins Facility Monetization below), along with a refinery grade propylene splitter and various petrochemical and feedstock pipelines in the Gulf Coast region, an oil sands offgas processing plant near Fort McMurray, Alberta, and an NGL/olefin fractionation facility at Redwater, Alberta. In September 2016, these Canadian operations were sold. (See
Note 3 – Divestiture
of Notes to Consolidated Financial Statements.) This segment also includes an NGL and natural gas marketing business, storage facilities, and an undivided 50 percent interest in an NGL fractionator near Conway, Kansas, and a 50 percent equity-method investment in OPPL.
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As of
December 31, 2016
, Williams held an approximate 60 percent interest in us, comprised of an approximate 58 percent limited partner interest and all of our 2 percent general partner interest and IDRs. (See Financial Repositioning in Overview below.)
Unless indicated otherwise, the following discussion and analysis of critical accounting estimates, results of operations, and financial condition and liquidity should be read in conjunction with the consolidated financial statements and notes thereto included in Part II, Item 8 of this report.
Distributions
On February 10, 2017, we paid a quarterly distribution of
$0.85
per unit to unitholders of record as of February 3, 2017. In January 2017, we announced our expectation to reduce the quarterly distribution to $0.60 per unit beginning with the first quarter of 2017 distribution.
Overview
Net income (loss) attributable to controlling interests
for the year ended
December 31, 2016
, increased $1.88 billion compared to the year ended
December 31, 2015
, reflecting the absence of a 2015 goodwill impairment, lower impairments of equity-method investments, an increase in olefins margins associated with our Geismar plant, decreases in operating and maintenance and selling, general, and administrative expenses, and higher equity earnings. These favorable changes were partially offset by the 2016 impairment charge and subsequent loss on sale associated with our Canadian operations, lower insurance recoveries, and higher interest incurred. See additional discussion in Results of Operations.
Acquisition of Additional Interests in Appalachia Midstream Investments
In February, 2017, we announced agreements to acquire additional interests in two Marcellus Shale gathering systems within Northeast G&P’s Appalachia Midstream Investments in exchange for equity-method investment interests in DBJV and the Ranch Westex gas processing plant, both currently reported within the Central segment. We also expect to receive a total of $200 million in cash as part of the agreements subject to customary closing conditions and purchase price adjustments. The transactions are expected to close in late first-quarter or early second-quarter 2017.
Financial Repositioning
In January 2017, we announced 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 non-economic 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. Following these transactions, Williams owns a 74 percent limited partner interest in us. It is anticipated that the combination of these measures will improve our cost of capital, provide for debt reduction, and eliminate our need to access the public equity markets for several years.
In addition to the previously announced Geismar monetization process, Williams has announced plans to monetize other select assets that are not core to our strategy. Williams expects to raise more than $2 billion in after-tax proceeds from the monetization process of Geismar and the other select assets. As we pursue these other asset monetizations, it is possible that we may incur 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.
Organizational Realignment
In September 2016, Williams announced organizational changes aiming to simplify our structure, increase direct operational alignment to advance our natural gas-focused strategy, and drive continued focus on customer service and execution. Effective January 1, 2017, we implemented these changes, which combined the management of certain of our operations and reduced the overall number of operating areas managed within our business. This is consistent with the manner in which our chief operating decision maker will evaluate performance and make resource allocation decisions.The discussions and disclosures in Item 7. Management’s Discussion and Analysis and Item 8. Financial Statements and Supplementary, however, continue to reflect the segment reporting structure in place prior to this recent change.
Specifically, the operations previously reported within the Central reporting segment in 2016 are now generally managed within the West reporting segment and certain businesses previously within our NGL & Petchem Services reporting segment are managed by the West, Atlantic-Gulf, and Northeast G&P reporting segments as follows:
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The NGL and natural gas marketing business, certain storage and fractionation operations, and our equity-method investment in OPPL are managed within the West reporting segment;
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Certain pipelines in the Gulf region are managed within the Atlantic-Gulf reporting segment;
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Our equity-method investment in Aux Sable is managed within the Northeast G&P reporting segment.
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The remaining operations of the NGL & Petchem Services segment include our Geismar olefins plant, our RGP Splitter, as well as our historical Canadian operations that were sold in September 2016. We are currently seeking to monetize our ownership interest in the Geismar, Louisiana, olefins plant and complex (see Geismar olefins facility monetization below).
Central
Barnett Shale and Mid-Continent contract restructurings
In August 2016, we conditionally committed to execute a new gas gathering agreement in the Barnett Shale. The agreement was executed in the fourth quarter of 2016, in conjunction with our existing customer, Chesapeake Energy Corporation, closing the sale of its Barnett Shale properties to another producer. That other producer, which has an investment grade credit rating, is now our customer under the new gas gathering agreement. The restructured agreement provided a $754 million up-front cash payment to us primarily in exchange for eliminating future minimum volume commitments. The restructured agreement also provides for revised gathering rates. Based on current commodity price assumptions at the time of the agreement, we generally expect the up-front cash proceeds and the ongoing cash flows generated by gathering services, to represent equivalent net present value of cash flows as compared to expected performance under the existing agreement. Additionally, we agreed to a revised contract in the Mid-Continent region, also with Chesapeake Energy Corporation. The revised contract was executed in the third quarter of 2016 and provided an up-front cash payment to us of $66 million primarily in exchange for changing from a cost of service contract to fixed-fee terms. The majority of the up-front cash proceeds from both these agreements were recognized as deferred revenue and will be amortized into income in future periods. In the near term, we do not expect that our trend of reported results will be significantly impacted by the effect of the discount associated with the up-front cash proceeds relative to the original minimum volume commitments and reduced gathering rates. It was anticipated that both agreements would reduce customer concentration risk and provide support to realize additional drilling and improved volumes in these regions.
West
Northwest Pipeline rate case
On January 23, 2017, Northwest Pipeline filed a Stipulation and Settlement Agreement with the FERC for new rates. The new rates become effective January 1, 2018, and are not expected to materially affect our trend of earnings. Pursuant to this agreement, Northwest Pipeline can file for new rates to be effective after October 1, 2018, and must file a general rate case for new rates to become effective no later than January 1, 2023.
Powder River basin contract restructuring
In October 2016, in conjunction with our partner in the Bucking Horse natural gas processing plant and Jackalope Gas Gathering System, we announced an agreement with Chesapeake Energy Corporation to restructure gathering and processing contracts in the Powder River basin. The restructured contracts became effective in January 2017 and replaced the previous cost-of-service arrangement with MVCs in the near-term such that we do not expect that our near-term trend of reported results will be significantly impacted by the restructured terms.
NGL & Petchem Services
Geismar olefins facility monetization
In September 2016, we announced we have initiated an ongoing process to explore monetization of our ownership interest in the Geismar, Louisiana, olefins plant and complex, consistent with our strategy to narrow our focus and allocate capital to our natural gas-focused business.
Sale of Canadian operations
In September 2016, we completed the sale of our Canadian operations for total consideration of
$672 million
. In connection with the sale, Williams agreed to waive
$150 million
of incentive distributions in the fourth quarter of 2016. We recognized an impairment charge of
$341 million
during the second quarter of 2016 related to these operations and an additional loss of
$34 million
upon completion of the sale. (See
Note 3 – Divestiture
of Notes to Consolidated Financial Statements.)
Redwater expansion
In March 2016, we completed the expansion of our Redwater facilities to provide NGL transportation and fractionation services to Williams associated with its long-term agreement to provide gas processing services to a second bitumen upgrader in Canada’s oil sands near Fort McMurray, Alberta. With this capacity increase, additional NGL/olefins mixtures from Williams are fractionated into an ethane/ethylene mix, propane, polymer grade propylene, normal butane, an alkylation feed and condensate under a long-term, fee-based agreement. We sold these operations in September 2016. (See
Note 3 – Divestiture
of Notes to Consolidated Financial Statements.)
Atlantic-Gulf
Rock Springs expansion
In August 2016, our Rock Springs expansion was placed into service. The project expanded Transco’s existing natural gas transmission system from New Jersey to a generation facility in Maryland and increased capacity by 192 Mdth/d.
Gulf Trace expansion
In February 2017, the Gulf Trace expansion was placed into service. The project expanded Transco’s existing natural gas transmission system together with greenfield facilities to provide incremental firm transportation capacity from Station 65 in St. Helena Parish, Louisiana to a new interconnection with Sabine Pass Liquefaction in Cameron Parish, Louisiana. It is expected to increase capacity by 1,200 Mdth/d.
Commodity Prices
NGL per-unit margins were approximately 7 percent lower in 2016 compared to the same period of 2015. Following a sharp decline in late 2014 to early 2015, total NGL margins have remained somewhat consistent in 2015 and 2016. While 2014 and 2015 reflect limited ethane recoveries, we have seen an increase in ethane production during 2016.
NGL margins are defined as NGL revenues less any applicable Btu replacement cost, plant fuel, and third-party transportation and fractionation. Per-unit NGL margins are calculated based on sales of our own equity volumes at the processing plants. Our equity volumes include NGLs where we own the rights to the value from NGLs recovered at our plants under both “keep-whole” processing agreements, where we have the obligation to replace the lost heating value with natural gas, and “percent-of-liquids” agreements whereby we receive a portion of the extracted liquids with no obligation to replace the lost heating value.
The following graph illustrates the NGL production and sales volumes, as well as the margin differential between ethane and non-ethane products and the relative mix of those products.
The potential impact of commodity prices on our business is further discussed in the following Company Outlook.
Company Outlook
Our strategy is to provide large-scale energy infrastructure designed to maximize the opportunities created by the vast supply of natural gas and natural gas products that exists in the United States. We accomplish this by connecting the growing demand for cleaner fuels and feedstocks with our major positions in the premier natural gas and natural gas products supply basins. We continue to maintain a strong commitment to safety, environmental stewardship, operational excellence, and customer satisfaction. We believe that accomplishing these goals will position us to deliver safe and reliable service to our customers and an attractive return to our unitholders.
Our business plan for 2017 includes the previously discussed agreement with Williams to permanently waive incentive distribution rights in exchange for common units as well as Williams’ private purchase of $2.1 billion of common units. We expect to distribute $0.60 per unit, or $2.40 annually, beginning with the next distribution for the quarter ending March 31, 2017. Our business plan also includes the previously discussed asset monetizations, which include our ownership interest in the Geismar olefins facility as well as other select assets that are not core to our strategy. Williams expects the monetizations to yield after-tax proceeds of greater than $2.0 billion. These transactions are expected to improve our cost of capital, remove our need to access the public equity markets for the next several years, enhance our growth, and provide for debt reduction.
Our growth capital and investment expenditures in 2017 are expected to total $2.1 billion to $2.8 billion. Approximately $1.4 billion to $1.9 billion of our growth capital funding needs include Transco expansions and other interstate pipeline growth projects, most of which are fully contracted with firm transportation agreements. The remaining growth capital spending in 2017 primarily reflects investment in gathering and processing systems in the Northeast region limited primarily to known new producer volumes, including volumes that support Transco expansion projects including our Atlantic Sunrise project. In addition to growth capital and investment expenditures, we also remain committed to projects that maintain our assets for safe and reliable operations, as well as projects that meet legal, regulatory, and/or contractual commitments.
As a result of our significant continued capital and investment expenditures on Transco expansions and fee-based gathering and processing projects, as well as the previously discussed sale of our Canadian operations and the planned monetization of the Geismar olefins facility, fee-based businesses are becoming an even more significant component of our portfolio and serve to reduce the influence of commodity price fluctuations on our operating results and cash flows. We expect to benefit as continued growth in demand for low-cost natural gas is driven by increases in LNG exports, industrial demand and power generation. Current forward market prices indicate a slightly more favorable energy commodity price environment in 2017 as compared to 2016, including higher natural gas and NGL prices. However, some of our customers may continue to curtail or delay drilling plans until there is a more sustained recovery in prices, which may negatively impact our gathering volumes. Although there has been some improvement, the credit profiles of certain of our producer customers remain challenged. Unfavorable changes in energy commodity prices or the credit profile of our producer customers may also result in noncash impairments of our assets.
In 2017, our operating results will include increases from our fee-based businesses recently placed in service or expected to be placed in service in 2017, primarily within the Atlantic-Gulf segment, and lower general and administrative expenses due to cost reduction initiatives and asset monetizations. We expect overall gathering and processing volumes to remain steady in 2017 and increase thereafter to meet the growing demand for natural gas and natural gas products.
Potential risks and obstacles that could impact the execution of our plan include:
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Opposition to infrastructure projects, including the risk of delay in permits needed for our projects;
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Unexpected significant increases in capital expenditures or delays in capital project execution;
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Counterparty credit and performance risk, including that of Chesapeake Energy Corporation and its affiliates;
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Inability to execute or delay in completing planned asset monetizations;
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Lower than anticipated demand for natural gas and natural gas products which could result in lower than expected volumes, energy commodity prices and margins;
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General economic, financial markets, or further industry downturn, including increased interest rates;
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Physical damages to facilities, including damage to offshore facilities by named windstorms;
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Reduced availability of insurance coverage.
We seek to maintain a strong financial position and liquidity, as well as manage a diversified portfolio of energy infrastructure assets which continue to serve key growth markets and supply basins in the United States.
Expansion Projects
Our ongoing major expansion projects include the following:
Central
Eagle Ford
We plan to expand our gathering infrastructure in the Eagle Ford region in order to meet our customers’ production plans. The expansion of the gathering infrastructure includes the addition of new facilities, well connections, and gathering pipeline to the existing systems.
Northeast G&P
Oak Grove Expansion
We plan to expand our processing capacity at our Oak Grove facility by adding a second 200 MMcf/d cryogenic natural gas processing plant, which, based on our customers’ needs, is expected to be placed into service in 2020.
Gathering System Expansion
We will continue to expand the gathering systems in the Marcellus and Utica Shale regions that are needed to meet our customers’ production plans. The expansion of the gathering infrastructure includes additional compression and gathering pipeline to the existing system.
Atlantic-Gulf
Constitution Pipeline
In December 2014, we received approval from the FERC to construct and operate the jointly owned Constitution pipeline, which will have an expected capacity of 650 Mdth/d. However, in April 2016, the New York State Department of Environmental Conservation (NYSDEC) denied a necessary water quality certification for the New York portion of the pipeline. We remain steadfastly committed to the project, and in May 2016, Constitution appealed the NYSDEC’s denial of the certification and filed an action in federal court seeking a declaration that the State of New York’s authority to exercise permitting jurisdiction over certain other environmental matters is preempted by federal law. (See Note 4 – Variable Interest Entities of Notes to Consolidated Financial Statements.) We currently own 41 percent of Constitution with three other parties holding 25 percent, 24 percent, and 10 percent, respectively. We will be the operator of Constitution. The 126-mile Constitution pipeline will connect our gathering system in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and Tennessee Gas Pipeline systems in New York, as well as to a local distribution company serving New York and Pennsylvania. In light of the NYSDEC’s denial of the water quality certification and the actions taken to challenge the decision, the target in-service date has been revised to as early as the second half of 2018, which assumes that the legal challenge process is satisfactorily and promptly concluded.
Garden State
In April 2016, we received approval from the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from Station 210 in New Jersey to a new interconnection on our Trenton Woodbury Lateral in New Jersey. The project will be constructed in phases and is expected to increase capacity by 180 Mdth/d. We plan to place the initial phase of the project into service during the third quarter of 2017 and the remaining portion in the second quarter of 2018, assuming timely receipt of all necessary regulatory approvals.
Norphlet Project
In March 2016, we announced that we have reached an agreement to provide deepwater gas gathering services to the Appomattox development in the Gulf of Mexico. The project will provide offshore gas gathering services to our existing Transco lateral, which will provide transmission services onshore to our Mobile Bay processing facility. We also plan to make modifications to our Main Pass 261 Platform to install an alternate delivery route from the platform, as well as modifications to our Mobile Bay processing facility. The project is scheduled to go into service during the second quarter of 2020.
Hillabee
In February 2016, the FERC issued a certificate order for the initial phases of Transco’s Hillabee Expansion Project. The project involves an expansion of Transco’s existing natural gas transmission system from Station 85 in west central Alabama to a proposed new interconnection with the Sabal Trail project in Alabama. The project will be constructed in phases, and all of the project expansion capacity will be leased to Sabal Trail. We plan to place the initial phase of the project into service concurrent with the in-service date of the Sabal Trail project, which is planned to occur as early as the second quarter of 2017. The in-service date of the second phase of the project is planned for the second quarter of 2020 and together they are expected to increase capacity by 1,025 Mdth/d.
In March 2016, we entered into an agreement with the member-sponsors of Sabal Trail to resolve several matters. In accordance with the agreement, the member-sponsors will pay us an aggregate amount of $240 million in three equal installments as certain milestones of the project are met. The first $80 million payment was received in March 2016 and the second installment was received in September 2016. We expect to recognize income associated with these receipts over the term of the capacity lease agreement.
New York Bay Expansion
In July 2016, we received approval from the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from Pennsylvania to the Rockaway Delivery Lateral transfer point and the Narrows meter station in Richmond County, New York. We plan to place the project into service during the fourth quarter of 2017, and it is expected to increase capacity by 115 Mdth/d.
Atlantic Sunrise
In February 2017, we received approval from the FERC to expand Transco’s existing natural gas transmission system along with greenfield facilities to provide incremental firm transportation capacity from the northeastern Marcellus producing area to markets along Transco’s mainline as far south as Station 85 in west central Alabama. We expect to place a portion of the project facilities into service during the second half of 2017 and are targeting a full in-service during mid-2018, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 1,700 Mdth/d.
Virginia Southside II
In July 2016, we received approval from the FERC to expand Transco’s existing natural gas transmission system together with greenfield facilities to provide incremental firm transportation capacity from Station 210 in New Jersey and Station 165 in Virginia to a new lateral extending from our Brunswick Lateral in Virginia. We plan to place the project into service during the fourth quarter of 2017 and it is expected to increase capacity by 250 Mdth/d.
Dalton
In August 2016, we obtained approval from the FERC
to expand Transco’s existing natural gas transmission system together with greenfield facilities to provide incremental firm transportation capacity from Station 210 in New Jersey to markets in northwest Georgia. We plan to place the project into service in 2017 and it is expected to increase capacity by 448 Mdth/d.
Gulf Connector
In August 2016, we filed an application with the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from Station 65 in Louisiana to delivery points in Wharton and San Patricio Counties, Texas. The project will be constructed in two phases, with the initial phase of the project expected to be in service during the second half of 2018 and the remaining phase in 2019, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 475 Mdth/d.
Critical Accounting Estimates
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions. We believe that the nature of these estimates and assumptions is material due to the subjectivity and judgment necessary, or the susceptibility of such matters to change, and the impact of these on our financial condition or results of operations.
Equity-Method Investments
At the end of the third quarter of 2016, we became aware of changes involving certain of DBJV’s customer contracts, which impacted our estimates of DBJV’s future cash flows. As such, we evaluated this investment for impairment at September 30, 2016, and determined that no impairment was necessary. We also entered into initial discussions with the system operator regarding the terms and economic assumptions of these contract changes.
During the fourth quarter of 2016, these discussions led to negotiations with the system operator to exchange our interest in DBJV and another equity-method investment in the Permian basin (Ranch Westex) for its interests in certain gathering systems in the Northeast and cash. We already hold partial interests in these Northeast gathering systems through our Appalachia Midstream Investments. As previously discussed, we reached agreements for such transactions in February 2017.
As part of the preparation of our year-end financial statements, we evaluated the carrying amounts of our investments in DBJV, Ranch Westex and these certain gathering systems within our Appalachia Midstream Investments for impairment. We also evaluated other equity-method investments within the Northeast G&P segment for impairment as of December 31, 2016, including other gathering systems within our Appalachia Midstream Investments and our investment in UEOM. Our impairment evaluations utilized an income approach, but also considered the fair values indicated by the previously described transaction. The estimated fair value of our investment in DBJV exceeded its carrying value and no impairment was necessary. Based on the fair value of the consideration expected to be received, we currently expect to recognize a gain upon consummation of the previously described exchange transaction in 2017.
We estimated the fair value of our Appalachia Midstream Investments and UEOM using an income approach with discount rates ranging from 10.2 percent to 12.5 percent and also considered the value implied by the previously described transactions as applicable. For certain gathering systems within our Appalachia Midstream Investments, the fair value was determined to be less than our carrying value, resulting in an other-than-temporary impairment charge of $294 million. No impairment was necessary for other gathering systems within our Appalachia Midstream Investments or our investment in UEOM. For those investments evaluated for which no impairment was required, our estimate of fair value exceeded our carrying value by amounts ranging from approximately 2.5 percent to 7.5 percent. We estimate that an increase in the discount rate utilized of 50 basis points would have resulted in an additional impairment charge of approximately $45 million. We also recorded an additional impairment of $24 million related to our interest in Ranch Westex.
Judgments and assumptions are inherent in our estimates of future cash flows, discount rates, and market measures utilized. The use of alternate judgments and assumptions could result in a different calculation of fair value, which could ultimately result in the recognition of a different impairment charge in the consolidated financial statements.
At December 31, 2016, our Consolidated Balance Sheet includes approximately $6.7 billion of investments that are accounted for under the equity-method of accounting. We evaluate these investments for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such investments may have experienced an other-than-temporary decline in value. We continue to monitor our equity-method investments
for any indications that the carrying value may have experienced an other-than-temporary decline in value. When evidence of a loss in value has occurred, we compare our estimate of the fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred. We generally estimate the fair value of our investments using an income approach where significant judgments and assumptions include expected future cash flows and the appropriate discount rate. In some cases, we may utilize a form of market approach to estimate the fair value of our investments.
If the estimated fair value is less than the carrying value and we consider the decline in value to be other-than-temporary, the excess of the carrying value over the fair value is recognized in the consolidated financial statements as an impairment charge. Events or changes in circumstances that may be indicative of an other-than-temporary decline in value will vary by investment, but may include:
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A significant or sustained decline in the market value of an investee;
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Lower than expected cash distributions from investees;
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Significant asset impairments or operating losses recognized by investees;
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Significant delays in or lack of producer development or significant declines in producer volumes in markets served by investees;
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Significant delays in or failure to complete significant growth projects of investees.
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Constitution Pipeline Capitalized Project Costs
As of December 31, 2016,
Property, plant, and equipment – net
in our Consolidated Balance Sheet includes approximately $381 million of capitalized project costs for Constitution, for which we are the construction manager and own a 41 percent consolidated interest. In December 2014, we received approval from the FERC to construct and operate this jointly owned pipeline. However, in April 2016, the New York State Department of Environmental Conservation (NYSDEC) denied a necessary water quality certification for the New York portion of the Constitution pipeline. We remain steadfastly committed to the project, and in May 2016, Constitution appealed the NYSDEC's denial of the certification and filed an action in federal court seeking a declaration that the State of New York's authority to exercise permitting jurisdiction over certain other environmental matters is preempted by federal law.
As a result of the denial by the NYSDEC, we evaluated the capitalized project costs for impairment as of March 31, 2016, and as of December 31, 2016, and determined that no impairment was necessary. Our evaluation considered probability-weighted scenarios of undiscounted future net cash flows, including a scenario assuming successful resolution with the NYSDEC and construction of the pipeline, as well as a scenario where the project does not proceed. We continue to monitor the capitalized project costs associated with Constitution for potential impairment.
Results of Operations
Consolidated Overview
The following table and discussion is a summary of our consolidated results of operations for the three years ended
December 31, 2016
. The results of operations by segment are discussed in further detail following this consolidated overview discussion.
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Years Ended December 31,
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2016
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$ Change from 2015*
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% Change from 2015*
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2015
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$ Change from 2014*
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% Change from 2014*
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2014
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(Millions)
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Revenues:
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Service revenues
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$
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5,173
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+38
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+1
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%
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$
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5,135
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+1,247
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+32
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%
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$
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3,888
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Product sales
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2,318
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+122
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+6
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%
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2,196
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-1,325
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-38
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%
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3,521
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Total revenues
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7,491
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7,331
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7,409
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Costs and expenses:
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Product costs
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1,728
|
|
|
+51
|
|
|
+3
|
%
|
|
1,779
|
|
|
+1,237
|
|
|
+41
|
%
|
|
3,016
|
|
Operating and maintenance expenses
|
1,548
|
|
|
+77
|
|
|
+5
|
%
|
|
1,625
|
|
|
-348
|
|
|
-27
|
%
|
|
1,277
|
|
Depreciation and amortization expenses
|
1,720
|
|
|
-18
|
|
|
-1
|
%
|
|
1,702
|
|
|
-551
|
|
|
-48
|
%
|
|
1,151
|
|
Selling, general, and administrative expenses
|
630
|
|
|
+54
|
|
|
+8
|
%
|
|
684
|
|
|
-51
|
|
|
-8
|
%
|
|
633
|
|
Impairment of goodwill
|
—
|
|
|
+1,098
|
|
|
+100
|
%
|
|
1,098
|
|
|
-1,098
|
|
|
NM
|
|
|
—
|
|
Impairment of certain assets
|
457
|
|
|
-312
|
|
|
NM
|
|
|
145
|
|
|
-93
|
|
|
-179
|
%
|
|
52
|
|
Net insurance recoveries – Geismar Incident
|
(7
|
)
|
|
-119
|
|
|
-94
|
%
|
|
(126
|
)
|
|
-106
|
|
|
-46
|
%
|
|
(232
|
)
|
Other (income) expense – net
|
118
|
|
|
-77
|
|
|
-188
|
%
|
|
41
|
|
|
-138
|
|
|
NM
|
|
|
(97
|
)
|
Total costs and expenses
|
6,194
|
|
|
|
|
|
|
6,948
|
|
|
|
|
|
|
5,800
|
|
Operating income (loss)
|
1,297
|
|
|
|
|
|
|
383
|
|
|
|
|
|
|
1,609
|
|
Equity earnings (losses)
|
397
|
|
|
+62
|
|
|
+19
|
%
|
|
335
|
|
|
+107
|
|
|
+47
|
%
|
|
228
|
|
Impairment of equity-method investments
|
(430
|
)
|
|
+929
|
|
|
+68
|
%
|
|
(1,359
|
)
|
|
-1,359
|
|
|
NM
|
|
|
—
|
|
Other investing income (loss) – net
|
29
|
|
|
+27
|
|
|
NM
|
|
|
2
|
|
|
—
|
|
|
—
|
%
|
|
2
|
|
Interest expense
|
(916
|
)
|
|
-105
|
|
|
-13
|
%
|
|
(811
|
)
|
|
-249
|
|
|
-44
|
%
|
|
(562
|
)
|
Other income (expense) – net
|
62
|
|
|
-31
|
|
|
-33
|
%
|
|
93
|
|
|
+57
|
|
|
+158
|
%
|
|
36
|
|
Income (loss) before income taxes
|
439
|
|
|
|
|
|
|
(1,357
|
)
|
|
|
|
|
|
1,313
|
|
Provision (benefit) for income taxes
|
(80
|
)
|
|
+81
|
|
|
NM
|
|
|
1
|
|
|
+28
|
|
|
+97
|
%
|
|
29
|
|
Net income (loss)
|
519
|
|
|
|
|
|
|
(1,358
|
)
|
|
|
|
|
|
1,284
|
|
Less: Net income attributable to noncontrolling interests
|
88
|
|
|
+3
|
|
|
+3
|
%
|
|
91
|
|
|
+5
|
|
|
+5
|
%
|
|
96
|
|
Net income (loss) attributable to controlling interests
|
$
|
431
|
|
|
|
|
|
|
$
|
(1,449
|
)
|
|
|
|
|
|
$
|
1,188
|
|
_________
|
|
*
|
+ = Favorable change; - = Unfavorable change; NM = A percentage calculation is not meaningful due to a change in signs, a zero-value denominator, or a percentage change greater than 200.
|
2016 vs. 2015
Service revenues
increased primarily due to expansion projects placed in service in 2015 and 2016, including those associated with Transco’s natural gas transportation system and new transportation and fractionation revenue associated with Williams’ Horizon liquids extraction plant in Canada. The Canadian operations were sold in late September 2016. These increases were partially offset by a decrease in gathering, processing, and fractionation revenue primarily due to lower volumes primarily in the Barnett Shale and Anadarko basin.
Product sales
increased primarily due to higher olefins sales reflecting increased volumes at our Geismar plant as a result of the plant operating at higher production levels in 2016, partially offset by lower olefin sales from other olefin operations associated with lower volumes and per-unit sales prices.
Product sales
also reflect higher marketing revenues associated with higher NGL and propylene prices and natural gas and crude oil volumes, partially offset by lower NGL volumes and crude oil prices.
The decrease in
Product costs
includes lower olefin feedstock purchases and lower costs associated with other product sales, partially offset by higher marketing purchases primarily due to the same factors that increased marketing sales. The decline in olefin feedstock purchases is primarily associated with lower per-unit feedstock costs and volumes at our other olefin operations, partially offset by an increase in olefin feedstock purchases at our Geismar plant reflecting increased volumes resulting from higher production levels in 2016.
Operating and maintenance expenses
decreased primarily due to lower labor-related and outside service costs resulting from our first-quarter 2016 workforce reductions and cost containment efforts, lower costs associated with general maintenance activities in the Marcellus Shale, as well as the absence of ACMP transition-related costs recognized in 2015. These decreases are partially offset by $16 million of severance and related costs recognized in 2016 and higher pipeline testing and general maintenance costs at Transco.
Depreciation and amortization expenses
increased primarily due to depreciation on new assets placed in service, including Transco pipeline projects, partially offset by lower depreciation related to Canadian operations sold in 2016.
Selling, general, and administrative expenses (SG&A)
decreased primarily due to the absence of ACMP merger and transition-related costs recognized in 2015 and lower labor-related costs resulting from our first-quarter 2016 workforce reductions and cost containment efforts, partially offset by $21 million of severance and related costs recognized in 2016.
Impairment of goodwill
decreased due to the absence of a 2015 impairment charge associated with certain goodwill. (See
Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk
of Notes to Consolidated Financial Statements.)
Impairment of certain assets
reflects 2016 impairments of our Canadian operations, certain Mid-Continent assets, and other assets. (See
Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk
of Notes to Consolidated Financial Statements.) Impairments recognized in 2015 relate primarily to previously capitalized development costs and surplus equipment write-downs.
Net insurance recoveries – Geismar Incident
changed unfavorably reflecting the receipt of $126 million of insurance proceeds in the second quarter of 2015, as compared to the receipt of $7 million of proceeds in the fourth quarter of 2016.
The unfavorable change in
Other (income) expense – net
within
Operating income (loss)
includes a loss on the sale of our Canadian operations that were sold in September 2016, project development costs at Constitution as we discontinued capitalization of these costs in April 2016, and an unfavorable change in foreign currency exchange that primarily relates to losses incurred on foreign currency transactions and the remeasurement of the U.S. dollar-denominated current assets and liabilities within our former Canadian operations.
Operating income (loss)
changed favorably primarily due to the absence of a goodwill impairment in 2015, higher olefin margins related to the Geismar plant operating at higher production levels in 2016, lower costs related to the merger and integration of ACMP, lower costs and expenses associated with cost containment efforts, and higher service revenues reflecting new projects placed in service in 2015 and 2016. These favorable changes are partially offset by higher impairments of assets and loss on sale of certain assets in 2016, a decrease in insurance proceeds received, and higher depreciation expenses related to new projects placed in service.
Equity earnings (losses)
changed favorably primarily due to a $30 million increase at Discovery driven by the completion of the Keathley Canyon Connector in the first quarter of 2015. Additionally, equity earnings from OPPL, Laurel Mountain, and DBJV improved $16 million, $11 million, and $10 million, respectively.
Impairment of equity-method investments
reflects 2016 impairment charges associated with Appalachia Midstream Investments, DBJV, Laurel Mountain and Ranch Westex equity-method investments, while the 2015 impairment charges relate to our equity-method investments in Appalachia Midstream Investments, DBJV, UEOM, and Laurel Mountain. (See
Note 7 – Investing Activities
of Notes to Consolidated Financial Statements.)
Other investing income (loss) – net
reflects a 2016 gain on the sale of an equity-method investment interest in a gathering system that was part of our Appalachia Midstream Investments. (See
Note 7 – Investing Activities
of Notes to Consolidated Financial Statements.)
Interest expense
increased due to higher
Interest incurred
of
$85 million primarily attributable to new debt issuances in 2016 and 2015, as well as lower
Interest capitalized
of $20 million primarily related to construction projects that have been placed into service, partially offset by lower interest due to 2015 and 2016 debt retirements. (See
Note 14 – Debt, Banking Arrangements, and Leases
of Notes to Consolidated Financial Statements.)
Other income (expense) – net
below
Operating income (loss)
changed unfavorably primarily due to a decrease in allowance for equity funds used during construction (AFUDC) due to decreased spending on Constitution and the absence of a $14 million gain on early debt retirement in 2015.
Provision (benefit) for income taxes
changed favorably primarily due to lower foreign pretax income associated with our Canadian operations. See
Note 9 – Provision (Benefit) for Income Taxes
of Notes to Consolidated Financial Statements for a discussion of the effective tax rates compared to the federal statutory rate for both years.
The favorable change in
Net income attributable to noncontrolling interests
is primarily due to project development costs for Constitution, partially offset by the absence of a 2015 goodwill impairment at Cardinal.
2015 vs. 2014
Service revenues
increased primarily due to additional revenues associated with a full year of ACMP operations in 2015, increased revenues associated with the start-up of operations at Gulfstar One during the fourth quarter of 2014, and an increase in Transco’s natural gas transportation fees due to new projects placed in service in 2014 and 2015. Northeast G&P and Central also reflect higher volumes related to new well connects in several regions.
Product sales
decreased due to a decrease in marketing revenues primarily associated with lower prices across all products, partially offset by higher non-ethane volumes, and a decrease in revenues from our equity NGLs reflecting lower NGL prices, partially offset by higher NGL volumes.
Product sales
also decreased due to lower sales prices partially offset by higher volumes across all products at our other olefin operations. These decreases are partially offset by an increase in olefin sales primarily due to resuming our Geismar operations during 2015.
Product costs
decreased due to a decrease in marketing purchases primarily associated with lower per-unit costs, partially offset by higher non-ethane volumes, and a decrease in the natural gas purchases associated with the production of equity NGLs primarily due to lower natural gas prices, partially offset by higher volumes.
Product costs
also decreased due to lower feedstock purchases in our other olefin operations primarily due to lower per-unit feedstock costs, partially offset by higher volumes across most products, particularly propylene.
Operating and maintenance expenses
increased primarily due to new expenses associated with operations acquired in the acquisition of ACMP, increased growth of operating activity in certain areas, and increased maintenance and repair expenses, as well as the return to operations of the Geismar plant.
Depreciation and amortization expenses
increased primarily due to new expenses associated with operations acquired in the acquisition of ACMP and from depreciation on new projects placed in service, including Gulfstar One and the Geismar expansion.
SG&A
increased primarily due to an increase in administrative expenses primarily associated with operations acquired in the acquisition of ACMP.
Impairment of goodwill
reflects a 2015 impairment charge associated with certain goodwill. (See
Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk
of Notes to Consolidated Financial Statements.)
Impairment of certain assets
increased primarily due to 2015 impairments of previously capitalized development costs and surplus equipment write-downs. (See
Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk
of Notes to Consolidated Financial Statements.)
Net insurance recoveries – Geismar Incident
changed unfavorably primarily due to the receipt of $126 million of insurance recoveries in 2015 as compared to the receipt of $246 million of insurance recoveries in 2014.
Other (income) expense – net
within
Operating income (loss)
changed
unfavorably primarily due to the absence of $154 million of cash proceeds received in 2014 related to a contingency settlement gain and the absence of a $12 million net gain recognized in 2014 related to a partial acreage dedication release. (See
Note 8 – Other Income and Expenses
of Notes to Consolidated Financial Statements.)
Operating income (loss)
decreased primarily due to 2015 impairment of goodwill, higher impairments of certain assets, higher depreciation, operating, and maintenance expenses related to construction projects placed in service and the start-up of the Geismar plant, $229 million lower NGL margins driven by lower prices, and lower insurance recoveries related to the Geismar Incident. These decreases were partially offset by increased service revenues related to construction projects placed in service, $116 million higher olefin margins primarily due to our Geismar plant that returned to operations in 2015, and contributions from the operations acquired in the acquisition of ACMP.
Equity earnings (losses)
changed favorably primarily due to $75 million related to contributions of equity-method investments acquired in the acquisition of ACMP for a full year in 2015, as well as a $76 million increase at Discovery related to the completion of the Keathley Canyon Connector in early 2015. These changes were partially offset by $33 million of losses associated with our share of impairments recognized at the equity investees in 2015. (See
Note 7 – Investing Activities
of Notes to Consolidated Financial Statements.)
Impairment of equity-method investments
reflects 2015 impairment charges associated with certain equity-method investments. (See
Note 7 – Investing Activities
of Notes to Consolidated Financial Statements.)
Interest expense
increased due to a $181 million increase in
Interest incurred
primarily due to new debt issuances in 2014 and 2015, as well as interest expense associated with debt assumed in conjunction with the acquisition of ACMP. This increase was partially offset by lower interest due to 2015 debt retirements. In addition,
Interest capitalized
decreased $68 million primarily related to construction projects that have been placed into service. (See
Note 2 – Acquisitions
and
Note 14 – Debt, Banking Arrangements, and Leases
of Notes to Consolidated Financial Statements.)
Other income (expense) – net
below
Operating income
changed favorably primarily due to a $43 million benefit related to an increase in the AFUDC associated with an increase in spending on various Transco expansion projects and Constitution, as well as a $14 million gain on early debt retirement in April 2015.
Provision (benefit) for income taxes
changed favorably primarily due to lower foreign pretax income associated with our Canadian operations. See
Note 9 – Provision (Benefit) for Income Taxes
of Notes to Consolidated Financial Statements for a discussion of the effective tax rates compared to the federal statutory rate for both years.
Net income attributable to noncontrolling interests
changed favorably primarily due to the absence of 2014 income allocated to ACMP interests held by the public that is presented within noncontrolling interests for periods prior to consummation of the ACMP merger, partially offset by higher income allocated to noncontrolling interests associated with the start-up of Gulfstar One.
Year-Over-Year Operating Results – Segments
We evaluate segment operating performance based upon
Modified EBITDA
.
Note 19 – Segment Disclosures
of Notes to Consolidated Financial Statements includes a reconciliation of this non-GAAP measure to
Net income (loss)
. Management uses
Modified EBITDA
because it is an accepted financial indicator used by investors to compare company performance. In addition, management believes that this measure provides investors an enhanced perspective of the
operating performance of our assets.
Modified EBITDA
should not be considered in isolation or as a substitute for a measure of performance prepared in accordance with GAAP.
Central
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
2016
|
|
2015
|
|
2014
|
|
(Millions)
|
Service revenues
|
$
|
1,241
|
|
|
$
|
1,287
|
|
|
$
|
678
|
|
|
|
|
|
|
|
Segment costs and expenses
|
(387
|
)
|
|
(472
|
)
|
|
(272
|
)
|
Impairments of certain assets
|
(95
|
)
|
|
(11
|
)
|
|
(12
|
)
|
Proportional Modified EBITDA of equity-method investments
|
48
|
|
|
36
|
|
|
25
|
|
Central Modified EBITDA
|
$
|
807
|
|
|
$
|
840
|
|
|
$
|
419
|
|
The results of operations for the Central segment are only presented for periods under common control (periods subsequent to July 1, 2014) and are reflected at Williams’ historical basis in the underlying operations (see
Note 2 – Acquisitions
).
2016
vs.
2015
Modified EBITDA
decreased primarily due to higher
Impairments of certain assets
in 2016 as compared to 2015 as well as lower
Service
revenues
. These unfavorable changes were partially offset by a decrease in
Segment costs and expenses
related to a decrease in ACMP Merger and transition expenses in 2016 as well as lower labor-related and outside service costs resulting from our first quarter workforce reductions and ongoing cost containment efforts.
Service revenues
decreased primarily due to volume declines in the Barnett Shale and Anadarko areas as well as a net decrease in fee rates primarily in the Barnett Shale, Anadarko, and Eagle Ford Shale areas. These decreases were partially offset by higher rates and volumes in the Haynesville area primarily attributable to a contract executed in 2015, and additional volumes from new wells in the Haynesville Shale area.
Segment costs and expenses
decreased primarily due to a $45 million decrease in ACMP Merger and transition expenses and lower labor-related and outside service costs resulting from our first quarter workforce reductions and ongoing cost containment efforts.
Impairments of certain assets
increased primarily due to $63 million in impairments of certain Mid-Continent gathering assets and impairments or write-downs of other certain assets that may no longer be in use or are surplus in nature.
Proportional Modified EBITDA of equity-method investments
increased primarily due to increased gathering revenue from higher volumes in the Delaware basin gas gathering system.
2015
vs.
2014
Modified EBITDA
increased primarily due to the consolidation of results of operations comprising the Central segment for the entire year of 2015, an increase in revenues from increased volumes under the MVCs, and a decrease in acquisition, merger, and transition-related expenses.
Service revenues
increased primarily due to the consolidation of Central for all of 2015 and approximately $72 million recognized associated with increased volumes under the MVCs in the Barnett and Haynesville Shale areas.
Service revenues
also increased by $24 million due to higher volumes related to new well connects in the Haynesville Shale area.
Segment costs and expenses
increased primarily due to the consolidation of Central for all of 2015 and higher allocated support costs in 2015, partially offset by lower acquisition, merger, and transition-related expenses.
Proportional Modified EBITDA of equity-method investments
increased primarily due to the consolidation of Central beginning with the third quarter of 2014.
Northeast G&P
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
2016
|
|
2015
|
|
2014
|
|
(Millions)
|
Service revenues
|
$
|
838
|
|
|
$
|
810
|
|
|
$
|
550
|
|
Product sales
|
163
|
|
|
127
|
|
|
230
|
|
Segment revenues
|
1,001
|
|
|
937
|
|
|
780
|
|
|
|
|
|
|
|
Product costs
|
(159
|
)
|
|
(121
|
)
|
|
(221
|
)
|
Other segment costs and expenses
|
(351
|
)
|
|
(380
|
)
|
|
(109
|
)
|
Impairment of certain assets
|
(13
|
)
|
|
(32
|
)
|
|
(30
|
)
|
Proportional Modified EBITDA of equity-method investments
|
362
|
|
|
349
|
|
|
198
|
|
Northeast G&P Modified EBITDA
|
$
|
840
|
|
|
$
|
753
|
|
|
$
|
618
|
|
The results of operations for the Northeast G&P segment includes results for certain operations acquired in the acquisition of ACMP for periods under common control (periods subsequent to July 1, 2014) which are reflected at Williams’ historical basis in the underlying operations (see
Note 2 – Acquisitions
).
2016
vs.
2015
Modified EBITDA
increased primarily due to lower operating and maintenance expenses, higher service revenues, lower impairment charges, and improvements in
Proportional Modified EBITDA of equity-method investments
driven by higher volumes and lower impairments in 2016.
Service revenues
include a $27 million increase in Susquehanna Supply Hub gathering revenues resulting from fewer producer shut-ins associated with improved regional natural gas prices. In addition, revenues increased due to higher reimbursements for management services from certain equity-method investees. The increase in service revenues was partially offset by a $19 million decrease from our Ohio Valley Midstream operations primarily associated with lower volumes and rates driven by producer shut-ins and temporarily reduced gathering and processing rates with certain producers.
Product sales
increased primarily due to $33 million higher marketing sales associated with our Ohio Valley Midstream operations, due primarily to higher non-ethane marketing sales prices, partially offset by lower non-ethane volumes. The changes in marketing revenues are offset by similar changes in marketing purchases, reflected above as
Product costs
.
Product costs
increased primarily due to $35 million higher marketing costs associated with our Ohio Valley Midstream operations, due primarily to higher non-ethane marketing sales prices, partially offset by lower non-ethane volumes. The changes in marketing purchases are offset by similar changes in marketing revenues, reflected above as
Product sales
.
Other segment costs and expenses
decreased primarily due to a $38 million decrease in operating and maintenance expenses primarily resulting from lower costs related to supplies, outside services, and repairs, partially offset by slightly higher general and administrative expenses.
Impairment of certain assets
changed favorably primarily due to lower impairment charges associated with certain surplus equipment within our Ohio Valley Midstream business (see
Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk
of Notes to Consolidated Financial Statements).
Proportional Modified EBITDA of equity-method investments
changed favorably due to a $20 million increase from Caiman II resulting from higher volumes due to assets placed into service in 2015, an $11 million increase from
UEOM primarily associated with an increase in our ownership percentage, and a $10 million increase from Laurel Mountain primarily due to lower impairments incurred in 2016. These increases were partially offset by a $29 million decrease from Appalachia Midstream Investments primarily due to lower fee revenues driven by lower rates, partially offset by lower impairments in 2016 and higher volumes.
2015
vs.
2014
Modified EBITDA
increased primarily due to the consolidation of certain operations acquired in the acquisition of ACMP for the entire year of 2015 and higher service revenues driven by new well connections and the completion of various compression, processing, fractionation, and transportation projects. These increases were partially offset by the absence of cash received from a fourth quarter 2014 settlement discussed below.
Service revenues
increased primarily due to the consolidation of certain operations acquired in the acquisition of ACMP for all of 2015 and $90 million higher gathering fees associated with higher volumes driven by new well connections and the completion of various compression projects, as well as an increase in gathering rates, primarily in the Susquehanna Supply Hub and Utica Shale area.
Service revenues
also increased $27 million due to contributions from our Ohio Valley Midstream business resulting from the addition of processing, fractionation, and transportation facilities placed in service in 2014 and 2015. Overall volume growth was reduced as a result of producers deferring production due to low natural gas prices.
Product sales
decreased primarily due to a $104 million decline in marketing sales in the Ohio Valley Midstream business, primarily due to a 66 percent decline in non-ethane per unit marketing sales prices, partially offset by a 39 percent increase in NGL volumes. The changes in marketing revenues are offset by similar changes in marketing purchases, reflected above as
Product costs
.
Other segment costs and expenses
increased primarily due to the absence of $154 million of cash received in the fourth quarter of 2014 associated with the resolution of a contingent gain related to claims arising from the purchase of a business in a prior period (see
Note 8 – Other Income and Expenses
of Notes to Consolidated Financial Statements), higher expenses related to the consolidation of certain operations acquired in the acquisition of ACMP for all of 2015, and the absence of a $12 million net gain in 2014 related to a partial acreage dedication release. Additionally, costs increased due to $40 million higher operations and maintenance expenses resulting from growth in operations and higher pipeline remediation costs. Partially offsetting these increases were the absence of certain 2014 expenses, including $6 million in costs resulting from fire damage at a compressor station in the Susquehanna Supply Hub.
Impairment of certain assets
remained relatively consistent year over year due to $32 million of impairment charges in 2015, primarily related to our Ohio Valley Midstream business, and $30 million of impairment charges in 2014 related to certain materials and equipment.
Proportional Modified EBITDA of equity-method investments
increased primarily due to higher contributions from certain equity-method investments acquired in the acquisition of ACMP beginning with third-quarter 2014, partially offset by impairments in 2015. Additionally, the increase relates to $21 million higher contributions from Caiman II resulting from assets placed into service in 2014 and 2015, partially offset by the absence of business interruption insurance proceeds received in the prior year. These increases were partially offset by an $11 million decrease from Laurel Mountain. The decrease at Laurel Mountain was primarily due to $13 million of impairments and lower gathering fees due to lower gathering rates indexed to natural gas prices, partially offset by 24 percent higher volumes and an increase in our ownership percentage compared to the prior year.
Atlantic-Gulf
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
2016
|
|
2015
|
|
2014
|
|
(Millions)
|
Service revenues
|
$
|
1,952
|
|
|
$
|
1,881
|
|
|
$
|
1,501
|
|
Product sales
|
449
|
|
|
463
|
|
|
853
|
|
Segment revenues
|
2,401
|
|
|
2,344
|
|
|
2,354
|
|
|
|
|
|
|
|
Product costs
|
(405
|
)
|
|
(434
|
)
|
|
(791
|
)
|
Other segment costs and expenses
|
(682
|
)
|
|
(639
|
)
|
|
(639
|
)
|
Impairment of certain assets
|
(1
|
)
|
|
(5
|
)
|
|
(10
|
)
|
Proportional Modified EBITDA of equity-method investments
|
287
|
|
|
257
|
|
|
151
|
|
Atlantic-Gulf Modified EBITDA
|
$
|
1,600
|
|
|
$
|
1,523
|
|
|
$
|
1,065
|
|
|
|
|
|
|
|
NGL margin
|
$
|
38
|
|
|
$
|
27
|
|
|
$
|
57
|
|
2016 vs. 2015
Modified EBITDA
increased primarily due to higher service revenues and higher earnings at Discovery due to the completion of the Keathley Canyon Connector in the first quarter of 2015, partially offset by higher segment costs and expenses.
Service revenues
increased primarily due to:
|
|
•
|
A $79 million increase in Transco’s natural gas transportation fee revenues primarily associated with expansion projects placed in service in 2015 and 2016, partially offset by lower volume-based transportation services revenues;
|
|
|
•
|
A $20 million increase in eastern Gulf Coast region fee revenues primarily related to the impact of new volumes at Gulfstar One related to the Gunflint expansion (which was placed in service in the third quarter of 2016), higher volumes at Devils Tower related to the Kodiak field (which began production in early 2016), and higher volumes from a temporary increase related to disrupted operations of a competitor. These increases were partially offset by lower volumes from the impact of 2016 producers’ operational issues and suspending operations in order to facilitate the tie-in of the Gunflint expansion at Gulfstar One;
|
|
|
•
|
A $15 million decrease in Transco’s storage revenue related to potential refunds associated with a ruling received in certain rate case litigation in 2016;
|
|
|
•
|
A $12 million decrease in western Gulf Coast region fee revenues primarily related to lower volumes associated with producer maintenance in 2016 and natural declines in certain production areas.
|
Product sales
decreased primarily due to:
|
|
•
|
A $39 million decrease in system management gas sales from Transco. System management gas sales are offset in
Product costs
and, therefore, have no impact on
Modified EBITDA;
|
|
|
•
|
A $12 million decrease in crude oil and NGL marketing revenues. Crude oil marketing sales decreased $5 million primarily due to 13 percent lower crude oil per barrel sales prices, partially offset by 11 percent higher volumes. NGL marketing sales also decreased $7 million primarily due to 13 percent lower non-ethane volumes, partially offset by 35 percent higher ethane volumes and slightly higher ethane and non-ethane per-unit sales prices. These changes in marketing revenues are offset by similar changes in marketing purchases;
|
|
|
•
|
A $36 million increase in revenues from our equity NGLs primarily due to a temporary increase in keep-whole volumes due to disrupted operations of a competitor.
|
Product costs
decreased primarily due to:
|
|
•
|
A $39 million decrease in system management gas costs (offset in
Product sales
)
;
|
|
|
•
|
A $17 million decrease in marketing purchases (substantially offset in
Product sales
);
|
|
|
•
|
A $25 million increase in natural gas purchases associated with the production of equity NGLs primarily due to higher volumes.
|
The increase in
Other segment costs and expenses
includes $28 million higher operating expenses at Transco, primarily due to higher contract services for pipeline testing and general maintenance, as well as higher operating taxes, and $28 million higher Constitution project development costs as we discontinued capitalization of these costs beginning in April 2016. AFUDC also changed unfavorably by $11 million primarily associated with a decrease in spending on Constitution, and $8 million was incurred in first-quarter 2016 for severance and related costs associated with workforce reductions. These increases are partially offset by $22 million lower general and administrative expenses driven by first-quarter 2016 workforce reductions and ongoing cost containment efforts and an $11 million gain on an asset retirement in 2016.
The increase in
Proportional Modified EBITDA of equity-method investments
includes a $30 million increase from Discovery primarily due to higher fee revenues attributable to the completion of the Keathley Canyon Connector in the first quarter of 2015.
2015 vs. 2014
Modified EBITDA
increased primarily due to higher service revenues related to new fees from Gulfstar One, Transco expansion projects placed into service, and higher earnings at Discovery due to the completion of the Keathley Canyon Connector in the first quarter of 2015, partially offset by $30 million lower NGL margins driven by lower prices.
Service revenues
increased primarily due to $223 million of new fees associated with the start-up of operations at Gulfstar One in the fourth quarter of 2014 in addition to the related transportation fees, and a $155 million increase in Transco’s natural gas transportation fee revenues primarily associated with expansion projects placed in service in 2014 and 2015.
Product sales
decreased primarily due to:
|
|
•
|
A $350 million decrease in NGL and crude oil marketing revenues. NGL marketing sales decreased $185 million primarily due to a 54 percent decrease in non-ethane per-unit sales prices and a 5 percent decrease in non-ethane volumes primarily due to the absence of a 2014 temporary increase in production in the western Gulf Coast. Crude oil marketing sales decreased $165 million primarily due to 48 percent lower crude oil per barrel sales prices and lower volumes due to natural declines in production from certain deepwater wells flowing on our Mountaineer crude oil pipeline. These changes in marketing revenues are offset by similar changes in marketing purchases;
|
|
|
•
|
A $39 million decrease in revenues from our equity NGLs primarily due to 54 percent lower realized non-ethane per-unit sales prices.
|
Product costs
decreased primarily due to:
|
|
•
|
A $353 million decrease in marketing purchases (offset in
Product sales
);
|
|
|
•
|
A $9 million decrease in natural gas purchases associated with the production of equity NGLs primarily due to lower natural gas prices.
|
Other segment costs and expenses
are consistent and include a $43 million higher benefit related to a favorable change in equity AFUDC associated with an increase in spending on various Transco expansion projects and Constitution. These decreases were offset by higher operating and maintenance expenses primarily due to an
increase in miscellaneous contractual services primarily due to general maintenance, hydrostatic and other pipeline testing
and higher employee-related and operating tax expenses, in addition to higher expenses related to Gulfstar One which was placed in service in late 2014. Additionally, expenses recognized in 2015 include the establishment of a regulatory liability associated with rate collections in excess of our pension funding obligation and increased project development costs.
Proportional Modified EBITDA of equity-method investments
increased primarily related to higher fee revenues at Discovery due to the completion of the Keathley Canyon Connector in the first quarter of 2015.
West
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
2016
|
|
2015
|
|
2014
|
|
(Millions)
|
Service revenues
|
$
|
1,034
|
|
|
$
|
1,055
|
|
|
$
|
1,050
|
|
Product sales
|
278
|
|
|
257
|
|
|
546
|
|
Segment revenues
|
1,312
|
|
|
1,312
|
|
|
1,596
|
|
|
|
|
|
|
|
Product costs
|
(159
|
)
|
|
(145
|
)
|
|
(270
|
)
|
Other segment costs and expenses
|
(500
|
)
|
|
(513
|
)
|
|
(503
|
)
|
Impairment of certain assets
|
(4
|
)
|
|
(97
|
)
|
|
—
|
|
West Modified EBITDA
|
$
|
649
|
|
|
$
|
557
|
|
|
$
|
823
|
|
|
|
|
|
|
|
NGL margin
|
$
|
112
|
|
|
$
|
105
|
|
|
$
|
255
|
|
2016
vs.
2015
Modified EBITDA
increased primarily due to absence of a $94 million impairment charge in 2015 (see Note 17-Fair Value Measurements, Guarantees, and Concentration of Credit Risk) associated with previously capitalized project development costs for a gas processing plant.
Service revenues
decreased primarily due to a $20 million reduction associated with lower gathering and processing fees in the Piceance region attributable to reduced producer volumes and $12 million lower gathering and processing fees in the Four Corners region associated with system downtime and a natural decline in producer volumes. These reductions are partially offset by increased gathering and processing revenues of $14 million associated with higher gathering and processing rates in our Niobrara operations, partially offset by 25 percent lower gathering volumes.
Product sales
increased primarily due to:
|
|
•
|
A $21 million increase in revenues from our equity NGLs associated with higher NGL volumes, partially offset by $5 million of lower NGL prices;
|
|
|
•
|
An $11 million increase in marketing revenues primarily due to higher non-ethane volumes (offset in
Product costs
).
|
Product costs
increased primarily due to:
|
|
•
|
An $11 million increase in NGL marketing purchases primarily due to higher non-ethane volumes (offset in
Product sales)
;
|
|
|
•
|
A $9 million increase in natural gas purchases associated with the production of equity NGLs due to higher volumes, partially offset by lower natural gas prices.
|
Other segment costs and expenses
decreased due to lower labor-related costs driven by first-quarter 2016 workforce reductions and lower major maintenance and operating charges.
Impairment of certain assets
changed favorably primarily due to the absence of a $94 million impairment charge associated with previously capitalized project development costs for a gas processing plant.
2015
vs.
2014
Modified EBITDA
decreased due to lower NGL margins and a certain noncash impairment, partially offset by the addition of $26 million in
Modified EBITDA
attributed to the Niobrara operations, which were part of the acquisition of ACMP. The decrease in NGL margins are attributable to lower NGL prices and volumes, partially offset by lower per-unit natural gas costs.
Service revenues
increased due to $52 million higher gathering and processing revenues from the Niobrara operations due to the consolidation of Niobrara results for the entire year of 2015 and the start-up of the Bucking Horse processing facility in 2015. This increase is partially offset by $25 million lower commodity-based processing fees, the absence of $11 million in minimum volume shortfall payments received in 2014, and $10 million associated with lower volumes due primarily to natural declines.
Product sales
decreased primarily due to:
|
|
•
|
A $215 million decrease in revenues from our equity NGLs reflecting a $205 million decrease associated with 51 percent lower average per-unit sales prices driven by the significant decline in NGL prices, as well as a $10 million decrease in volumes primarily attributed to changes in inventory, plant maintenance, and natural declines;
|
|
|
•
|
A $54 million decrease in marketing revenues primarily due to a 60 percent decrease in average non-ethane per-unit sales prices driven by the significant decline in NGL prices, partially offset by 24 percent higher non-ethane volumes (offset in
Product costs
);
|
|
|
•
|
A $20 million decrease in other product sales, primarily condensate sales, driven by lower prices.
|
Product costs
decreased primarily due to:
|
|
•
|
A $65 million decrease in natural gas purchases associated with the production of equity NGLs reflecting 41 percent lower average per-unit natural gas costs as a result of the significant decline in natural gas prices;
|
|
|
•
|
A $52 million decrease in marketing purchases (offset in
Product sales)
;
|
|
|
•
|
An $8 million decrease in other product purchases driven by lower natural gas prices.
|
Impairment of certain assets
in 2015
primarily reflects a $94 million impairment charge associated with previously capitalized project development costs for a gas processing plant.
Other segment costs and expenses
increased primarily due to the addition of $26 million from the Niobrara operations and a $12 million net decrease in system gains. These increases were partially offset by $15 million of lower allocated support costs due to relative growth in the other segments and lower operating and maintenance expense.
NGL & Petchem Services
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
2016
|
|
2015
|
|
2014
|
|
(Millions)
|
Service revenues
|
$
|
168
|
|
|
$
|
139
|
|
|
$
|
126
|
|
Product sales
|
2,102
|
|
|
1,921
|
|
|
2,986
|
|
Segment revenues
|
2,270
|
|
|
2,060
|
|
|
3,112
|
|
|
|
|
|
|
|
Product costs
|
(1,717
|
)
|
|
(1,656
|
)
|
|
(2,829
|
)
|
Other segment costs and expenses
|
(296
|
)
|
|
(251
|
)
|
|
(241
|
)
|
Net insurance recoveries – Geismar Incident
|
7
|
|
|
126
|
|
|
232
|
|
Impairment of certain assets
|
(344
|
)
|
|
—
|
|
|
—
|
|
Proportional Modified EBITDA of equity-method investments
|
57
|
|
|
42
|
|
|
50
|
|
NGL & Petchem Services Modified EBITDA
|
$
|
(23
|
)
|
|
$
|
321
|
|
|
$
|
324
|
|
|
|
|
|
|
|
Olefins margin
|
$
|
337
|
|
|
$
|
226
|
|
|
$
|
110
|
|
NGL margin
|
12
|
|
|
21
|
|
|
68
|
|
2016
vs.
2015
Modified EBITDA
decreased primarily due to the impairment and loss on sale of our Canadian operations and lower insurance proceeds related to the Geismar Incident, partially offset by higher olefin margins driven by higher production levels at the Geismar facility and higher ethylene prices in 2016 than in 2015, as well as higher service revenues associated with the expansion of the Redwater facilities in Canada.
Service revenues
improved primarily due to the expansion of the Redwater facilities in March 2016 to provide transportation and fractionation services associated with the Williams Horizon liquids extraction plant. These operations were sold in September 2016.
Product sales
increased primarily due to:
|
|
•
|
A $140 million increase in marketing revenues primarily due to higher natural gas and NGL volumes, partially offset by primarily lower natural gas prices (substantially offset by higher
Product costs
);
|
|
|
•
|
A $94 million increase in olefin sales comprised of a $170 million increase from our Geismar plant that returned to service in late March 2015, partially offset by a $76 million decrease from our other olefin operations. The increase at Geismar includes $153 million associated with increased volumes as a result of the plant operating at higher production levels in 2016 than when production resumed in March 2015 following the Geismar Incident and $17 million primarily associated with higher ethylene per-unit sales prices. The decrease in other olefin sales includes a $14 million reduction due to the absence of our former Canadian operations in the fourth quarter of 2016, as well as lower volumes and lower per-unit sales prices within our other olefin operations;
|
|
|
•
|
A $49 million decrease in Canadian NGL production revenues comprised of a $41 million decrease associated with lower volumes and an $8 million decrease associated with lower prices across all products. The lower volumes include a $20 million reduction in the fourth quarter due to the sale of our Canadian operations in September 2016. The volume declines also reflect the shut-down and evacuation of the liquids extraction plant because of wild fires in the Fort McMurray area during the second quarter of 2016, and a longer period of planned maintenance in 2016.
|
Product costs
increased primarily due to:
|
|
•
|
A $132 million increase in marketing product costs primarily due to higher natural gas and NGL volumes, partially offset by primarily lower natural gas prices (more than offset by higher
Product sales
);
|
|
|
•
|
A $40 million decrease in NGL product costs due to a $29 million decrease in primarily propane and ethane volumes and an $11 million decrease reflecting a decline in the price of natural gas associated with the production of equity NGLs. The $29 million decline associated with lower volumes includes $13 million attributable to the fourth quarter of 2016, subsequent to the sale of our former Canadian operations;
|
|
|
•
|
A $17 million decrease in olefin feedstock purchases is primarily comprised of $78 million in lower purchases at our other olefins operations, partially offset by $61 million of higher purchases due primarily to increased volumes at our Geismar plant resulting from higher productions levels. The lower costs at our other olefin operations are comprised of $54 million in lower per-unit feedstock costs and $24 million in primarily lower propylene volumes;
|
|
|
•
|
Lower costs associated with various other products, primarily condensate.
|
The increase in
Other segment costs and expenses
is primarily due to a $34 million loss on the sale of our Canadian operations in September 2016
,
as well as a $20 million unfavorable change in foreign currency exchange that primarily relates to losses on foreign currency transactions and the remeasurement of U.S. dollar denominated current assets and liabilities within our former Canadian operations, partially offset by slightly lower general and administrative costs associated with our ongoing cost reduction efforts.
Net insurance recoveries – Geismar Incident
decreased due to a 2015 receipt of $126 million of insurance proceeds partially offset by a $7 million receipt in 2016.
Impairment of certain assets
primarily reflects the second-quarter 2016 impairment of our former Canadian operations (see
Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk
).
The increase in
Proportional Modified EBITDA of equity-method investments
reflects a $16 million improvement at OPPL primarily due to higher transportation volumes, as well as lower expenses in 2016 due to cost reduction efforts.
2015
vs.
2014
Modified EBITDA
is lower in 2015 compared to 2014 primarily due to lower insurance proceeds related to the Geismar Incident and lower NGL margins reflecting lower commodity prices, partially offset by higher volumes. Partially offsetting these decreases are higher olefin margins driven by the return to operation of the Geismar plant and higher marketing margins.
Service revenues
increased primarily due to increased third-party volumes stored at our Conway facility, as well as increased rates in 2015.
Product sales
decreased primarily due to:
|
|
•
|
A $1,187 million decrease in marketing revenues primarily due to lower prices across all products, especially non-ethane, partially offset by higher non-ethane volumes (more than offset in
Product costs
);
|
|
|
•
|
A $73 million decrease in Canadian NGL sales revenues comprised of a $120 million decrease associated with lower prices, partially offset by an increase of $47 million associated with higher volumes. Prices reflect 82 percent, 33 percent, and 46 percent per-unit lower propane, ethane, and butane prices, respectively. The higher volumes are driven by higher propane and ethane volumes, primarily due to the absence of certain operational issues at our off-gas provider and our Redwater facility in 2014. Propane volumes also increased due to sales from inventory in anticipation of a planned shutdown of the Redwater fractionator to finish construction of
|
the expansion, as well as higher quantities of propane being sold into the U.S. for storage due to the unfavorable propane market in Canada;
|
|
•
|
A $214 million increase in olefin sales primarily due to $298 million in higher sales from our Geismar plant that returned to operation, partially offset by an $84 million decrease from our other olefin operations due to lower sales prices, partially offset by higher volumes across all products, particularly propylene.
|
Product costs
decreased primarily due to:
|
|
•
|
A $1,228 million decrease in marketing product costs primarily due to lower non-ethane per-unit costs, partially offset by higher non-ethane volumes (substantially offset by lower
Product sales
);
|
|
|
•
|
A $26 million decrease in NGL product costs reflecting a $49 million decline in the price of natural gas associated with the production of equity NGLs, partially offset by a $23 million increase primarily associated with higher propane and ethane volumes;
|
|
|
•
|
A $98 million increase in olefin feedstock purchases is comprised of $127 million in higher purchases due to increased volumes at our Geismar plant as it returned to operation, partially offset by $29 million in lower other olefin operations feedstock purchases primarily due to lower per-unit feedstock costs, partially offset by higher volumes across most products, particularly propylene.
|
The unfavorable change in
Other segment costs and expenses
is primarily due to higher operating expenses including increased expenses associated with the return to operation of the Geismar plant
.
The decrease in
Net insurance recoveries - Geismar Incident
is primarily due to the 2015 receipt of $126 million of insurance proceeds compared to $246 million received in 2014, partially offset by the absence of covered insurable expenses in excess of our retentions (deductibles) related to the Geismar Incident in 2015 compared to $14 million in 2014.
Proportional Modified EBITDA of equity-method investments
reflects a $19 million decrease from Aux Sable primarily due to lower NGL margins and certain contingency loss accruals, partially offset by an $11 million increase from OPPL associated with higher transportation volumes.
Management’s Discussion and Analysis of Financial Condition and Liquidity
Overview
In 2016, we continued to focus upon growth in our businesses through disciplined investments and reducing our costs and funding needs. Examples of this activity included:
|
|
•
|
Expansion of Transco’s interstate natural gas pipeline system through projects such as Rock Springs to meet the demand of growth markets;
|
|
|
•
|
Completion of the Gulfstar One expansion project to provide production handling and gathering services for the Gunflint oil and gas discovery in the eastern deepwater Gulf of Mexico;
|
|
|
•
|
Restructuring of contracts in the Barnett Shale and Mid-Continent region, which included cash payments to us of $820 million;
|
|
|
•
|
Sale of our Canadian operations. (See
Note 3 – Divestiture
of Notes to Consolidated Financial Statements.)
|
Outlook
Fee-based businesses are becoming an even more significant component of our portfolio and serve to reduce the influence of commodity price fluctuations on our cash flows. We expect to benefit as continued growth in demand for low-cost natural gas is driven by increases in LNG exports, industrial demand, and power generation.
We believe we have, or have access to, the financial resources and liquidity necessary to meet our requirements for working capital, capital and investment expenditures, unitholder distributions, and debt service payments while maintaining a sufficient level of liquidity. In particular, as previously discussed in Company Outlook, our expected growth capital and investment expenditures total approximately $2.1 billion to $2.8 billion in 2017. Approximately $1.4 billion to $1.9 billion of our growth capital funding needs include Transco expansions and other interstate pipeline growth projects, most of which are fully contracted with firm transportation agreements. The remaining growth capital spending in 2017 primarily reflects investment in gathering and processing systems in the Northeast region limited primarily to known new producer volumes, including volumes that support Transco expansion projects including our Atlantic Sunrise project. In addition to growth capital and investment expenditures, we also remain committed to projects that maintain our assets for safe and reliable operations, as well as projects that meet legal, regulatory, and/or contractual commitments. We retain the flexibility to adjust planned levels of capital and investment expenditures in response to changes in economic conditions or business opportunities.
In January 2017 and February 2017 we received proceeds totaling approximately $2.1 billion from additional investment in us by Williams through a private placement as part of the previously described Financial Repositioning (see Overview in Management’s Discussion and Analysis of Financial Condition and Results of Operations). We also announced in January 2017 that we will redeem all of our
$750 million
6.125 percent
senior notes due 2022 on February 23, 2017. In addition, Williams expects after-tax proceeds in excess of $2 billion from planned asset monetizations of Geismar and other select assets during 2017, which we expect to use for additional debt reduction and to fund capital and investment expenditures.
Liquidity
Based on our forecasted levels of cash flow from operations and other sources of liquidity, we expect to have sufficient liquidity to manage our businesses in 2017. Our internal and external sources of consolidated liquidity to fund working capital requirements, capital and investment expenditures, debt service payments, and distributions to unitholders include:
|
|
•
|
Cash and cash equivalents on hand;
|
|
|
•
|
Cash generated from operations;
|
|
|
•
|
Distributions from our equity-method investees based on our level of ownership;
|
|
|
•
|
Cash proceeds from the January 2017 and February 2017 purchase of common units by Williams (see
Note 15 – Partners’ Capital
of Notes to Consolidated Financial Statements);
|
|
|
•
|
Use of our credit facility and/or commercial paper program;
|
|
|
•
|
Proceeds from planned asset monetizations.
|
We anticipate our more significant uses of cash to be:
|
|
•
|
Working capital requirements;
|
|
|
•
|
Maintenance and expansion capital and investment expenditures;
|
|
|
•
|
Interest on our long-term debt;
|
|
|
•
|
Repayment of current debt maturities, and additional reductions in debt with funds received as part of the Financial Repositioning announced in January 2017;
|
|
|
•
|
Quarterly distributions to our unitholders.
|
We implemented a distribution reinvestment program (DRIP) in the third quarter of 2016. Williams previously announced that it planned to reinvest approximately $1.2 billion in us in 2017 via the DRIP. As part of the Financial Repositioning, Williams discontinued its participation in the DRIP. (See
Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies
of Notes to Consolidated Financial Statements.)
Potential risks associated with our planned levels of liquidity discussed above include those previously discussed in Company Outlook.
As of
December 31, 2016
, we had a working capital deficit (current liabilities, inclusive of
$785 million
in
Long-term debt due within one year
, in excess of current assets) of
$1.285 billion
. Our available liquidity is as follows:
|
|
|
|
|
Available Liquidity
|
December 31, 2016
|
|
(Millions)
|
Cash and cash equivalents
|
$
|
145
|
|
Capacity available under our $3.5 billion credit facility, less amounts outstanding under our $3 billion commercial paper program (1)
|
3,407
|
|
|
$
|
3,552
|
|
______________
|
|
(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. At
December 31, 2016
, we had
$93 million
of
Commercial paper
outstanding. The highest amount outstanding under our commercial paper program and credit facility during 2016 was $2.326 billion. At
December 31, 2016
, we were in compliance with the financial covenants associated with this credit facility. See
Note 14 – Debt, Banking Arrangements, and Leases
of Notes to Consolidated Financial Statements for additional information on our credit facility and commercial paper program. Borrowing capacity available under our $3.5 billion credit facility as of February 20, 2017, was $3.5 billion.
|
Incentive Distribution Rights
As part of the Financial Repositioning, Williams permanently waived its right to incentive distributions from us. (See Overview in Management’s Discussion and Analysis of Financial Condition and Results of Operations.)
Through December 31, 2016, Williams’ ownership interest in us included the right to incentive distributions determined in accordance with our partnership agreement. In connection with the sale of our Canadian operations in the third quarter of 2016, Williams agreed to waive $150 million of incentive distributions otherwise payable by us to Williams in the fourth quarter of 2016. (See
Note 3 – Divestiture
of Notes to Consolidated Financial Statements.)
Williams had agreed to temporarily waive incentive distributions of approximately $2 million per quarter in connection with our acquisition of an approximate 13 percent additional interest in UEOM on June 10, 2015. The waiver would have continued through the quarter ending September 30, 2017.
Williams was required to pay us a $428 million termination fee associated with the Termination Agreement (as described in
Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies
of Notes to Consolidated Financial Statements), which settled through a reduction of quarterly incentive distributions payable to Williams (such reduction not to exceed $209 million per quarter). The November 2015, February 2016, and May 2016 distributions to Williams were reduced by $209 million, $209 million, and $10 million, respectively, related to this termination fee.
Registrations
In September 2016, we filed a registration statement for our DRIP. (See
Note 15 – Partners’ Capital
of Notes to Consolidated Financial Statements.) In November 2016, we received reinvested distributions of $260 million, of which $250 million related to Williams.
In February 2015, we filed a shelf registration statement, as a well-known seasoned issuer, and we also filed a shelf registration statement for the offer and sale from time to time of common units representing limited partner interests in us having an aggregate offering price of up to $1 billion. These sales are to be made over a period of time and from time to time in transactions at prices which are market prices prevailing at the time of sale, prices related to market price, or at negotiated prices. Such sales are to be made pursuant to an equity distribution agreement between us and certain banks who may act as sales agents or purchase for their own accounts as principals. During 2016 and 2015, we received net proceeds of approximately $115 million and approximately $59 million, respectively, from equity issued under this registration.
Distributions from Equity-Method Investees
The organizational documents of entities in which we have an equity-method investment generally require distribution of their available cash to their members on a quarterly basis. In each case, available cash is reduced, in part, by reserves appropriate for operating their respective businesses. (See
Note 7 – Investing Activities
of Notes to Consolidated Financial Statements for our more significant equity-method investees.)
Credit Ratings
Our ability to borrow money is impacted by our credit ratings. Our current ratings are as follows:
|
|
|
|
|
|
|
|
Rating Agency
|
|
Outlook
|
|
Senior Unsecured
Debt Rating
|
|
Corporate Credit Rating
|
S&P Global Ratings
|
|
Stable
|
|
BBB-
|
|
BBB-
|
Moody’s Investors Service
|
|
Stable
|
|
Baa3
|
|
N/A
|
Fitch Ratings
|
|
Stable
|
|
BBB-
|
|
N/A
|
No assurance can be given that the credit rating agencies will continue to assign us investment-grade ratings even if we meet or exceed their current criteria for investment-grade ratios. A downgrade of our credit rating might increase our future cost of borrowing and would require us to provide additional collateral to third parties, negatively impacting our available liquidity. As of
December 31, 2016
, we estimate that a downgrade to a rating below investment-grade could require us to provide up to $376 million in additional collateral of either cash or letters of credit with third parties under existing contracts.
Cash Distributions to Unitholders
We paid a cash distribution of
$0.85
per common unit on
February 10, 2017
, to unitholders of record at the close of business on February 3, 2017.
As part of the Financial Repositioning, we announced that our quarterly cash distribution for the quarter ended March 31, 2017, is expected to be reduced to $0.60 per common unit, or $2.40 annually.
Sources (Uses) of Cash
The following table summarizes the sources (uses) of cash and cash equivalents for each of the periods presented (see Notes to Consolidated Financial Statements for the Notes referenced in the table):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flow
|
|
Years Ended December 31,
|
|
Category
|
|
2016
|
|
2015
|
|
2014
|
|
|
|
(Millions)
|
Sources of cash and cash equivalents:
|
|
|
|
|
|
|
|
Operating activities - net
|
Operating
|
|
$
|
3,938
|
|
|
$
|
2,661
|
|
|
$
|
2,345
|
|
Proceeds from credit-facility borrowings
|
Financing
|
|
3,250
|
|
|
3,832
|
|
|
1,646
|
|
Proceeds from debt offerings (see Note 14)
|
Financing
|
|
998
|
|
|
3,842
|
|
|
2,740
|
|
Proceeds from sale of Canadian operations (see Note 3)
|
Investing
|
|
672
|
|
|
—
|
|
|
—
|
|
Proceeds from sales of common units (see Note 15)
|
Financing
|
|
614
|
|
|
59
|
|
|
55
|
|
Distributions from unconsolidated affiliates in excess of cumulative earnings
|
Investing
|
|
472
|
|
|
404
|
|
|
141
|
|
Contributions from noncontrolling interests
|
Financing
|
|
29
|
|
|
111
|
|
|
334
|
|
Special distribution from Gulfstream (see Note 7)
|
Financing
|
|
—
|
|
|
396
|
|
|
—
|
|
Proceeds from commercial paper - net
|
Financing
|
|
—
|
|
|
—
|
|
|
572
|
|
|
|
|
|
|
|
|
|
Uses of cash and cash equivalents:
|
|
|
|
|
|
|
|
Payments on credit-facility borrowings
|
Financing
|
|
(4,560
|
)
|
|
(3,162
|
)
|
|
(1,156
|
)
|
Distributions to limited partner unitholders and general partner (1)
|
Financing
|
|
(2,531
|
)
|
|
(2,686
|
)
|
|
(2,448
|
)
|
Capital expenditures
|
Investing
|
|
(1,944
|
)
|
|
(2,795
|
)
|
|
(3,692
|
)
|
Payments of commercial paper - net
|
Financing
|
|
(409
|
)
|
|
(306
|
)
|
|
—
|
|
Payments on debt retirements (see Note 14)
|
Financing
|
|
(375
|
)
|
|
(1,533
|
)
|
|
—
|
|
Purchases of and contributions to equity-method investments
|
Investing
|
|
(177
|
)
|
|
(594
|
)
|
|
(468
|
)
|
Contribution to Gulfstream for repayment of debt (see Note 7)
|
Financing
|
|
(148
|
)
|
|
(248
|
)
|
|
—
|
|
Dividends and distributions to noncontrolling interests
|
Financing
|
|
(92
|
)
|
|
(87
|
)
|
|
(243
|
)
|
Purchases of businesses, net of cash acquired
|
Investing
|
|
—
|
|
|
(112
|
)
|
|
—
|
|
|
|
|
|
|
|
|
|
Other sources / (uses) - net
|
Financing and Investing
|
|
312
|
|
|
143
|
|
|
235
|
|
Increase (decrease) in cash and cash equivalents
|
|
|
$
|
49
|
|
|
$
|
(75
|
)
|
|
$
|
61
|
|
____________
|
|
(1)
|
Includes $1.693 billion, $1.846 billion, and $1.867 billion to Williams in 2016, 2015, and 2014, respectively.
|
Operating activities
The factors that determine operating activities are largely the same as those that affect
Net income (loss)
, with the exception of noncash items such as
Depreciation and amortization
,
Provision (benefit) for deferred income taxes
,
Impairment of goodwill
,
Impairment of equity-method investments
, and
Impairment of and net (gain) loss on sale of assets and businesses
.
Our
Net cash provided (used) by operating activities
in 2016 increased from 2015 primarily due to the impact of higher operating income, net favorable changes in operating working capital, and receipts from contract restructurings.
Our
Net cash provided (used) by operating activities
in 2015 increased from 2014 primarily due to the impact of net favorable changes in operating working capital and the absence of contributions from ACMP for the first six months of 2014.
Off-Balance Sheet Arrangements and Guarantees of Debt or Other Commitments
We have various other guarantees and commitments which are disclosed in
Note 4 – Variable Interest Entities
,
Note 11 – Property, Plant and Equipment
,
Note 14 – Debt, Banking Arrangements, and Leases
,
Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk
, and
Note 18 – Contingent Liabilities and Commitments
of Notes to Consolidated Financial Statements. We do not believe these guarantees and commitments or the possible fulfillment of them will prevent us from meeting our liquidity needs.
Contractual Obligations
The table below summarizes the maturity dates of our contractual obligations at
December 31, 2016
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2017
|
|
2018 - 2019
|
|
2020 - 2021
|
|
Thereafter
|
|
Total
|
|
(Millions)
|
Long-term debt: (1)(2)
|
|
|
|
|
|
|
|
|
|
Principal
|
$
|
785
|
|
|
$
|
1,350
|
|
|
$
|
2,600
|
|
|
$
|
13,718
|
|
|
$
|
18,453
|
|
Interest
|
855
|
|
|
1,647
|
|
|
1,460
|
|
|
6,119
|
|
|
10,081
|
|
Commercial paper
|
93
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
93
|
|
Operating leases
|
52
|
|
|
83
|
|
|
58
|
|
|
71
|
|
|
264
|
|
Purchase obligations (3)
|
1,010
|
|
|
680
|
|
|
632
|
|
|
318
|
|
|
2,640
|
|
Other obligations (4)
|
1
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
2
|
|
Total
|
$
|
2,796
|
|
|
$
|
3,761
|
|
|
$
|
4,750
|
|
|
$
|
20,226
|
|
|
$
|
31,533
|
|
____________
|
|
(1)
|
Includes the borrowings outstanding under our credit facility, but does not include any related variable-rate interest payments.
|
|
|
(2)
|
Includes $750 million of 6.125 percent senior notes due 2022 that we intend to redeem on February 23, 2017 and related interest, presented in the table above according to the original contractual terms.
|
|
|
(3)
|
Includes approximately $244 million in open property, plant, and equipment purchase orders. Includes an estimated $418 million long-term ethane purchase obligation with index-based pricing terms that is reflected in this table at
December 31, 2016
prices. This obligation is part of an overall exchange agreement whereby volumes we transport on OPPL are sold at a third-party fractionator near Conway, Kansas, and we are subsequently obligated to purchase ethane volumes at Mont Belvieu. The purchased ethane volumes may be utilized or resold at comparable prices in the Mont Belvieu market. Includes an estimated $619 million long-term ethane purchase obligation with index-based pricing terms that primarily supplies third parties at their plants and is valued in this table at a price calculated using
December 31, 2016
prices. Any excess purchased volumes may be sold at comparable market prices. Includes an estimated $586 million long-term mixed NGLs purchase obligation with index-based pricing terms that is reflected in this table at
December 31, 2016
prices. In addition, we have not included certain natural gas life-of-lease contracts for which the future volumes are indeterminable. We have not included commitments, beyond purchase orders, for the acquisition or construction of property, plant, and equipment or expected contributions to our jointly owned investments. (See Company Outlook – Expansion Projects.)
|
|
|
(4)
|
We have not included income tax liabilities in the table above. See
Note 9 – Provision (Benefit) for Income Taxes
of Notes to Consolidated Financial Statements for a discussion of income taxes.
|
Effects of Inflation
Our operations have historically not been materially affected by inflation. Approximately 40 percent of our gross property, plant, and equipment is comprised of our interstate natural gas pipeline assets. They are subject to regulation, which limits recovery to historical cost. While amounts in excess of historical cost are not recoverable under current FERC practices, we anticipate being allowed to recover and earn a return based on increased actual cost incurred to replace existing assets. Cost-based regulations, along with competition and other market factors, may limit our ability to recover such increased costs. For our gathering and processing assets, operating costs are influenced to a greater extent by both competition for specialized services and specific price changes in crude oil and natural gas and related commodities than by changes in general inflation. Crude oil, natural gas, and NGL prices are particularly sensitive to the market perceptions concerning the supply and demand balance in the near future, as well as general economic conditions. However, our exposure to certain of these price changes is reduced through the fee-based nature of certain of our services and the use of hedging instruments.
Environmental
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 (see
Note 18 – Contingent Liabilities and Commitments
of Notes to Consolidated Financial Statements). We are monitoring these sites in a coordinated effort with other potentially responsible parties, the 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. Current estimates of the most likely costs of such activities are approximately
$16 million
, all of which are included in
Other accrued liabilities
and
Regulatory liabilities, deferred income, and other
on the
Consolidated Balance Sheet
at
December 31, 2016
. We will seek recovery of approximately
$9 million
of these accrued costs through future natural gas transmission rates. The remainder of these costs will be funded from operations. During
2016
, we paid approximately $4 million for cleanup and/or remediation and monitoring activities. We expect to pay approximately $6 million in
2017
for these activities. 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
December 31, 2016
, 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.
In March 2008, the EPA promulgated a new, lower National Ambient Air Quality Standard (NAAQS) for ground-level ozone. In May 2012, the EPA completed designation of new eight-hour ozone nonattainment areas. Several Transco facilities are located in 2008 ozone nonattainment areas. In December 2014, the EPA proposed to further reduce the ground-level ozone NAAQS from the March 2008 levels and subsequently finalized a rule on October 1, 2015. We are monitoring the rule's implementation as the reduction will trigger additional federal and state regulatory actions that may impact our operations. To date, no federal actions have been proposed to mandate additional emission controls at these facilities. Pursuant to recently finalized state regulatory actions associated with implementation of the 2008 ozone standard, we anticipate that some facilities may be subject to increased controls within five years. 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
on the
Consolidated Balance Sheet
for both new and existing facilities in affected areas. We are unable at this time to estimate with any certainty the cost of additions that may be required to meet the regulations.
On January 22, 2010, the EPA set a new one-hour nitrogen dioxide (NO
2
) NAAQS. The effective date of the new NO
2
standard was April 12, 2010. On January 20, 2012, the EPA determined pursuant to available information that no area in the country is violating the 2010 NO
2
NAAQS and thus designated all areas of the country as “unclassifiable/attainment.” Also, at that time the EPA noted its plan to deploy an expanded NO
2
monitoring network beginning in 2013. However on October 5, 2012, the EPA proposed a graduated implementation of the monitoring network between January 1, 2014 and January 1, 2017. Once three years of data is collected from the new monitoring network, the EPA will reassess attainment status with the one-hour NO
2
NAAQS. Until that time, the EPA or states may require ambient air quality modeling on a case by case basis to demonstrate compliance with the NO
2
standard. Because we are unable to predict the outcome of the EPA’s or states’ future assessment using the new monitoring network, we are unable to estimate the cost of additions that may be required to meet this regulation.
Our interstate natural gas pipelines consider prudently incurred environmental assessment and remediation costs and the costs associated with compliance with environmental standards to be recoverable through rates.
Item 8. Financial Statements and Supplementary Data
Report of Independent Registered Public Accounting Firm
The Board of Directors of WPZ GP LLC,
General Partner of Williams Partners L.P.
and the Limited Partners of Williams Partners L.P.
We have audited the accompanying consolidated balance sheet of Williams Partners L.P. (the “Partnership”) as of December 31, 2016 and 2015, and the related consolidated statements of comprehensive income (loss), changes in equity, and cash flows for each of the three years in the period ended December 31, 2016. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We did not audit the financial statements of Gulfstream Natural Gas System, L.L.C. (“Gulfstream”), a limited liability corporation in which the Partnership has a 50 percent interest. In the consolidated financial statements, the Partnership’s investment in Gulfstream was $261 million and $293 million as of December 31, 2016 and 2015, respectively, and the Partnership’s equity earnings in the net income of Gulfstream were $69 million, $65 million and $65 million, respectively, for each of the three years in the period ended December 31, 2016. Gulfstream’s financial statements were audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for Gulfstream, is based solely on the report of the other auditors.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits and the report of other auditors provide a reasonable basis for our opinion.
In our opinion, based on our audits and the report of other auditors, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Williams Partners L.P. at December 31, 2016 and 2015, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2016, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Williams Partners L.P.’s internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated
February 22, 2017
, expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Tulsa, Oklahoma
February 22, 2017
Report of Independent Registered Public Accounting Firm
To the Members of Gulfstream Natural Gas System, L.L.C.
We have audited the balance sheets of Gulfstream Natural Gas System, L.L.C. (the “Company”) as of December 31, 2016 and 2015, and the related statements of operations, comprehensive income, cash flows, and members’ equity for each of the three years in the period ended December 31, 2016. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States) and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material respects, the financial position of Gulfstream Natural Gas System, L.L.C. as of December 31, 2016 and 2015, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2016, in conformity with accounting principles generally accepted in the United States of America.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
February 22, 2017
Williams Partners L.P.
Consolidated Statement of Comprehensive Income (Loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
2016
|
|
2015
|
|
2014
|
|
(Millions, except per-unit amounts)
|
Revenues:
|
|
|
|
|
|
|
Service revenues
|
|
$
|
5,173
|
|
|
$
|
5,135
|
|
|
$
|
3,888
|
|
Product sales
|
|
2,318
|
|
|
2,196
|
|
|
3,521
|
|
Total revenues
|
|
7,491
|
|
|
7,331
|
|
|
7,409
|
|
Costs and expenses:
|
|
|
|
|
|
|
Product costs
|
|
1,728
|
|
|
1,779
|
|
|
3,016
|
|
Operating and maintenance expenses
|
|
1,548
|
|
|
1,625
|
|
|
1,277
|
|
Depreciation and amortization expenses
|
|
1,720
|
|
|
1,702
|
|
|
1,151
|
|
Selling, general, and administrative expenses
|
|
630
|
|
|
684
|
|
|
633
|
|
Impairment of goodwill (Note 17)
|
|
—
|
|
|
1,098
|
|
|
—
|
|
Impairment of certain assets (Note 17)
|
|
457
|
|
|
145
|
|
|
52
|
|
Net insurance recoveries – Geismar Incident
|
|
(7
|
)
|
|
(126
|
)
|
|
(232
|
)
|
Other (income) expense – net
|
|
118
|
|
|
41
|
|
|
(97
|
)
|
Total costs and expenses
|
|
6,194
|
|
|
6,948
|
|
|
5,800
|
|
Operating income (loss)
|
|
1,297
|
|
|
383
|
|
|
1,609
|
|
Equity earnings (losses)
|
|
397
|
|
|
335
|
|
|
228
|
|
Impairment of equity-method investments (Note 17)
|
|
(430
|
)
|
|
(1,359
|
)
|
|
—
|
|
Other investing income (loss) – net
|
|
29
|
|
|
2
|
|
|
2
|
|
Interest incurred
|
|
(949
|
)
|
|
(864
|
)
|
|
(683
|
)
|
Interest capitalized
|
|
33
|
|
|
53
|
|
|
121
|
|
Other income (expense) – net
|
|
62
|
|
|
93
|
|
|
36
|
|
Income (loss) before income taxes
|
|
439
|
|
|
(1,357
|
)
|
|
1,313
|
|
Provision (benefit) for income taxes
|
|
(80
|
)
|
|
1
|
|
|
29
|
|
Net income (loss)
|
|
519
|
|
|
(1,358
|
)
|
|
1,284
|
|
Less: Net income attributable to noncontrolling interests
|
|
88
|
|
|
91
|
|
|
96
|
|
Net income (loss) attributable to controlling interests
|
|
$
|
431
|
|
|
$
|
(1,449
|
)
|
|
$
|
1,188
|
|
Allocation of net income (loss) for calculation of earnings per common unit:
|
|
|
|
|
|
|
Net income (loss) attributable to controlling interests
|
|
$
|
431
|
|
|
$
|
(1,449
|
)
|
|
$
|
1,188
|
|
Allocation of net income (loss) to general partner
|
|
517
|
|
|
384
|
|
|
756
|
|
Allocation of net income (loss) to Class B units
|
|
12
|
|
|
(46
|
)
|
|
—
|
|
Allocation of net income (loss) to Class D units
|
|
—
|
|
|
68
|
|
|
73
|
|
Allocation of net income (loss) to common units
|
|
$
|
(98
|
)
|
|
$
|
(1,855
|
)
|
|
$
|
359
|
|
Basic and diluted earnings (loss) per common unit:
|
|
|
|
|
|
|
Net income (loss) per common unit
|
|
$
|
(.17
|
)
|
|
$
|
(3.27
|
)
|
|
$
|
.99
|
|
Weighted average number of common units outstanding (thousands)
|
|
592,519
|
|
|
567,275
|
|
|
361,968
|
|
Cash distributions per common unit
|
|
$
|
3.4000
|
|
|
$
|
3.4000
|
|
|
$
|
3.5995
|
|
Other comprehensive income (loss):
|
|
|
|
|
|
|
Cash flow hedging activities:
|
|
|
|
|
|
|
Net unrealized gain (loss) from derivative instruments
|
|
$
|
5
|
|
|
$
|
6
|
|
|
$
|
(1
|
)
|
Reclassifications into earnings of net derivative instruments (gain) loss
|
|
(3
|
)
|
|
(7
|
)
|
|
—
|
|
Foreign currency translation activities:
|
|
|
|
|
|
|
Foreign currency translation adjustments
|
|
61
|
|
|
(173
|
)
|
|
(89
|
)
|
Reclassification into earnings upon sale of foreign entity
|
|
108
|
|
|
—
|
|
|
—
|
|
Other comprehensive income (loss)
|
|
171
|
|
|
(174
|
)
|
|
(90
|
)
|
Comprehensive income (loss)
|
|
690
|
|
|
(1,532
|
)
|
|
1,194
|
|
Less: Comprehensive income attributable to noncontrolling interests
|
|
88
|
|
|
91
|
|
|
96
|
|
Comprehensive income (loss) attributable to controlling interests
|
|
$
|
602
|
|
|
$
|
(1,623
|
)
|
|
$
|
1,098
|
|
See accompanying notes.
Williams Partners L.P.
Consolidated Balance Sheet
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
2016
|
|
2015
|
|
(Millions)
|
ASSETS
|
|
|
|
Current assets:
|
|
|
|
Cash and cash equivalents
|
$
|
145
|
|
|
$
|
96
|
|
Trade accounts and other receivables (net of allowance of $6 at December 31, 2016 and $3 at December 31, 2015)
|
926
|
|
|
1,026
|
|
Inventories
|
138
|
|
|
127
|
|
Other current assets and deferred charges
|
205
|
|
|
190
|
|
Total current assets
|
1,414
|
|
|
1,439
|
|
Investments
|
6,701
|
|
|
7,336
|
|
Property, plant, and equipment – net
|
28,021
|
|
|
28,600
|
|
Intangible assets – net of accumulated amortization
|
9,662
|
|
|
10,016
|
|
Regulatory assets, deferred charges, and other
|
467
|
|
|
479
|
|
Total assets
|
$
|
46,265
|
|
|
$
|
47,870
|
|
LIABILITIES AND EQUITY
|
|
|
|
Current liabilities:
|
|
|
|
Accounts payable:
|
|
|
|
Trade
|
$
|
589
|
|
|
$
|
648
|
|
Affiliate
|
109
|
|
|
141
|
|
Accrued interest
|
258
|
|
|
231
|
|
Asset retirement obligations
|
61
|
|
|
57
|
|
Other accrued liabilities
|
804
|
|
|
469
|
|
Commercial paper
|
93
|
|
|
499
|
|
Long-term debt due within one year
|
785
|
|
|
176
|
|
Total current liabilities
|
2,699
|
|
|
2,221
|
|
Long-term debt
|
17,685
|
|
|
19,001
|
|
Asset retirement obligations
|
798
|
|
|
857
|
|
Deferred income tax liabilities
|
20
|
|
|
119
|
|
Regulatory liabilities, deferred income, and other
|
1,860
|
|
|
1,066
|
|
Contingent liabilities and commitments (Note 18)
|
|
|
|
|
Equity:
|
|
|
|
Partners’ equity:
|
|
|
|
Common units (607,064,550 and 588,546,022 units outstanding at December 31, 2016 and 2015, respectively)
|
18,300
|
|
|
19,730
|
|
Class B units (16,690,016 and 14,784,015 units outstanding as of December 31, 2016 and 2015, respectively)
|
769
|
|
|
771
|
|
General partner
|
2,385
|
|
|
2,552
|
|
Accumulated other comprehensive income (loss)
|
(1
|
)
|
|
(172
|
)
|
Total partners’ equity
|
21,453
|
|
|
22,881
|
|
Noncontrolling interests in consolidated subsidiaries
|
1,750
|
|
|
1,725
|
|
Total equity
|
23,203
|
|
|
24,606
|
|
Total liabilities and equity
|
$
|
46,265
|
|
|
$
|
47,870
|
|
See accompanying notes.
Williams Partners L.P.
Consolidated Statement of Changes in Equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Williams Partners L.P.
|
|
|
|
|
|
Limited Partners
|
|
|
|
|
|
|
|
|
|
|
|
Common
Units
|
|
Class B Units
|
|
Class D Units
|
|
General
Partner
|
|
Accumulated
Other
Comprehensive
Income (Loss)
|
|
Total Partners’ Equity
|
|
Noncontrolling
Interests
|
|
Total
Equity
|
|
(Millions)
|
Balance – December 31, 2013
|
$
|
11,596
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(536
|
)
|
|
$
|
92
|
|
|
$
|
11,152
|
|
|
$
|
415
|
|
|
$
|
11,567
|
|
Net income (loss)
|
354
|
|
|
—
|
|
|
62
|
|
|
772
|
|
|
—
|
|
|
1,188
|
|
|
96
|
|
|
1,284
|
|
Other comprehensive income (loss)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(90
|
)
|
|
(90
|
)
|
|
—
|
|
|
(90
|
)
|
Cash distributions
|
(1,706
|
)
|
|
—
|
|
|
—
|
|
|
(742
|
)
|
|
—
|
|
|
(2,448
|
)
|
|
—
|
|
|
(2,448
|
)
|
Contributions from The Williams Companies, Inc.- net (Note 1)
|
—
|
|
|
—
|
|
|
—
|
|
|
10,703
|
|
|
—
|
|
|
10,703
|
|
|
7,502
|
|
|
18,205
|
|
Sales of common units (Note 15)
|
55
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
55
|
|
|
—
|
|
|
55
|
|
Issuance of Class D units in common control transaction (Note 1)
|
—
|
|
|
—
|
|
|
1,017
|
|
|
(1,017
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Beneficial conversion feature of Class D units
|
117
|
|
|
—
|
|
|
(117
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Amortization of beneficial conversion feature of Class D units (Note 5)
|
(49
|
)
|
|
—
|
|
|
49
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Contributions from general partner
|
—
|
|
|
—
|
|
|
—
|
|
|
13
|
|
|
—
|
|
|
13
|
|
|
—
|
|
|
13
|
|
Distributions to noncontrolling interests
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(243
|
)
|
|
(243
|
)
|
Contributions from noncontrolling interests
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
334
|
|
|
334
|
|
Other
|
—
|
|
|
—
|
|
|
—
|
|
|
21
|
|
|
—
|
|
|
21
|
|
|
(13
|
)
|
|
8
|
|
Net increase (decrease) in equity
|
(1,229
|
)
|
|
—
|
|
|
1,011
|
|
|
9,750
|
|
|
(90
|
)
|
|
9,442
|
|
|
7,676
|
|
|
17,118
|
|
Balance – December 31, 2014
|
$
|
10,367
|
|
|
$
|
—
|
|
|
$
|
1,011
|
|
|
$
|
9,214
|
|
|
$
|
2
|
|
|
$
|
20,594
|
|
|
$
|
8,091
|
|
|
$
|
28,685
|
|
Net income (loss)
|
(1,988
|
)
|
|
(52
|
)
|
|
1
|
|
|
590
|
|
|
—
|
|
|
(1,449
|
)
|
|
91
|
|
|
(1,358
|
)
|
Other comprehensive income (loss)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(174
|
)
|
|
(174
|
)
|
|
—
|
|
|
(174
|
)
|
Contributions from The Williams Companies, Inc.- net (Note 1)
|
12,254
|
|
|
823
|
|
|
—
|
|
|
(6,573
|
)
|
|
—
|
|
|
6,504
|
|
|
(6,484
|
)
|
|
20
|
|
Sales of common units (Note 15)
|
59
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
59
|
|
|
—
|
|
|
59
|
|
Amortization of beneficial conversion feature of Class D units (Note 5)
|
(68
|
)
|
|
—
|
|
|
68
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Conversion of Class D units to common units (Note 5)
|
1,080
|
|
|
—
|
|
|
(1,080
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Cash distributions
|
(1,995
|
)
|
|
—
|
|
|
—
|
|
|
(691
|
)
|
|
—
|
|
|
(2,686
|
)
|
|
—
|
|
|
(2,686
|
)
|
Contributions from general partner
|
—
|
|
|
—
|
|
|
—
|
|
|
14
|
|
|
—
|
|
|
14
|
|
|
—
|
|
|
14
|
|
Contributions from noncontrolling interests
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
111
|
|
|
111
|
|
Distributions to noncontrolling interests
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(87
|
)
|
|
(87
|
)
|
Other
|
21
|
|
|
—
|
|
|
—
|
|
|
(2
|
)
|
|
—
|
|
|
19
|
|
|
3
|
|
|
22
|
|
Net increase (decrease) in equity
|
9,363
|
|
|
771
|
|
|
(1,011
|
)
|
|
(6,662
|
)
|
|
(174
|
)
|
|
2,287
|
|
|
(6,366
|
)
|
|
(4,079
|
)
|
Balance – December 31, 2015
|
$
|
19,730
|
|
|
$
|
771
|
|
|
$
|
—
|
|
|
$
|
2,552
|
|
|
$
|
(172
|
)
|
|
$
|
22,881
|
|
|
$
|
1,725
|
|
|
$
|
24,606
|
|
Net income (loss)
|
(57
|
)
|
|
(2
|
)
|
|
—
|
|
|
490
|
|
|
—
|
|
|
431
|
|
|
88
|
|
|
519
|
|
Other comprehensive income (loss)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
171
|
|
|
171
|
|
|
—
|
|
|
171
|
|
Noncash consideration from The Williams Companies, Inc. (Note 3)
|
—
|
|
|
—
|
|
|
—
|
|
|
(150
|
)
|
|
—
|
|
|
(150
|
)
|
|
—
|
|
|
(150
|
)
|
Sales of common units (Note 15)
|
624
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
624
|
|
|
—
|
|
|
624
|
|
Distributions to limited partners and general partner
|
(2,007
|
)
|
|
—
|
|
|
—
|
|
|
(533
|
)
|
|
—
|
|
|
(2,540
|
)
|
|
—
|
|
|
(2,540
|
)
|
Contributions from general partner
|
—
|
|
|
—
|
|
|
—
|
|
|
26
|
|
|
—
|
|
|
26
|
|
|
—
|
|
|
26
|
|
Contributions from noncontrolling interests
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
29
|
|
|
29
|
|
Distributions to noncontrolling interests
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(92
|
)
|
|
(92
|
)
|
Other
|
10
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
10
|
|
|
—
|
|
|
10
|
|
Net increase (decrease) in equity
|
(1,430
|
)
|
|
(2
|
)
|
|
—
|
|
|
(167
|
)
|
|
171
|
|
|
(1,428
|
)
|
|
25
|
|
|
(1,403
|
)
|
Balance – December 31, 2016
|
$
|
18,300
|
|
|
$
|
769
|
|
|
$
|
—
|
|
|
$
|
2,385
|
|
|
$
|
(1
|
)
|
|
$
|
21,453
|
|
|
$
|
1,750
|
|
|
$
|
23,203
|
|
See accompanying notes.
Williams Partners L.P.
Consolidated Statement of Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
2016
|
|
2015
|
|
2014
|
|
(Millions)
|
OPERATING ACTIVITIES:
|
|
|
|
|
|
Net income (loss)
|
$
|
519
|
|
|
$
|
(1,358
|
)
|
|
$
|
1,284
|
|
Adjustments to reconcile to net cash provided (used) by operating activities:
|
|
|
|
|
|
Depreciation and amortization
|
1,720
|
|
|
1,702
|
|
|
1,151
|
|
Provision (benefit) for deferred income taxes
|
(83
|
)
|
|
4
|
|
|
25
|
|
Impairment of goodwill
|
—
|
|
|
1,098
|
|
|
—
|
|
Impairment of equity-method investments
|
430
|
|
|
1,359
|
|
|
—
|
|
Impairment of and net (gain) loss on sale of assets and businesses
|
481
|
|
|
150
|
|
|
68
|
|
Amortization of stock-based awards
|
20
|
|
|
27
|
|
|
9
|
|
Cash provided (used) by changes in current assets and liabilities:
|
|
|
|
|
|
Accounts and notes receivable
|
80
|
|
|
(67
|
)
|
|
(169
|
)
|
Inventories
|
(20
|
)
|
|
105
|
|
|
(36
|
)
|
Other current assets and deferred charges
|
(2
|
)
|
|
2
|
|
|
(43
|
)
|
Accounts payable
|
5
|
|
|
(128
|
)
|
|
(42
|
)
|
Accrued liabilities
|
503
|
|
|
(15
|
)
|
|
(233
|
)
|
Affiliate accounts receivable and payable – net
|
(37
|
)
|
|
—
|
|
|
9
|
|
Other, including changes in noncurrent assets and liabilities
|
322
|
|
|
(218
|
)
|
|
322
|
|
Net cash provided (used) by operating activities
|
3,938
|
|
|
2,661
|
|
|
2,345
|
|
FINANCING ACTIVITIES:
|
|
|
|
|
|
Proceeds from (payments of) commercial paper – net
|
(409
|
)
|
|
(306
|
)
|
|
572
|
|
Proceeds from long-term debt
|
4,248
|
|
|
7,675
|
|
|
4,386
|
|
Payments of long-term debt
|
(4,936
|
)
|
|
(4,699
|
)
|
|
(1,157
|
)
|
Proceeds from sales of common units
|
614
|
|
|
59
|
|
|
55
|
|
Contributions from general partner
|
26
|
|
|
14
|
|
|
13
|
|
Distributions to limited partners and general partner
|
(2,531
|
)
|
|
(2,686
|
)
|
|
(2,448
|
)
|
Distributions to noncontrolling interests
|
(92
|
)
|
|
(87
|
)
|
|
(243
|
)
|
Contributions from noncontrolling interests
|
29
|
|
|
111
|
|
|
334
|
|
Contributions from The Williams Companies, Inc. – net
|
—
|
|
|
20
|
|
|
73
|
|
Payments for debt issuance costs
|
(9
|
)
|
|
(33
|
)
|
|
(24
|
)
|
Special distribution from Gulfstream
|
—
|
|
|
396
|
|
|
—
|
|
Contribution to Gulfstream for repayment of debt
|
(148
|
)
|
|
(248
|
)
|
|
—
|
|
Other – net
|
—
|
|
|
(1
|
)
|
|
24
|
|
Net cash provided (used) by financing activities
|
(3,208
|
)
|
|
215
|
|
|
1,585
|
|
INVESTING ACTIVITIES:
|
|
|
|
|
|
Property, plant, and equipment:
|
|
|
|
|
|
Capital expenditures (1)
|
(1,944
|
)
|
|
(2,795
|
)
|
|
(3,692
|
)
|
Net proceeds from dispositions
|
6
|
|
|
3
|
|
|
34
|
|
Proceeds from sale of businesses, net of cash divested
|
672
|
|
|
—
|
|
|
—
|
|
Purchases of businesses, net of cash acquired
|
—
|
|
|
(112
|
)
|
|
—
|
|
Purchases of and contributions to equity-method investments
|
(177
|
)
|
|
(594
|
)
|
|
(468
|
)
|
Distributions from unconsolidated affiliates in excess of cumulative earnings
|
472
|
|
|
404
|
|
|
141
|
|
Other – net
|
290
|
|
|
143
|
|
|
116
|
|
Net cash provided (used) by investing activities
|
(681
|
)
|
|
(2,951
|
)
|
|
(3,869
|
)
|
Increase (decrease) in cash and cash equivalents
|
49
|
|
|
(75
|
)
|
|
61
|
|
Cash and cash equivalents at beginning of year
|
96
|
|
|
171
|
|
|
110
|
|
Cash and cash equivalents at end of year
|
$
|
145
|
|
|
$
|
96
|
|
|
$
|
171
|
|
_________
|
|
|
|
|
|
(1) Increases to property, plant, and equipment
|
$
|
(1,871
|
)
|
|
$
|
(2,649
|
)
|
|
$
|
(3,571
|
)
|
Changes in related accounts payable and accrued liabilities
|
(73
|
)
|
|
(146
|
)
|
|
(121
|
)
|
Capital expenditures
|
$
|
(1,944
|
)
|
|
$
|
(2,795
|
)
|
|
$
|
(3,692
|
)
|
See accompanying notes.
|
|
|
|
Williams Partners L.P.
|
Notes to Consolidated Financial Statements
|
|
Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies
General
Unless the context clearly indicates otherwise, references in this report to “we,” “our,” “us,” or like terms refer to Williams Partners L.P. 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 December 31, 2016, Williams owned an approximate
58 percent
limited partner interest, a
2 percent
general partner interest, and incentive distribution rights (IDRs) in us. Our operations are located principally in the United States.
Financial Repositioning
In January 2017, we announced agreements with Williams, wherein Williams permanently waived the general partner’s IDRs and converted its
2 percent
general partner interest in us to a non-economic 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, following our quarterly distribution in February 2017, Williams paid additional consideration of approximately
$50 million
to us for these units. Following these transactions, Williams owns a
74 percent
limited partner interest in us.
Public Unit Exchange
On May 12, 2015, we entered into an 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).
On September 28, 2015, we entered into a Termination Agreement and Release (Termination Agreement), terminating the WPZ Public Unit Exchange. Under the terms of the Termination Agreement, Williams was required to pay us a
$428 million
termination fee, which settled through a reduction of quarterly incentive distributions payable to Williams (such reduction not to exceed
$209 million
per quarter). Our November 2015, February 2016, and May 2016 distributions to Williams were reduced by
$209 million
,
$209 million
, and
$10 million
, respectively, related to this termination fee.
ACMP Merger
On February 2, 2015, Williams Partners L.P. merged with and into Access Midstream Partners, L.P. (ACMP Merger). For the purpose of these financial statements and notes, Williams Partners L.P. (WPZ) refers to the renamed merged partnership, while Pre-merger Access Midstream Partners, L.P. (ACMP) and Pre-merger Williams Partners L.P. (Pre-merger WPZ) refer to the separate partnerships prior to the consummation of the ACMP Merger and subsequent name change. The net assets of Pre-merger WPZ and ACMP were combined at Williams’ historical basis. Williams’ basis in ACMP reflected its business combination accounting resulting from acquiring control of ACMP on July 1, 2014.
Description of Business
Our operations are located in North America and are organized into the following reportable segments: Central, Northeast G&P, Atlantic-Gulf, West, and NGL & Petchem Services.
|
|
|
|
Williams Partners L.P.
|
Notes to Consolidated Financial Statements – (Continued)
|
|
Central provides domestic gathering, treating, and compression services to producers under long-term, fixed-fee contracts. Its primary operating areas are in 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. Central also includes a
50 percent
equity-method investment in the Delaware basin gas gathering system (DBJV) in the Mid-Continent region.
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 (UEOM), a
69 percent
equity-method investment in Laurel Mountain Midstream, LLC (Laurel Mountain), a
58 percent
equity-method investment in Caiman Energy II, LLC (Caiman II), and Appalachia Midstream Services, LLC, which owns equity-method investments with an approximate average
41 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, as well as a
50 percent
equity-method investment in Gulfstream Natural Gas System, L.L.C. (Gulfstream), a
41 percent
interest in Constitution Pipeline Company, LLC (Constitution) (a consolidated entity), which is under development, and a
60 percent
equity-method investment in Discovery Producer Services LLC (Discovery).
West is comprised of our gathering, processing, and treating operations in New Mexico, Colorado, and Wyoming and our interstate natural gas pipeline, Northwest Pipeline LLC (Northwest Pipeline).
NGL & Petchem Services is comprised of our
88.5 percent
undivided interest in an olefins production facility in Geismar, Louisiana, along with a refinery grade propylene splitter and pipelines in the Gulf Coast region, an oil sands offgas processing plant located near Fort McMurray, Alberta, and a natural gas liquid (NGL)/olefin fractionation facility at Redwater, Alberta. In September 2016, we completed the sale of our Canadian operations. (See
Note 3 – Divestiture
.)This segment also includes our 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 (OPPL).
Basis of Presentation
Prior to the ACMP Merger, Williams owned certain limited partnership interests in both Pre-merger WPZ and ACMP, as well as 100 percent of the general partners of both partnerships. Due to the ownership of the general partners, Williams controlled both partnerships. Williams’ control of Pre-merger WPZ began with its inception in 2005, while control of ACMP was achieved upon obtaining an additional
50 percent
interest in its general partner effective July 1, 2014. Williams previously acquired
50 percent
of the ACMP general partner in a separate transaction in 2012.
ACMP Merger
The ACMP Merger has been accounted for as a combination between entities under common control, with Pre-merger WPZ representing the predecessor entity. As such, the accompanying financial statements represent a continuation of Pre-merger WPZ, the accounting acquirer, except for certain adjustments to give effect to the exchange ratio applied to Pre-merger WPZ’s historically outstanding units. Because the ACMP Merger was between entities under common control, it was treated similar to a pooling of interests whereby the historical results of operations for ACMP were combined with those of Pre-merger WPZ for periods under common control (periods subsequent to July 1, 2014) and the net assets of ACMP were combined at Williams’ historical basis. (See
Note 2 – Acquisitions
.)
Historical earnings of ACMP prior to the ACMP Merger have been presented herein as allocated to either the capital account of the general partner for interests owned by Williams or to noncontrolling interests for interests held
|
|
|
|
Williams Partners L.P.
|
Notes to Consolidated Financial Statements – (Continued)
|
|
by the public. Thus, there was no change in the total amount of historical earnings attributable to common unitholders. In conjunction with the ACMP Merger, the partners’ equity interests in ACMP have been reclassified out of the capital account of the general partner for interests owned by Williams and noncontrolling interests for interests held by the public and into the capital accounts of common and Class B interests as a
Contributions from The Williams Companies, Inc. - net
within the
Consolidated Statement of Changes in Equity
.
Canada Acquisition
In February 2014, Pre-merger WPZ acquired certain Canadian operations from Williams (Canada Acquisition) for total consideration of
$56 million
of cash (including a
$31 million
post-closing adjustment paid in the second quarter of 2014),
25,577,521
Pre-merger WPZ Class D limited-partner units, and an increase in the capital account of our general partner to allow it to maintain its
2 percent
general partner interest. In lieu of cash distributions, the Class D units received quarterly distributions of additional paid-in-kind Class D units. This common control acquisition was treated similar to a pooling of interests whereby the historical results of operations were combined with ours for all periods presented and the acquired assets and liabilities were combined with ours at their historical amounts. These Canadian operations are reported in our NGL & Petchem Services segment.
In October 2014, a purchase price adjustment was finalized whereby Pre-merger WPZ received
$56 million
in cash from Williams in the fourth quarter of 2014
and Williams waived
$2 million
in payments on its IDRs with respect to Pre-merger WPZ’s November 2014 distribution.
The Canadian operations previously participated in Williams’ cash management program under a credit agreement with Williams. Net changes in amounts due to/from Williams prior to the Canada Acquisition, along with the cash consideration paid for the Canada Acquisition, are reflected within
Contributions from The Williams Companies, Inc. - net
within the
Consolidated Statement of Changes in Equity
.
Significant risks and uncertainties
We have announced plans to monetize our olefins production plant in Geismar, Louisiana, as well as other select assets that are not core to our strategy. As we pursue these other select asset monetizations, it is possible that we may incur 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.
Summary of Significant Accounting Policies
Principles of consolidation
The consolidated financial statements include the accounts of all entities that we control and our proportionate interest in the accounts of certain ventures in which we own an undivided interest. Management’s judgment is required to evaluate whether we control an entity. Key areas of that evaluation include:
|
|
•
|
Determining whether an entity is a variable interest entity (VIE);
|
|
|
•
|
Determining whether we are the primary beneficiary of a VIE, including evaluating which activities of the VIE most significantly impact its economic performance and the degree of power that we and our related parties have over those activities through our variable interests;
|
|
|
•
|
Identifying events that require reconsideration of whether an entity is a VIE and continuously evaluating whether we are a VIE’s primary beneficiary;
|
|
|
|
|
Williams Partners L.P.
|
Notes to Consolidated Financial Statements – (Continued)
|
|
|
|
•
|
Evaluating whether other owners in entities that are not VIEs are able to effectively participate in significant decisions that would be expected to be made in the ordinary course of business such that we do not have the power to control such entities.
|
We apply the equity method of accounting to investments over which we exercise significant influence but do not control.
Common control transactions
Entities and assets acquired from Williams and its affiliates are accounted for as common control transactions whereby the net assets acquired are combined with ours at their historical amounts. If any cash consideration transferred to Williams in such a transaction exceeds the carrying value of the net assets acquired, the excess is treated as a capital transaction with our general partner, similar to a dividend. If the carrying value of the net assets acquired exceeds any cash consideration transferred and limited partner units are also issued as consideration, then the limited partner units are recorded at an amount equal to the excess of the carrying value of the net assets acquired over any cash consideration transferred. To the extent that such transactions require prior periods to be recast, historical net equity amounts prior to the transaction date are reflected in the account of the general partner or noncontrolling interests, if applicable. Cash consideration up to the carrying value of net assets acquired is presented as an investing activity in our
Consolidated Statement of Cash Flows
. Cash consideration in excess of the carrying value of net assets acquired is presented as a financing activity in our
Consolidated Statement of Cash Flows
.
Equity-method investment basis differences
Differences between the cost of our equity-method investments and our underlying equity in the net assets of investees are accounted for as if the investees were consolidated subsidiaries.
Equity earnings (losses)
in the
Consolidated Statement of Comprehensive Income (Loss)
includes our allocable share of net income (loss) of investees adjusted for any depreciation and amortization, as applicable, associated with basis differences.
Use of estimates
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.
Significant estimates and assumptions include:
|
|
•
|
Impairment assessments of investments, property, plant, and equipment, goodwill, and other identifiable intangible assets;
|
|
|
•
|
Litigation-related contingencies;
|
|
|
•
|
Environmental remediation obligations;
|
|
|
•
|
Depreciation and/or amortization of equity-method investment basis differences;
|
|
|
•
|
Asset retirement obligations;
|
|
|
•
|
Acquisition related purchase price allocations.
|
These estimates are discussed further throughout these notes.
|
|
|
|
Williams Partners L.P.
|
Notes to Consolidated Financial Statements – (Continued)
|
|
Regulatory accounting
Transco and Northwest Pipeline are regulated by the Federal Energy Regulatory Commission (FERC). Their rates, which are established by the FERC, are designed to recover the costs of providing the regulated services, and their competitive environment makes it probable that such rates can be charged and collected. Therefore, our management has determined that it is appropriate under Accounting Standards Codification (ASC) Topic 980, “Regulated Operations”, to account for and report regulatory assets and liabilities related to these operations consistent with the economic effect of the way in which their rates are established. Accounting for these operations that are regulated can differ from the accounting requirements for nonregulated operations. For example, for regulated operations, allowance for funds used during construction (AFUDC) represents the estimated cost of debt and equity funds applicable to utility plant in process of construction and is capitalized as a cost of property, plant, and equipment because it constitutes an actual cost of construction under established regulatory practices; nonregulated operations are only allowed to capitalize the cost of debt funds related to construction activities, while a component for equity is prohibited. The components of our regulatory assets and liabilities relate to the effects of deferred taxes on equity funds used during construction, asset retirement obligations, fuel cost differentials, levelized incremental depreciation, negative salvage, and pension and other postretirement benefits. Our current and noncurrent regulatory asset and liability balances for the years ended
December 31, 2016
and
2015
are as follows:
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
2016
|
|
2015
|
|
(Millions)
|
Current assets reported within
Other current assets and deferred charges
|
$
|
91
|
|
|
$
|
84
|
|
Noncurrent assets reported within
Regulatory assets, deferred charges, and other
|
299
|
|
|
305
|
|
Total regulated assets
|
$
|
390
|
|
|
$
|
389
|
|
|
|
|
|
Current liabilities reported within
Other accrued liabilities
|
$
|
11
|
|
|
$
|
4
|
|
Noncurrent liabilities reported within
Regulatory liabilities, deferred income, and other
|
480
|
|
|
409
|
|
Total regulated liabilities
|
$
|
491
|
|
|
$
|
413
|
|
Cash and cash equivalents
Cash and cash equivalents
in the
Consolidated Balance Sheet
includes amounts primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government. These have maturity dates of three months or less when acquired.
Accounts receivable
Accounts receivable are carried on a gross basis, with no discounting, less an allowance for doubtful accounts. We estimate the allowance for doubtful accounts based on existing economic conditions, the financial condition of our customers, and the amount and age of past due accounts. 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. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted.
Inventories
Inventories
in the
Consolidated Balance Sheet
consist of natural gas liquids, olefins, natural gas in underground storage, and materials and supplies and are stated at the lower of cost or market. The cost of inventories is primarily determined using the average-cost method.
|
|
|
|
Williams Partners L.P.
|
Notes to Consolidated Financial Statements – (Continued)
|
|
Property, plant, and equipment
Property, plant, and equipment is recorded at cost. We base the carrying value of these assets on estimates, assumptions, and judgments relative to capitalized costs, useful lives, and salvage values.
As regulated entities, Northwest Pipeline and Transco provide for depreciation using the straight-line method at FERC-prescribed rates. Depreciation for nonregulated entities is provided primarily on the straight-line method over estimated useful lives, except for certain offshore facilities that apply an accelerated depreciation method.
Gains or losses from the ordinary sale or retirement of property, plant, and equipment for regulated pipelines are credited or charged to accumulated depreciation. Other gains or losses are recorded in
Other (income) expense – net
included in
Operating income (loss)
in the
Consolidated Statement of Comprehensive Income (Loss)
.
Ordinary maintenance and repair costs are generally expensed as incurred. Costs of major renewals and replacements are capitalized as property, plant, and equipment.
We record a liability and increase the basis in the underlying asset for the present value of each expected future asset retirement obligation (ARO) at the time the liability is initially incurred, typically when the asset is acquired or constructed. As regulated entities, Northwest Pipeline and Transco offset the depreciation of the underlying asset that is attributable to capitalized ARO cost to a regulatory asset as management expects to recover these amounts in future rates. We measure changes in the liability due to passage of time by applying an interest rate to the liability balance. This amount is recognized as an increase in the carrying amount of the liability and as a corresponding accretion expense included in
Operating and maintenance expenses
in the
Consolidated Statement of Comprehensive Income (Loss)
, except for regulated entities, for which the liability is offset by a regulatory asset. The regulatory asset is amortized commensurate with our collection of those costs in rates.
Measurements of AROs include, as a component of future expected costs, an estimate of the price that a third party would demand, and could expect to receive, for bearing the uncertainties inherent in the obligations, sometimes referred to as a market-risk premium.
Goodwill
Goodwill included within
Intangible assets – net of accumulated amortization
in the
Consolidated Balance Sheet
represents the excess of the consideration, plus the fair value of any noncontrolling interest or any previously held equity interest, over the fair value of the net assets acquired. It is not subject to amortization but is evaluated annually as of October 1 for impairment or more frequently if impairment indicators are present that would indicate it is more likely than not that the fair value of the reporting unit is less than its carrying amount. As part of the evaluation, we compare our estimate of the fair value of the reporting unit with its carrying value, including goodwill. If the carrying value of the reporting unit exceeds its fair value, a computation of the implied fair value of the goodwill is compared with its related carrying value. If the carrying value of the reporting unit goodwill exceeds the implied fair value of that goodwill, an impairment loss is recognized in the amount of the excess. Judgments and assumptions are inherent in our management’s estimates of fair value.
Other intangible assets
Our identifiable intangible assets included within
Intangible assets – net of accumulated amortization
in the
Consolidated Balance Sheet
are primarily related to gas gathering, processing, and fractionation contractual customer relationships. Our intangible assets are amortized on a straight-line basis over the period in which these assets contribute to our cash flows. We evaluate these assets for changes in the expected remaining useful lives and would reflect any changes prospectively through amortization over the revised remaining useful life.
|
|
|
|
Williams Partners L.P.
|
Notes to Consolidated Financial Statements – (Continued)
|
|
Impairment of property, plant, and equipment, other identifiable intangible assets, and investments
We evaluate our property, plant, and equipment and other identifiable intangible assets for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable. When an indicator of impairment has occurred, we compare our management’s estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has occurred and we may apply a probability-weighted approach to consider the likelihood of different cash flow assumptions and possible outcomes including selling in the near term or holding for the remaining estimated useful life. If an impairment of the carrying value has occurred, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value. This evaluation is performed at the lowest level for which separately identifiable cash flows exist.
For assets identified to be disposed of in the future and considered held for sale, we compare the carrying value to the estimated fair value less the cost to sell to determine if recognition of an impairment is required. Until the assets are disposed of, the estimated fair value, which includes estimated cash flows from operations until the assumed date of sale, is recalculated when related events or circumstances change.
We evaluate our investments for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such investments may have experienced an other-than-temporary decline in value. When evidence of loss in value has occurred, we compare our estimate of fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred. If the estimated fair value is less than the carrying value and we consider the decline in value to be other-than-temporary, the excess of the carrying value over the fair value is recognized in the consolidated financial statements as an impairment charge.
Judgments and assumptions are inherent in our management’s estimate of undiscounted future cash flows and an asset’s or investment’s fair value. Additionally, judgment is used to determine the probability of sale with respect to assets considered for disposal.
Deferred income
We record a liability for deferred income related to cash received from customers in advance of providing our services. Such amounts are generally recognized in revenue upon satisfying our performance obligations, primarily providing services based on units of production or over remaining contractual service periods ranging from
1
to
25
years. Deferred income is reflected within
Other accrued liabilities
and
Regulatory liabilities, deferred income, and other
on the
Consolidated Balance Sheet
. (See
Note 13 – Other Accrued Liabilities
.)
During 2016, we received cash proceeds totaling
$820 million
associated with restructuring certain gas gathering contracts in the Barnett Shale and Mid-Continent regions. The proceeds were recorded as deferred income and are being amortized into income in 2016 and future periods.
In October 2016, we received
$104 million
of newly constructed assets as part of a noncash investing transaction with a customer for which we provide production handling and other services. The transaction was recorded in
Property, plant, and equipment – net
and deferred income in the
Consolidated Balance Sheet
and is being amortized based on units of production through 2024. Due to the noncash nature of this transaction, it is not presented within the
Consolidated Statement of Cash Flows
.
Contingent liabilities
We record liabilities for estimated loss contingencies, including environmental matters, when we assess that a loss is probable and the amount of the loss can be reasonably estimated. These liabilities are calculated based upon our assumptions and estimates with respect to the likelihood or amount of loss and upon advice of legal counsel, engineers, or other third parties regarding the probable outcomes of the matters. These calculations are made without consideration
|
|
|
|
Williams Partners L.P.
|
Notes to Consolidated Financial Statements – (Continued)
|
|
of any potential recovery from third parties. We recognize insurance recoveries or reimbursements from others when realizable. Revisions to these liabilities are generally reflected in income when new or different facts or information become known or circumstances change that affect the previous assumptions or estimates.
Cash flows from revolving credit facility and commercial paper program
Proceeds and payments related to borrowings under our credit facility are reflected in the financing activities in the
Consolidated Statement of Cash Flows
on a gross basis. Proceeds and payments related to borrowings under our commercial paper program are reflected in the financing activities in the
Consolidated Statement of Cash Flows
on a net basis, as the outstanding notes generally have maturity dates less than three months from the date of issuance. (See
Note 14 – Debt, Banking Arrangements, and Leases
.)
Derivative instruments and hedging activities
We may utilize derivatives to manage a portion of our commodity price risk. These instruments consist primarily of swaps, futures, and forward contracts involving short- and long-term purchases and sales of energy commodities. We report the fair value of derivatives, except those for which the normal purchases and normal sales exception has been elected, in
Other current assets and deferred charges
;
Regulatory assets, deferred charges, and other
;
Other accrued liabilities
;
or
Regulatory liabilities, deferred income, and other
in the
Consolidated Balance Sheet
. We determine the current and noncurrent classification based on the timing of expected future cash flows of individual trades. We report these amounts on a gross basis. Additionally, we report cash collateral receivables and payables with our counterparties on a gross basis. (See
Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk
.)
The accounting for the changes in fair value of a commodity derivative can be summarized as follows:
|
|
|
|
Derivative Treatment
|
|
Accounting Method
|
Normal purchases and normal sales exception
|
|
Accrual accounting
|
Designated in a qualifying hedging relationship
|
|
Hedge accounting
|
All other derivatives
|
|
Mark-to-market accounting
|
We may elect the normal purchases and normal sales exception for certain short- and long-term purchases and sales of physical energy commodities. Under accrual accounting, any change in the fair value of these derivatives is not reflected on the balance sheet after the initial election of the exception.
We may also designate a hedging relationship for certain commodity derivatives. For a derivative to qualify for designation in a hedging relationship, it must meet specific criteria and we must maintain appropriate documentation. We establish hedging relationships pursuant to our risk management policies. We evaluate the hedging relationships at the inception of the hedge and on an ongoing basis to determine whether the hedging relationship is, and is expected to remain, highly effective in achieving offsetting changes in fair value or cash flows attributable to the underlying risk being hedged. We also regularly assess whether the hedged forecasted transaction is probable of occurring. If a derivative ceases to be or is no longer expected to be highly effective, or if we believe the likelihood of occurrence of the hedged forecasted transaction is no longer probable, hedge accounting is discontinued prospectively, and future changes in the fair value of the derivative are recognized currently in
Product sales
or
Product costs
in the
Consolidated Statement of Comprehensive Income (Loss)
.
For commodity derivatives designated as a cash flow hedge, the effective portion of the change in fair value of the derivative is reported in
Accumulated other comprehensive income (loss)
(AOCI) in the
Consolidated Balance Sheet
and reclassified into earnings in the period in which the hedged item affects earnings. Any ineffective portion of the derivative’s change in fair value is recognized currently in
Product sales
or
Product costs
in the
Consolidated Statement of Comprehensive Income (Loss)
. Gains or losses deferred in AOCI associated with terminated derivatives, derivatives that cease to be highly effective hedges, derivatives for which the forecasted transaction is reasonably possible but no longer probable of occurring, and cash flow hedges that have been otherwise discontinued remain in AOCI until the
|
|
|
|
Williams Partners L.P.
|
Notes to Consolidated Financial Statements – (Continued)
|
|
hedged item affects earnings. If it becomes probable that the forecasted transaction designated as the hedged item in a cash flow hedge will not occur, any gain or loss deferred in AOCI is recognized in
Product sales
or
Product costs
in the
Consolidated Statement of Comprehensive Income (Loss)
at that time. The change in likelihood of a forecasted transaction is a judgmental decision that includes qualitative assessments made by management.
For commodity derivatives that are not designated in a hedging relationship, and for which we have not elected the normal purchases and normal sales exception, we report changes in fair value currently in
Product sales
or
Product costs
in the
Consolidated Statement of Comprehensive Income (Loss)
.
Certain gains and losses on derivative instruments included in the
Consolidated Statement of Comprehensive Income (Loss)
are netted together to a single net gain or loss, while other gains and losses are reported on a gross basis. Gains and losses recorded on a net basis include unrealized gains and losses on all derivatives that are not designated as hedges and for which we have not elected the normal purchases and normal sales exception.
Realized gains and losses on derivatives that require physical delivery, as well as natural gas derivatives for NGL processing activities and which are not held for trading purposes nor were entered into as a pre-contemplated buy/sell arrangement, are recorded on a gross basis.
Revenue recognition
Revenues
As a result of the ratemaking process, certain revenues 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.
Service revenues
Revenues from our interstate natural gas pipeline businesses include services pursuant to long-term firm transportation and storage agreements. These agreements provide for a reservation charge based on the volume of contracted capacity and a commodity charge based on the volume of gas delivered, both at rates specified in our FERC tariffs. We recognize revenues for reservation charges ratably over the contract period 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 injection and withdrawal 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.
Certain revenues from our midstream operations include those derived from natural gas gathering, processing, treating, and compression services and are performed under volumetric-based fee contracts. These revenues are recorded when services have been performed.
Certain of our gas gathering and processing agreements have minimum volume commitments. If a customer under such an agreement fails to meet its minimum volume commitment for a specified period, generally measured on an annual basis, it is obligated to pay a contractually determined fee based upon the shortfall between actual production volumes and the minimum volume commitment for that period. The revenue associated with minimum volume commitments is recognized in the period that the actual shortfall is determined and is no longer subject to future reduction or offset, which is generally at the end of the annual period or fourth quarter.
Crude oil gathering and transportation revenues and offshore production handling fees are recognized when the services have been performed. Certain offshore production handling contracts contain fixed payment terms that result in the deferral of revenues until such services have been performed or such capacity has been made available.
Storage revenues from our midstream operations associated with prepaid contracted storage capacity contracts are recognized on a straight-line basis over the life of the contract as services are provided.
|
|
|
|
Williams Partners L.P.
|
Notes to Consolidated Financial Statements – (Continued)
|
|
Product sales
In the course of providing transportation services to customers of our interstate natural gas pipeline businesses, we may receive different quantities of gas from shippers than the quantities delivered on behalf of those shippers. The resulting imbalances are primarily settled through the purchase and sale of gas with our customers under terms provided for in our FERC tariffs. Revenue is recognized from the sale of gas upon settlement of the transportation and exchange imbalances.
We market NGLs, crude oil, natural gas, and olefins that we purchase from our producer customers as part of the overall service provided to producers. Revenues from marketing NGLs are recognized when the products have been sold and delivered.
Under our keep-whole and percent-of-liquids processing contracts, we retain the rights to all or a portion of the NGLs extracted from the producers’ natural gas stream and recognize revenues when the extracted NGLs are sold and delivered.
Our domestic olefins business produces olefins from purchased or produced feedstock and we recognize revenues when the olefins are sold and delivered.
Our Canadian businesses that were sold in September 2016 had processing and fractionation operations where we retained certain NGLs and olefins from an upgrader’s offgas stream and we recognized revenues when the fractionated products were sold and delivered.
Interest capitalized
We capitalize interest during construction on major projects with construction periods of at least
3 months
and a total project cost in excess of
$1 million
. Interest is capitalized on borrowed funds and, where regulation by the FERC exists, on internally generated funds (equity AFUDC). The latter is included in
Other income (expense) – net
below
Operating income (loss)
in the
Consolidated Statement of Comprehensive Income (Loss)
. The rates used by regulated companies are calculated in accordance with FERC rules. Rates used by nonregulated companies are based on our average interest rate on debt.
Employee equity-based awards
We recognize compensation expense on employee equity-based awards, net of estimated forfeitures, on a straight-line basis. (See
Note 16 – Equity-Based Compensation
.)
Pension and other postretirement benefits
We do not have employees. Certain of the costs charged to us by Williams associated with employees who directly support us include costs related to Williams’ pension and other postretirement benefit plans. (See
Note 10 – Benefit Plans
.) Although the underlying benefit plans of Williams are single-employer plans, we follow multiemployer plan accounting whereby the amount charged to us, and thus paid by us, is based on our share of net periodic benefit cost.
Income taxes
We generally are not a taxable entity for income tax purposes, with the exception of Texas franchise tax and foreign income taxes associated with our Canadian operations, which were sold in September 2016. Other income taxes are generally borne by individual partners. Net income for financial statement purposes may differ significantly from taxable income of unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under our partnership agreement. The aggregated 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 to us.
|
|
|
|
Williams Partners L.P.
|
Notes to Consolidated Financial Statements – (Continued)
|
|
Foreign deferred income taxes associated with our Canadian operations, which were sold in September 2016, have been computed using the liability method and have been provided on all temporary differences between the financial basis and the tax basis of the related assets and liabilities. Our management’s judgment and income tax assumptions are used to determine the levels, if any, of valuation allowances associated with deferred tax assets.
Earnings (loss) per common unit
We use the two-class method to calculate basic and diluted earnings (loss) per common unit whereby net income (loss), adjusted for items specifically allocated to our general partner, is allocated on a pro-rata basis between ownership interests. Basic and diluted earnings (loss) per common unit are based on the average number of common units outstanding. Diluted earnings (loss) per common unit includes any dilutive effect of nonvested restricted common units determined by the treasury-stock method, unless common unitholders are allocated a loss.
Foreign currency translation
Our former foreign subsidiaries used the Canadian dollar as their functional currency. Assets and liabilities of such foreign subsidiaries were translated at the spot rate in effect at the applicable reporting date, and the combined statements of comprehensive income (loss) were translated into the U.S. dollar at the average exchange rates in effect during the applicable period. The resulting cumulative translation adjustment was recorded as a separate component of AOCI in the
Consolidated Balance Sheet
.
Transactions denominated in currencies other than the functional currency were recorded based on exchange rates at the time such transactions arose. Subsequent changes in exchange rates when the transactions were settled resulted in transaction gains and losses which were reflected in
Other (income) expense – net
within
Costs and expenses
in the
Consolidated Statement of Comprehensive Income (Loss)
. All of our Canadian operations were sold in September 2016.
Accounting standards issued but not yet adopted
In January 2017, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2017-04 “Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment” (ASU 2017-04). ASU 2017-04 modifies the concept of goodwill impairment to represent the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill. Under ASU 2017-04, entities will no longer be required to determine the implied fair value of goodwill by assigning the fair value of a reporting unit to its individual assets and liabilities as if that reporting unit had been acquired in a business combination. ASU 2017-04 is effective for goodwill impairment testing for interim and annual periods beginning after December 15, 2019, and requires a prospective transition. Early adoption is permitted for interim and annual goodwill impairment tests performed after January 1, 2017, and we plan to adopt this standard in 2017. Our West reportable segment has
$47 million
of goodwill included in
Intangible assets – net of accumulated amortization
in the
Consolidated Balance Sheet
(see
Note 12 – Goodwill and Other Intangible Assets
).
In August 2016, the FASB issued ASU 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 eight cash flow classification issues, including debt prepayment or debt extinguishment costs and distributions received from equity method investees, to reduce diversity in practice. ASU 2016-15 is effective for interim and annual periods beginning after December 15, 2017. Early adoption is permitted. ASU 2016-15 requires a retrospective transition. We are evaluating the impact of ASU 2016-15 on our consolidated financial statements.
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
|
|
|
|
Williams Partners L.P.
|
Notes to Consolidated Financial Statements – (Continued)
|
|
is effective for interim and annual periods beginning after December 15, 2019. Early adoption is permitted. ASU 2016-13 requires varying transition methods for the different categories of amendments. We are evaluating the impact of ASU 2016-13 on our consolidated financial statements. 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 than under our current policy.
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 clarifies the definition of a lease, requires a dual approach to lease classification similar to current lease classifications, and causes lessees to recognize leases on the balance sheet as a lease liability with a corresponding right-of-use asset. ASU 2016-02 is effective for interim and annual periods beginning after December 15, 2018. Early adoption is permitted. ASU 2016-02 requires a modified retrospective transition for capital or operating leases existing at or entered into after the beginning of the earliest comparative period presented in the financial statements. We are reviewing contracts to identify leases, particularly reviewing the applicability of ASU 2016-02 to contracts involving easements/rights-of-way.
In May 2014, the FASB issued ASU 2014-09 establishing Accounting Standards Codification (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 is effective for interim and annual reporting periods beginning after December 15, 2017. ASC 606 allows either full retrospective or modified retrospective transition and early adoption is permitted for annual periods beginning after December 15, 2016.
We continue to evaluate the impact the standard may have on our financial statements. For each revenue contract type, we are conducting a formal contract review process to evaluate the impact, if any, that the new revenue standard may have. We have substantially completed that process, but continue to evaluate our accounting for noncash consideration, which exists in contracts where we receive commodities as full or partial consideration, contracts with a significant financing component, which may exist in situations where the timing of the consideration we received varies significantly from the timing of the service we provide, and the accounting for contributions in aid of construction. As such, we are unable to determine the potential impact upon the amount and timing of revenue recognition and related disclosures. Additionally, we have identified possible financial system and internal control changes necessary for adoption. We currently anticipate utilizing a modified retrospective transition upon the adoption of ASC 606 as of January 1, 2018.
Note 2 – Acquisitions
ACMP
As previously discussed in
Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies
, the net assets of Pre-merger WPZ and ACMP have been combined at Williams’ historical basis. Williams’ basis in ACMP reflects its business combination accounting resulting from acquiring control of ACMP on July 1, 2014 (ACMP Acquisition), which, among other things, requires identifiable assets acquired and liabilities assumed to be measured at their acquisition-date fair values.
The valuation techniques used to measure the acquisition-date fair value of ACMP consisted of valuing the limited partner units and general partner interest separately. The limited partner units of ACMP, consisting of common and Class B units, were valued based on ACMP’s closing common unit price at July 1, 2014. The general partner interest, including IDRs, was valued on a noncontrolling basis using an income approach based on a discounted cash flow analysis and a market comparison analysis based on comparable guideline companies and an implied fair value from Williams’ purchase.
The following table presents the allocation of the acquisition-date fair value of the major classes of the assets acquired, which are presented primarily in the Central and Northeast G&P segments, liabilities assumed, noncontrolling
|
|
|
|
Williams Partners L.P.
|
Notes to Consolidated Financial Statements – (Continued)
|
|
interest, and equity at July 1, 2014. The fair value of accounts receivable acquired equaled contractual amounts receivable. Changes to the preliminary allocation disclosed in Exhibit 99.1 of the Form 8-K dated May 6, 2015, which were recorded in the first quarter of 2015, reflect an increase of
$150 million
in
Property, plant, and equipment
and
$25 million
in
Goodwill
, and a decrease of
$168 million
in
Other intangible assets
and
$7 million
in
Investments
. These adjustments during the measurement period were not considered significant to require retrospective revisions of our financial statements.
|
|
|
|
|
|
(Millions)
|
Accounts receivable
|
$
|
168
|
|
Other current assets
|
63
|
|
Investments
|
5,865
|
|
Property, plant, and equipment
|
7,165
|
|
Goodwill
|
499
|
|
Other intangible assets
|
8,841
|
|
Current liabilities
|
(408
|
)
|
Debt
|
(4,052
|
)
|
Other noncurrent liabilities
|
(9
|
)
|
Noncontrolling interest in ACMP’s subsidiaries
|
(958
|
)
|
Noncontrolling interest representing ACMP public unitholders
|
(6,544
|
)
|
Equity
|
(10,630
|
)
|
Other intangible assets
recognized in the acquisition are related to contractual customer relationships from gas gathering agreements with our customers. The basis for determining the value of these intangible assets was estimated future net cash flows to be derived from acquired contractual customer relationships discounted using a risk-adjusted discount rate. These intangible assets are being amortized on a straight-line basis over
30 years
during which contractual customer relationships are expected to contribute to our cash flows. As estimated at the time of acquisition, approximately
56 percent
of the expected future revenues from these contractual customer relationships were impacted by our ability and intent to renew or renegotiate existing customer contracts. We expense costs incurred to renew or extend the terms of our gas gathering, processing, and fractionation contracts with customers. Based on the estimated future revenues during the current contract periods (as estimated at the time of acquisition), the weighted-average periods to the next renewal or extension of the existing customer contracts were approximately
17 years
.
The following unaudited pro forma
Total revenues
and
Net income (loss) attributable to controlling interests
for the year ended December 31, 2014, are presented as if the ACMP Acquisition had been completed on January 1, 2014. These pro forma amounts are not necessarily indicative of what the actual results would have been if the acquisition had in fact occurred on the date or for the period indicated, nor do they purport to project
Total revenues
or
Net income (loss) attributable to controlling interests
for any future periods or as of any date. These amounts do not give effect to any potential cost savings, operating synergies, or revenue enhancements to result from the transactions or the potential costs to achieve these cost savings, operating synergies, and revenue enhancements.
|
|
|
|
|
|
|
|
December 31,
|
|
|
2014
|
|
|
(Millions)
|
Total revenues
|
|
$
|
7,953
|
|
Net income (loss) attributable to controlling interests
|
|
$
|
1,376
|
|
Significant adjustments to pro forma
Net income (loss) attributable to controlling interests
include additional depreciation and amortization expense associated with reflecting the acquired investments, property, plant, and equipment, and other intangible assets at fair value. The adjustments assume estimated useful lives of
30 years
.
During the year ended December 31, 2014, ACMP contributed
Total revenues
of
$781 million
and
Net income (loss) attributable to controlling interests
of
$165 million
.
|
|
|
|
Williams Partners L.P.
|
Notes to Consolidated Financial Statements – (Continued)
|
|
Costs incurred by Williams related to this acquisition were
$16 million
in 2014 and are reported within our Central segment and included in
Selling, general, and administrative expenses
in the
Consolidated Statement of Comprehensive Income (Loss)
. Direct transaction costs associated with financing commitments were
$9 million
in 2014 and reported within
Interest incurred
in the
Consolidated Statement of Comprehensive Income (Loss)
.
Eagle Ford Gathering System
In May 2015, we acquired a gathering system comprised of approximately
140
miles of pipeline and a sour gas compression facility in the Eagle Ford Shale, included in our Central segment, for
$112 million
. The acquisition was accounted for as a business combination, and the allocation of the acquisition-date fair value of the major classes of assets acquired includes
$80 million
of
Property, plant, and equipment – net
and
$32 million
of
Intangible assets – net of accumulated amortization
in the
Consolidated Balance Sheet
. Changes to the preliminary allocation disclosed in the second quarter of 2015 reflect an increase of
$20 million
in
Property, plant, and equipment – net
, and a decrease of
$20 million
in
Intangible assets – net of accumulated amortization
.
UEOM Equity-Method Investment
In June 2015, we acquired an additional
13 percent
interest in our equity-method investment, UEOM, for
$357 million
. Following the acquisition we own approximately
62 percent
of UEOM. However, we continue to account for this as an equity-method investment because we do not control UEOM due to the significant participatory rights of our partner. In connection with the acquisition of the additional interest, our general partner agreed to waive approximately
$2 million
of its IDR payments each quarter through 2017. See
Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies
for discussion of agreement with Williams wherein Williams permanently waived IDR payment obligations from us.
Note 3 – Divestiture
In September 2016, we completed the sale of subsidiaries conducting Canadian operations (such subsidiaries, the disposal group). Consideration received to date totaled
$672 million
, net of
$13 million
of cash divested and subject to customary working capital adjustments. Consideration also included
$150 million
in the form of a waiver of incentive distributions otherwise payable to Williams in the fourth quarter of 2016. The waiver recognizes certain affiliate contracts wherein our Canadian operations provided services to Williams. This noncash transaction is reflected as a decrease in
General partner equity
in the
Consolidated Statement of Changes in Equity
. The proceeds were primarily used to reduce borrowings on credit facilities.
During the second quarter of 2016, we designated these operations as held for sale. As a result, we measured the fair value of the disposal group as of June 30, 2016, resulting in an impairment charge of
$341 million
, reflected in
Impairment of certain assets
in the
Consolidated Statement of Comprehensive Income (Loss)
. (See
Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk
.) During the second half of 2016, we recorded an additional loss of
$34 million
at our NGL & Petchem Services segment upon completion of the sale, primarily reflecting revisions to the sales price and including an
$11 million
benefit related to transactions to hedge our foreign currency exchange risk on the Canadian proceeds, reflected in
Other (income) expense – net
within
Costs and expenses
in the
Consolidated Statement of Comprehensive Income (Loss)
.
The following table presents the results of operations for the disposal group, excluding the impairment and loss noted above.
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
2016
|
|
2015
|
|
(Millions)
|
Income (loss) before income taxes of disposal group
|
$
|
(9
|
)
|
|
$
|
6
|
|
|
|
|
|
Williams Partners L.P.
|
Notes to Consolidated Financial Statements – (Continued)
|
|
Note 4 – Variable Interest Entities
As of
December 31, 2016
, we consolidate the following 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 for the Tubular Bells oil and gas discovery 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 construction manager for 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
$687 million
,
which we expect will be funded with capital contributions from us and the other equity partners on a proportional basis.
In December 2014, we received approval from the FERC to construct and operate the Constitution pipeline. However, in April 2016, the New York State Department of Environmental Conservation (NYSDEC) denied a necessary water quality certification for the New York portion of the Constitution pipeline. We remain steadfastly committed to the project, and in May 2016, Constitution appealed the NYSDEC's denial of the certification and filed an action in federal court seeking a declaration that the State of New York's authority to exercise permitting jurisdiction over certain other environmental matters is preempted by federal law. The oral argument before the Second Circuit Court of Appeals regarding the NYSDEC’s denial of Constitution’s application for water quality certification under Section 401 of the Clean Water Act was held on November 16, 2016. We anticipate a decision from the Second Circuit Court of Appeals as early as second quarter 2017. In light of the NYSDEC's denial of the water quality certification and the actions taken to challenge the decision, the project in-service date is targeted as early as the second half of 2018, which assumes that the legal challenge process is satisfactorily and promptly concluded. An unfavorable resolution could result in the impairment of a significant portion of the capitalized project costs, which total
$381 million
on a consolidated basis at December 31, 2016, and are included within
Property, plant, and equipment – net
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.
|
|
|
|
Williams Partners L.P.
|
Notes to Consolidated Financial Statements – (Continued)
|
|
The following table presents amounts included in our
Consolidated Balance Sheet
that are for the use or obligation of our consolidated VIEs:
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2016
|
|
2015
|
|
Classification
|
|
(Millions)
|
|
|
Assets (liabilities):
|
|
|
|
|
|
Cash and cash equivalents
|
$
|
82
|
|
|
$
|
70
|
|
|
Cash and cash equivalents
|
Accounts receivable
|
91
|
|
|
71
|
|
|
Trade accounts and other receivables
|
Prepaid assets
|
3
|
|
|
2
|
|
|
Other current assets and deferred charges
|
Property, plant, and equipment
–
net
|
3,024
|
|
|
3,000
|
|
|
Property, plant, and equipment – net
|
Intangible assets
–
net
|
1,431
|
|
|
1,483
|
|
|
Intangible assets – net of accumulated amortization
|
Accounts payable
|
(44
|
)
|
|
(59
|
)
|
|
Accounts payable – trade
|
Accrued liabilities
|
(3
|
)
|
|
(14
|
)
|
|
Other accrued liabilities
|
Current deferred revenue
|
(63
|
)
|
|
(62
|
)
|
|
Other accrued liabilities
|
Noncurrent asset retirement obligations
|
(99
|
)
|
|
(93
|
)
|
|
Asset retirement obligations
|
Noncurrent deferred revenue associated with customer advance payments
|
(324
|
)
|
|
(331
|
)
|
|
Regulatory liabilities, deferred income, and other
|
|
|
|
|
Williams Partners L.P.
|
Notes to Consolidated Financial Statements – (Continued)
|
|
Note 5 – Allocation of Net Income (Loss) and Distributions
The allocation of net income (loss) among our general partner, limited partners, and noncontrolling interests is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
2016
|
|
2015
|
|
2014
|
|
(Millions)
|
Allocation of net income to general partner:
|
|
|
|
|
|
Net income (loss)
|
$
|
519
|
|
|
$
|
(1,358
|
)
|
|
$
|
1,284
|
|
Net income applicable to pre-merger operations allocated to general partner
|
—
|
|
|
(2
|
)
|
|
(95
|
)
|
Net income applicable to pre-partnership operations allocated to general partner
|
—
|
|
|
—
|
|
|
(15
|
)
|
Net income applicable to noncontrolling interests
|
(88
|
)
|
|
(91
|
)
|
|
(96
|
)
|
Costs charged directly to the general partner
|
1
|
|
|
21
|
|
|
1
|
|
Income (loss) subject to 2% allocation of general partner interest
|
432
|
|
|
(1,430
|
)
|
|
1,079
|
|
General partner’s share of net income
|
2
|
%
|
|
2
|
%
|
|
2
|
%
|
General partner’s allocated share of net income (loss) before items directly allocable to general partner interest
|
9
|
|
|
(29
|
)
|
|
22
|
|
Priority allocations, including incentive distributions, paid to general partner
|
482
|
|
|
638
|
|
|
641
|
|
Pre-merger net income allocated to general partner interest
|
—
|
|
|
2
|
|
|
95
|
|
Pre-partnership net income allocated to general partner interest
|
—
|
|
|
—
|
|
|
15
|
|
Costs charged directly to the general partner
|
(1
|
)
|
|
(21
|
)
|
|
(1
|
)
|
Net income allocated to general partner’s equity
|
$
|
490
|
|
|
$
|
590
|
|
|
$
|
772
|
|
|
|
|
|
|
|
Net income (loss)
|
$
|
519
|
|
|
$
|
(1,358
|
)
|
|
$
|
1,284
|
|
Net income allocated to general partner’s equity
|
490
|
|
|
590
|
|
|
772
|
|
Net income (loss) allocated to Class B limited partners’ equity
|
(2
|
)
|
|
(52
|
)
|
|
—
|
|
Net income allocated to Class D limited partners’ equity (1)
|
—
|
|
|
69
|
|
|
62
|
|
Net income allocated to noncontrolling interests
|
88
|
|
|
91
|
|
|
96
|
|
Net income (loss) allocated to common limited partners’ equity
|
$
|
(57
|
)
|
|
$
|
(2,056
|
)
|
|
$
|
354
|
|
|
|
|
|
|
|
Adjustments to reconcile
Net income (loss) allocated to common limited partners' equity
to
Allocation of net income (loss) to common units:
|
|
|
|
|
|
Incentive distributions paid
|
474
|
|
|
633
|
|
|
640
|
|
Incentive distributions declared
|
(473
|
)
|
|
(423
|
)
|
|
(626
|
)
|
Impact of unit issuance timing and other (2)
|
(42
|
)
|
|
(9
|
)
|
|
(9
|
)
|
Allocation of net income (loss) to common units
|
$
|
(98
|
)
|
|
$
|
(1,855
|
)
|
|
$
|
359
|
|
|
|
|
|
|
|
____________
|
|
(1)
|
Includes amortization of the beneficial conversion feature associated with the Pre-merger WPZ Class D units of
$68 million
and
$49 million
for the years ended December 31, 2015 and 2014, respectively. See following discussion of Class D units.
|
|
|
(2)
|
The 2016 amount includes the effect of units issued and the conversion of the general partner interest in us to a non-economic interest in conjunction with our Financial Repositioning (see
Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies
.)
|
Common Units
On February 10, 2017, we paid a cash distribution of
$0.85
per common unit on our outstanding common units to unitholders of record at the close of business on February 3, 2017.
|
|
|
|
Williams Partners L.P.
|
Notes to Consolidated Financial Statements – (Continued)
|
|
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. During 2016 and 2015 we issued
1,906,001
and
1,058,172
, respectively, of additional paid-in-kind Class B units associated with quarterly distributions. On February 10, 2017, we issued
375,800
Class B units associated with the fourth-quarter 2016 distribution.
Class D Units
As previously mentioned (see
Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies
), a portion of the total consideration for the Canada Acquisition was funded through the issuance of Pre-merger WPZ Class D units to an affiliate of our general partner. The Pre-merger WPZ Class D units were issued at a discount to the market price of Pre-merger WPZ’s common units. The discount represented a beneficial conversion feature and is reflected as an increase in the common unit capital account and a decrease in the Class D capital account on the
Consolidated Statement of Changes in Equity
. This discount was being amortized through the originally expected first quarter 2016 conversion date, resulting in an increase to the Class D capital account and a decrease to the common unit capital account. The remaining unamortized balance was recognized in the first quarter of 2015 due to the ACMP Merger. All Pre-merger WPZ Class D units were converted into common units in conjunction with the ACMP Merger. The Pre-merger WPZ Class D units were not entitled to cash distributions. Instead, prior to conversion into Pre-merger WPZ common units, the Pre-merger WPZ Class D units received quarterly distributions of additional paid-in-kind Pre-merger WPZ Class D units. During 2014, we issued
1,377,893
Pre-merger WPZ Class D units as the paid-in-kind Class D distributions.
Note 6 – Related Party Transactions
Reimbursement of Expenses of Our General Partner
The employees of our operated assets are employees of Williams. Williams directly charges us for the payroll and benefit costs associated with operations employees and carries the obligations for many employee-related benefits in its financial statements, including the liabilities related to employee retirement, medical plans, and paid time off. Our share of the costs is charged to us through affiliate billings and reflected in
Operating and maintenance expenses
in the
Consolidated Statement of Comprehensive Income (Loss)
and
Property, plant, and equipment – net
in the
Consolidated Balance Sheet
.
In addition, employees of Williams provide general and administrative services to us, and we are charged for certain administrative expenses incurred by Williams. These charges are either directly identifiable or allocated to our assets. Direct charges are for goods and services provided by Williams at our request. Allocated charges are based on a three-factor formula, which considers revenues; property, plant, and equipment; and payroll. Our share of direct and allocated administrative expenses is reflected in
Selling, general, and administrative expenses
in the
Consolidated Statement of Comprehensive Income (Loss)
and
Property, plant, and equipment – net
in the
Consolidated Balance Sheet
.
In management’s estimation, the allocation methodologies used are reasonable and result in a reasonable allocation to us of our costs of doing business incurred by Williams.
Transactions with Affiliates and Equity-Method Investees
Service revenues,
in the Consolidated Statement of Comprehensive Income (Loss), includes transportation and fractionation revenues from our expanded NGL/olefins fractionation facility located in Redwater, Alberta. This facility supported Williams’ Horizon liquids extraction plant in Canada until both were sold in September 2016 (see
Note 3 – Divestiture
).
|
|
|
|
Williams Partners L.P.
|
Notes to Consolidated Financial Statements – (Continued)
|
|
Product costs
,
in the
Consolidated Statement of Comprehensive Income (Loss)
, includes charges for the following types of transactions:
|
|
•
|
Purchases of NGLs for resale from Discovery;
|
|
|
•
|
Payments to OPPL for transportation of NGLs from certain natural gas processing plants;
|
|
|
•
|
Purchases of NGLs for resale from Williams’ former Horizon liquids extraction plant in Canada.
|
Summary of the related party transactions discussed in all sections above.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
2016
|
|
2015
|
|
2014
|
|
|
(Millions)
|
Service revenues
|
|
$
|
31
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Product costs
|
|
181
|
|
|
169
|
|
|
186
|
|
Operating and maintenance expenses - employee costs
|
|
470
|
|
|
498
|
|
|
413
|
|
Selling, general, and administrative expenses:
|
|
|
|
|
|
|
Employee direct costs
|
|
344
|
|
|
368
|
|
|
331
|
|
Employee allocated costs
|
|
160
|
|
|
195
|
|
|
171
|
|
HB Construction Company Ltd., a subsidiary of Williams, provided construction services to us until the sale of our Canadian operations in September 2016. Charges for these construction services as well as other capitalized payroll and benefit costs charged by Williams described above were previously capitalized within
Property, plant, and equipment – net
in the
Consolidated Balance Sheet
and totaled
$103 million
and
$187 million
during 2016 and 2015, respectively.
The
Accounts payable — affiliate
in the
Consolidated Balance Sheet
represents the payable positions that result from the transactions with affiliates discussed above. We also have
$19 million
and
$12 million
in
Accounts payable — trade
in the
Consolidated Balance Sheet
with our equity-method investees at December 31, 2016 and 2015, respectively.
Operating Agreements with Equity-Method Investees
We have operating agreements with certain equity-method investees. These operating agreements typically provide for reimbursement or payment to us for certain direct operational payroll and employee benefit costs, materials, supplies, and other charges and also for management services. Williams supplied a portion of these services, primarily those related to employees since we do not have any employees, to certain equity-method investees. The total charges to equity-method investees for these fees are
$66 million
,
$64 million
, and
$65 million
for the years ended December 31, 2016, 2015, and 2014, respectively.
Omnibus Agreement
Under this agreement, Williams is obligated to reimburse us for certain items including (i) maintenance capital expenditure amounts incurred by us or our subsidiaries for certain U.S. Department of Transportation projects, up to a maximum of
$50 million
, and (ii) an amount based on the amortization over time of deferred revenue amounts that relate to cash payments received by Williams prior to the closing of the contribution transaction for services to be rendered by us in the future at the Devils Tower floating production platform. Net amounts received under this agreement for the years ended December 31, 2016, 2015, and 2014 were
$11 million
,
$12 million
, and
$11 million
, respectively.
We have a contribution receivable from our general partner of
$3 million
and
$3 million
at December 31, 2016 and 2015, respectively, for amounts reimbursable to us under omnibus agreements presented within
Total partners’ equity
in the
Consolidated Balance Sheet
.
|
|
|
|
Williams Partners L.P.
|
Notes to Consolidated Financial Statements – (Continued)
|
|
Acquisitions and Equity Issuances
Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies
includes related party transactions for Financial Repositioning, the ACMP Merger, and the Canada Acquisition. The Canadian operations previously participated in Williams’ cash management program under a credit agreement with Williams. Net changes in amounts due to/from Williams prior to the Canada Acquisition are reflected within
Contributions
from The Williams Companies, Inc. - net
within the Consolidated Statement of Changes in Equity.
Note 15 – Partners’ Capital
includes related party transactions for a distribution reinvestment program (DRIP) in November 2016 and a private placement transaction in August 2016.
Board of Directors
A former member of Williams’ Board of Directors, who was elected in 2013 and resigned during 2016, is also the current chairman, president, and chief executive officer of an energy services company that is a customer of ours. We recorded
$144 million
,
$111 million
, and
$115 million
in
Service revenues
in
Consolidated Statement of Comprehensive Income (Loss)
from this company for transportation and storage of natural gas for the years ended December 31, 2016, 2015, and 2014, respectively.
Note 7 – Investing Activities
Impairment of equity-method investments
The following table presents other-than-temporary impairment charges related to certain equity-method investments. (See
Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk
.)
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
2016
|
|
2015
|
|
|
(Millions)
|
Northeast G&P
|
|
|
|
|
Appalachia Midstream Investments
|
|
$
|
294
|
|
|
$
|
562
|
|
Laurel Mountain
|
|
50
|
|
|
45
|
|
UEOM
|
|
—
|
|
|
241
|
|
Central
|
|
|
|
|
DBJV
|
|
59
|
|
|
503
|
|
Ranch Westex
|
|
24
|
|
|
—
|
|
Other
|
|
3
|
|
|
8
|
|
|
|
$
|
430
|
|
|
$
|
1,359
|
|
Equity earnings (losses)
In 2015, we recognized a loss of
$19 million
associated with our share of underlying property impairments at certain of the Appalachia Midstream Investments. This loss is reported within the Northeast G&P segment.
Other investing income (loss) – net
In 2016, we recognized a
$27 million
gain from the sale of an equity-method investment interest in a gathering system that was part of our Appalachia Midstream Investments within the Northeast G&P segment.
|
|
|
|
Williams Partners L.P.
|
Notes to Consolidated Financial Statements – (Continued)
|
|
Investments
|
|
|
|
|
|
|
|
|
|
|
|
Ownership Interest at December 31, 2016
|
|
December 31,
|
|
|
2016
|
|
2015
|
|
|
|
(Millions)
|
Appalachia Midstream Investments
|
(1)
|
|
$
|
2,062
|
|
|
$
|
2,464
|
|
UEOM
|
62%
|
|
1,448
|
|
|
1,525
|
|
DBJV
|
50%
|
|
988
|
|
|
977
|
|
Discovery
|
60%
|
|
572
|
|
|
602
|
|
OPPL
|
50%
|
|
430
|
|
|
445
|
|
Caiman II
|
58%
|
|
426
|
|
|
418
|
|
Laurel Mountain
|
69%
|
|
324
|
|
|
391
|
|
Gulfstream
|
50%
|
|
261
|
|
|
293
|
|
Other
|
Various
|
|
190
|
|
|
221
|
|
|
|
|
$
|
6,701
|
|
|
$
|
7,336
|
|
____________
|
|
(1)
|
Includes equity-method investments in multiple gathering systems in the Marcellus Shale with an approximate average
41 percent
interest.
|
We have differences between the carrying value of our equity-method investments and the underlying equity in the net assets of the investees of
$1.9 billion
at
December 31, 2016
and
$2.4 billion
at December 31, 2015. These differences primarily relate to our investments in Appalachia Midstream Investments, DBJV, and UEOM associated with property, plant, and equipment, as well as customer-based intangible assets and goodwill.
Purchases of and contributions to equity-method investments
We generally fund our portion of significant expansion or development projects of these investees through additional capital contributions. These transactions increased the carrying value of our investments and included:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
2016
|
|
2015
|
|
2014
|
|
(Millions)
|
DBJV
|
$
|
105
|
|
|
$
|
57
|
|
|
$
|
20
|
|
Appalachia Midstream Investments
|
28
|
|
|
93
|
|
|
84
|
|
Caiman II
|
22
|
|
|
—
|
|
|
175
|
|
UEOM
|
—
|
|
|
357
|
|
|
57
|
|
Discovery
|
—
|
|
|
35
|
|
|
106
|
|
Other
|
22
|
|
|
52
|
|
|
26
|
|
|
$
|
177
|
|
|
$
|
594
|
|
|
$
|
468
|
|
Dividends and distributions
The organizational documents of entities in which we have an equity-method interest generally require distribution of available cash to members on at least a quarterly basis. These transactions reduced the carrying value of our investments and included:
|
|
|
|
Williams Partners L.P.
|
Notes to Consolidated Financial Statements – (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
2016
|
|
2015
|
|
2014
|
|
(Millions)
|
Appalachia Midstream Investments
|
$
|
211
|
|
|
$
|
219
|
|
|
$
|
130
|
|
Discovery
|
141
|
|
|
116
|
|
|
36
|
|
Gulfstream
|
100
|
|
|
88
|
|
|
81
|
|
UEOM
|
92
|
|
|
42
|
|
|
—
|
|
OPPL
|
69
|
|
|
45
|
|
|
27
|
|
Caiman II
|
40
|
|
|
33
|
|
|
13
|
|
DBJV
|
39
|
|
|
33
|
|
|
—
|
|
Laurel Mountain
|
28
|
|
|
31
|
|
|
39
|
|
Other
|
22
|
|
|
26
|
|
|
39
|
|
|
$
|
742
|
|
|
$
|
633
|
|
|
$
|
365
|
|
In addition, on September 24, 2015, we received a special distribution of
$396 million
from Gulfstream reflecting our proportional share of the proceeds from new debt issued by Gulfstream. The new debt was issued to refinance Gulfstream’s debt maturities. Subsequently, we contributed
$248 million
and
$148 million
to Gulfstream for our proportional share of amounts necessary to fund debt maturities of
$500 million
due on November 1, 2015 and
$300 million
due on June 1, 2016, respectively.
Summarized Financial Position and Results of Operations of All Equity-Method Investments
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
2016
|
|
2015
|
|
(Millions)
|
Assets (liabilities):
|
|
|
|
Current assets
|
$
|
508
|
|
|
$
|
773
|
|
Noncurrent assets
|
9,695
|
|
|
9,549
|
|
Current liabilities
|
(412
|
)
|
|
(633
|
)
|
Noncurrent liabilities
|
(1,484
|
)
|
|
(1,450
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
2016
|
|
2015
|
|
2014
|
|
(Millions)
|
Gross revenue
|
$
|
1,883
|
|
|
$
|
1,707
|
|
|
$
|
1,623
|
|
Operating income
|
799
|
|
|
690
|
|
|
534
|
|
Net income
|
726
|
|
|
611
|
|
|
460
|
|
|
|
|
|
Williams Partners L.P.
|
Notes to Consolidated Financial Statements – (Continued)
|
|
Note 8 – Other Income and Expenses
The following table presents certain gains or losses reflected in
Other (income) expense – net
within
Costs and expenses
in the
Consolidated Statement of Comprehensive Income (Loss)
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
2016
|
|
2015
|
|
2014
|
|
|
(Millions)
|
Central
|
|
|
|
|
|
|
Loss related to sale of certain assets
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
10
|
|
Northeast G&P
|
|
|
|
|
|
|
Contingency gain settlement (1)
|
|
—
|
|
|
—
|
|
|
(154
|
)
|
Net gain related to partial acreage dedication release
|
|
—
|
|
|
—
|
|
|
(12
|
)
|
Atlantic-Gulf
|
|
|
|
|
|
|
Amortization of regulatory assets associated with asset retirement obligations
|
|
33
|
|
|
33
|
|
|
33
|
|
Accrual of regulatory liability related to overcollection of certain employee expenses
|
|
25
|
|
|
20
|
|
|
14
|
|
Project development costs related to Constitution (Note 4)
|
|
28
|
|
|
—
|
|
|
—
|
|
Gain on asset retirement
|
|
(11
|
)
|
|
—
|
|
|
—
|
|
NGL & Petchem Services
|
|
|
|
|
|
|
Loss on sale of Canadian operations (Note 3)
|
|
34
|
|
|
—
|
|
|
—
|
|
Net foreign currency exchange (gains) losses (2)
|
|
10
|
|
|
(10
|
)
|
|
(3
|
)
|
__________
|
|
(1)
|
In November 2014, we settled a claim arising from the resolution of a contingent gain related to claims associated with the purchase of a business in a prior period. Pursuant to the settlement, we received $154 million in cash, all of which was recognized as a gain in the fourth quarter of 2014.
|
|
|
(2)
|
Primarily relates to gains and losses incurred on foreign currency transactions and the remeasurement of U.S. dollar-denominated current assets and liabilities within our former Canadian operations (see
Note 3 – Divestiture
).
|
ACMP Acquisition, Merger, and Transition
Certain ACMP acquisition, merger, and transition costs included in the
Consolidated Statement of Comprehensive Income (Loss)
are as follows:
|
|
•
|
Selling, general, and administrative expenses
includes
$26 million
in 2015 and
$27 million
in 2014 (including
$16 million
of acquisition costs) primarily related to professional advisory fees within the Central segment.
|
|
|
•
|
Selling, general, and administrative expenses
includes
$9 million
in 2015 and
$15 million
in 2014 of related employee transition costs within the Central segment.
|
|
|
•
|
Operating and maintenance expenses
includes
$12 million
in 2015 and
$15 million
in 2014 primarily related to employee transition costs within the Central segment.
|
|
|
•
|
Interest incurred
includes transaction-related financing costs of
$2 million
in 2015 from the merger and
$9 million
in 2014 from the acquisition.
|
|
|
|
|
Williams Partners L.P.
|
Notes to Consolidated Financial Statements – (Continued)
|
|
Additional Items
Certain additional items included in the
Consolidated Statement of Comprehensive Income (Loss)
are as follows:
|
|
•
|
Service revenues
includes
$173 million
associated with the amortization of deferred income related to the restructuring of certain gas gathering contracts in the Barnett Shale and Mid-Continent regions.
Service revenues
also includes
$58 million
,
$239 million
, and
$167 million
recognized in the fourth quarter of 2016, 2015, and 2014, respectively, from minimum volume commitment fees
in the Barnett Shale and Mid-Continent regions within the Central segment.
|
|
|
•
|
Selling, general, and administrative expenses
and
Operating and maintenance expenses
include
$37 million
in 2016 of severance and other related costs. Amounts by segment
are as follows:
|
|
|
|
|
|
|
Year Ended December 31, 2016
|
|
(Millions)
|
Central
|
$
|
8
|
|
Northeast G&P
|
3
|
|
Atlantic-Gulf
|
8
|
|
West
|
5
|
|
NGL & Petchem Services
|
4
|
|
Other
|
9
|
|
|
|
•
|
Other income (expense) – net
below
Operating income (loss)
includes
$65 million
,
$76 million
,and
$33 million
in 2016, 2015, and 2014, respectively, for equity AFUDC within the Atlantic-Gulf segment.
|
|
|
•
|
Other income (expense) – net
below
Operating income (loss)
includes a
$14 million
gain in 2015 resulting from the early retirement of certain debt.
|
Note 9 – Provision (Benefit) for Income Taxes
The
Provision (benefit) for income taxes
includes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
2016
|
|
2015
|
|
2014
|
|
(Millions)
|
Current:
|
|
|
|
|
|
State
|
$
|
2
|
|
|
$
|
(3
|
)
|
|
$
|
3
|
|
Foreign
|
1
|
|
|
—
|
|
|
1
|
|
|
3
|
|
|
(3
|
)
|
|
4
|
|
Deferred:
|
|
|
|
|
|
State
|
(1
|
)
|
|
(3
|
)
|
|
8
|
|
Foreign
|
(82
|
)
|
|
7
|
|
|
17
|
|
|
(83
|
)
|
|
4
|
|
|
25
|
|
Provision (benefit) for income taxes
|
$
|
(80
|
)
|
|
$
|
1
|
|
|
$
|
29
|
|
|
|
|
|
Williams Partners L.P.
|
Notes to Consolidated Financial Statements – (Continued)
|
|
Reconciliations from the
Provision (benefit) at statutory rate
to recorded
Provision (benefit) for income taxes
are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
2016
|
|
2015
|
|
2014
|
|
(Millions)
|
Provision (benefit) at statutory rate
|
$
|
154
|
|
|
$
|
(475
|
)
|
|
$
|
459
|
|
Increases (decreases) in taxes resulting from:
|
|
|
|
|
|
Income not subject to U.S. federal tax
|
(154
|
)
|
|
475
|
|
|
(459
|
)
|
State income taxes
|
1
|
|
|
(6
|
)
|
|
11
|
|
Foreign operations — net
|
(81
|
)
|
|
7
|
|
|
18
|
|
Provision (benefit) for income taxes
|
$
|
(80
|
)
|
|
$
|
1
|
|
|
$
|
29
|
|
The 2016 foreign deferred benefit includes the tax effect of a
$341 million
impairment associated with the Canadian operations (see
Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk
). The 2015 state deferred benefit includes
$7 million
related to the impact of a Texas franchise tax rate decrease. The 2015 foreign deferred provision includes
$8 million
related to the impact of an Alberta provincial tax rate increase.
Income (loss) before income taxes
includes
$387 million
of foreign loss in 2016, and
$1 million
and
$72 million
of foreign income in
2015
and
2014
, respectively.
Deferred income tax liabilities, primarily attributable to the taxable temporary differences from property, plant, and equipment, were
$20 million
and
$119 million
in
2016
and
2015
, respectively.
Cash payments for income taxes (net of refunds) were
$3 million
in 2016. Cash refunds for income taxes (net of payments) were
$4 million
and
$28 million
in 2015 and 2014, respectively.
As of
December 31, 2016
, we have
no
unrecognized tax benefits.
Tax years after
2012
are subject to examination by the Texas Comptroller. Generally, tax returns for our Canadian entities are open to audit for tax years after
2011
. Tax years 2014 and 2013 are currently under examination. Williams has indemnified us for any adjustments to foreign tax returns filed prior to the Canada Acquisition in 2014. We have indemnified the purchaser of our Canadian operations for any adjustments to foreign tax returns for periods prior to the sale of our Canadian operations in September 2016 (see
Note 3 – Divestiture
).
Note 10 – Benefit Plans
Certain of the benefit costs charged to us by our general partners associated with employees who directly support us are described below. Additionally, allocated corporate expenses from Williams to us also include amounts related to these same employee benefits, which are not included in the amounts presented below. Employees supporting ACMP were not participants in the pension and other postretirement benefit plans sponsored by Williams during 2014. As a result, there are no pension and other postretirement benefit costs included in the 2014 amounts presented below associated with those employees. During 2014, employees supporting ACMP were eligible for defined contribution plans sponsored by the general partner of ACMP. The cost for the employer matching contributions for the period subsequent to July 1, 2014, is included in the defined contribution amount presented below. Effective January 1, 2015, these employees became Williams employees and eligible for certain employee benefit plans sponsored by Williams. Therefore, costs associated with these former ACMP employees are included in the 2015 and 2016 amounts presented below.
Defined Benefit Pension Plans
Williams has noncontributory defined benefit pension plans (Williams Pension Plan, Williams Inactive Employees Pension Plan, and The Williams Companies Retirement Restoration Plan) that provide pension benefits for its eligible
|
|
|
|
Williams Partners L.P.
|
Notes to Consolidated Financial Statements – (Continued)
|
|
employees. Pension costs charged to us by Williams for
2016
,
2015
, and
2014
totaled
$32 million
,
$43 million
, and
$28 million
, respectively. At the total Williams plan level, the pension plans had a projected benefit obligation of
$1.5 billion
at
December 31, 2016
and
2015
. The plans were underfunded by
$212 million
and
$223 million
at
December 31, 2016
and
2015
, respectively.
Postretirement Benefits Other than Pensions
Williams provides subsidized retiree health care and life insurance benefits for certain eligible participants. We recognized a net periodic postretirement benefit credited to us by Williams of
$12 million
,
$12 million
, and
$14 million
in
2016
,
2015
, and
2014
, respectively. At the total Williams plan level, the postretirement benefit plans had an accumulated postretirement benefit obligation of
$197 million
and
$202 million
at
December 31, 2016
and
2015
, respectively. The plans were overfunded by
$11 million
and underfunded by
$1 million
at
December 31, 2016
and
2015
, respectively.
Any differences between the annual expense and amounts currently being recovered in rates by Transco and Northwest Pipeline are recorded as an adjustment to expense and collected or refunded through future rate adjustments.
Defined Contribution Plans
Williams maintains defined contribution plans for the benefit of substantially all of its employees. We were charged compensation expense of
$24 million
,
$27 million
, and
$25 million
in
2016
,
2015
, and
2014
, respectively, for contributions to these plans.
Note 11 – Property, Plant and Equipment
The following table presents nonregulated and regulated
Property, plant, and equipment – net
as presented on the
Consolidated Balance Sheet
for the years ended:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated
|
|
Depreciation
|
|
|
|
|
|
Useful Life (1)
|
|
Rates (1)
|
|
December 31,
|
|
(Years)
|
|
(%)
|
|
2016
|
|
2015
|
|
|
|
|
|
(Millions)
|
Nonregulated:
|
|
|
|
|
|
|
|
Natural gas gathering and processing facilities
|
5 - 40
|
|
|
|
$
|
20,267
|
|
|
$
|
20,636
|
|
Construction in progress
|
Not applicable
|
|
|
|
355
|
|
|
740
|
|
Other
|
3 - 45
|
|
|
|
1,740
|
|
|
1,743
|
|
Regulated:
|
|
|
|
|
|
|
|
Natural gas transmission facilities
|
|
|
1.2 - 6.97
|
|
12,692
|
|
|
12,189
|
|
Construction in progress
|
Not applicable
|
|
Not applicable
|
|
1,603
|
|
|
941
|
|
Other
|
5 - 45
|
|
1.35 - 33.33
|
|
1,590
|
|
|
1,584
|
|
Total property, plant, and equipment, at cost
|
|
|
|
|
$
|
38,247
|
|
|
$
|
37,833
|
|
Accumulated depreciation and amortization
|
|
|
|
|
(10,226
|
)
|
|
(9,233
|
)
|
Property, plant, and equipment – net
|
|
|
|
|
$
|
28,021
|
|
|
$
|
28,600
|
|
_________________
|
|
(1)
|
Estimated useful life and depreciation rates are presented as of
December 31, 2016
. Depreciation rates and estimated useful lives for regulated assets are prescribed by the FERC.
|
Depreciation and amortization expense for
Property, plant, and equipment – net
was
$1,364 million
,
$1,348 million
, and
$944 million
in
2016
,
2015
, and
2014
, respectively.
Regulated
Property, plant, and equipment – net
includes approximately
$665 million
and
$706 million
at
December 31, 2016
and
2015
, respectively, related to amounts in excess of the original cost of the regulated facilities within our gas pipeline businesses as a result of our prior acquisitions. This amount is being amortized over
40 years
using the straight-line amortization method. Current FERC policy does not permit recovery through rates for amounts in excess of original cost of construction.
|
|
|
|
Williams Partners L.P.
|
Notes to Consolidated Financial Statements – (Continued)
|
|
Asset Retirement Obligations
Our accrued obligations relate to underground storage caverns, offshore platforms and pipelines, fractionation and compression facilities, gas gathering well connections and pipelines, and gas transmission pipelines and facilities. At the end of the useful life of each respective asset, we are legally obligated to plug storage caverns and remove any related surface equipment, to restore land and remove surface equipment at gas processing, fractionation, and compression facilities, to dismantle offshore platforms and appropriately abandon offshore pipelines, to cap certain gathering pipelines at the wellhead connection and remove any related surface equipment, and to remove certain components of gas transmission facilities from the ground.
The following table presents the significant changes to our ARO, of which
$798 million
and
$857 million
are included in
Asset retirement obligations
with the remaining portion in
Asset retirement obligations
under
Current liabilities
on the
Consolidated Balance Sheet
at December 31,
2016
and
2015
, respectively.
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
2016
|
|
2015
|
|
(Millions)
|
Beginning balance
|
$
|
914
|
|
|
$
|
831
|
|
Liabilities incurred
|
21
|
|
|
41
|
|
Liabilities settled
|
(8
|
)
|
|
(3
|
)
|
Accretion expense
|
69
|
|
|
60
|
|
Revisions (1)
|
(137
|
)
|
|
(15
|
)
|
Ending balance
|
$
|
859
|
|
|
$
|
914
|
|
______________
|
|
(1)
|
Several factors are considered in the annual review process, including inflation rates, current estimates for removal cost, market risk premiums, discount rates, and the estimated remaining useful life of the assets. The 2016 revisions reflect changes in removal cost estimates, increases in the estimated remaining useful life of certain assets, and decreases in the inflation rate and discount rates used in the annual review process. The 2015 revisions reflect changes in removal cost estimates and the estimated remaining useful life of assets, a decrease in the inflation rate, and increases in the discount rates used in the annual review process.
|
The funds Transco collects through a portion of its rates to fund its ARO are deposited into an external trust account dedicated to funding its ARO (ARO Trust). (See
Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk
.) Under its current rate settlement, Transco’s annual funding obligation is approximately
$36 million
, with installments to be deposited monthly.
|
|
|
|
Williams Partners L.P.
|
Notes to Consolidated Financial Statements – (Continued)
|
|
Note 12 – Goodwill and Other Intangible Assets
Goodwill
Changes in the carrying amount of goodwill, included in
Intangible assets – net of accumulated amortization
, by reportable segment for the periods indicated are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Central
|
|
Northeast G&P
|
|
West
|
|
Total
|
|
(Millions)
|
December 31, 2014
|
$
|
240
|
|
|
$
|
835
|
|
|
$
|
45
|
|
|
$
|
1,120
|
|
Purchase accounting adjustment
|
10
|
|
|
13
|
|
|
2
|
|
|
25
|
|
Impairment
|
(250
|
)
|
|
(848
|
)
|
|
—
|
|
|
(1,098
|
)
|
December 31, 2015
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
47
|
|
|
$
|
47
|
|
December 31, 2016
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
47
|
|
|
$
|
47
|
|
Our goodwill is not subject to amortization, but is evaluated at least annually for impairment or more frequently if impairment indicators are present. We did not identify or recognize any impairments to goodwill in connection with our annual evaluation of goodwill for impairment (performed as of October 1) during the years ended December 31,
2016
and
2014
. During 2015, we performed an interim assessment of goodwill within the Central and Northeast G&P segments as of September 30, 2015, and the annual assessment of goodwill within the Northeast G&P and West segments as of October 1, 2015. The estimated fair value of the reporting units evaluated exceeded their carrying amounts, and thus no impairment was identified. We performed an additional goodwill impairment evaluation as of
December 31, 2015
, of the goodwill recorded within the Central, Northeast G&P, and West segments. As a result of this evaluation, we recorded goodwill impairment charges totaling
$1.098 billion
. (See
Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk
.)
Other Intangible Assets
The gross carrying amount and accumulated amortization of
other intangible assets, included in
Intangible assets – net of accumulated amortization
,
at December 31 are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016
|
|
2015
|
|
Gross Carrying Amount
|
|
Accumulated Amortization
|
|
Gross Carrying Amount
|
|
Accumulated Amortization
|
|
(Millions)
|
Contractual customer relationships
|
$
|
10,634
|
|
|
$
|
(1,019
|
)
|
|
$
|
10,632
|
|
|
$
|
(663
|
)
|
Other intangible assets
primarily relate to gas gathering, processing, and fractionation contractual customer relationships recognized in the ACMP and Eagle Ford acquisitions (see
Note 2 – Acquisitions
) as well as previous acquisitions. Other intangible assets are being amortized on a straight-line basis over an initial period of 30 years which represents a portion of the term over which the contractual customer relationships are expected to contribute to our cash flows.
We expense costs incurred to renew or extend the terms of our gas gathering, processing, and fractionation contracts with customers. Based on the estimated future revenues during the contract periods (as estimated at the time of the respective acquisition), the weighted-average periods prior to the next renewal or extension of the contractual customer relationships associated with the ACMP and Eagle Ford acquisitions were approximately
17 years
and
10 years
, respectively. Although a significant portion of the expected future cash flows associated with these contracts are dependent on our ability to renew or extend the arrangements beyond the initial contract periods, these expected future cash flows are significantly influenced by the scope and pace of our producer customers’ drilling programs. Once
|
|
|
|
Williams Partners L.P.
|
Notes to Consolidated Financial Statements – (Continued)
|
|
producer customers’ wells are connected to our gathering infrastructure, their likelihood of switching to another provider before the wells are abandoned is reduced due to the significant capital investment required.
The amortization expense related to
other intangible assets
was
$356 million
,
$353 million
, and
$207 million
in
2016
,
2015
, and
2014
, respectively. The estimated amortization expense for each of the next five succeeding fiscal years is approximately $356 million.
Note 13 – Other Accrued Liabilities
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
2016
|
|
2015
|
|
(Millions)
|
Deferred income
|
$
|
338
|
|
|
$
|
94
|
|
Refundable deposits
|
160
|
|
|
—
|
|
Special distribution repayable to Gulfstream (See Note 7 - Investing Activities)
|
—
|
|
|
149
|
|
Other, including other loss contingencies
|
306
|
|
|
226
|
|
|
$
|
804
|
|
|
$
|
469
|
|
Deferred income
in 2016 includes cash proceeds associated with restructuring certain gas gathering contracts in the Barnett Shale and Mid-Continent regions. (See
Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies
.)
Refundable deposits
in 2016 includes receipts to resolve several matters in relation to Transco’s Hillabee Expansion Project. In accordance with the agreement, the member–sponsors of Sabal Trail will pay us an aggregate amount of
$240 million
in three equal installments as certain milestones of the project are met, of which
$160 million
was received in 2016. We expect to recognize income associated with these receipts over the term of an underlying contract once the project is in service.
Note 14 – Debt, Banking Arrangements, and Leases
Long-Term Debt
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
2016
|
|
2015
|
|
|
(Millions)
|
Unsecured:
|
|
|
|
|
Transco:
|
|
|
|
|
6.4% Notes due 2016 (1)
|
|
$
|
—
|
|
|
$
|
200
|
|
6.05% Notes due 2018
|
|
250
|
|
|
250
|
|
7.08% Debentures due 2026
|
|
8
|
|
|
8
|
|
7.25% Debentures due 2026
|
|
200
|
|
|
200
|
|
7.85% Notes due 2026
|
|
1,000
|
|
|
—
|
|
5.4% Notes due 2041
|
|
375
|
|
|
375
|
|
4.45% Notes due 2042
|
|
400
|
|
|
400
|
|
Northwest Pipeline:
|
|
|
|
|
7% Notes due 2016
|
|
—
|
|
|
175
|
|
5.95% Notes due 2017
|
|
185
|
|
|
185
|
|
6.05% Notes due 2018
|
|
250
|
|
|
250
|
|
7.125% Debentures due 2025
|
|
85
|
|
|
85
|
|
Williams Partners L.P.:
|
|
|
|
|
7.25% Notes due 2017
|
|
600
|
|
|
600
|
|
5.25% Notes due 2020
|
|
1,500
|
|
|
1,500
|
|
4.125% Notes due 2020
|
|
600
|
|
|
600
|
|
|
|
|
|
Williams Partners L.P.
|
Notes to Consolidated Financial Statements – (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
2016
|
|
2015
|
|
|
(Millions)
|
4% Notes due 2021
|
|
500
|
|
|
500
|
|
3.6% Notes due 2022
|
|
1,250
|
|
|
1,250
|
|
3.35% Notes due 2022
|
|
750
|
|
|
750
|
|
6.125% Notes due 2022
|
|
750
|
|
|
750
|
|
4.5% Notes due 2023
|
|
600
|
|
|
600
|
|
4.875% Notes due 2023
|
|
1,400
|
|
|
1,400
|
|
4.3% Notes due 2024
|
|
1,000
|
|
|
1,000
|
|
4.875% Notes due 2024
|
|
750
|
|
|
750
|
|
3.9% Notes due 2025
|
|
750
|
|
|
750
|
|
4% Notes due 2025
|
|
750
|
|
|
750
|
|
6.3% Notes due 2040
|
|
1,250
|
|
|
1,250
|
|
5.8% Notes due 2043
|
|
400
|
|
|
400
|
|
5.4% Notes due 2044
|
|
500
|
|
|
500
|
|
4.9% Notes due 2045
|
|
500
|
|
|
500
|
|
5.1% Notes due 2045
|
|
1,000
|
|
|
1,000
|
|
Term Loan, variable interest rate, due 2018
|
|
850
|
|
|
850
|
|
Credit facility loans
|
|
—
|
|
|
1,310
|
|
Capital lease obligations
|
|
—
|
|
|
1
|
|
Debt issuance costs
|
|
(90
|
)
|
|
(91
|
)
|
Net unamortized debt premium (discount)
|
|
107
|
|
|
129
|
|
Long-term debt, including current portion
|
|
18,470
|
|
|
19,177
|
|
Long-term debt due within one year
|
|
(785
|
)
|
|
(176
|
)
|
Long-term debt
|
|
$
|
17,685
|
|
|
$
|
19,001
|
|
_____________
|
|
(1)
|
Presented as long-term debt at December 31, 2015, due to Transco’s intent and ability to refinance.
|
The terms of our senior unsecured notes are governed by indentures that contain covenants that, among other things, limit: (1) our ability and the ability of our subsidiaries to create liens securing indebtedness and (2) mergers, consolidations, and sales of assets. The indentures also contain customary events of default, upon which the trustee or the holders of the senior unsecured notes may declare all outstanding senior unsecured notes to be due and payable immediately.
The following table presents aggregate minimum maturities of long-term debt, excluding net unamortized debt premium (discount), debt issuance costs, and capital lease obligations, for each of the next five years:
|
|
|
|
|
|
December 31,
2016
|
|
(Millions)
|
2017
|
$
|
785
|
|
2018
|
1,350
|
|
2019
|
—
|
|
2020
|
2,100
|
|
2021
|
500
|
|
Issuances and retirements
We retired
$600 million
of
7.25 percent
senior unsecured notes that matured on February 1, 2017.
Northwest Pipeline retired
$175 million
of
7 percent
senior unsecured notes that matured on June 15, 2016.
|
|
|
|
Williams Partners L.P.
|
Notes to Consolidated Financial Statements – (Continued)
|
|
Transco retired
$200 million
of
6.4 percent
senior unsecured notes that matured on April 15, 2016.
On January 22, 2016, Transco, issued
$1 billion
of
7.85 percent
senior unsecured notes due 2026 to investors in a private debt placement. In January 2017, Transco completed an exchange of these notes for substantially identical new notes that are registered under the Securities Act of 1933, as amended. Transco used the net proceeds to repay debt and to fund capital expenditures.
In December 2015, we borrowed
$850 million
on a variable interest rate loan with certain lenders due 2018. At December 31, 2016, the interest rate was
2.50 percent
. We used the proceeds for working capital, capital expenditures, and for general partnership purposes.
On April 15, 2015, we paid
$783 million
, including a redemption premium, to early retire
$750 million
of
5.875 percent
senior notes due 2021 with a carrying value of
$797 million
.
On March 3, 2015, we completed a public offering of
$1.25 billion
of
3.6 percent
senior unsecured notes due 2022,
$750 million
of
4 percent
senior unsecured notes due 2025, and
$1 billion
of
5.1 percent
senior unsecured notes due 2045. We used the net proceeds to repay amounts outstanding under our commercial paper program and credit facility, to fund capital expenditures, and for general partnership purposes.
We retired
$750 million
of
3.8 percent
senior unsecured notes that matured on February 15, 2015.
Credit Facilities
|
|
|
|
|
|
|
|
|
|
December 31, 2016
|
|
Available
|
|
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.
|
Long-term credit facilities
Prior to our merger both Pre-merger WPZ and ACMP had separate credit facilities that terminated on February 2, 2015.
On February 2, 2015, we along with Transco, Northwest Pipeline, the lenders named therein and an administrative agent entered into the Second Amended & Restated Credit Agreement with aggregate commitments available of
$3.5 billion
, with up to an additional
$500 million
increase in aggregate commitments available under certain circumstances. The maturity date of the facility is February 2, 2020. However, the co-borrowers may request up to two extensions of the maturity date each for an additional one year period to allow a maturity date as late as February 2, 2022, under certain circumstances. The agreement allows for swing line loans up to an aggregate amount of
$150 million
, subject to available capacity under the credit facility, and letters of credit commitments of
$1.125 billion
. Transco and Northwest Pipeline are each able to borrow up to $500 million under this credit facility to the extent not otherwise utilized by the other co-borrowers. On December 18, 2015, we along with Transco, Northwest Pipeline, the lenders named therein and an administrative agent entered into the Amendment No. 1 to Second Amended & Restated Credit Agreement modifying the thresholds specified in the covenant related to the maximum ratio of our debt to EBITDA.
The agreement governing our credit facility contains the following terms and conditions:
|
|
•
|
Various covenants may limit, among other things, a borrower’s and its material subsidiaries’ ability to grant certain liens supporting indebtedness, merge or consolidate, sell all or substantially all of its assets, enter into
|
|
|
|
|
Williams Partners L.P.
|
Notes to Consolidated Financial Statements – (Continued)
|
|
certain affiliate transactions, make certain distributions during an event of default, enter into certain restrictive agreements, and allow any material change in the nature of its business.
|
|
•
|
If an event of default with respect to a borrower occurs under the credit facility, the lenders will be able to terminate the commitments for all borrowers and accelerate the maturity of any loans of the defaulting borrower under the credit facility agreement and exercise other rights and remedies.
|
|
|
•
|
Other than swing line loans, each time funds are borrowed, the borrower must choose whether such borrowing will be an alternate base rate borrowing or a Eurodollar borrowing. If such borrowing is an alternate base rate borrowing, interest is calculated on the basis of the greater of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus one half of 1 percent and (c) a periodic fixed rate equal to the London Interbank Offered Rate (LIBOR) plus
1 percent
, plus, in the case of each of (a), (b) and (c), an applicable margin. If the borrowing is a Eurodollar borrowing, interest is calculated on the basis of LIBOR for the relevant period plus an applicable margin. Interest on swing line loans is calculated as the sum of the alternate base rate plus an applicable margin. The borrower is required to pay a commitment fee based on the unused portion of the credit facility. The applicable margin and the commitment fee are determined for each borrower by reference to a pricing schedule based on such borrower’s senior unsecured long-term debt ratings.
|
Significant financial covenants under the agreement require the ratio of debt to EBITDA, each as defined in the credit facility, be no greater than:
|
|
•
|
5.75
to 1, for the quarters ending December 31, 2015, March 31, 2016 and June 30, 2016;
|
|
|
•
|
5.50
to 1, for the quarters ending September 30, 2016 and December 31, 2016;
|
|
|
•
|
5.00
to 1, for the quarter ending March 31, 2017 and each subsequent fiscal quarter, except for the the fiscal quarter and the two following fiscal quarters in which one or more acquisitions has been executed, in which case the ratio of debt to EBITDA is to be no greater than
5.5
to 1.
|
The ratio of debt to capitalization (defined as net worth plus debt) must be no greater than
65 percent
for each of Transco and Northwest Pipeline. We are in compliance with these financial covenants as measured at December 31, 2016.
As of February 20, 2017, there are no amounts outstanding under our long-term credit facility.
Short-term credit facility
On August 26, 2015, we entered into a
$1.0 billion
short-term credit facility. On December 23, 2015, the capacity of this facility decreased to
$150 million
in conjunction with entering into the
$850 million
term loan. The
$150 million
short-term credit facility is no longer available as it expired August 24, 2016.
Commercial Paper Program
On February 2, 2015, we amended and restated the commercial paper program for the ACMP Merger and to allow a maximum outstanding amount of unsecured commercial paper notes of
$3 billion
. The maturities of the commercial paper notes vary but may not exceed
397
days from the date of issuance. The commercial paper notes are sold under customary terms in the commercial paper market and are issued at a discount from par, or, alternatively, are sold at par and bear varying interest rates on a fixed or floating basis. Proceeds from these notes are used for general partnership purposes, including funding capital expenditures, working capital, and partnership distributions. We classify commercial paper outstanding in
Current liabilities
in the
Consolidated Balance Sheet
, as the outstanding notes at
December 31, 2016
and
December 31, 2015
, have maturity dates less than three months from the date of issuance. At
December 31, 2016
,
$93 million
of
Commercial paper
was outstanding at a weighted-average interest rate of
1.06 percent
. At
December 31, 2015
,
$499 million
of
Commercial paper
was outstanding at a weighted-average interest rate of
0.92 percent
.
|
|
|
|
Williams Partners L.P.
|
Notes to Consolidated Financial Statements – (Continued)
|
|
Cash Payments for Interest (Net of Amounts Capitalized)
Cash payments for interest (net of amounts capitalized) were
$891 million
in 2016,
$795 million
in 2015, and
$499 million
in 2014.
Leases-Lessee
The future minimum annual rentals under noncancelable operating leases, are payable as follows:
|
|
|
|
|
|
December 31,
2016
|
|
(Millions)
|
2017
|
$
|
48
|
|
2018
|
44
|
|
2019
|
39
|
|
2020
|
34
|
|
2021
|
24
|
|
Thereafter
|
71
|
|
Total
|
$
|
260
|
|
Total rent expense was
$59 million
in 2016,
$62 million
in 2015, and
$55 million
in 2014 and primarily included in
Operating and maintenance expenses
and
Selling, general, and administrative expenses
in the
Consolidated Statement of Comprehensive Income (Loss)
.
Other
On January 25, 2017, we announced that we will redeem all of our
$750 million
6.125 percent
senior notes due 2022 on February 23, 2017.
Note 15 – Partners’ Capital
Financial Repositioning
In January 2017, we announced agreements with Williams, wherein Williams permanently waived the general partner’s IDRs and converted its
2 percent
general partner interest in us to a non-economic 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, following our quarterly distribution in February 2017, Williams paid additional consideration of approximately
$50 million
to us for these units.
Distribution Reinvestment Program and Other Private Placement Transactions
In September 2016, we filed a Form S-3D registration statement with the Securities and Exchange Commission for our new distribution reinvestment program. The DRIP commenced with the quarterly distribution for the quarter ending September 30, 2016. Under the DRIP, registered unitholders may invest all or a portion of their cash distributions in our common units. The price for newly issued common units purchased under the DRIP is the average of the high and low trading prices of our common units for the
five
trading days immediately preceding the distribution, less a discount rate of
2.5 percent
.
The November 2016 distribution resulted in
7,891,414
common units issued at a discounted average price of
$32.92
per share associated with reinvested distributions of
$260 million
, of which
$250 million
related to Williams.
|
|
|
|
Williams Partners L.P.
|
Notes to Consolidated Financial Statements – (Continued)
|
|
In August 2016, we completed an equity issuance of
6,975,446
common units sold to Williams in a private placement. The units were sold for an aggregate purchase price of
$250 million
. The proceeds were used to repay amounts outstanding under our credit facility and for general partnership purposes.
Equity Distribution Agreement Transactions
In November 2016, we issued
3,254,958
common units pursuant to an equity distribution agreement between us and certain banks resulting in net proceeds of
$115 million
. The net proceeds were used for general partnership purposes. We incurred commission fees of approximately
$1.2 million
associated with these transactions.
In January 2016, we issued
18,643
common units pursuant to an equity distribution agreement between us and certain banks. The net proceeds of
$414 thousand
were used for general partnership purposes. We incurred commission fees of
$4 thousand
associated with these transactions.
In November 2015, we issued
1,790,840
common units pursuant to an equity distribution agreement between us and certain banks. The net proceeds of
$59 million
were used for general partnership purposes. We incurred commission fees of
$592 thousand
associated with these transactions.
In August 2014, Pre-merger WPZ issued
1,080,448
Pre-merger WPZ common units pursuant to an equity distribution agreement between Pre-merger WPZ and certain banks. The net proceeds of
$55 million
were used for general partnership purposes. Pre-merger WPZ incurred commission fees of
$554 thousand
associated with these transactions.
Other
In 2014,
Contributions from The Williams Companies, Inc. – net
within the
Consolidated Statement of Changes in Equity
includes the partners’ equity interests in ACMP as of July 1, 2014, presented within the capital account of the general partner for interests owned by Williams and noncontrolling interests for interests held by the public. Additionally, activity associated with the partners’ equity interests in ACMP during the period under common control until the ACMP Merger date has been presented accordingly within the capital account of the general partner for the interests owned by Williams or noncontrolling interests for interests held by the public. (See
Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies
.)
Limited Partners’ Rights
Significant rights of the limited partners include the following:
|
|
•
|
Right to receive distributions of available cash within
45 days
after the end of each quarter.
|
|
|
•
|
No limited partner shall have any management control over our business and affairs; the general partner shall conduct, direct and manage our activities.
|
|
|
•
|
The general partner may be removed if such removal is approved by the unitholders holding at least 66 2/3 percent of the outstanding units voting as a single class, including units held by our general partner and its affiliates.
|
|
|
|
|
Williams Partners L.P.
|
Notes to Consolidated Financial Statements – (Continued)
|
|
Incentive Distribution Rights
Prior to the previously described Financial Repositioning in January 2017, our general partner was entitled to incentive distributions if the amount we distribute to unitholders with respect to any quarter exceeds specified target levels shown below:
|
|
|
|
|
|
|
|
|
|
Total Quarterly Distribution per unit
|
|
Unitholders
|
|
General
Partner
|
Minimum Quarterly Distribution
|
|
$0.3375
|
|
98%
|
|
2%
|
First Target Distribution
|
|
Up to $0.388125
|
|
98
|
|
2
|
Second Target Distribution
|
|
Above $0.388125 up to $0.421875
|
|
85
|
|
15
|
Third Target Distribution
|
|
Above $0.421875 up to $0.50625
|
|
75
|
|
25
|
Thereafter
|
|
Above $0.50625
|
|
50
|
|
50
|
In the event of liquidation, all property and cash in excess of that required to discharge all liabilities will be distributed to the unitholders and our general partner in proportion to their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.
Issuances of Additional Partnership Securities
Our partnership agreement allows us to issue additional partnership securities for any partnership purpose at any time and from time to time for consideration and on terms and conditions as our general partner determines, all without the approval of any limited partners.
Note 16 – Equity-Based Compensation
Williams’ Plan Information
The Williams Companies, Inc. 2007 Incentive Plan (Plan) provides for Williams common-stock-based awards to both employees and nonmanagement directors. The Plan permits the granting of various types of awards including, but not limited to, stock options and restricted stock units. Awards may be granted for no consideration other than prior and future services or based on certain financial performance targets being achieved.
Williams bills us directly for compensation expense related to stock-based compensation awards based on the fair value of the awards.
Operating and maintenance expenses
and
Selling, general, and administrative expenses
include equity-based compensation expense for the years ended December 31,
2016
,
2015
, and
2014
of
$20 million
,
$19 million
and
$14 million
, respectively.
Williams Partners’ Plan Information
During 2014, certain employees of ACMP’s general partner received equity-based compensation through ACMP’s equity-based compensation program. The fair value of the awards issued was based on the fair market value of the common units on the date of grant. This value is being amortized over the vesting period, which is
one
to
four years
from the date of grant. These awards were converted to WPZ equity-based awards in accordance with the terms of the ACMP Merger.
No
additional grants of restricted common units were awarded through Williams Partners’ equity-based compensation programs in 2016 or 2015, and no additional grants are expected in the future.
Operating and maintenance expenses
and
Selling, general, and administrative expenses
include equity-based compensation expense related to Williams Partners’ equity-based compensation program of
$16 million
,
$26 million
, and
$11 million
for the years ended December 31,
2016
,
2015
, and 2014, respectively. As of December 31,
2016
, there was
$11 million
of unrecognized compensation expense attributable to the outstanding awards, which does not include the effect of estimated forfeitures of
$1 million
. These amounts are expected to be recognized over a weighted average period of
1.2 years
.
|
|
|
|
Williams Partners L.P.
|
Notes to Consolidated Financial Statements – (Continued)
|
|
The following summary reflects nonvested restricted common unit activity for awards issued by Williams Partners and related information for the year ended December 31,
2016
:
|
|
|
|
|
|
|
|
Restricted Common Units Outstanding
|
Units
|
|
Weighted-
Average
Fair Value
|
|
(Millions)
|
|
|
Nonvested at December 31, 2015
|
1.2
|
|
|
$
|
55.93
|
|
Forfeited
|
(0.1
|
)
|
|
$
|
52.85
|
|
Vested
|
(0.5
|
)
|
|
$
|
59.09
|
|
Nonvested at December 31, 2016
|
0.6
|
|
|
$
|
52.97
|
|
Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk
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, commercial paper, 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 December 31, 2016:
|
|
|
|
|
|
|
|
|
|
Measured on a recurring basis:
|
|
|
|
|
|
|
|
|
|
ARO Trust investments
|
$
|
96
|
|
|
$
|
96
|
|
|
$
|
96
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Energy derivatives assets designated as hedging instruments
|
2
|
|
|
2
|
|
|
—
|
|
|
2
|
|
|
—
|
|
Energy derivatives assets not designated as hedging instruments
|
1
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
1
|
|
Energy derivatives liabilities not designated as hedging instruments
|
(6
|
)
|
|
(6
|
)
|
|
—
|
|
|
—
|
|
|
(6
|
)
|
Additional disclosures:
|
|
|
|
|
|
|
|
|
|
Other receivables
|
15
|
|
|
15
|
|
|
15
|
|
|
—
|
|
|
—
|
|
Long-term debt, including current portion
|
(18,470
|
)
|
|
(18,907
|
)
|
|
—
|
|
|
(18,907
|
)
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
Assets (liabilities) at December 31, 2015:
|
|
|
|
|
|
|
|
|
|
Measured on a recurring basis:
|
|
|
|
|
|
|
|
|
|
ARO Trust investments
|
$
|
67
|
|
|
$
|
67
|
|
|
$
|
67
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Energy derivatives assets not designated as hedging instruments
|
5
|
|
|
5
|
|
|
—
|
|
|
3
|
|
|
2
|
|
Energy derivatives liabilities not designated as hedging instruments
|
(2
|
)
|
|
(2
|
)
|
|
—
|
|
|
—
|
|
|
(2
|
)
|
Additional disclosures:
|
|
|
|
|
|
|
|
|
|
Other receivables
|
12
|
|
|
12
|
|
|
10
|
|
|
2
|
|
|
—
|
|
Long-term debt, including current portion (1)
|
(19,176
|
)
|
|
(15,988
|
)
|
|
—
|
|
|
(15,988
|
)
|
|
—
|
|
________________
|
|
(1)
|
Excludes capital leases.
|
|
|
|
|
Williams Partners L.P.
|
Notes to Consolidated Financial Statements – (Continued)
|
|
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 that is specifically designated to fund future asset retirement obligations. 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, is classified as available-for-sale, 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 years ended
December 31, 2016
or
2015
.
Additional fair value disclosures
Other receivables
:
Other receivables primarily 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
:
The disclosed fair value of our long-term debt is determined 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.
Nonrecurring fair value measurements
We performed an interim assessment of the goodwill associated with our Central Region and Northeast Region reporting units within the Central and Northeast G&P segments, respectively, as of September 30, 2015. We performed the annual assessment of goodwill associated with our Northeast G&P and West G&P reporting units as of October 1, 2015.
No
impairment charges were required following these evaluations.
During the fourth quarter of 2015, we observed a significant decline in the market values of WPZ and comparable midstream companies within the industry. This served to reduce our estimate of enterprise value and increased our estimates of discount rates. As a result, we performed an impairment assessment as of December 31, 2015, of the goodwill associated with these reporting units.
We estimated the fair value of each reporting unit based on an income approach utilizing discount rates specific to the underlying businesses of each reporting unit. These discount rates considered variables unique to each business area, including equity yields of comparable midstream businesses, expectations for future growth, and customer performance considerations. Weighted-average discount rates utilized ranged from approximately
11 percent
to
13 percent
across the four reporting units.
|
|
|
|
Williams Partners L.P.
|
Notes to Consolidated Financial Statements – (Continued)
|
|
As a result of the increases in discount rates during the fourth quarter of 2015, coupled with certain reductions in estimated future cash flows determined during the same period, the fair values of the Central Region, Northeast Region and Northeast G&P reporting units were determined to be below their respective carrying values. We then calculated the implied fair value of goodwill by performing a hypothetical application of the acquisition method wherein the estimated fair value was allocated to the underlying assets and liabilities of each reporting unit. As a result of these Level 3 measurements, we determined that the previously recorded goodwill associated with each reporting unit was fully impaired, resulting in a fourth-quarter 2015 noncash charge of
$1,098 million
, reflected in
Impairment of goodwill
in the
Consolidated Statement of Comprehensive Income (Loss)
. For the West G&P reporting unit, the estimated fair value exceeded the carrying value and
no
impairment was recorded.
|
|
|
|
Williams Partners L.P.
|
Notes to Consolidated Financial Statements – (Continued)
|
|
The following table presents impairments of assets and investments associated with certain nonrecurring fair value measurements within Level 3 of the fair value hierarchy.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Impairments
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
Classification
|
|
Segment
|
|
Date of Measurement
|
|
Fair Value
|
|
2016
|
|
2015
|
|
2014
|
|
|
|
|
|
|
|
(Millions)
|
Surplus equipment (1)
|
Property, plant, and equipment – net
|
|
Northeast G&P
|
|
June 30, 2014
|
|
$
|
46
|
|
|
|
|
|
|
$
|
17
|
|
Surplus equipment (1)
|
Property, plant, and equipment – net
|
|
Northeast G&P
|
|
December 31, 2014
|
|
32
|
|
|
|
|
|
|
13
|
|
Surplus equipment (1)
|
Property, plant, and equipment – net
|
|
Northeast G&P
|
|
June 30, 2015
|
|
17
|
|
|
|
|
$
|
20
|
|
|
|
Surplus equipment (1)
|
Assets held for sale
|
|
Central
|
|
December 31, 2014
|
|
1
|
|
|
|
|
|
|
12
|
|
Previously capitalized project development costs (2)
|
Property, plant, and equipment – net
|
|
West
|
|
December 31, 2015
|
|
13
|
|
|
|
|
94
|
|
|
|
Canadian operations (3)
|
Assets held for sale
|
|
NGL & Petchem Services
|
|
June 30, 2016
|
|
924
|
|
|
$
|
341
|
|
|
|
|
|
Certain gathering operations (4)
|
Property, plant, and equipment – net
|
|
Central
|
|
June 30, 2016
|
|
18
|
|
|
48
|
|
|
|
|
|
Level 3 fair value measurements of certain assets
|
|
|
|
|
|
|
|
|
389
|
|
|
114
|
|
|
42
|
|
Other impairments and write-downs (5)
|
|
|
|
|
|
|
|
|
68
|
|
|
31
|
|
|
10
|
|
Impairment of certain assets
|
|
|
|
|
|
|
|
|
$
|
457
|
|
|
$
|
145
|
|
|
$
|
52
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity-method investments (6)
|
Investments
|
|
Central and Northeast G&P
|
|
September 30, 2015
|
|
$
|
1,203
|
|
|
|
|
$
|
461
|
|
|
|
Equity-method investments (7)
|
Investments
|
|
Central and Northeast G&P
|
|
December 31, 2015
|
|
4,017
|
|
|
|
|
890
|
|
|
|
Equity-method investments (8)
|
Investments
|
|
Central and Northeast G&P
|
|
March 31, 2016
|
|
1,294
|
|
|
$
|
109
|
|
|
|
|
|
Equity-method investments (9)
|
Investments
|
|
Central and Northeast G&P
|
|
December 31, 2016
|
|
1,295
|
|
|
318
|
|
|
|
|
|
Other equity-method investment
|
Investments
|
|
NGL & Petchem Services
|
|
December 31, 2015
|
|
58
|
|
|
|
|
8
|
|
|
|
Other equity-method investment
|
Investments
|
|
Central
|
|
March 31, 2016
|
|
—
|
|
|
3
|
|
|
|
|
|
Impairment of equity-method investments
|
|
|
|
|
|
|
|
|
$
|
430
|
|
|
$
|
1,359
|
|
|
|
__________________
|
|
(1)
|
Relates to certain surplus equipment. The estimated fair value was determined by a market approach based on our analysis of observable inputs in the principal market.
|
|
|
|
|
Williams Partners L.P.
|
Notes to Consolidated Financial Statements – (Continued)
|
|
|
|
(2)
|
Relates to a gas processing plant, the completion of which is considered remote due to unfavorable impact of low natural gas prices on customer drilling activities. The assessed fair value primarily represents the estimated salvage value of certain equipment measured using a market approach based on our analysis of observable inputs in the principal market.
|
|
|
(3)
|
Relates to our Canadian operations. We designated these operations as held for sale as of June 30, 2016. As a result, we measured the fair value of the disposal group, resulting in an impairment charge. The estimated fair value was determined by a market approach based primarily on inputs received in the marketing process and reflected our estimate of the potential assumed proceeds. We disposed of our Canadian operations through a sale during the third quarter of 2016. See
Note 3 – Divestiture
.
|
|
|
(4)
|
Relates to certain gathering assets within the Mid-Continent region. The estimated fair value was determined by a market approach based on our analysis of observable inputs in the principal market.
|
|
|
(5)
|
Reflects multiple individually insignificant impairments and write-downs of other certain assets that may no longer be in use or are surplus in nature for which the fair value was determined to be zero or an insignificant salvage value.
|
|
|
(6)
|
Relates to equity-method investments in DBJV at Central and certain of the Appalachia Midstream Investments at Northeast G&P. The historical carrying value of these investments was initially recorded based on estimated fair value during the third quarter of 2014 in conjunction with the acquisition of ACMP. We estimated the fair value of these investments using an income approach based on expected future cash flows and appropriate discount rates. The determination of estimated future cash flows involved significant assumptions regarding gathering volumes and related capital spending. Discount rates utilized were
11.8 percent
and
8.8 percent
for DBJV and certain of the Appalachia Midstream Investments, respectively, and reflected our cost of capital as impacted by market conditions, and risks associated with the underlying businesses.
|
|
|
(7)
|
Relates to equity-method investments in DBJV at Central and Northeast G&P’s UEOM and Laurel Mountain investments, as well as certain of the Appalachia Midstream Investments. We estimated the fair value of these investments using an income approach based on expected future cash flows and appropriate discount rates. The determination of estimated future cash flows involved significant assumptions regarding gathering volumes and related capital spending. Discount rates utilized ranged from
10.8 percent
to
14.4 percent
and reflected further fourth-quarter 2015 increases in our cost of capital, revised estimates of expected future cash flows, and risks associated with the underlying businesses.
|
|
|
(8)
|
Relates to Central’s equity-method investment in DBJV and Northeast G&P’s equity-method investment in Laurel Mountain. Our carrying values in these equity-method investments had been written down to fair value at December 31, 2015. Our first-quarter 2016 analysis reflected higher discount rates for both of these investments, along with lower natural gas prices for Laurel Mountain. We estimated the fair value of these investments using an income approach based on expected future cash flows and appropriate discount rates. The determination of estimated future cash flows involved significant assumptions regarding gathering volumes and related capital spending. Discount rates utilized ranged from
13.0 percent
to
13.3 percent
and reflected increases in our cost of capital, revised estimates of expected future cash flows, and risks associated with the underlying businesses.
|
|
|
(9)
|
Relates to equity-method investments in Ranch Westex at Central and multiple Appalachia Midstream Investments at Northeast G&P. The historical carrying value of these investments was initially recorded based on estimated fair value during the third quarter of 2014 in conjunction with the acquisition of ACMP. We estimated the fair value of these Appalachia Midstream Investments using an income approach based on expected future cash flows and appropriate discount rates. The determination of estimated future cash flows involved significant assumptions regarding gathering volumes, rates, and related capital spending. The discount rate utilized for the Appalachia Midstream Investments evaluation was
10.2 percent
and reflected our cost of capital as impacted by market conditions and risks associated with the underlying businesses. In addition to utilizing an income approach, we
|
|
|
|
|
Williams Partners L.P.
|
Notes to Consolidated Financial Statements – (Continued)
|
|
also considered a market approach for certain Appalachia Midstream Investments and Ranch Westex based on an agreement reached in February 2017 to exchange our interests in DBJV and Ranch Westex for additional interests in certain Appalachia Midstream Investments and cash.
Guarantees
We are required by our revolving credit agreements 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.
Concentration of Credit Risk
Cash equivalents
Our cash equivalents are primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government.
Trade accounts and other receivables
The following table summarizes concentration of receivables
, net of allowances.
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
2016
|
|
2015
|
|
(Millions)
|
NGLs, natural gas, and related products and services
|
$
|
736
|
|
|
$
|
821
|
|
Transportation of natural gas and related products
|
187
|
|
|
202
|
|
Other
|
3
|
|
|
3
|
|
Total
|
$
|
926
|
|
|
$
|
1,026
|
|
Customers include producers, distribution companies, industrial users, gas marketers, and pipelines primarily located in the continental United States. As a general policy, collateral is not required for receivables, but customers’ financial condition and credit worthiness are evaluated regularly. Based upon this evaluation, we may obtain collateral to support receivables. As of December 31, 2016 and
2015
, Chesapeake Energy Corporation, and its affiliates (Chesapeake), a customer primarily within our Central, Northeast G&P, and West segments, accounted for
$133 million
and
$364 million
, respectively, of the consolidated
Trade accounts and other receivables
balances.
Revenues
In 2016 and 2015, Chesapeake accounted for
14 percent
and
18 percent
, respectively, of our consolidated revenues.
Note 18 – Contingent Liabilities and Commitments
Environmental Matters
We are a participant in certain environmental activities in various stages including assessment studies, cleanup operations, and 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), and 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
|
|
|
|
Williams Partners L.P.
|
Notes to Consolidated Financial Statements – (Continued)
|
|
of
December 31, 2016
, we have accrued liabilities totaling
$16 million
for these matters, as discussed below. Our accrual reflects the most likely costs of cleanup, which are generally based on completed assessment studies, preliminary results of studies, or our experience with other similar cleanup operations. Certain assessment studies are still in process for which the ultimate outcome may yield significantly different estimates of most likely costs. Any incremental amount in excess of amounts currently accrued cannot be reasonably estimated at this time due to uncertainty about the actual number of contaminated sites ultimately identified, the actual amount and extent of contamination discovered, and the final cleanup standards mandated by the EPA and other governmental authorities.
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, new 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 new rule regarding National Ambient Air Quality Standards for ground-level ozone, setting a new standard of 70 parts per billion. We are monitoring the rule’s implementation and evaluating potential impacts to our operations. For these and other new regulations, we are unable to estimate the costs of asset additions or modifications necessary to comply due to uncertainty created by the 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
December 31, 2016
, we have accrued liabilities of
$9 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
December 31, 2016
, we have accrued liabilities totaling
$7 million
for these costs.
Geismar Incident
On June 13, 2013, an explosion and fire occurred at our Geismar olefins plant and rendered the facility temporarily inoperable (Geismar Incident). As a result, there were two fatalities and numerous individuals (including employees and contractors) reported injuries. We are addressing the following contingent liabilities in connection with the Geismar Incident.
On October 21, 2013, the EPA issued an Inspection Report pursuant to the Clean Air Act’s Risk Management Program following its inspection of the facility on June 24 through June 28, 2013. The report notes the EPA’s preliminary determinations about the facility’s documentation regarding process safety, process hazard analysis, as well as operating procedures, employee training, and other matters. On June 16, 2014, we received a request for information related to the Geismar Incident from the EPA under Section 114 of the Clean Air Act to which we responded on August 13, 2014. The EPA could issue penalties pertaining to final determinations.
Multiple lawsuits, including class actions for alleged offsite impacts, property damage, customer claims, and personal injury, have been filed against us. To date, we have settled certain of the personal injury claims for an aggregate immaterial amount that we have recovered from our insurers. The first two trials, for nine plaintiffs claiming personal injury, were held in Louisiana state court in Iberville Parish, Louisiana, in September and November 2016. The juries returned adverse verdicts against Williams, our subsidiary Williams Olefins, LLC, and other defendants. The defendants, including us, intend to appeal the verdicts. Trial dates for additional plaintiffs are scheduled in April 2017 and August 2017. We believe it is probable that additional losses will be incurred on some lawsuits, while for others we believe it is only reasonably possible that losses will be incurred. However, due to ongoing litigation involving defenses to liability, the number of individual plaintiffs, limited information as to the nature and extent of all plaintiffs’ damages, and the ultimate outcome of all appeals, we are unable to reliably estimate any such losses at this time. We believe that it is
|
|
|
|
Williams Partners L.P.
|
Notes to Consolidated Financial Statements – (Continued)
|
|
probable that any ultimate losses incurred will be covered by our general liability insurance policy, which has an aggregate limit of
$610 million
applicable to this event and retention (deductible) of
$2 million
per occurrence.
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 in Texas, Pennsylvania, and Ohio based on allegations that we improperly participated with that major customer in causing the alleged royalty underpayments. We have also received subpoenas from the United States Department of Justice and the Pennsylvania Attorney General requesting documents relating to the agreements between us and our major customer and calculations of the major customer’s royalty payments. On December 9, 2015, the Pennsylvania Attorney General filed a civil suit against one of our major customers and us alleging breaches of the Pennsylvania Unfair Trade Practices and Consumer Protection Law, and on February 8, 2016, the Pennsylvania Attorney General filed an amended complaint in such civil suit, which omitted us as a party. We believe that the claims asserted are subject to indemnity obligations owed to us by that major customer. Our customer and plaintiffs in the Texas cases reached a settlement, and therefore all claims asserted (or possibly asserted) by any such plaintiffs against us in the Texas cases have been fully dismissed with prejudice. On February 7, 2017, the plaintiffs in the Ohio case voluntarily dismissed the case without prejudice. Due to the preliminary status of the remaining cases, we are unable to estimate a range of potential loss at this time.
Stockholder 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 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 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. 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.
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.
Commitments
Commitments for construction and acquisition of property, plant, and equipment are approximately
$244 million
at
December 31, 2016
.
Note 19 – Segment Disclosures
Our reportable segments are Central, Northeast G&P, Atlantic-Gulf, West, and NGL & Petchem Services. (See
Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies
.)
|
|
|
|
Williams Partners L.P.
|
Notes to Consolidated Financial Statements – (Continued)
|
|
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 geographic area data includes
Revenues from external customers
based on product shipment origin and
Long-lived assets
based upon physical location:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
Canada
|
|
Total
|
|
|
|
(Millions)
|
Revenues from external customers:
|
|
|
|
|
|
|
|
2016
|
|
$
|
7,406
|
|
|
$
|
85
|
|
|
$
|
7,491
|
|
|
2015
|
|
7,228
|
|
|
103
|
|
|
7,331
|
|
|
2014
|
|
7,212
|
|
|
197
|
|
|
7,409
|
|
|
|
|
|
|
|
|
|
Long-lived assets:
|
|
|
|
|
|
|
|
2016
|
|
$
|
37,683
|
|
|
$
|
—
|
|
|
$
|
37,683
|
|
|
2015
|
|
37,586
|
|
|
1,030
|
|
|
38,616
|
|
|
2014
|
|
37,798
|
|
|
1,095
|
|
|
38,893
|
|
Long-lived assets
are comprised of property, plant, and equipment, goodwill, and other intangible assets.
|
|
|
|
Williams Partners L.P.
|
Notes to Consolidated Financial Statements – (Continued)
|
|
The following table reflects the reconciliation of
Segment revenues
to
Total
revenues
as reported in the
Consolidated Statement of Comprehensive Income (Loss)
and
Other financial information
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Central
|
|
Northeast
G&P
|
|
Atlantic-
Gulf
|
|
West
|
|
NGL &
Petchem
Services
|
|
Eliminations
|
|
Total
|
|
(Millions)
|
2016
|
Segment revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
|
$
|
1,228
|
|
|
$
|
804
|
|
|
$
|
1,939
|
|
|
$
|
1,034
|
|
|
$
|
168
|
|
|
$
|
—
|
|
|
$
|
5,173
|
|
Internal
|
13
|
|
|
34
|
|
|
13
|
|
|
—
|
|
|
—
|
|
|
(60
|
)
|
|
—
|
|
Total service revenues
|
1,241
|
|
|
838
|
|
|
1,952
|
|
|
1,034
|
|
|
168
|
|
|
(60
|
)
|
|
5,173
|
|
Product sales
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
|
—
|
|
|
135
|
|
|
244
|
|
|
18
|
|
|
1,921
|
|
|
—
|
|
|
2,318
|
|
Internal
|
—
|
|
|
28
|
|
|
205
|
|
|
260
|
|
|
181
|
|
|
(674
|
)
|
|
—
|
|
Total product sales
|
—
|
|
|
163
|
|
|
449
|
|
|
278
|
|
|
2,102
|
|
|
(674
|
)
|
|
2,318
|
|
Total revenues
|
$
|
1,241
|
|
|
$
|
1,001
|
|
|
$
|
2,401
|
|
|
$
|
1,312
|
|
|
$
|
2,270
|
|
|
$
|
(734
|
)
|
|
$
|
7,491
|
|
Other financial information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proportional Modified EBITDA of equity-method investments
|
$
|
48
|
|
|
$
|
362
|
|
|
$
|
287
|
|
|
$
|
—
|
|
|
$
|
57
|
|
|
$
|
—
|
|
|
$
|
754
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015
|
|
|
|
|
Segment revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
|
$
|
1,261
|
|
|
$
|
803
|
|
|
$
|
1,877
|
|
|
$
|
1,055
|
|
|
$
|
139
|
|
|
$
|
—
|
|
|
$
|
5,135
|
|
Internal
|
26
|
|
|
7
|
|
|
4
|
|
|
—
|
|
|
—
|
|
|
(37
|
)
|
|
—
|
|
Total service revenues
|
1,287
|
|
|
810
|
|
|
1,881
|
|
|
1,055
|
|
|
139
|
|
|
(37
|
)
|
|
5,135
|
|
Product sales
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
|
—
|
|
|
109
|
|
|
287
|
|
|
36
|
|
|
1,764
|
|
|
—
|
|
|
2,196
|
|
Internal
|
—
|
|
|
18
|
|
|
176
|
|
|
221
|
|
|
157
|
|
|
(572
|
)
|
|
—
|
|
Total product sales
|
—
|
|
|
127
|
|
|
463
|
|
|
257
|
|
|
1,921
|
|
|
(572
|
)
|
|
2,196
|
|
Total revenues
|
$
|
1,287
|
|
|
$
|
937
|
|
|
$
|
2,344
|
|
|
$
|
1,312
|
|
|
$
|
2,060
|
|
|
$
|
(609
|
)
|
|
$
|
7,331
|
|
Other financial information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proportional Modified EBITDA of equity-method investments
|
$
|
36
|
|
|
$
|
349
|
|
|
$
|
257
|
|
|
$
|
—
|
|
|
$
|
42
|
|
|
$
|
15
|
|
|
$
|
699
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
|
$
|
666
|
|
|
$
|
549
|
|
|
$
|
1,497
|
|
|
$
|
1,050
|
|
|
$
|
126
|
|
|
$
|
—
|
|
|
$
|
3,888
|
|
Internal
|
12
|
|
|
1
|
|
|
4
|
|
|
—
|
|
|
—
|
|
|
(17
|
)
|
|
—
|
|
Total service revenues
|
678
|
|
|
550
|
|
|
1,501
|
|
|
1,050
|
|
|
126
|
|
|
(17
|
)
|
|
3,888
|
|
Product sales
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
|
—
|
|
|
225
|
|
|
499
|
|
|
70
|
|
|
2,727
|
|
|
—
|
|
|
3,521
|
|
Internal
|
—
|
|
|
5
|
|
|
354
|
|
|
476
|
|
|
259
|
|
|
(1,094
|
)
|
|
—
|
|
Total product sales
|
—
|
|
|
230
|
|
|
853
|
|
|
546
|
|
|
2,986
|
|
|
(1,094
|
)
|
|
3,521
|
|
Total revenues
|
$
|
678
|
|
|
$
|
780
|
|
|
$
|
2,354
|
|
|
$
|
1,596
|
|
|
$
|
3,112
|
|
|
$
|
(1,111
|
)
|
|
$
|
7,409
|
|
Other financial information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proportional Modified EBITDA of equity-method investments
|
$
|
25
|
|
|
$
|
198
|
|
|
$
|
151
|
|
|
$
|
—
|
|
|
$
|
50
|
|
|
$
|
7
|
|
|
$
|
431
|
|
|
|
|
|
Williams Partners L.P.
|
Notes to Consolidated Financial Statements – (Continued)
|
|
The following table reflects the reconciliation of
Modified EBITDA
to
Net income (loss)
as reported in the
Consolidated Statement of Comprehensive Income (Loss)
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
2016
|
|
2015
|
|
2014
|
|
|
|
|
|
(Millions)
|
Modified EBITDA by segment:
|
|
|
|
|
|
Central
|
$
|
807
|
|
|
$
|
840
|
|
|
$
|
419
|
|
Northeast G&P
|
840
|
|
|
753
|
|
|
618
|
|
Atlantic-Gulf
|
1,600
|
|
|
1,523
|
|
|
1,065
|
|
West
|
649
|
|
|
557
|
|
|
823
|
|
NGL & Petchem Services
|
(23
|
)
|
|
321
|
|
|
324
|
|
Other
|
(9
|
)
|
|
9
|
|
|
(5
|
)
|
|
3,864
|
|
|
4,003
|
|
|
3,244
|
|
Accretion expense associated with asset retirement obligations for nonregulated operations
|
(31
|
)
|
|
(28
|
)
|
|
(17
|
)
|
Depreciation and amortization expenses
|
(1,720
|
)
|
|
(1,702
|
)
|
|
(1,151
|
)
|
Impairment of goodwill
|
—
|
|
|
(1,098
|
)
|
|
—
|
|
Equity earnings (losses)
|
397
|
|
|
335
|
|
|
228
|
|
Impairment of equity-method investments
|
(430
|
)
|
|
(1,359
|
)
|
|
—
|
|
Other investing income (loss) – net
|
29
|
|
|
2
|
|
|
2
|
|
Proportional Modified EBITDA of equity-method investments
|
(754
|
)
|
|
(699
|
)
|
|
(431
|
)
|
Interest expense
|
(916
|
)
|
|
(811
|
)
|
|
(562
|
)
|
(Provision) benefit for income taxes
|
80
|
|
|
(1
|
)
|
|
(29
|
)
|
Net income (loss)
|
$
|
519
|
|
|
$
|
(1,358
|
)
|
|
$
|
1,284
|
|
The following table reflects
Total assets
,
Investments
,
and
Additions to long-lived assets
by reportable segments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Assets at December 31,
|
|
Investments at December 31,
|
|
Additions to Long-Lived Assets at December 31,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
2014
|
|
(Millions)
|
Central (1)
|
$
|
13,129
|
|
|
$
|
13,914
|
|
|
$
|
1,033
|
|
|
$
|
1,050
|
|
|
$
|
88
|
|
|
$
|
363
|
|
|
$
|
13,016
|
|
Northeast G&P (1)
|
13,324
|
|
|
13,827
|
|
|
4,289
|
|
|
4,823
|
|
|
217
|
|
|
560
|
|
|
4,497
|
|
Atlantic-Gulf
|
13,892
|
|
|
12,171
|
|
|
893
|
|
|
959
|
|
|
1,590
|
|
|
1,573
|
|
|
1,593
|
|
West (1)
|
4,715
|
|
|
5,035
|
|
|
—
|
|
|
—
|
|
|
124
|
|
|
225
|
|
|
698
|
|
NGL & Petchem Services
|
2,304
|
|
|
3,306
|
|
|
486
|
|
|
504
|
|
|
83
|
|
|
236
|
|
|
601
|
|
Other corporate assets
|
207
|
|
|
350
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3
|
|
|
8
|
|
Eliminations (2)
|
(1,306
|
)
|
|
(733
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total
|
$
|
46,265
|
|
|
$
|
47,870
|
|
|
$
|
6,701
|
|
|
$
|
7,336
|
|
|
$
|
2,102
|
|
|
$
|
2,960
|
|
|
$
|
20,413
|
|
|
|
(1)
|
2014
Additions to long-lived assets
includes the acquisition-date fair value of long-lived assets from the ACMP Acquisition (
Note 2 – Acquisitions
).
|
|
|
(2)
|
Eliminations primarily relate to the intercompany accounts receivable generated by our cash management program.
|
|
|
|
|
Williams Partners L.P.
|
Quarterly Financial Data
|
(Unaudited)
|
Summarized quarterly financial data are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First
Quarter
|
|
Second
Quarter
|
|
Third
Quarter
|
|
Fourth
Quarter
|
|
|
(Millions, except per-unit amounts)
|
2016
|
|
|
|
|
|
|
|
|
Revenues (1)
|
|
$
|
1,654
|
|
|
$
|
1,740
|
|
|
$
|
1,907
|
|
|
$
|
2,190
|
|
Product costs (1)
|
|
317
|
|
|
403
|
|
|
463
|
|
|
545
|
|
Net income (loss)
|
|
79
|
|
|
(77
|
)
|
|
351
|
|
|
166
|
|
Net income (loss) attributable to controlling interests
|
|
50
|
|
|
(90
|
)
|
|
326
|
|
|
145
|
|
Net income (loss) allocated to common units for calculation of earnings per common unit (2)
|
|
(148
|
)
|
|
(289
|
)
|
|
247
|
|
|
143
|
|
Basic and diluted net income (loss) per common unit (3)
|
|
(.25
|
)
|
|
(.49
|
)
|
|
.42
|
|
|
.24
|
|
2015
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
1,711
|
|
|
$
|
1,830
|
|
|
$
|
1,792
|
|
|
$
|
1,998
|
|
Product costs
|
|
463
|
|
|
494
|
|
|
426
|
|
|
396
|
|
Net income (loss)
|
|
112
|
|
|
332
|
|
|
(167
|
)
|
|
(1,635
|
)
|
Net income (loss) attributable to controlling interests
|
|
89
|
|
|
300
|
|
|
(194
|
)
|
|
(1,644
|
)
|
Net income (loss) allocated to common units for calculation of earnings per common unit (2)
|
|
(172
|
)
|
|
83
|
|
|
(190
|
)
|
|
(1,577
|
)
|
Basic and diluted net income (loss) per common unit (3)
|
|
(.34
|
)
|
|
.14
|
|
|
(.32
|
)
|
|
(2.68
|
)
|
________________
|
|
(1)
|
Amounts reported for second quarter 2016 have been adjusted to reflect the presentation of certain revenues and costs on a gross basis. These adjustments increased previously reported
Revenues
and
Product costs
by $10 million, with no impact on
Operating income (loss)
.
|
|
|
(2)
|
The sum of
Net income (loss) allocated to common units for calculation of earnings per common unit
for the four quarters may not equal the total for the year due to timing of unit issuances.
|
|
|
(3)
|
The sum of
Net income (loss) per common unit
for the four quarters may not equal the total for the year due to changes in the average number of common units outstanding and rounding.
|
2016
Net income (loss)
for fourth-quarter 2016 includes:
|
|
•
|
$173 million of income associated with the amortization of deferred income related to the restructuring of certain gas gathering contracts in the Barnett Shale and Mid-Continent regions and $58 million of related minimum volume commitment fees (see
Note 8 – Other Income and Expenses
of Notes to Consolidated Financial Statements);
|
|
|
•
|
$318 million impairment loss on certain equity-method investments (see
Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk
).
|
Net income (loss)
for second-quarter 2016 includes a $341 million impairment loss on Canadian assets (see
Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk
).
Net income (loss)
for first-quarter 2016 includes a $112 million impairment loss on equity-method investments (see
Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk
).
|
|
|
|
Williams Partners L.P.
|
Quarterly Financial Data – (Continued)
|
(Unaudited)
|
2015
Net income (loss)
for fourth-quarter 2015 includes:
|
|
•
|
$239 million in revenue associated with minimum volume commitment fees in the Barnett Shale and Mid-Continent regions (see
Note 8 – Other Income and Expenses
);
|
|
|
•
|
$116 million impairment loss on certain assets (see
Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk
);
|
|
|
•
|
$898 million impairment loss on certain equity-method investments (see
Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk
);
|
|
|
•
|
$1,098 million impairment of goodwill (see
Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk
).
|
Net income (loss)
for third-quarter 2015 includes a $461 million impairment loss on certain equity-method investments (see
Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk
).
Net income (loss)
for second-quarter 2015 includes a $126 million gain associated with insurance recoveries related to the Geismar Incident.