Exhibit 99.1
DEFINITIONS
The following is a listing of certain abbreviations, acronyms and other industry terminology used throughout this Exhibit 99.1.
Measurements:
Barrel: One barrel of petroleum products that equals 42 U.S. gallons
BPD: Barrels per day
Bcf : One billion cubic feet of natural gas
Bcf/d: One billion cubic feet of natural gas per day
British Thermal Unit (Btu): A unit of energy needed to raise the temperature of one pound of water by one degree
Fahrenheit
Dekatherms (Dth): A unit of energy equal to one million British thermal units
Mbbls/d: One thousand barrels per day
Mdth/d: One thousand dekatherms per day
MMcf/d: One million cubic feet per day
MMdth: One million dekatherms or approximately one trillion British thermal units
MMdth/d: One million dekatherms per day
TBtu: One trillion British thermal units
Consolidated Entities:
Bluegrass Pipeline: Bluegrass Pipeline Company LLC
Constitution: Constitution Pipeline Company, LLC
Gulfstar One: Gulfstar One LLC
Northwest Pipeline: Northwest Pipeline LLC
Transco: Transcontinental Gas Pipe Line Company, LLC
WPZ: Williams Partners L.P.
Partially Owned Entities: Entities in which we do not own a 100 percent ownership interest and which we account
for as an equity investment, including principally the following:
Access GP: Access Midstream Partners GP, L.L.C.
Access Midstream Partners: Access GP and ACMP
Accroven: Accroven SRL
ACMP: Access Midstream Partners, L.P.
Aux Sable: Aux Sable Liquid Products LP
Caiman II: Caiman Energy II, LLC
Discovery: Discovery Producer Services LLC
Gulfstream: Gulfstream Natural Gas System, L.L.C.
Laurel Mountain: Laurel Mountain Midstream, LLC
OPPL: Overland Pass Pipeline Company LLC
Government and Regulatory:
Code, the: Internal Revenue Code of 1986
EPA: Environmental Protection Agency
Exchange Act, the: Securities and Exchange Act of 1934, as amended
FERC: Federal Energy Regulatory Commission
IRS: Internal Revenue Service
SEC: Securities and Exchange Commission
Other:
B/B Splitter: Butylene/Butane splitter
Caiman Acquisition: WPZ’s April 2012 purchase of 100 percent of Caiman Eastern Midstream, LLC located in
the Ohio River Valley area of the Marcellus Shale region
DAC: Debutanized aromatic concentrate
Fractionation: The process by which a mixed stream of natural gas liquids is separated into its constituent products,
such as ethane, propane, and butane
IDR: Incentive distribution right
Laser Acquisition: WPZ’s February 2012 purchase from Delphi Midstream Partners, LLC of 100 percent of
certain entities that operate in Susquehanna County, PA and southern New York
LNG: Liquefied natural gas; natural gas which has been liquefied at cryogenic temperatures
NGLs: Natural gas liquids; natural gas liquids result from natural gas processing and crude oil refining and are
used as petrochemical feedstocks, heating fuels, and gasoline additives, among other applications
NGL margins: NGL revenues less Btu replacement cost, plant fuel, transportation, and fractionation
Throughput: The volume of product transported or passing through a pipeline, plant, terminal, or other facility
Item 6. Selected Financial Data
The following financial data at December 31, 2013 and 2012, and for each of the three years in the period ended December 31, 2013, should be read in conjunction with the other financial information included in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 8, Financial Statements and Supplementary Data of this Exhibit 99.1. All other financial data has been prepared from our accounting records.
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| | | | | | | | | | | | | | | | | | | |
| | 2013 | | 2012 | | 2011 | | 2010 | | 2009 |
| | (Millions, except per-share amounts) |
| Revenues | $ | 6,860 |
| | $ | 7,486 |
| | $ | 7,930 |
| | $ | 6,638 |
| | $ | 5,278 |
|
| Income (loss) from continuing operations (1) | 679 |
| | 929 |
| | 1,078 |
| | 271 |
| | 346 |
|
| Amounts attributable to The Williams Companies, Inc.: | | | | | | | | | |
| Income (loss) from continuing operations (1) | 441 |
| | 723 |
| | 803 |
| | 104 |
| | 206 |
|
| Diluted earnings (loss) per common share: | | | | | | | | | |
| Income (loss) from continuing operations (1) | 0.64 |
| | 1.15 |
| | 1.34 |
| | 0.17 |
| | 0.35 |
|
| Total assets at December 31 (2) (3) | 27,142 |
| | 24,327 |
| | 16,502 |
| | 24,972 |
| | 25,280 |
|
| Commercial paper and long-term debt due within one year at December 31 (4) | 226 |
| | 1 |
| | 353 |
| | 508 |
| | 17 |
|
| Long-term debt at December 31 (3) | 11,353 |
| | 10,735 |
| | 8,369 |
| | 8,600 |
| | 8,259 |
|
| Stockholders’ equity at December 31 (2) (3) | 4,864 |
| | 4,752 |
| | 1,296 |
| | 6,803 |
| | 7,990 |
|
| Cash dividends declared per common share | 1.438 |
| | 1.196 |
| | 0.775 |
| | 0.485 |
| | 0.44 |
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_________
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| (1) | Income from continuing operations for 2013 includes $99 million of deferred income tax expense incurred on undistributed earnings of our foreign operations that are no longer considered permanently reinvested. 2011 includes $271 million of pre-tax early debt retirement costs, and 2010 includes $648 million of debt retirement and other pre-tax costs associated with our strategic restructuring transaction in the first quarter of 2010. |
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| (2) | Total assets and stockholders’ equity for 2011 decreased due to the special dividend to spin off our former exploration and production business. |
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| (3) | The increases in 2012 reflect assets and investments acquired, primarily related to the Caiman and Laser Acquisitions and our investment in Access Midstream Partners, as well as debt and equity issuances. |
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| (4) | The increase in 2013 reflects borrowings under WPZ’s commercial paper program initiated in 2013. |
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
General
We are an energy infrastructure company focused on connecting North America’s significant hydrocarbon resource plays to growing markets for natural gas, NGLs, and olefins. Our operations are located principally in the United States, but span from the deepwater Gulf of Mexico to the Canadian oil sands, and are organized into the Williams Partners, Williams NGL & Petchem Services, and Access Midstream Partners reportable segments. All remaining business activities are included in Other.
Williams Partners
Williams Partners includes WPZ, our consolidated master limited partnership, which includes two interstate natural gas pipelines, as well as investments in natural gas pipeline-related companies, which serve regions from the San Juan basin in northwestern New Mexico and southwestern Colorado to Oregon and Washington and from the Gulf of Mexico to the northeastern United States. WPZ also includes natural gas gathering, processing, and treating facilities and oil gathering and transportation facilities located primarily in the Rocky Mountain, Gulf Coast, and Marcellus Shale regions of the United States. WPZ also owns a 5/6 interest in an olefin production facility, along with a refinery grade propylene splitter and pipelines in the Gulf region, an oil sands offgas processing plant near Fort McMurray, Alberta, and an NGL/olefin fractionation facility and B/B splitter facility at Redwater, Alberta.
As of December 31, 2013, we own approximately 64 percent of the interests in WPZ, including the interests of the general partner, which is wholly owned by us, and IDRs. As of March 31, 2014, following the Canada Dropdown, we own approximately 66 percent of the interests in WPZ, including the interests of the general partner, and IDRs.
Williams Partners’ ongoing strategy is to safely and reliably operate large-scale, interstate natural gas transmission and midstream infrastructures 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 and utilizing our low cost-of-capital to invest in growing markets, including the deepwater Gulf of Mexico, the Marcellus Shale, the Gulf Coast Region, the Canadian oil sands, and areas of increasing natural gas demand.
Williams Partners’ interstate transmission and related 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 little near-term impact on revenues because the majority of cost of service is recovered through firm capacity reservation charges in transportation rates.
Williams NGL & Petchem Services
Williams NGL & Petchem Services includes certain other domestic olefins pipeline assets, certain Canadian growth projects under development, including a propane dehydrogenation facility and a liquids extraction plant, as well as the proposed Bluegrass Pipeline joint project (see Note 19 – Subsequent Events of Notes to Consolidated Financial Statements for more information regarding recent developments related to Bluegrass Pipeline). As discussed in Note 1 – Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies of Notes to Consolidated Financial Statements, the currently operating Canadian assets were contributed to Williams Partners in the first quarter of 2014 and are now presented in the Williams Partners segment. As a result, the Williams NGL & Petchem Services segment is currently comprised primarily of projects under development and thus has no operating revenues to date.
Access Midstream Partners
Access Midstream Partners includes our equity method investment in ACMP, acquired in December 2012. As of December 31, 2013, this investment includes a 23 percent limited partner interest in ACMP and a 50 percent indirect interest in Access GP, including incentive distribution rights. ACMP is a publicly traded master limited partnership that owns, operates, develops, and acquires natural gas gathering systems and other midstream energy assets, which bolsters
our position in the Marcellus and Utica shale plays and adds diversity via the Eagle Ford, Haynesville, Barnett, Mid-Continent, and Niobrara areas.
Unless indicated otherwise, the following discussion and analysis of critical accounting estimates, results of operations, and financial condition and liquidity relates to our current continuing operations and should be read in conjunction with the consolidated financial statements and notes thereto included in Part II, Item 8 of this document.
Canada Dropdown
On February 28, 2014, we contributed certain of our Canadian operations to WPZ, including an oil sands offgas processing plant near Fort McMurray, Alberta, and an NGL/olefin fractionation facility and B/B splitter facility at Redwater, Alberta. These businesses were previously reported within our Williams NGL & Petchem Services segment, but are now reported within Williams Partners. Prior period segment disclosures have been recast for this transaction. WPZ funded the transaction with $25 million of cash (subject to certain closing adjustments), the issuance of 25,577,521 Class D limited-partner units, and an increase in the capital account of its general partner to allow us to maintain our 2 percent general partner interest. In lieu of cash distributions, the Class D units will receive quarterly distributions of additional paid-in-kind Class D units. All Class D units outstanding will be convertible to common units beginning in the first quarter of 2016. The contribution agreement governing the Canada Dropdown provides that WPZ can issue additional Class D units to us on a quarterly basis through 2015 for up to a total of $200 million in cash for the purpose of funding certain facility expansions.
Dividend Growth
We increased our quarterly dividends from $0.325 per share in the fourth quarter of 2012 to $0.380 per share in the fourth quarter of 2013. Also, consistent with our expectation of receiving increasing cash distributions from our interests in WPZ and Access Midstream Partners, we expect to increase our dividend on a quarterly basis. Our Board of Directors has approved a dividend of $0.4025 per share for the first quarter of 2014 and we expect approximately 20 percent annual increase in total dividends in both 2014 and 2015.
Overview
Income (loss) from continuing operations attributable to The Williams Companies, Inc., for the year ended December 31, 2013, changed unfavorably by $282 million compared to the year ended December 31, 2012. This change primarily reflects a $230 million decline in Williams Partners segment profit primarily due to lower NGL margins driven by reduced ethane recoveries and lower olefins margins as a result of the Geismar Incident as described below, partially offset by higher fee-based revenues; $61 million in segment profit from our investment in ACMP acquired at the end of 2012; and $99 million of deferred income tax expense recognized in 2013 related to undistributed earnings of certain foreign operations that are no longer considered permanently reinvested. See additional discussion in Results of Operations.
Abundant and low-cost natural gas reserves in the United States continue to drive strong demand for midstream and pipeline infrastructure. We believe that we have successfully positioned our energy infrastructure businesses for significant future growth.
Williams Partners
Geismar Incident
On June 13, 2013, an explosion and fire occurred at WPZ’s Geismar olefins plant. The fire was extinguished on the day of the incident. The incident (Geismar Incident) rendered the facility temporarily inoperable and resulted in significant human, financial, and operational effects.
We have substantial insurance coverage for repair and replacement costs, lost production and additional expenses related to the incident as follows:
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| • | Property damage and business interruption coverage with a combined per-occurrence limit of $500 million and retentions (deductibles) of $10 million per occurrence for property damage and a 60-day waiting period per occurrence for business interruption; |
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| • | General liability coverage with per-occurrence and aggregate annual limits of $610 million and retentions (deductibles) of $2 million per occurrence; |
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| • | Workers’ compensation coverage with statutory limits and retentions (deductibles) of $1 million total per occurrence. |
We are cooperating with the Chemical Safety Board and the EPA regarding their investigations of the Geismar Incident. While certain negotiations pertaining to various citations and assessments remain ongoing with the Occupational Safety and Health Administration (OSHA), they have released the incident area back to us, and we are in the process of repairing the damage incurred. We have expensed $13 million of costs in 2013 under our insurance deductibles in Operating and maintenance expenses in the Consolidated Statement of Income. Recoveries under our business interruption policy will be recognized upon resolution of any contingencies with the insurer associated with the claim. During the fourth quarter of 2013, we incurred $10 million of covered insurable expenses in excess of our retentions (deductibles) which partially offset the $50 million of insurance proceeds received during the third quarter of 2013, which was reported as a gain in Other (income) expense – net within Costs and expenses in our Consolidated Statement of Income.
Following the repair and plant expansion, the Geismar plant is expected to be in operation in June 2014. We expect our insurance coverage will significantly mitigate our financial loss. We currently estimate approximately $430 million of total cash recoveries from insurers related to business interruption and approximately $70 million related to the repair of the plant. Of these amounts, we received $50 million of insurance proceeds during 2013. In February 2014, the insurer agreed to pay a second installment of $125 million, which is expected to be received in the first quarter of 2014. We are impacted by certain uninsured losses, including amounts associated with the 60-day waiting period for business interruption, as well as other deductibles, policy limits, and uninsured expenses. Our assumptions and estimates, including the timing for the expanded plant return to operation, repair cost estimates, and insurance proceeds associated with our property damage and business interruption coverage are subject to various risks and uncertainties that could cause the actual results to be materially different.
Mid-Atlantic Connector
The Mid-Atlantic Connector Project involved an expansion of Transco’s mainline from an existing interconnection with East Tennessee Natural Gas in North Carolina to markets as far downstream as Maryland. We placed the project into service in the first quarter of 2013, and it increased capacity by 142 Mdth/d.
Overland Pass Pipeline
Through our equity investment in OPPL, we completed the construction of a pipeline expansion in the second quarter of 2013, which increased the pipeline’s capacity to 255 Mbbls/d. In addition, a new connection was completed in April 2013 to bring new NGL volumes to OPPL from the Bakken Shale in the Williston basin.
Three Rivers Midstream
In April 2013, we announced an agreement to launch a new midstream joint project to provide gas gathering and gas processing services for production located in northwest Pennsylvania. The project is expected to invest in both wet-gas handling infrastructure and dry-gas infrastructure serving the Marcellus and Utica Shale wells in the area. We will initially own substantially all of the new project, Three Rivers Midstream, and operate the assets. Our partner has the right to invest capital and increase its ownership to a maximum of 50 percent by July 2015. Further development has been delayed pending additional evaluation of producers’ drilling plans.
Gulfstar One
Effective April 1, 2013, WPZ sold a 49 percent interest in Gulfstar One LLC (Gulfstar One) to a third party for $187 million, representing their proportionate share of estimated capital expenditures to date for the construction of Gulfstar FPS™, which is a proprietary floating production system and has been under construction since late 2011. It is supported by multiple agreements with two major producers to provide production handling, export pipeline, oil and gas gathering and gas processing services for the Tubular Bells field development located in the eastern deepwater Gulf of Mexico. The Gulfstar FPS™ will tie into our wholly owned oil and gas gathering and gas processing systems in the eastern Gulf of Mexico. Gulfstar FPS™ is expected to have an initial capacity of 60 Mbbls/d, up to 200 MMcf/d of natural gas and the capability to provide seawater injection services. We expect Gulfstar FPS™ to be capable of serving as a central host facility for other deepwater prospects in the area. The project is expected to be in service in the third quarter 2014. In December 2013, Gulfstar One agreed to host the Gunflint development, which will result in an expansion of the Gulfstar One system to provide production handling capacity of 20 Mbbls/d and 40 MMcf/d for Gunflint. The project has a first oil target of mid-2016, dependent on the producer’s development activities.
Marcellus Shale
In the second quarter of 2013, we completed an expansion to our natural gas gathering system, processing facilities, and fractionator in our Ohio Valley Midstream business of the Marcellus Shale including a third turbo-expander at our Fort Beeler facility, which added 200 MMcf/d of processing capacity. In the first half of 2014, we expect to add fractionation capacity at our Moundsville fractionators bringing the NGL handling capacity to approximately 43 Mbbls/d, complete our first turbo-expander at our Oak Grove facility to add 200 MMcf/d of processing capacity, and finalize the construction of our first deethanizer with a capacity of 40 Mbbls/d and the associated 50-mile ethane line to Houston, Pennsylvania.
Mid-South
The Mid-South expansion project involved an expansion of Transco’s mainline from Station 85 in Choctaw County, Alabama to markets as far downstream as North Carolina. We placed the first phase of the project into service in the third quarter of 2012, which increased capacity by 95 Mdth/d. The second phase was placed into service in the second quarter of 2013, which increased capacity by an additional 130 Mdth/d.
Northeast Supply Link
The Northeast Supply Link Project involved an expansion of Transco’s existing natural gas transmission system from the Marcellus Shale production region on the Leidy Line to various delivery points in New York and New Jersey. The project was placed into service in the fourth quarter of 2013 and increased capacity by 250 Mdth/d.
Filing of rate cases
On August 31, 2012, Transco submitted to the FERC a general rate filing principally designed to recover increased costs and to comply with the terms of the settlement in its prior rate proceeding. The new rates became effective March 1, 2013, subject to refund and the outcome of the hearing. On August 27, 2013, Transco filed a stipulation and agreement with the FERC proposing to resolve all issues in this proceeding without the need for a hearing (Agreement). On December 6, 2013, the FERC issued an order approving the Agreement without modifications. Pursuant to its terms, the Agreement will become effective March 1, 2014. We have provided a reserve for rate refunds of $98 million which we believe is adequate for required refunds as of December 31, 2013, under the Agreement. Refunds will be made on or before April 30, 2014.
Caiman II
As a result of planned contributions through the second quarter of 2014, we expect, subject to regulatory approval, to increase our ownership in Caiman II from 47.5 percent up to approximately 59 percent. These additional contributions are used to fund a portion of Blue Racer Midstream, a joint project which comprises an expansion to gathering and processing and the associated liquids infrastructure serving oil and gas producers in the Utica Shale.
Atlantic Sunrise
The Atlantic Sunrise Expansion Project involves an expansion of our existing natural gas transmission system along with greenfield facilities to provide firm transportation from the northeastern Marcellus producing area to markets along Transco’s mainline as far south as Station 85 in Alabama. We plan to file an application with the FERC in the second quarter of 2015 for approval of the project. We plan to place the project into service during the second half of 2017 assuming timely receipt of all necessary regulatory approvals and it is expected to increase capacity by 1,700 Mdth/d.
Ethane Recovery Project
In December 2013, we completed the ethane recovery project, which is an expansion of our Canadian facilities which allows us to recover ethane/ethylene mix from our operations that process offgas from the Alberta oil sands. We modified our oil sands offgas extraction plant near Fort McMurray, Alberta, and constructed a deethanizer at our Redwater fractionation facility that processes approximately 10 Mbbls/d of ethane/ethylene mix. We have signed a long-term contract to provide the ethane/ethylene mix to a third-party customer.
Volume impacts in 2013
Due to unfavorable ethane economics, we reduced our recoveries of ethane in our plants during most of 2013, which resulted in 31 percent lower NGL production volumes and 48 percent lower NGL equity sales volumes in 2013 compared to 2012.
As a result of the Geismar Incident, ethylene sales volumes have decreased 56 percent in 2013 compared to 2012.
Volatile commodity prices
NGL margins were approximately 40 percent lower in 2013 compared to 2012 driven by reduced ethane recoveries, as previously mentioned, coupled with lower NGL prices and higher natural gas prices, and the absence of hedge gains recognized in 2012, which primarily increased our realized non-ethane sales prices. However, our average per-unit composite NGL margin in 2013 has increased slightly compared to 2012 as the relative mix of NGL products produced has shifted to a greater proportion of higher-margin non-ethane products.
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 effects of this price volatility, notably the decline in equity ethane sales driven by reduced recoveries, as well as the margin differential between ethane and non-ethane products and the relative mix of those products.
Williams NGL & Petchem Services
Canadian PDH Facility
During the first quarter of 2013, we announced plans to build Canada’s first propane dehydrogenation (PDH) facility located in Alberta. The new PDH facility is expected to produce approximately 1.1 billion pounds annually, significantly increasing Williams’ production of polymer-grade propylene currently at 180 million pounds annually. The project is in the development stage and is expected to start-up in the second quarter of 2017.
Bluegrass Pipeline and Moss Lake
In the second quarter of 2013, we formed a joint project to develop the Bluegrass Pipeline. We own a 50 percent interest in Bluegrass Pipeline (a consolidated entity), which would connect processing facilities in the Marcellus and Utica shale-gas areas in the U.S. Northeast to growing petrochemical and export markets in the U.S. Gulf Coast. The proposed pipeline would deliver mixed NGLs from these producing areas to proposed new fractionation and storage facilities, which would have connectivity to petrochemical facilities and product pipelines along the coasts of Louisiana and Texas. We are in discussions with potential customers regarding the commitments to the pipeline. Completion of this project is subject to all necessary or required approvals, elections, and actions, as well as execution of formal customer commitments. We currently estimate that the Bluegrass Pipeline will be placed in-service in mid-to-late 2016. See Note 19 – Subsequent Events of Notes to Consolidated Financial Statements for more information regarding recent developments.
Through our 50 percent equity investment in Moss Lake Fractionation LLC, the project would also include constructing a new large-scale fractionation plant and expanding NGL storage facilities in Louisiana. In October 2013, we announced a related joint project, Moss Lake LPG Terminal, which explores the development of a new liquefied petroleum gas export terminal and related facilities on the Gulf Coast to provide customers access to international markets. See Note 19 – Subsequent Events of Notes to Consolidated Financial Statements for more information regarding recent developments.
Company Outlook
Our strategy is to provide large-scale energy infrastructure designed to maximize the opportunities created by the vast supply of natural gas, natural gas products, and crude oil that exists in North America. We seek to accomplish this through further developing our scale positions in current key markets and basins and entering new growth markets and basins where we can become the large-scale service provider. We will maintain a strong commitment to safety, environmental stewardship, operational excellence and customer satisfaction. We believe that accomplishing these goals will position us to deliver an attractive return to our shareholders.
Fee-based businesses are a significant component of our portfolio. As we continue to transition to an overall business mix that is increasingly fee-based, the influence of commodity price fluctuations on our operating results and cash flows is expected to become somewhat less significant.
As previously noted, the financial impact of the Geismar Incident is expected to be significantly mitigated by our insurance policies. We expect the timing of recognizing recoveries under our business interruption policy will favorably impact our operating results in 2014.
Our business plan for 2014 reflects both significant capital investment and continued dividend growth. Our planned consolidated capital investments for 2014 total approximately $4.6 billion. We also expect approximately 20 percent growth in total 2014 dividends, which we expect to fund primarily with distributions received from WPZ and ACMP. We expect to maintain an attractive cost of capital and reliable access to capital markets, both of which will allow us to pursue development projects and acquisitions.
Potential risks and obstacles that could impact the execution of our plan include:
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| • | General economic, financial markets, or industry downturn; |
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| • | Unexpected significant increases in capital expenditures or delays in capital project execution; |
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| • | Lower than anticipated or delay in receiving insurance recoveries associated with the Geismar Incident; |
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| • | Limited availability of capital due to a change in our financial condition, interest rates, market or industry conditions; |
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| • | Lower than expected distributions, including IDRs, from WPZ. WPZ’s liquidity could also be impacted by a lack of adequate access to capital markets to fund its growth; |
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| • | Counterparty credit and performance risk; |
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| • | Decreased volumes from third parties served by our midstream business; |
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| • | Lower than anticipated energy commodity prices and margins; |
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| • | Changes in the political and regulatory environments; |
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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 continue to address these risks through disciplined investment strategies, sufficient liquidity from cash and cash equivalents and available capacity under our revolving credit facilities.
In 2014, we anticipate an overall improvement in operating results compared to 2013 primarily due to an increase in our fee based, olefins, and Canadian midstream businesses, partially offset by lower NGL margins and higher operating expenses associated with the growth of our business.
The following factors, among others, could impact our businesses in 2014.
Williams Partners
Commodity price changes
NGL and olefin price changes have historically correlated somewhat with changes in the price of crude oil, although NGL, olefin, crude, and natural gas prices are highly volatile, and difficult to predict. Commodity margins are highly dependent upon regional supply/demand balances of natural gas as they relate to NGL margins, while olefins are impacted by continued demand within the global economy. NGL prices will benefit from exports to satisfy global demand. NGL products are currently the preferred feedstock for ethylene and propylene production, and are expected to remain advantaged over crude-based feedstocks into the foreseeable future. We continue to benefit from our strategic feedstock cost advantage in propylene production from Canadian oil sands offgas.
In 2014, we anticipate higher overall commodity prices compared to 2013:
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| • | Natural gas prices are expected to be higher in part due to the additional demand to replace the gas volumes withdrawn during the colder than normal weather over the past winter season. |
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| • | Ethane prices are expected to be somewhat higher due to a modest increase in demand as well as slightly higher natural gas prices. |
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| • | Propane prices are expected to be higher from an increase in exports and higher natural gas prices. |
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| • | Propylene prices are expected to be comparable to 2013 prices. |
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| • | Ethylene prices are expected to be slightly lower as compared to 2013 prices. The overall ethylene crack spread is also expected to be slightly lower due to the anticipated lower sales price and a projected higher ethane price. |
Gathering, processing, and NGL sales volumes
The growth of natural gas production supporting our gathering and processing volumes is impacted by producer drilling activities, which are influenced by commodity prices including natural gas, ethane and propane prices. In addition, the natural decline in production rates in producing areas impact the amount of gas available for gathering and processing. Due in part to the higher natural gas prices in the early part of the year, we anticipate that overall drilling economics will improve slightly, which will benefit us in the long-term.
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| • | In Williams Partners’ northeast region, we anticipate significant growth compared to the prior year in our natural gas gathering and processing volumes as our infrastructure grows to support drilling activities in the region. |
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| • | In Williams Partners’ Transco and Northwest Pipeline businesses, we anticipate higher natural gas transportation volumes compared to 2013, as a result of expansion projects placed into service in 2013 and anticipated to be placed in service in 2014. |
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| • | In Williams Partners’ Gulf Coast region, we expect higher production handling volumes compared to 2013, following the scheduled completion of Gulfstar FPS™ in third quarter 2014. |
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| • | In Williams Partners’ western region, we anticipate an unfavorable impact in equity NGL volumes in 2014 compared to 2013, primarily due to a customer contract that expired in September 2013. |
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| • | In 2014, Williams Partners’ domestic businesses anticipates a continuation of periods when it will not be economical to recover ethane. |
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| • | In Williams Partners’ Canadian midstream business, we anticipate new ethane volumes in 2014 associated with the fourth quarter 2013 completion of the Canadian ethane recovery project, which is expected to benefit from a contractual minimum ethane sales price. |
Olefin production volumes
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| • | Williams Partners’ Gulf olefins business anticipates higher ethylene volumes in 2014 compared to 2013 substantially due to the repair and expansion of the Geismar plant expected to be in operation in the second quarter of 2014. |
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| • | Williams Partners’ Canadian olefins business expects higher propylene volumes in 2014 than 2013. Volumes in 2013 were negatively impacted by both a planned maintenance turnaround and downtime associated with the tie-in of the Canadian ethane recovery project. |
Other
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| • | Williams Partners’ Gulf olefins business expects to receive insurance recoveries under its business interruption policy related to the Geismar Incident that will favorably impact our operating results in 2014. |
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| • | Williams Partners’ expects higher operating expenses in 2014 compared to 2013, including depreciation expense related to its growing operations in its northeast region and expansion projects in its gas pipeline and Gulf olefins businesses. |
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| • | Williams Partners’ expects higher equity earnings compared to 2013 following the scheduled completion of Discovery’s Keathley Canyon Connector™ lateral in the fourth quarter of 2014. |
Eminence Storage Field leak
On December 28, 2010, we detected a leak in one of the seven underground natural gas storage caverns at our Eminence Storage Field in Mississippi. Due to the leak and related damage to the well at an adjacent cavern, both caverns are out of service. In addition, two other caverns at the field, which were constructed at or about the same time as those caverns, have experienced operating problems, and we have determined that they should also be retired. The event has not affected the performance of our obligations under our service agreements with our customers.
In September 2011, we filed an application with the FERC seeking authorization to abandon these four caverns. In February 2013, the FERC issued an order approving the abandonment. We estimate the remaining cost to complete the abandonment of the caverns will be approximately $7 million, and is expected to be spent through the first half of 2014.
As of December 31, 2013, we have incurred approximately $93 million of these abandonment costs. Management considers these costs to be prudent costs incurred in the abandonment of these caverns. Consistent with the terms of the recent rate case, we expensed $12 million in 2013 related to a portion of the Eminence abandonment regulatory asset that will not be recovered in rates. We have also recognized income of $16 million in 2013 related to insurance recoveries associated with this event.
Access Midstream Partners
In the third-quarter of 2013, Access Midstream Partners increased its cash distribution by five cents per unit. Following the step-up in distributions in 2013, annual distributions to unitholders are expected to grow by approximately 15 percent in 2014 and 2015. We forecast that we will receive cash distributions of approximately $140 million from our investment in Access Midstream Partners for 2014.
Considering the expected distribution growth from Access Midstream Partners, including the benefit we receive from our 50 percent indirect interest in Access GP and its incentive distribution rights, we expect to recognize growing equity earnings from our investment. Our earnings recognized, however, will be reduced by the noncash amortization of the difference between the cost of our investment and our underlying share of the net assets of Access Midstream Partners.
Expansion Projects
We expect to invest total capital in 2014 among our business segments as follows:
|
| | | | | | | |
| | Low | | High |
| | (Millions) |
| Segment: | | | |
| Williams Partners | $ | 3,025 |
| | $ | 3,525 |
|
| Williams NGL & Petchem Services | 775 |
| | 1,075 |
|
Our ongoing major expansion projects include the following:
Williams Partners
Atlantic Sunrise
The Atlantic Sunrise Expansion Project involves an expansion of our existing natural gas transmission system along with greenfield facilities to provide firm transportation from the northeastern Marcellus producing area to markets along Transco’s mainline as far south as Station 85 in Alabama. We plan to file an application with the FERC in the second quarter of 2015 for approval of the project. We plan to place the project into service during the second half of 2017 assuming timely receipt of all necessary regulatory approvals and it is expected to increase capacity by 1,700 Mdth/d.
Leidy Southeast
In September 2013, we filed an application with the FERC for Transco’s Leidy Southeast Expansion project to expand our existing natural gas transmission system from the Marcellus Shale production region on Transco’s Leidy Line in Pennsylvania to delivery points along its mainline as far south as Station 85 in Alabama. We plan to place the project into service during the fourth quarter of 2015, and expect it to increase capacity by 525 Mdth/d.
Mobile Bay South III
In July 2013, we filed an application with the FERC for an expansion of Transco’s Mobile Bay line south from Station 85 in west central Alabama to delivery points along the line. We plan to place the project into service during the second quarter of 2015 and it is expected to increase capacity on the line by 225 Mdth/d.
Constitution Pipeline
In June 2013, we filed an application with the FERC for authorization to construct and operate the new jointly owned Constitution pipeline. 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 120-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. We plan to place the project into service in late 2015 to 2016, with an expected capacity of 650 Mdth/d. The pipeline is fully subscribed with two shippers.
Northeast Connector
In April 2013, we filed an application with the FERC to expand Transco’s existing natural gas transmission system from southeastern Pennsylvania to the proposed Rockaway Delivery Lateral. We plan to place the project into service during the second half of 2014, and expect it to increase capacity by 100 Mdth/d.
Rockaway Delivery Lateral
In January 2013, we filed an application with the FERC for Transco to construct a three-mile offshore lateral to a distribution system in New York. We plan to place the project into service during the second half of 2014, the capacity of the lateral is expected to be 647 Mdth/d.
Virginia Southside
In December 2012, we filed an application with the FERC to expand Transco’s existing natural gas transmission system from New Jersey to a proposed power station in Virginia and a delivery point in North Carolina. We plan to place the project into service during the third quarter of 2015, and expect it to increase capacity by 270 Mdth/d.
Marcellus Shale Expansions
| |
| • | Expansion of our gathering infrastructure including compression and gathering pipelines in the Susquehanna Supply Hub in northeastern Pennsylvania as production in the Marcellus increases. The Susquehanna Supply Hub is expected to reach a natural gas take away capacity of 3 Bcf/d by 2015. |
| |
| • | As previously discussed, we completed construction at our Fort Beeler facility in the Marcellus Shale, which added 200 MMcf/d of processing capacity in the second quarter of 2013. We have several significant projects under construction with targeted construction completion in the first half of 2014. We are completing a 43 Mbbls/d expansion of the Moundsville fractionator, installation of 40 Mbbls/d of deethanization capacity, a 50-mile ethane pipeline, condensate stabilization, and the first 200 MMcf/d of processing at Oak Grove. |
| |
| • | Expansions to the Laurel Mountain gathering system infrastructure to increase the capacity to 667 MMcf/d by the end of 2015 through capital to be invested within this equity investment. |
| |
| • | Construction of the Blue Racer Midstream joint project, an expansion to gathering and processing and the associated liquids infrastructure serving oil and gas producers in the Utica shale, primarily in Ohio and Northwest Pennsylvania through capital to be invested within our Caiman II equity investment. Expansion plans include the addition of Natrium II, a second 200 MMcf/d processing plant at Natrium by the end of the first quarter of 2014. Construction of an additional 200 MMcf/d processing plant is underway at the Berne complex in Monroe County, Ohio. Berne I is expected to come online in the third quarter of 2014. |
Gulfstar One
We will design, construct, and install our Gulfstar FPS™, a spar-based floating production system that utilizes a standard design approach with a capacity of 60 Mbbls/d of oil, up to 200 MMcf/d of natural gas, and the capability
to provide seawater injection services, as previously discussed. Construction is under way and the project is expected to be in service in the third quarter 2014. The previously discussed expansion that increases Gulfstar One’s production handling capacity related to the Gunflint Development is expected to be completed in mid-2016, dependent on the producer’s development activities.
Parachute
Due to a reduction in drilling in the Piceance basin during 2012 and early 2013, we delayed the in-service date of our 350 MMcf/d cryogenic natural gas processing plant in Parachute that was planned for service in 2014. We are currently planning an in-service date in mid-2016. We will continue to monitor the situation to determine whether a different in-service date is warranted.
Geismar
As a result of the Geismar Incident, the expansion of our Geismar olefins production facility is expected to be completed when the Geismar plant returns to operation, which is expected to occur in June 2014. The expansion is expected to increase the facility’s ethylene production capacity by 600 million pounds per year to a new annual capacity of 1.95 billion pounds. The additional capacity will be wholly owned by us and is expected to increase our ownership of the Geismar production facility from the current 83.3 percent.
Keathley Canyon Connector™
Discovery is constructing a 215-mile, 20-inch deepwater lateral pipeline in the central deepwater Gulf of Mexico that it will own and operate. Discovery has signed long-term agreements with anchor customers for natural gas gathering and processing services for production from the Keathley Canyon and Green Canyon areas. The Keathley Canyon Connector™ lateral will originate from a third-party floating production facility in the southeast portion of the Keathley Canyon area and will connect to Discovery’s existing 30-inch offshore natural gas transmission system. The gas will be processed at Discovery’s Larose Plant and the NGLs will be fractionated at Discovery’s Paradis Fractionator. The lateral pipeline is estimated to have the capacity to flow more than 400 MMcf/d and will accommodate the tie-in of other deepwater prospects. The pipeline is expected to be in service in the fourth quarter of 2014.
Redwater Expansion
As part of a long-term agreement to provide gas processing to a second bitumen upgrader in Canada’s oil sands near Fort McMurray, Alberta, we plan to increase the capacity of the Redwater facilities where NGL/olefins mixtures will be fractionated into an ethane/ethylene mix, propane, polymer grade propylene, normal butane, an alkylation feed and condensate. This project is expected to be placed into service during the third quarter of 2015.
Williams NGL & Petchem Services
Canadian PDH Facility
As previously discussed, we are planning to build a PDH facility in Alberta that will significantly increase production of polymer-grade propylene. Start-up for the PDH facility is expected to occur in the second quarter of 2017.
NGL Infrastructure Expansion
As part of a long-term agreement to provide gas processing to a second bitumen upgrader in Canada’s oil sands near Fort McMurray, Alberta, we plan to build a new liquids extraction plant and an extension of the Boreal Pipeline. The extension of the Boreal Pipeline will enable transportation of the NGL/olefins mixture from the new extraction plant. The NGL/olefins recovered are initially expected to be approximately 12 Mbbls/d by mid-2015. To mitigate the associated ethane price risk, we have a long-term supply agreement with a third-party customer.
Gulf Coast Expansion
In November 2012, we acquired 10 liquids pipelines in the Gulf Coast region. The acquired pipelines will be combined with an organic build-out of several projects to expand our petrochemical services in that region. The projects include the construction and commissioning of pipeline systems capable of transporting various products in the Gulf Coast region. The projects are expected to be placed into service beginning in late 2014 through 2015.
Bluegrass Pipeline
As previously discussed, in the second quarter we formed a joint project to develop the proposed Bluegrass Pipeline. Pre-construction activities are under way and we currently estimate that the project will be placed in-service in mid-to-late 2016 (see Note 19 – Subsequent Events of Notes to Consolidated Financial Statements for more information regarding recent developments).
Critical Accounting Estimates
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions. We have reviewed the selection, application, and disclosure of these critical accounting estimates with our Audit Committee. 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.
Pension and Postretirement Obligations
We have employee benefit plans that include pension and other postretirement benefits. Net periodic benefit cost and obligations for these plans are impacted by various estimates and assumptions. These estimates and assumptions include the expected long-term rates of return on plan assets, discount rates, expected rate of compensation increase, health care cost trend rates, and employee demographics, including retirement age and mortality. These assumptions are reviewed annually and adjustments are made as needed. The assumptions utilized to compute cost and the benefit obligations are shown in Note 9 – Employee Benefit Plans of Notes to Consolidated Financial Statements.
The following table presents the estimated increase (decrease) in net periodic benefit cost and obligations resulting from a one-percentage-point change in the specific assumption.
|
| | | | | | | | | | | | | | | |
| | Benefit Cost | | Benefit Obligation |
| | One- Percentage- Point Increase | | One- Percentage- Point Decrease | | One- Percentage- Point Increase | | One- Percentage- Point Decrease |
| | (Millions) |
| Pension benefits: | | | | | | | |
| Discount rate | $ | (6 | ) | | $ | 7 |
| | $ | (114 | ) | | $ | 133 |
|
| Expected long-term rate of return on plan assets | (11 | ) | | 11 |
| | — |
| | — |
|
| Rate of compensation increase | 2 |
| | (1 | ) | | 7 |
| | (6 | ) |
| Other postretirement benefits: | | | | | | | |
| Discount rate | 1 |
| | 1 |
| | (20 | ) | | 24 |
|
| Expected long-term rate of return on plan assets | (2 | ) | | 2 |
| | — |
| | — |
|
| Assumed health care cost trend rate | 5 |
| | (4 | ) | | 7 |
| | (6 | ) |
Our expected long-term rates of return on plan assets, as determined at the beginning of each fiscal year, are based on the average rate of return expected on the funds invested in the plans. We determine our long-term expected rates of return on plan assets using our expectations of capital market results, which includes an analysis of historical results as well as forward-looking projections. These capital market expectations are based on a period of at least 10 years and take into account our investment strategy and mix of assets, which is weighted toward domestic and international equity securities. We develop our expectations using input from several external sources, including consultation with our third-party independent investment consultant. The forward-looking capital market projections are developed using a
consensus of economists’ expectations for inflation, GDP growth, and dividend yield along with expected changes in risk premiums. The capital market return projections for specific asset classes in the investment portfolio are then applied to the relative weightings of the asset classes in the investment portfolio. The resulting rates are an estimate of future results and, thus, likely to be different than actual results.
In 2013, the benefit plans’ assets reflected strong equity performance as well as negative returns from the fixed income strategies. While the 2013 investment performance was greater than our expected rates of return, the expected rates of return on plan assets are long-term in nature and are not significantly impacted by short-term market performance. Changes to our asset allocation would also impact these expected rates of return. Our expected long-term rate of return on plan assets used for our pension plans was 6.3 percent in 2012. In 2013, we reduced our expected long-term rate of return on pension assets to 5.9 percent. This reduction was implemented due to a downward trend in long-term capital market expectations. The 2013 actual return on plan assets for our pension plans was approximately 15.5 percent. The 10-year average rate of return on pension plan assets through December 2013 was approximately 5.7 percent.
The discount rates are used to measure the benefit obligations of our pension and other postretirement benefit plans. The objective of the discount rates is to determine the amount, if invested at the December 31 measurement date in a portfolio of high-quality debt securities, that will provide the necessary cash flows when benefit payments are due. Increases in the discount rates decrease the obligation and, generally, decrease the related cost. The discount rates for our pension and other postretirement benefit plans are determined separately based on an approach specific to our plans and their respective expected benefit cash flows as described in Note 1 – Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies and Note 9 – Employee Benefit Plans of Notes to Consolidated Financial Statements. Our discount rate assumptions are impacted by changes in general economic and market conditions that affect interest rates on long-term, high-quality debt securities as well as by the duration of our plans’ liabilities. The weighted-average discount rate used to measure our pension plans’ benefit obligation increased during 2013 by 125 basis points, which significantly contributed to the actuarial gain of $173 million in the current year.
The expected rate of compensation increase represents average long-term salary increases. An increase in this rate causes the pension obligation and cost to increase.
The assumed health care cost trend rates are based on national trend rates adjusted for our actual historical cost rates and plan design. An increase in this rate causes the other postretirement benefit obligation and cost to increase.
Goodwill
At December 31, 2013, our Consolidated Balance Sheet includes $646 million of goodwill. We performed our annual assessment of goodwill for impairment as of October 1. All of our goodwill is allocated to WPZ’s Northeast gathering and processing business (the reporting unit). In our evaluation, our estimate of the fair value of the reporting unit exceeded its carrying value by 15 percent, including goodwill, and thus no impairment loss was recognized in 2013. The fair value of WPZ’s Northeast gathering and processing business was estimated by an income approach utilizing discounted cash flows and corroborated with a market capitalization analysis.
Judgments and assumptions are inherent in our estimate of future cash flows used to evaluate these assets. The use of alternate judgments and assumptions could result in a different calculation of fair value, which could ultimately result in the recognition of an impairment charge in the consolidated financial statements. Our calculation of fair value used a discount rate of 10.5 percent. We estimate that an increase of approximately 140 basis points in the discount rate could result in a fair value of the reporting unit below its carrying value, all other variables held constant.
Equity-method investments
At December 31, 2013, our Consolidated Balance Sheet includes approximately $4.4 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. 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. 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:
| |
| • | A significant or sustained decline in the market value of a publicly-traded investee; |
| |
| • | Lower than expected cash distributions from investees (including incentive distributions); |
| |
| • | Significant asset impairments or operating losses recognized by investees; |
| |
| • | Significant delays in or lack of producer development or significant declines in producer volumes in markets served by investees; |
| |
| • | Significant delays in or failure to complete significant growth projects of investees. |
No impairments of investments accounted for under the equity method have been recorded for the year ended December 31, 2013.
Capitalized project development costs
As of December 31, 2013, our Consolidated Balance Sheet includes approximately $113 million of capitalized project development costs associated with the Bluegrass Pipeline, of which our net interest is 50 percent or $56.5 million. Completion of this project is subject to execution of customer contracts sufficient to support the project. We are in discussions with potential customers regarding commitments to the pipeline and these discussions have not yet yielded sufficient commitments to satisfy this condition. As a result, we evaluated the capitalized project costs for impairment as of December 31, 2013, and determined that no impairment was necessary. Our evaluation considered probability-weighted scenarios of undiscounted future net cash flows, including reasonably possible scenarios assuming the construction and operation of the pipeline under differing levels of commitments from customers and the possibility that the project does not proceed. It is reasonably possible that the probability-weighted estimate of undiscounted future net cash flows may change in the near term, resulting in the write down of this asset to fair value. Such changes in estimates could result from lack of sufficient commitments from potential customers, lack of approval of the project by our partner, lack of executed regulatory approvals and unexpected changes in forecasted costs, and other factors impacting project economics.
We will continue to evaluate these and other capitalized project development costs for impairment in the future if we believe events or changes in circumstances indicate that we may not be able to recover the carrying value. Should we determine in future periods that we will be unable to obtain sufficient customer commitments or fail to realize other key project variables and conclude that a project is probable of not being developed, all of the capitalized project development costs for that project would be expensed as they would no longer qualify for continued capitalization. See Note 19 – Subsequent Events of Notes to Consolidated Financial Statements.
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, 2013. The results of operations by segment are discussed in further detail following this consolidated overview discussion.
|
| | | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2013 | | $ Change from 2012* | | % Change from 2012* | | 2012 | | $ Change from 2011* | | % Change from 2011* | | 2011 |
| | (Millions) |
| Revenues: | | | | | | | | | | | | | |
| Service revenues | $ | 2,939 |
| | +210 |
| | +8% |
| | $ | 2,729 |
| | +197 | | +8% | | $ | 2,532 |
|
| Product sales | 3,921 |
| | -836 |
| | -18% |
| | 4,757 |
| | -641 | | -12% | | 5,398 |
|
| Total revenues | 6,860 |
| | | | | | 7,486 |
| | | | | | 7,930 |
|
| Costs and expenses: | | | | | | | | | | | | | |
| Product costs | 3,027 |
| | +469 |
| | +13% |
| | 3,496 |
| | +438 | | +11% | | 3,934 |
|
| Operating and maintenance expenses | 1,097 |
| | -70 |
| | -7% |
| | 1,027 |
| | -37 | | -4% | | 990 |
|
| Depreciation and amortization expenses | 815 |
| | -59 |
| | -8% |
| | 756 |
| | -95 | | -14% | | 661 |
|
| Selling, general, and administrative expenses | 512 |
| | +59 |
| | +10% |
| | 571 |
| | -94 | | -20% | | 477 |
|
| Other (income) expense — net | 34 |
| | -10 |
| | -42% |
| | 24 |
| | -23 | | NM | | 1 |
|
| Total costs and expenses | 5,485 |
| | | | | | 5,874 |
| | | | | | 6,063 |
|
| Operating income (loss) | 1,375 |
| | | | | | 1,612 |
| | | | | | 1,867 |
|
| Equity earnings (losses) | 134 |
| | +23 |
| | +21% |
| | 111 |
| | -44 | | -28% | | 155 |
|
| Interest expense | (510 | ) | | -1 |
| | 0% |
| | (509 | ) | | +64 | | +11% | | (573 | ) |
| Other investing income — net | 81 |
| | +4 |
| | +5% |
| | 77 |
| | +64 | | NM | | 13 |
|
| Early debt retirement costs | — |
| | — |
| | — |
| | — |
| | +271 | | +100% | | (271 | ) |
| Other income (expense) — net | — |
| | +2 |
| | +100% |
| | (2 | ) | | -13 | | NM | | 11 |
|
| Income (loss) from continuing operations before income taxes | 1,080 |
| | | | | | 1,289 |
| | | | | | 1,202 |
|
| Provision (benefit) for income taxes | 401 |
| | -41 |
| | -11% |
| | 360 |
| | -236 | | -190% | | 124 |
|
| Income (loss) from continuing operations | 679 |
| | | | | | 929 |
| | | | | | 1,078 |
|
| Income (loss) from discontinued operations | (11 | ) | | -147 |
| | NM |
| | 136 |
| | +553 | | NM | | (417 | ) |
| Net income (loss) | 668 |
| | | | | | 1,065 |
| | | | | | 661 |
|
| Less: Net income attributable to noncontrolling interests | 238 |
| | -32 |
| | -16% |
| | 206 |
| | +79 | | +28% | | 285 |
|
| Net income (loss) attributable to The Williams Companies, Inc. | $ | 430 |
| | | | | | $ | 859 |
| | | | | | $ | 376 |
|
_______
| |
| * | + = 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. |
2013 vs. 2012
The increase in Service revenues is primarily due to higher fee revenues associated with the growth in the businesses acquired in the 2012 Caiman and Laser Acquisitions, as well as contributions from the processing and fractionation facilities placed in service in the latter half of 2012 and in 2013. Additionally, natural gas transportation fee revenues increased from expansion projects placed into service in 2012 and 2013 and new rates effective during first-quarter 2013. Partially offsetting these increases are decreased gathering and processing fee revenues driven by lower volumes in the Piceance, Four Corners, and eastern Gulf Coast areas.
The decrease in Product sales is primarily due to lower NGL production revenues driven by reduced ethane recoveries and decreases in average NGL per-unit sales prices, as well as lower olefin production revenues primarily from the loss of production as a result of the Geismar Incident, partially offset by higher olefin per-unit sales prices. Additionally, marketing revenues decreased resulting from lower NGL per-unit prices and lower crude oil and ethane volumes, partially offset by higher non-ethane volumes. The changes in marketing revenues are more than offset by similar changes in marketing purchases, reflected above as Product costs.
The decrease in Product costs is primarily due to lower NGL marketing purchases resulting from lower NGL prices and lower crude oil volumes, partially offset by higher non-ethane volumes. The changes in marketing purchases are substantially offset by similar changes in marketing revenues. In addition, olefin feedstock purchases decreased reflecting lower volumes and lower average per-unit feedstock costs. Costs associated with the production of NGLs also decreased primarily resulting from lower ethane recoveries, partially offset by an increase in average natural gas prices.
The increase in Operating and maintenance expenses is primarily associated with the subsequent growth in the operations of the businesses acquired in the Caiman and Laser Acquisitions, a scheduled third-quarter 2013 shutdown to conduct maintenance at our Canadian olefins facility, and $13 million of costs incurred under our insurance deductibles resulting from the Geismar Incident. These increases are partially offset by lower compressor and natural gas pipeline maintenance and repair expenses primarily due to the absence of expenses related to the substantial completion of our natural gas pipeline integrity management plan during 2012 and lower operating costs in our Four Corners area, which experienced lower volumes.
The increase in Depreciation and amortization expenses reflects a full year of depreciation and amortization expense in 2013 related to the Caiman and Laser Acquisitions and depreciation on subsequent infrastructure additions, increased depreciation of certain assets that were decommissioned in the third quarter of 2013 in preparation for the completion of the ethane recovery system, as well as higher depreciation on the Boreal Pipeline which was placed into service in 2012. The absence of increased depreciation in 2012 on certain assets in the Gulf Coast region resulting from a change in the estimated useful lives partially offset these increases.
The decrease in Selling, general, and administrative expenses (SG&A) is primarily due to the absence of reorganization related costs in 2012 and the absence of acquisition and transition costs incurred in 2012. (See Note 6 – Other Income and Expenses of Notes to Consolidated Financial Statements.)
Other (income) expense – net within Operating income includes the following increases to net expense:
| |
| • | $25 million accrued loss for a settlement in principle of a producer claim against us; |
| |
| • | $23 million increase in amortization expense related to our regulatory asset associated with asset retirement obligations; |
| |
| • | $20 million write-off of development costs of an abandoned project; |
| |
| • | $12 million expense recognized in 2013 related to the portion of the Eminence abandonment regulatory asset that will not be recovered in rates. |
Other (income) expense – net within Operating income includes the following decreases to net expense:
| |
| • | $40 million of income associated with net insurance recoveries related to the Geismar Incident in 2013; |
| |
| • | $16 million of income from insurance recoveries related to the abandonment of certain of Eminence storage assets in 2013; |
| |
| • | $9 million involuntary conversion gain recognized in 2013 related to a 2012 furnace fire for our Geismar olefins plant. |
The unfavorable change in Operating income (loss) generally reflects lower NGL production margins, lower olefin production margins, higher operating costs, the net unfavorable changes in Other (income) expense as described above, partially offset by increased fee revenues, higher marketing margins, and lower SG&A expenses.
The favorable change in Equity earnings (losses) is primarily due to higher equity earnings from Access Midstream Partners resulting from the acquisition of this investment in late 2012 and improved equity earnings from Laurel Mountain. These increases are partially offset by lower equity earnings from Discovery.
Interest expense increased due to a $42 million increase in Interest capitalized related to construction projects primarily at Williams Partners, substantially offset by a $43 million increase in Interest incurred primarily due to an increase in borrowings (see Note 13 – Debt, Banking Arrangements, and Leases of Notes to Consolidated Financial Statements).
The favorable change in Other investing income – net is primarily due to a $43 million increase in interest income associated with a receivable related to the sale of certain former Venezuela assets and gains of $31 million resulting from Access Midstream Partners' equity issuances in 2013. These increases are partially offset by the absence of $63 million of income recognized in 2012, including $10 million of interest income, related to the 2010 sale of our interest in Accroven SRL. (See Note 5 – Investing Activities of Notes to Consolidated Financial Statements.)
Provision (benefit) for income taxes changed unfavorably primarily due to $99 million of deferred income tax expense recognized in 2013 related to the undistributed earnings of certain foreign operations that are no longer considered permanently reinvested. This is partially offset by a reduction in tax expense due to lower pre-tax income. See Note 7 – 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.
Income (loss) from discontinued operations in 2013 primarily includes a $15 million charge resulting from an unfavorable ruling associated with our former Alaska refinery related to the Trans-Alaska Pipeline System Quality Bank. Income (loss) from discontinued operations in 2012 primarily includes a $144 million gain on reconsolidation following the sale of certain of our former Venezuela operations. (See Note 4 – Discontinued Operations of Notes to Consolidated Financial Statements.)
The unfavorable change in Net income attributable to noncontrolling interests primarily reflects our slightly decreased percentage of limited partner ownership of WPZ and higher operating results at WPZ, partially offset by higher income allocated to the general partner associated with incentive distribution rights. It also reflects our partners’ share of increased interest income related to a receivable from the sale of certain former Venezuela assets. (See Note 5 – Investing Activities of Notes to Consolidated Financial Statements.)
2012 vs. 2011
The increase in Service revenues is primarily due to higher fee revenues resulting from increased gathering and processing volumes in the Marcellus Shale, including new volumes from our assets acquired in the 2012 Caiman Acquisition and Laser Acquisition and higher volumes in the western deepwater Gulf of Mexico and in the Piceance basin. Additionally, natural gas transportation revenues increased from expansion projects placed into service in 2011 and 2012.
The decrease in Product sales is primarily due to lower NGL and olefin production revenues reflecting an overall decrease in average per-unit sales prices, and lower marketing revenues primarily due to significant decreases in NGL and olefin prices, partially offset by higher NGL and crude volumes, as well as new volumes from natural gas marketing activities.
The decrease in Product costs is primarily due to lower olefins feedstock costs reflecting a decrease in average per-unit prices and lower costs associated with the production of NGLs primarily resulting from a decrease in average natural gas prices. Marketing purchases also decreased primarily due to significantly lower average NGL prices, partially offset by higher NGL and crude volumes, as well as new volumes from natural gas marketing activities.
The increase in Operating and maintenance expenses is primarily due to increased maintenance expenses primarily associated with assets acquired in 2012 and increased employee-related benefit costs, partially offset by lower costs in our Four Corners area related to the consolidation of certain operations.
The increase in Depreciation and amortization expenses is primarily associated with assets acquired in 2012. (See Note 2 – Acquisitions, Goodwill, and Other Intangible Assets of Notes to Consolidated Financial Statements.)
The increase in SG&A is primarily due to $23 million of acquisition and transition-related costs incurred in 2012 as well as higher employee-related and information technology expenses driven by general growth within business operations. SG&A also includes $26 million of reorganization-related costs incurred in 2012 primarily relating to our engagement of a consulting firm to assist in better aligning resources to support our business strategy following the spin-off of WPX Energy, Inc (WPX) and is substantially offset by the absence of general corporate expenses related to the spin-off of WPX, which was completed on December 31, 2011.
The unfavorable change in Other (income) expense - net within Operating income (loss) primarily reflects the absence of the Gulf Liquids litigation contingency accrual reduction of $19 million in 2011. (See Note 6 – Other Income and Expenses and Note 17 – Contingent Liabilities and Commitments of Notes to Consolidated Financial Statements.)
The unfavorable change in Operating income (loss) generally reflects lower NGL production and marketing margins, as well as previously described increases in Operating and maintenance expenses, Depreciation and amortization expenses, SG&A and an unfavorable change in Other (income) expense — net. Higher fee revenues and olefin production margins partially offset these decreases.
The unfavorable change in Equity earnings (losses) is primarily due to lower Laurel Mountain, Aux Sable and Discovery equity earnings primarily reflecting lower operating results of these investees and the impairment of two minor NGL processing plants at Laurel Mountain in 2012.
Interest expense decreased due to an increase in Interest capitalized related to construction projects, as well as a decrease in Interest incurred related to corporate debt retirements in December 2011, partially offset by an increase in borrowings and the absence of a $14 million reduction of an interest accrual related to a litigation contingency in 2011 as previously discussed.
The favorable change in Other investing income — net is primarily due to $63 million of income, including interest, recognized in 2012 as compared to an $11 million gain in 2011 related to the 2010 sale of our interest in Accroven SRL. (See Note 5 – Investing Activities of Notes to Consolidated Financial Statements.)
Early debt retirement costs in 2011 reflect costs related to corporate debt retirements in December 2011, including $254 million in related premiums.
Provision (benefit) for income taxes changed unfavorably primarily due to higher pre-tax income, the absence of approximately $147 million tax benefit from federal settlements and an international revised assessment in 2011, and the absence of $66 million deferred tax benefit recognized in 2011 related to the undistributed earnings of certain foreign operations that we considered to be permanently reinvested. See Note 7 – 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.
Income (loss) from discontinued operations in 2012 primarily includes a gain on reconsolidation following the sale of certain of our former Venezuela operations. Income (loss) from discontinued operations in 2011 primarily reflects the results of operations of our former exploration and production business as discontinued operations following the spin-off of WPX. See Note 4 – Discontinued Operations of Notes to Consolidated Financial Statements for a more detailed discussion of the items in Income (loss) from discontinued operations.
The favorable change in Net income attributable to noncontrolling interests primarily reflects lower operating results at WPZ and higher income allocated to the general partner driven by incentive distribution rights, partially offset by our decreased percentage of limited partner ownership of WPZ, which was 68 percent at December 31, 2012, compared to 73 percent at December 31, 2011.
Year-Over-Year Operating Results – Segments
Williams Partners
|
| | | | | | | | | | | |
| | Years Ended December 31, |
| | 2013 | | 2012 | | 2011 |
| | (Millions) |
| Segment revenues | $ | 6,835 |
| | $ | 7,471 |
| | $ | 7,916 |
|
| Segment costs and expenses | (5,262 | ) | | (5,675 | ) | | (5,884 | ) |
| Equity earnings (losses) | 104 |
| | 111 |
| | 142 |
|
| Segment profit | $ | 1,677 |
| | $ | 1,907 |
| | $ | 2,174 |
|
2013 vs. 2012
The decrease in segment revenues includes:
| |
| • | A $350 million decrease in revenues from our equity NGLs including $248 million due to lower volumes and a $102 million decrease associated with 10 percent lower average realized non-ethane per-unit sales prices and 44 percent lower average ethane per-unit sales prices. Equity ethane sales volumes are 80 percent lower driven by unfavorable ethane economics, as previously mentioned, and equity non-ethane volumes are 7 percent lower primarily due to a customer contract that expired in September 2013 and a change in a customer’s contract at the end of 2012 to fee-based processing, along with periods of severe winter weather conditions in the first quarter of 2013 that prevented producers from delivering gas in our western onshore operations. |
| |
| • | A $314 million decrease in olefin sales due to $368 million associated with lower volumes, partially offset by $54 million associated with higher per-unit sales prices. Olefins production volumes are lower at our facilities in the Gulf Coast primarily due to the loss of production as a result of the Geismar Incident, an outage in a third-party storage facility which caused us to reduce production at our RGP splitter facility, and changes in inventory management. Our Canadian operations experienced lower olefins sales volumes due to a scheduled third-quarter 2013 shutdown to conduct maintenance and to install ethane recovery equipment, as well as the impact of delays associated with resuming production during the fourth quarter of 2013. These decreased volumes were partially offset by the absence of the impact of filling the Boreal Pipeline in June 2012. Ethylene and propylene prices averaged 21 percent and 12 percent higher, respectively, partially offset by 29 percent lower butadiene prices. |
| |
| • | A $224 million decrease in marketing revenues primarily due to $241 million associated with lower NGL prices and $136 million associated with lower crude oil volumes, partially offset by $130 million related to higher non-ethane volumes primarily related to new marketing activity in our Ohio Valley Midstream business. The changes in marketing revenues are more than offset by similar changes in marketing purchases. |
| |
| • | A $200 million increase in service revenues primarily includes $167 million higher fee revenues resulting from higher gathering volumes driven by new well connections related to infrastructure additions placed into service in 2012 and 2013, a full year of operations associated with gathering systems included in the 2012 acquisitions, and increased gathering rates associated with customer contract modifications primarily in the Susquehanna Supply Hub, as well as contributions from the processing and fractionation facilities placed in service in the latter half of 2012 and in 2013 in the Ohio Valley Midstream business. Natural gas transportation revenues also increased $106 million primarily due to expansion projects placed into service in 2012 and 2013, as well as new rates effective in first-quarter 2013. Partially offsetting these increases is a $43 million decrease in gathering and processing revenues primarily due to a natural decline in production volumes, primarily in the Piceance basin and Four Corners area, and severe winter weather conditions in the first quarter of 2013, which prevented producers from delivering gas in our western onshore operations. In addition, fee revenues decreased $34 million in the eastern Gulf Coast primarily driven by natural declines in Bass Lite and Blind Faith production area volumes. |
| |
| • | A $53 million increase in other product sales primarily due to higher system management gas sales from our gas pipeline businesses (offset in segment costs and expenses). |
The decrease in segment costs and expenses includes:
| |
| • | A $252 million decrease in marketing purchases primarily due to lower NGL prices and lower crude oil volumes, partially offset by higher non-ethane volumes (substantially offset in marketing revenues). |
| |
| • | A $224 million decrease in olefin feedstock purchases due to $202 million associated with lower volumes, as discussed above, and $22 million lower feedstock and fuel costs, reflecting 21 percent lower average per-unit ethylene feedstock costs, partially offset by 9 percent higher average per-unit propylene feedstock costs. |
| |
| • | A $41 million decrease in costs associated with our equity NGLs reflecting a $117 million decrease due to lower natural gas volumes driven by lower ethane recoveries, partially offset by a $76 million increase related to a 41 percent increase in average natural gas prices. |
| |
| • | A $75 million increase in operating costs includes $61 million in higher Operating and maintenance expenses primarily associated with the businesses acquired in the Laser and Caiman Acquisitions in February and April 2012, respectively, and the subsequent growth in these operations, as well as $13 million of costs incurred under our insurance deductibles associated with the Geismar Incident and increased maintenance at our Canadian facility related to the scheduled third-quarter 2013 shutdown previously discussed. These increases are partially offset by lower compressor and pipeline maintenance and repair expenses at our Gulf Coast businesses primarily due to the absence of expenses relating to the substantial completion of a natural gas pipeline integrity management plan during 2012. Additionally, the increase in operating costs includes $57 million in higher Depreciation and amortization expenses primarily reflecting a full year of expense in 2013 associated with the businesses acquired in 2012 and depreciation on subsequent infrastructure additions and certain assets in Canada that were decommissioned in the third quarter of 2013 in preparation of the completion of the ethane recovery system, in addition to the depreciation related to the Boreal Pipeline which was placed into service in June 2012, partially offset by the absence of increased depreciation in 2012 on certain assets in the Gulf Coast region resulting from a change in the estimated useful lives. Partially offsetting these increases in operating costs is lower SG&A primarily due to the absence of acquisition and transition costs of $23 million incurred in 2012. |
| |
| • | A $44 million increase in other product costs primarily due to higher system management gas costs from our gas pipeline businesses (offset in segment revenues). |
| |
| • | A $13 million favorable change in Other (income) expense – net primarily attributable to the recognition of $40 million of income associated with the net insurance recoveries related to the Geismar Incident during 2013, $9 million involuntary conversion gains related to a 2012 furnace fire at our Geismar olefins plant and a $5 million favorable change in net foreign currency exchange gains. The favorable changes are partially offset by a $25 million accrued loss for a settlement in principle of a producer claim against us and $23 million higher amortization of regulatory assets associated with asset retirement obligations in 2013. |
The decrease in segment profit includes:
| |
| • | A $309 million decrease in NGL margins driven primarily by lower NGL volumes and prices and higher natural gas prices. |
| |
| • | A $90 million decrease in olefin margins including $156 million associated with lower product volumes at our Geismar plant offset by $41 million associated with higher ethylene per-unit sales prices and $21 million lower ethylene feedstock costs. |
| |
| • | A $75 million increase in operating costs as previously discussed. |
| |
| • | A $7 million decrease in Equity earnings (losses) primarily due to $20 million lower equity earnings from Discovery driven by lower NGL margins reflecting lower volumes including reduced ethane recoveries and natural declines, as well as lower NGL prices. In addition, charges to write-down two lateral pipelines and electrical equipment in 2013 and the absence of a favorable customer settlement in 2012 decreased equity earnings from Discovery. The decrease is partially offset by $15 million improved equity earnings from Laurel Mountain driven primarily by 55 percent higher gathering volumes, the receipt of an annual minimum volume commitment fee in 2013, and lower leased compression expenses. |
| |
| • | A $200 million increase in service revenues as previously discussed. |
| |
| • | A $28 million increase in marketing margins primarily due to favorable prices in 2013 and the absence of losses recognized in the second quarter of 2012 driven by significant declines in NGL prices while product was in transit. |
| |
| • | A $13 million favorable change in Other (income) expense – net as previously discussed. |
2012 vs. 2011
The decrease in segment revenues includes:
| |
| • | A $411 million decrease in revenues from our equity NGLs primarily reflecting a decrease of $406 million associated with an overall 27 percent decrease in average NGL per-unit sales prices. Average ethane and non-ethane per-unit prices decreased by 49 percent and 17 percent, respectively. |
| |
| • | An $86 million decrease in olefin sales revenues including $42 million lower ethylene production sales revenues primarily due to 10 percent lower average per-unit sales prices and $41 million lower propylene production sales revenues primarily due to 18 percent lower average per-unit sales prices, partially offset by 10 percent higher sales volumes at our RGP splitter and four percent higher sales volumes in Canada. |
| |
| • | Marketing revenues were $83 million lower primarily due to a significant decrease in NGL and olefin prices, partially offset by higher NGL and crude volumes, as well as new volumes from natural gas marketing activities. |
| |
| • | A $39 million decrease in system management gas sales from our gas pipeline businesses (offset in segment costs and expenses). |
| |
| • | A $196 million increase in service revenues primarily includes $163 million higher fee revenues due to higher volumes in the Marcellus Shale, including new volumes on our gathering and processing assets in our Ohio Valley Midstream and Susquehanna Supply Hub businesses; higher volumes in the western deepwater Gulf of Mexico, including higher volumes on our Perdido Norte natural gas and oil pipelines; and higher volumes in the Piceance basin. It also includes a $40 million increase in transportation revenues associated with natural gas pipeline expansion projects placed in service during 2011 and 2012. |
The decrease in segment costs and expenses includes:
| |
| • | A $180 million decrease in olefin feedstock costs including $130 million lower ethylene feedstock costs driven by 38 percent lower average per-unit feedstock costs, $29 million lower propylene feedstock costs primarily due to 19 percent lower per-unit feedstock costs, and $23 million lower feedstock costs for other olefin by-products primarily due to lower per-unit feedstock costs, partially offset by higher feedstock volumes. |
| |
| • | A $150 million decrease in costs associated with our equity NGLs primarily due to a 30 percent decrease in average natural gas prices. |
| |
| • | A $39 million decrease in system management gas costs from our gas pipeline businesses (offset in segment revenues). |
| |
| • | A $50 million decrease in marketing purchases primarily due to significantly lower average NGL prices, partially offset by higher NGL and crude volumes, as well as new volumes from natural gas marketing activities. The changes in natural gas marketing purchases are more than offset by similar changes in natural gas marketing revenues. |
| |
| • | A $134 million increase in operating costs including higher depreciation and amortization of assets and intangibles, along with maintenance costs associated with assets acquired in 2012, partially offset by lower costs in our Four Corners area related to the consolidation of certain operations. |
| |
| • | An $84 million increase in general and administrative expenses including $23 million of Caiman and Laser acquisition and transition-related costs, as well as increases in employee-related and information technology expenses driven by general growth within our business operations. |
The decrease in segment profit includes:
| |
| • | A $261 million decrease in NGL margins driven primarily by commodity price changes including lower NGL prices, partially offset by lower natural gas prices. |
| |
| • | A $134 million increase in operating costs as previously discussed. |
| |
| • | An $84 million increase in general and administrative expenses as previously discussed. |
| |
| • | A $33 million decrease in margins related to the marketing of NGLs primarily due to the impact of a significant and rapid decline in NGL prices, primarily during the second quarter of 2012, while product was in transit and a $7 million unfavorable change in write-downs of inventories to lower of cost or market. These unfavorable variances compare to periods of increasing prices during 2011. |
| |
| • | A $31 million decrease in Equity earnings (losses) primarily due to $19 million lower Laurel Mountain equity earnings driven by lower gathering rates indexed to natural gas prices, higher operating costs, including depreciation, and the impairment of two minor NGL processing plants, partially offset by higher gathered volumes; $12 million lower Aux Sable equity earnings primarily due to lower NGL margins; and $12 million lower Discovery equity earnings primarily due to lower NGL margins and volumes. These decreases are partially offset by $11 million higher Gulfstream equity earnings primarily due to WPZ’s acquisition of additional interest in Gulfstream, which was previously reflected in Other. |
| |
| • | A $196 million increase in service revenues as previously discussed. |
| |
| • | A $94 million increase in olefin product margins including $88 million higher ethylene production margins and $13 million higher DAC margins from our Geismar facility primarily due to significantly lower per-unit feedstock prices, partially offset by $14 million lower propylene margins from our Canadian facility primarily due to lower propylene sales prices. |
Williams NGL & Petchem Services
|
| | | | | | | | | | | |
| | Years Ended December 31, |
| | 2013 | | 2012 | | 2011 |
| | (Millions) |
| Segment costs and expenses | $ | (32 | ) | | $ | (3 | ) | | $ | 18 |
|
| Segment profit (loss) | $ | (32 | ) | | $ | (3 | ) | | $ | 18 |
|
2013 vs. 2012
Segment costs and expenses increased primarily due to the $20 million write-off of an abandoned project during 2013 as well as costs incurred during 2013 related to the development of the Bluegrass Pipeline.
2012 vs. 2011
Segment costs and expenses changed unfavorably primarily due to the absence of $19 million of income related to the reduction of our accrual for the Gulf Liquids litigation in 2011 (See Note 17 – Contingent Liabilities and Commitments of Notes to Consolidated Financial Statements.)
Access Midstream Partners
|
| | | | | | | | | | | |
| | Years Ended December 31, |
| | 2013 | | 2012 | | 2011 |
| | (Millions) |
| Segment profit | $ | 61 |
| | $ | — |
| | $ | — |
|
2013 vs. 2012
Segment profit in 2013 includes $93 million of equity earnings recognized from Access Midstream Partners, which we acquired an interest in during December 2012. Offsetting the 2013 equity earnings is $63 million of noncash amortization of the difference between the cost of our investment and our underlying share of the net assets of Access Midstream Partners. In addition, segment profit in 2013 includes noncash gains of $31 million resulting from Access Midstream Partners’ equity issuances in 2013. These equity issuances resulted in the dilution of our ownership of limited partnership units from approximately 24 percent to 23 percent, which is accounted for as though we sold a portion of our investment.
In 2013, we received regular quarterly distributions from Access Midstream Partners totaling $93 million.
Other
|
| | | | | | | | | | | |
| | Years Ended December 31, |
| | 2013 | | 2012 | | 2011 |
| | (Millions) |
| Segment revenues | $ | 36 |
| | $ | 27 |
| | $ | 25 |
|
| Segment profit (loss) | $ | (5 | ) | | $ | 56 |
| | $ | 24 |
|
2013 vs. 2012
The unfavorable change in segment profit is primarily due to the absence of the gain of $53 million recognized in 2012 related to the 2010 sale of our interest in Accroven SRL. As part of a settlement regarding certain Venezuelan assets in the first quarter of 2012, we received payment for all outstanding balances due from this sale. (See Note 5 – Investing Activities of Notes to Consolidated Financial Statements.) The unfavorable change also reflects $6 million of project development costs incurred in the first quarter of 2013.
2012 vs. 2011
The favorable change in segment profit is primarily due to $42 million of increased gains recognized related to the 2010 sale of our interest in Accroven SRL. (See Note 5 – Investing Activities of Notes to Consolidated Financial Statements.) The favorable change is partially offset by $12 million decreased equity earnings due to the contribution of a 24.5 percent interest in Gulfstream to WPZ in May 2011.
Management’s Discussion and Analysis of Financial Condition and Liquidity
Overview
In 2013, we continued to focus upon both growth in our businesses through disciplined investment and growth in our per-share dividends. Examples of this growth included:
| |
| • | Expansion of Williams Partners’ interstate natural gas pipeline system to meet the demand of growth markets; |
| |
| • | Continued investment in Williams Partners’ gathering and processing capacity and infrastructure in the Marcellus Shale area and deepwater Gulf of Mexico, as well as expansion of our olefins business in the Gulf Coast region; |
| |
| • | Expansion of our Canadian facilities and investment in a joint project to develop the Bluegrass Pipeline (see Note 19 – Subsequent Events of Notes to Consolidated Financial Statements); |
| |
| • | Total per-share dividends grew 20 percent to $1.4375 in 2013 compared to $1.19625 in 2012. |
This growth was funded through cash flow from operations, distributions from WPZ and Access Midstream Partners, debt and equity offerings at WPZ, and cash on hand.
Outlook
We seek to manage our businesses with a focus on applying conservative financial policy in order to maintain investment-grade credit metrics. Our plan for 2014 reflects our ongoing transition to an overall business mix that is increasingly fee-based. Although our cash flows are impacted by fluctuations in energy commodity prices, that impact is somewhat mitigated by certain of our cash flow streams that are not directly impacted by short-term commodity price movements, including:
| |
| • | Firm demand and capacity reservation transportation revenues under long-term contracts; |
| |
| • | Fee-based revenues from certain gathering and processing services. |
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, dividends and distributions, debt service payments, and tax payments, including an estimated $111 million tax payment as a result of WPZ’s expected acquisition of certain of our Canadian operations, while maintaining a sufficient level of liquidity. In particular, we note the following:
| |
| • | We expect capital and investment expenditures to total between $4.16 billion and $5.04 billion in 2014. Of this total, maintenance capital expenditures, which are generally considered nondiscretionary and include expenditures to meet legal and regulatory requirements, to maintain and/or extend the operating capacity and useful lives of our assets, and to complete certain well connections, are expected to total between $360 million and $440 million. Expansion capital expenditures, which are generally more discretionary to fund projects in order to grow our business are expected to total between $3.8 billion and $4.6 billion. See Company Outlook - Expansion Projects for discussions describing the general nature of these expenditures. In addition, we retain the flexibility to adjust our planned levels of capital and investment expenditures in response to changes in economic conditions or business opportunities. |
| |
| • | We expect to pay total cash dividends of approximately $1.75 per common share in 2014, an increase of 22 percent over 2013 levels. |
| |
| • | We expect to fund working capital requirements, capital and investment expenditures, debt service payments, dividends and distributions, and tax payments primarily through cash flow from operations, cash and cash equivalents on hand, issuances of WPZ debt and/or equity securities, and utilization of our credit facility and WPZ’s credit facility and/or commercial paper program. Based on a range of market assumptions, we currently estimate our cash flow from operations will be between $2.85 billion and $3.175 billion in 2014. |
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 2014. Our internal and external sources of consolidated liquidity include cash generated from our operations, including cash distributions from WPZ and our equity method investments based on our level of ownership and incentive distribution rights, cash and cash equivalents on hand, cash proceeds from WPZ’s offerings of common units, our credit facility and WPZ’s credit facility and/or commercial paper program. Additional sources of liquidity, if needed, include bank financings, proceeds from the issuance of debt and/or equity securities, and proceeds from asset sales. These sources are available to us at the parent level and are expected to be available to certain of our subsidiaries, particularly equity and debt issuances from WPZ. WPZ is expected to be self-funding through its cash flows from operations, use of its credit facility and/or commercial paper program, and its access to capital markets.
Potential risks associated with our planned levels of liquidity and the planned capital and investment expenditures discussed above include those previously discussed in Company Outlook.
As of December 31, 2013, we had a working capital deficit (current liabilities, inclusive of commercial paper borrowings, in excess of current assets) of $300 million. However, we note the following about our available liquidity.
|
| | | | | | | | | | | | |
| | | December 31, 2013 |
| Available Liquidity | | WPZ | | WMB | | Total |
| | | (Millions) |
| Cash and cash equivalents | | $ | 110 |
| | $ | 571 |
| (1) | $ | 681 |
|
| Capacity available under our $1.5 billion credit facility (expires July 31, 2018) (2) | | | | 1,500 |
| | 1,500 |
|
| Capacity available to WPZ under its $2.5 billion five-year credit facility (expires July 31, 2018) less amounts outstanding under its $2 billion commercial paper program (3)(4) | | 2,275 |
| | | | 2,275 |
|
| | | $ | 2,385 |
| | $ | 2,071 |
| | $ | 4,456 |
|
__________
| |
| (1) | Includes $271 million of Cash and cash equivalents held primarily by certain international entities, that we intend to utilize to fund growth in our Canadian midstream operations. The remainder of our Cash and cash equivalents is primarily held in government-backed instruments. |
| |
| (2) | We did not borrow on our credit facility during 2013. At December 31, 2013, we are in compliance with the financial covenants associated with this credit facility. (See Note 13 – Debt, Banking Arrangements, and Leases of Notes to Consolidated Financial Statements.) On July 31, 2013, we amended our $900 million credit facility to increase the aggregate commitments to $1.5 billion and extend the maturity date to July 31, 2018. The amended credit facility, under certain circumstances, may be increased up to an additional $500 million. |
| |
| (3) | The highest amount outstanding during 2013 was $1.085 billion under WPZ’s commercial paper program. As of February 25, 2014, $900 million is outstanding under WPZ’s commercial paper program. At December 31, 2013, WPZ is in compliance with the financial covenants associated with the credit facility and commercial paper program. (See Note 13 – Debt, Banking Arrangements, and Leases of Notes to Consolidated Financial Statements.) The WPZ credit facility is only available to WPZ, Transco, and Northwest Pipeline as co-borrowers. On July 31, 2013, WPZ amended its $2.4 billion credit facility to increase the aggregate commitments to $2.5 billion and extend the maturity date to July 31, 2018. The amended credit facility, under certain circumstances, may be increased up to an additional $500 million. |
| |
| (4) | In managing our available liquidity, we do not expect a maximum outstanding amount under WPZ’s commercial paper program in excess of the capacity available under WPZ’s credit facility. |
In addition to the credit facilities and WPZ’s commercial paper program listed above, we have issued letters of credit totaling $16 million as of December 31, 2013, under certain bilateral bank agreements.
As described in Note 13 – Debt, Banking Arrangements, and Leases of Notes to Consolidated Financial Statements, we have determined that we have net assets that are technically considered restricted in accordance with Rule 4-08(e) of Regulation S-X of the Securities and Exchange Commission in excess of 25 percent of our consolidated net assets. We do not expect this determination will impact our ability to pay dividends or meet future obligations as the terms of WPZ’s partnership agreement require it to make quarterly distributions of all available cash, as defined, to its unitholders.
Commercial Paper
In March 2013, WPZ initiated a commercial paper program. The program allows a maximum outstanding amount at any time of $2 billion of unsecured commercial paper notes. 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. WPZ classifies these commercial paper notes outstanding as short-term borrowings as they have maturity dates less than three months from the date of issuance. At December 31, 2013, WPZ had $225 million in commercial paper outstanding.
Debt Offering
In November 2013, WPZ completed a public offering of $600 million of 4.5 percent senior unsecured notes due 2023 and $400 million of 5.8 percent senior unsecured notes due 2043. WPZ used the net proceeds to repay amounts outstanding under its commercial paper program, to fund capital expenditures, and for general partnership purposes.
Distributions from Equity Method Investees
Our equity-method investees’ organizational documents 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. Our more significant equity-method investees include: Access Midstream Partners, Aux Sable, Caiman II, Discovery, Gulfstream, Laurel Mountain, and OPPL.
Shelf Registration
In April 2013, WPZ filed a shelf registration statement for the offer and sale from time to time of common units representing limited partner interests in WPZ having an aggregate offering price of up to $600 million. These sales will 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 will be made pursuant to an equity distribution agreement between WPZ and certain banks who may act as sales agents or purchase for their own accounts as principals. As of December 31, 2013, no common units have been issued under this registration.
Equity Offerings
In August 2013, WPZ completed an equity issuance of 21,500,000 common units representing limited partner interests. Subsequently, the underwriters exercised their option to purchase 3,225,000 common units. The net proceeds of approximately $1.2 billion to WPZ were used to repay amounts outstanding under its commercial paper program, to fund capital expenditures, and for general partnership purposes.
In March 2013, WPZ completed an equity issuance of 14,250,000 common units representing limited partner interests, including 3,000,000 common units sold to us in a private placement. Subsequently, the underwriters exercised their option to purchase 1,687,500 common units. The net proceeds of approximately $760 million to WPZ, including $143 million received from us on the private placement sale, were used to repay amounts outstanding under the WPZ credit facility.
WPZ Incentive Distribution Rights
Our ownership interest in WPZ includes the right to incentive distributions determined in accordance with WPZ’s partnership agreement. We have agreed to temporarily waive our incentive distributions through 2013 related to the common units issued by WPZ to us and the seller in connection with the Caiman Acquisition. In connection with the
contribution of certain Gulf olefins assets to WPZ in November 2012, we also agreed to waive $16 million per quarter of incentive distributions until the later of December 31, 2013 or 30 days after the Geismar plant expansion is operational. Cash distributions to us from WPZ through the February 2014 distribution were reduced by a total of $147 million associated with these waived incentive distributions.
In May 2013, we agreed to waive additional incentive distributions of up to $200 million total through the subsequent four quarters to further support WPZ’s cash distribution metrics as its large platform of growth projects moves toward completion. Cash distributions to us from WPZ through the February 2014 distribution were reduced by a total of $90 million in association with these waived incentive distributions.
Credit Ratings
Our ability to borrow money is impacted by our credit ratings and the credit ratings of WPZ. The current ratings are as follows:
|
| | | | | | | |
| | | | | | | | |
| | Rating Agency | | Outlook | | Senior Unsecured Debt Rating | | Corporate Credit Rating |
| Williams: | | | | | | | |
| | | | | | | | |
| | Standard & Poor’s | | Stable | | BBB- | | BBB |
| | | | | | | | |
| | Moody’s Investors Service | | Stable | | Baa3 | | N/A |
| | | | | | | | |
| | Fitch Ratings | | Stable | | BBB- | | N/A |
| | | | | | | | |
| Williams Partners: | | | | | | |
| | | | | | | | |
| | Standard & Poor’s | | Stable | | BBB | | BBB |
| | | | | | | | |
| | Moody’s Investors Service | | Stable | | Baa2 | | N/A |
| | | | | | | | |
| | Fitch Ratings | | Positive | | BBB- | | N/A |
With respect to Standard and Poor’s, a rating of “BBB” or above indicates an investment grade rating. A rating below “BBB” indicates that the security has significant speculative characteristics. A “BB” rating indicates that Standard and Poor’s believes the issuer has the capacity to meet its financial commitment on the obligation, but adverse business conditions could lead to insufficient ability to meet financial commitments. Standard and Poor’s may modify its ratings with a “+” or a “-” sign to show the obligor’s relative standing within a major rating category.
With respect to Moody’s, a rating of “Baa” or above indicates an investment grade rating. A rating below “Baa” is considered to have speculative elements. The “1”, “2”, and “3” modifiers show the relative standing within a major category. A “1” indicates that an obligation ranks in the higher end of the broad rating category, “2” indicates a mid-range ranking, and “3” indicates a ranking at the lower end of the category.
With respect to Fitch, a rating of “BBB” or above indicates an investment grade rating. A rating below “BBB” is considered speculative grade. Fitch may add a “+” or a “-” sign to show the obligor’s relative standing within a major rating category.
Credit rating agencies perform independent analyses when assigning credit ratings. 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 post additional collateral with third parties, negatively impacting our available liquidity. As of December 31, 2013, we estimate that a downgrade to a rating below investment grade for us or WPZ could require us to post up to $8 million or $282 million, respectively, in additional collateral with third parties.
Sources (Uses) of Cash
|
| | | | | | | | | | | |
| | Years Ended December 31, |
| | 2013 | | 2012 | | 2011 |
| | (Millions) |
| Net cash provided (used) by: | | | | | |
| Operating activities | $ | 2,217 |
| | $ | 1,835 |
| | $ | 3,439 |
|
| Financing activities | 1,677 |
| | 5,036 |
| | (342 | ) |
| Investing activities | (4,052 | ) | | (6,921 | ) | | (3,003 | ) |
| Increase (decrease) in cash and cash equivalents | $ | (158 | ) | | $ | (50 | ) | | $ | 94 |
|
Operating activities
The factors that determine operating activities are largely the same as those that affect Net income (loss), with the exception of noncash expenses such as Depreciation, depletion, and amortization, Provision (benefit) for deferred income taxes, and Gain on reconsolidation of Wilpro entities. Our Net cash provided by operating activities in 2013 increased from 2012 primarily due to proceeds from insurance recoveries on the Eminence Storage Field leak and Geismar Incident, $93 million of distributions from our investment in Access Midstream Partners acquired in December 2012, and net favorable changes in operating working capital, partially offset by lower operating income.
Our Net cash provided by operating activities in 2012 decreased from 2011 primarily due to the absence of cash flows from our former exploration and production business and lower operating results.
Financing activities
Significant transactions include:
2013
| |
| • | $224 million net proceeds received from WPZ’s commercial paper issuances; |
| |
| • | $1.705 billion received from WPZ’s credit facility borrowings: |
| |
| • | $994 million net proceeds received from WPZ’s November 2013 public offering of $600 million of 4.5 percent senior unsecured notes due 2023 and $400 million of 5.8 percent senior unsecured notes due 2043; |
| |
| • | $2.08 billion paid on WPZ’s credit facility borrowings; |
| |
| • | $1.819 billion received from WPZ’s equity offerings; |
| |
| • | $982 million paid for quarterly dividends on common stock for the year ended December 31, 2013; |
| |
| • | $489 million paid for dividends and distributions to noncontrolling interests; |
| |
| • | $467 million received in contributions from noncontrolling interests. |
2012
| |
| • | $2.5 billion net proceeds received from our 2012 equity offerings; |
| |
| • | $1.559 billion received from WPZ’s 2012 equity offerings; |
| |
| • | $842 million net proceeds received from our December 2012 public offering of $850 million of 3.7 percent senior unsecured notes due 2023; |
| |
| • | $745 million net proceeds received from WPZ’s August 2012 public offering of $750 million of senior unsecured notes due 2022; |
| |
| • | $395 million net proceeds received from Transco’s July 2012 issuance of $400 million of senior unsecured notes; |
| |
| • | $1.49 billion received from WPZ’s credit facility borrowings; |
| |
| • | $1.115 billion of WPZ’s credit facility borrowings paid; |
| |
| • | $325 million paid to retire Transco’s 8.875 percent notes that matured in July 2012; |
| |
| • | We paid $742 million of quarterly dividends on common stock for the year ended December 31, 2012; |
| |
| • | We paid $387 million of dividends and distributions to noncontrolling interests. |
2011
| |
| • | $526 million of cash retained by WPX upon spin-off on December 31, 2011; |
| |
| • | $746 million of notes and debentures retired in December 2011 and $254 million paid in associated premiums; |
| |
| • | $1.5 billion received from WPX’s issuance of senior unsecured notes in November 2011; |
| |
| • | $500 million received from WPZ’s public offering of senior unsecured notes in November 2011 primarily used to repay borrowings on its credit facility mentioned below; |
| |
| • | $375 million received by Transco from the issuance of senior unsecured notes in August 2011; |
| |
| • | $300 million paid to retire Transco’s senior unsecured notes that matured in August 2011; |
| |
| • | $300 million received in borrowings from WPZ’s $1.75 billion unsecured credit facility; |
| |
| • | $150 million paid to retire WPZ’s senior unsecured notes that matured in June 2011; |
| |
| • | We paid $457 million of quarterly dividends on common stock for the year ended December 31, 2011; |
| |
| • | $425 million in net borrowings and payments related to WPZ’s credit facility; |
| |
| • | We paid $214 million of dividends and distributions to noncontrolling interests. |
Investing activities
Significant transactions include:
2013
| |
| • | Capital expenditures totaled $3.572 billion for 2013; |
| |
| • | Purchases of and contributions to our equity method investments of $455 million. |
2012
| |
| • | Capital expenditures totaled $2.529 billion for 2012; |
| |
| • | Purchases of and contributions to our equity method investments of $2.7 billion, including $2.19 billion paid in December 2012 for our investment in Access Midstream Partners; |
| |
| • | $1.72 billion paid, net of purchase price adjustments, for WPZ’s Caiman Acquisition in April 2012; |
| |
| • | $325 million paid, net of cash acquired in the transaction, for WPZ’s Laser Acquisition in March 2012; |
| |
| • | $121 million received from the reconsolidation of the Wilpro entities (see Note 4 – Discontinued Operations of our Notes to Consolidated Financial Statements). |
2011
| |
| • | Capital expenditures totaled $2.796 billion in 2011; |
| |
| • | We contributed $137 million to our Laurel Mountain equity investment. |
Off-Balance Sheet Arrangements and Guarantees of Debt or Other Commitments
We have various other guarantees and commitments which are disclosed in Note 3 – Variable Interest Entities, Note 11 – Property, Plant, and Equipment, Note 13 – Debt, Banking Arrangements, and Leases, Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk, and Note 17 – Contingent Liabilities and Commitments of Notes to Consolidated Financial Statements. We do not believe these guarantees 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, 2013:
|
| | | | | | | | | | | | | | | | | | | |
| | 2014 | | 2015 - 2016 | | 2017 - 2018 | | Thereafter | | Total |
| | | | | | (Millions) | | | | |
| Long-term debt: | | | | | | | | | |
| Principal | $ | — |
| | $ | 1,125 |
| | $ | 1,285 |
| | $ | 8,980 |
| | $ | 11,390 |
|
| Interest | 624 |
| | 1,182 |
| | 1,026 |
| | 5,008 |
| | 7,840 |
|
| Commercial paper | 225 |
| | — |
| | — |
| | — |
| | 225 |
|
| Capital leases | 1 |
| | — |
| | — |
| | — |
| | 1 |
|
| Operating leases (1) | 54 |
| | 91 |
| | 66 |
| | 123 |
| | 334 |
|
| Purchase obligations (2) | 2,055 |
| | 519 |
| | 440 |
| | 938 |
| | 3,952 |
|
| Other obligations (3)(4) | 2 |
| | 2 |
| | — |
| | — |
| | 4 |
|
| Total | $ | 2,961 |
| | $ | 2,919 |
| | $ | 2,817 |
| | $ | 15,049 |
| | $ | 23,746 |
|
__________
| |
| (1) | Includes a right-of-way agreement with the Jicarilla Apache Nation. We are required to make a fixed annual payment of $8 million and an additional annual payment, which varies depending on per-unit NGL margins and the volume of gas gathered by our gathering facilities subject to the right-of-way agreement. The table above for years 2015 and thereafter does not include such variable amounts related to this agreement as the variable amount is not yet determinable. The variable portion to be paid in 2014 based on 2013 gathering volumes is $5 million and is included in the table for year 2014. |
| |
| (2) | Includes approximately $1.2 billion in open property, plant, and equipment purchase orders. Larger projects include Gulfstar One and the Oak Grove plant. Includes an estimated $621 million long-term ethane purchase obligation with index-based pricing terms that is reflected in this table at December 31, 2013 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 $953 million long-term NGL purchase obligation with index-based pricing terms that primarily supplies a third party at its plant and is valued in this table at a price calculated using December 31, 2013 prices. Any excess purchased volumes may be sold at comparable market 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).
| |
| (3) | Does not include estimated contributions to our pension and other postretirement benefit plans. We made contributions to our pension and other postretirement benefit plans of $100 million in 2013 and $92 million in 2012. In 2014, we expect to contribute approximately $71 million to these plans (see Note 9 – Employee Benefit Plans of Notes to Consolidated Financial Statements). Tax-qualified pension plans are required to meet minimum contribution requirements. In the past, we have contributed amounts to our tax-qualified pension plans in excess of the minimum required contribution. These excess amounts can be used to offset future minimum contribution requirements. During 2013, we contributed $90 million to our tax-qualified pension plans. In addition to these contributions, a portion of the excess contributions was used to meet the minimum contribution requirements. During 2014, we expect to contribute approximately $60 million to our tax-qualified pension plans and use excess amounts to satisfy minimum contribution requirements, if needed. Additionally, estimated future minimum funding requirements may vary significantly from historical requirements if actual results differ significantly from estimated results for assumptions such as returns on plan assets, interest rates, retirement rates, mortality, and other significant assumptions or by changes to current legislation and regulations. |
| |
| (4) | We have not included income tax liabilities in the table above. See Note 7 – Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of income taxes, including our contingent tax liability reserves. |
Effects of Inflation
Our operations have historically not been materially affected by inflation. Approximately 47 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 Organization of the Petroleum Exporting Countries (OPEC) production levels and/or 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 17 – 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 $47 million, all of which are included in Accrued liabilities and Other noncurrent liabilities on the Consolidated Balance Sheet at December 31, 2013. We will seek recovery of approximately $13 million of these accrued costs through future natural gas transmission rates. The remainder of these costs will be funded from operations. During 2013, we paid approximately $16 million for cleanup and/or remediation and monitoring activities. We expect to pay approximately $13 million in 2014 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, 2013, 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. However, in September 2009, the EPA announced it would reconsider the 2008 NAAQS for ground level ozone to ensure that the standards were clearly grounded in science and were protective of both public health and the environment. As a result, the EPA delayed designation of new eight-hour ozone nonattainment areas under the 2008 standards until the reconsideration is complete. In January 2010, the EPA proposed to further reduce the ground-level ozone NAAQS from the March 2008 levels. In September 2011, the EPA announced that it was proceeding with required actions to implement the 2008 ozone standard and area designations. In May 2012, the EPA completed designation of new eight-hour ozone nonattainment areas. Several Transco facilities are located in 2008 ozone nonattainment areas; however, each facility has been previously subjected to federal and/or state emission control requirements implemented to address the preceding ozone standards. To date, no new federal or state actions have been proposed to mandate additional emission controls at these facilities. At this time, it is unknown whether future federal or state regulatory actions associated with implementation of the 2008 ozone standard will impact our operations and increase the cost of additions to Property, plant and equipment – net on the Consolidated Balance Sheet. Until any additional federal or state regulatory actions are proposed, we are unable to estimate the cost of additions that may be required to meet this new regulation. Additionally, several nonattainment areas exist in or near areas where we have operating assets. States are required to develop implementation plans to bring these areas into compliance. Implementing regulations are 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.
In June 2010, the EPA promulgated a final rule establishing a new one-hour sulfur dioxide (SO2) NAAQS. The effective date of the new SO2 standard was August 23, 2010. The EPA has not adopted final modeling guidance. We are unable at this time to estimate the cost of additions that may be required to meet this new regulation.
On January 22, 2010, the EPA set a new one-hour nitrogen dioxide (NO2) NAAQS. The effective date of the new NO2 standard was April 12, 2010. This standard is subject to challenge in federal court. On January 20, 2012, the EPA determined pursuant to available information that no area in the country is violating the 2010 NO2 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 NO2 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 NO2 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 NO2 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 7A. Quantitative and Qualitative Disclosures About Market Risk
Interest Rate Risk
Our current interest rate risk exposure is related primarily to our debt portfolio. Our debt portfolio is primarily comprised of fixed rate debt, which mitigates the impact of fluctuations in interest rates. Any borrowings under our credit facilities and any issuances under WPZ’s commercial paper program could be at a variable interest rate and could expose us to the risk of increasing interest rates. The maturity of our long-term debt portfolio is partially influenced by the expected lives of our operating assets. (See Note 13 – Debt, Banking Arrangements, and Leases of Notes to Consolidated Financial Statements.)
The tables below provide information by maturity date about our interest rate risk-sensitive instruments as of December 31, 2013 and 2012. Long-term debt in the tables represents principal cash flows, net of (discount) premium, and weighted-average interest rates by expected maturity dates. The fair value of our publicly traded long-term debt is valued using indicative year-end traded bond market prices. Private debt is valued based on market rates and the prices of similar securities with similar terms and credit ratings.
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2014 | | 2015 | | 2016 | | 2017 | | 2018 | | Thereafter (1) | | Total | | Fair Value December 31, 2013 |
| | (Millions) |
| Long-term debt, including current portion: (2) | | | | | | | | | | | | | | | | |
| Fixed rate | $ | — |
| $ | 750 |
| $ | 375 |
| $ | 785 |
| $ | 500 |
| $ | 8,943 |
| $ | 11,353 |
| $ | 11,971 |
|
| Interest rate | | 5.5 | % | | 5.6 | % | | 5.6 | % | | 5.5 | % | | 5.4 | % | | 6.0 | % | | | | |
| Variable rate (3) | $ | 225 |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | 225 |
| $ | 225 |
|
| Interest rate (4) | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | 2013 | | 2014 | | 2015 | | 2016 | | 2017 | | Thereafter (1) | | Total | | Fair Value December 31, 2012 |
| | (Millions) |
| Long-term debt, including current portion: (2) | | | | | | | | | | | | | | | | |
| Fixed rate | $ | — |
| $ | — |
| $ | 750 |
| $ | 375 |
| $ | 785 |
| $ | 8,449 |
| $ | 10,359 |
| $ | 12,013 |
|
| Interest rate | | 5.5 | % | | 5.5 | % | | 5.6 | % | | 5.7 | % | | 5.6 | % | | 6.0 | % | | | | |
| Variable rate | $ | — |
| $ | — |
| $ | — |
| $ | 375 |
| $ | — |
| $ | — |
| $ | 375 |
| $ | 375 |
|
| Interest rate (4) | | | | | | | | | | | | | | | | |
__________________
| |
| (1) | Includes unamortized discount and premium. |
| |
| (2) | Excludes capital leases. |
| |
| (3) | Consists of Commercial paper. |
| |
| (4) | The weighted average interest rate was 0.42 percent and 2.7 percent at December 31, 2013 and 2012, respectively. |
Commodity Price Risk
We are exposed to the impact of fluctuations in the market price of NGLs, olefins, and natural gas, as well as other market factors, such as market volatility and energy commodity price correlations. We are exposed to these risks in connection with our owned energy-related assets, our long-term energy-related contracts, and limited proprietary trading activities. Our management of the risks associated with these market fluctuations includes maintaining a conservative capital structure and significant liquidity, as well as using various derivatives and nonderivative energy-related contracts. The fair value of derivative contracts is subject to many factors, including changes in energy commodity market prices, the liquidity and volatility of the markets in which the contracts are transacted, and changes in interest rates. At
December 31, 2013 and 2012, our derivative activity was not material. (See Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements.)
Foreign Currency Risk
Our foreign operations, whose functional currency is the local currency, are located primarily in Canada. Net assets of our foreign operations were approximately $1.12 billion and $899 million at December 31, 2013 and 2012, respectively. These investments have the potential to impact our financial position due to fluctuations in these local currencies arising from the process of translating the local functional currency into the U.S. dollar. As an example, a 20 percent change in the respective functional currencies against the U.S. dollar would have changed Total stockholders’ equity by approximately $224 million at December 31, 2013.
Item 8. Financial Statements and Supplementary Data
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders of
The Williams Companies, Inc.
We have audited the accompanying consolidated balance sheet of The Williams Companies, Inc. as of December 31, 2013 and 2012, and the related consolidated statements of income, comprehensive income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2013. Our audits also included the financial statement schedules listed in the index at Item 9.01(d), within this Exhibit 99.1. These financial statements and schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedules 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 Company has a 50 percent interest) or Access Midstream Partners, L.P. (“ACMP”) (a publicly traded master limited partnership in which the Company has a 50 percent general partner interest and a 23 percent limited partner interest). The Company’s investment in Gulfstream constituted one percent of the Company’s assets as of each of December 31, 2013 and 2012, and the Company’s equity earnings in the net income of Gulfstream constituted six, five, and five percent, respectively, of the Company’s income from continuing operations before income taxes for each of the three years in the period ended December 31, 2013. The Company’s investment in ACMP constituted eight percent of the Company’s assets as of December 31, 2013, and the Company’s equity earnings in the net income of ACMP constituted nine percent of the Company’s income from continuing operations before income taxes for the year ended December 31, 2013. Gulfstream’s and ACMP’s financial statements for the periods indicated above were audited by other auditors whose reports have been furnished to us, and our opinion, insofar as it relates to the amounts included for Gulfstream and ACMP for these periods, is based solely on the reports 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 reports of other auditors provide a reasonable basis for our opinion.
In our opinion, based on our audits and the reports of other auditors, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of The Williams Companies, Inc. at December 31, 2013 and 2012, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2013, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedules, when considered in relation to the basic financial statements taken as a whole, present fairly in all material respects the information set forth therein.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), The Williams Companies, Inc.’s internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework) and our report dated February 26, 2014, expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Tulsa, Oklahoma
February 26, 2014, except as it relates to the matter
discussed under Basis of Presentation - Canada dropdown
in Note 1 and Note 18, as to which the date is
May 22, 2014
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, 2013 and 2012, and the related statements of operations, comprehensive income, members' equity, and cash flows for each of the three years in the period ended December 31, 2013. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements based on our audits.
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. 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, 2013 and 2012, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2013, in conformity with accounting principles generally accepted in the United States of America.
/s/ Deloitte & Touche LLP
Houston, Texas
February 24, 2014
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of Access Midstream Partners GP, L.L.C., as General Partner of Access Midstream Partners, L.P. and the Unitholders:
In our opinion, the consolidated balance sheet of Access Midstream Partners, L.P. as of December 31, 2013, and the related consolidated statements of operations, of changes in partners’ capital and of cash flows for the year then ended (not presented herein) present fairly, in all material respects, the financial position of Access Midstream Partners, L.P. and its subsidiaries (the “Partnership) as of December 31, 2013, and the results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America. 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 audit. We conducted our audit of these statements 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
Tulsa, Oklahoma
February 21, 2014, except for Note 16 for the inclusion of the Guarantor Condensed Consolidating Financial Information which is dated March 3, 2014
The Williams Companies, Inc.
Consolidated Statement of Income
|
| | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2013 | | 2012 | | 2011 |
| | (Millions, except per-share amounts) |
| Revenues: | | | | | | |
| Service revenues | | $ | 2,939 |
|
| $ | 2,729 |
| | $ | 2,532 |
|
| Product sales | | 3,921 |
|
| 4,757 |
| | 5,398 |
|
| Total revenues | | 6,860 |
|
| 7,486 |
| | 7,930 |
|
| Costs and expenses: | |
|
|
| | |
| Product costs | | 3,027 |
|
| 3,496 |
| | 3,934 |
|
| Operating and maintenance expenses | | 1,097 |
|
| 1,027 |
| | 990 |
|
| Depreciation and amortization expenses | | 815 |
|
| 756 |
| | 661 |
|
| Selling, general, and administrative expenses | | 512 |
|
| 571 |
| | 477 |
|
| Other (income) expense – net | | 34 |
|
| 24 |
| | 1 |
|
| Total costs and expenses | | 5,485 |
|
| 5,874 |
| | 6,063 |
|
| Operating income (loss) | | 1,375 |
|
| 1,612 |
| | 1,867 |
|
| Equity earnings (losses) | | 134 |
|
| 111 |
| | 155 |
|
| Interest incurred |
| (611 | ) |
| (568 | ) | | (598 | ) |
| Interest capitalized |
| 101 |
|
| 59 |
| | 25 |
|
| Other investing income – net | | 81 |
|
| 77 |
| | 13 |
|
| Early debt retirement costs | | — |
| | — |
| | (271 | ) |
| Other income (expense) – net | | — |
|
| (2 | ) | | 11 |
|
| Income (loss) from continuing operations before income taxes | | 1,080 |
|
| 1,289 |
| | 1,202 |
|
| Provision (benefit) for income taxes | | 401 |
|
| 360 |
| | 124 |
|
| Income (loss) from continuing operations | | 679 |
|
| 929 |
| | 1,078 |
|
| Income (loss) from discontinued operations | | (11 | ) |
| 136 |
| | (417 | ) |
| Net income (loss) | | 668 |
|
| 1,065 |
| | 661 |
|
| Less: Net income attributable to noncontrolling interests | | 238 |
|
| 206 |
| | 285 |
|
| Net income (loss) attributable to The Williams Companies, Inc. | | $ | 430 |
|
| $ | 859 |
| | $ | 376 |
|
| Amounts attributable to The Williams Companies, Inc.: | | | | | | |
| Income (loss) from continuing operations | | $ | 441 |
| | $ | 723 |
| | $ | 803 |
|
| Income (loss) from discontinued operations | | (11 | ) | | 136 |
| | (427 | ) |
| Net income (loss) | | $ | 430 |
| | $ | 859 |
| | $ | 376 |
|
| Basic earnings (loss) per common share: | | | | | | |
| Income (loss) from continuing operations | | $ | .65 |
| | $ | 1.17 |
| | $ | 1.36 |
|
| Income (loss) from discontinued operations | | (.02 | ) | | .22 |
| | (.72 | ) |
| Net income (loss) | | $ | .63 |
| | $ | 1.39 |
| | $ | .64 |
|
| Weighted-average shares (thousands) | | 682,948 |
| | 619,792 |
| | 588,553 |
|
| Diluted earnings (loss) per common share: | | | | | | |
| Income (loss) from continuing operations | | $ | .64 |
| | $ | 1.15 |
| | $ | 1.34 |
|
| Income (loss) from discontinued operations | | (.02 | ) | | .22 |
| | (.71 | ) |
| Net income (loss) | | $ | .62 |
| | $ | 1.37 |
| | $ | .63 |
|
| Weighted-average shares (thousands) | | 687,185 |
| | 625,486 |
| | 598,175 |
|
See accompanying notes.
The Williams Companies, Inc.
Consolidated Statement of Comprehensive Income
|
| | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2013 | | 2012 | | 2011 |
| | | (Millions) |
| Net income (loss) | | $ | 668 |
| | $ | 1,065 |
| | $ | 661 |
|
| Other comprehensive income (loss): | | | | | | |
| Cash flow hedging activities: | | | | | | |
| Net unrealized gain (loss) from derivative instruments, net of taxes of ($7) and ($152) in 2012 and 2011, respectively | | 1 |
| | 22 |
| | 243 |
|
| Reclassifications into earnings of net derivative instruments (gain) loss, net of taxes of $7 and $124 in 2012 and 2011, respectively | | (1 | ) | | (23 | ) | | (190 | ) |
| Foreign currency translation adjustments, net of taxes of $24 in 2013 | | (41 | ) | | 22 |
| | (18 | ) |
| Pension and other postretirement benefits: | | | | | | |
| Prior service credit arising during the year, net of taxes of ($9), ($1) and ($1) in 2013, 2012 and 2011, respectively (Note 9) | | 14 |
| | 1 |
| | 1 |
|
| Amortization of prior service cost (credit) included in net periodic benefit cost, net of taxes of $1 in 2013, 2012, and 2011 | | (2 | ) | | (1 | ) | | (2 | ) |
| Net actuarial gain (loss) arising during the year, net of taxes of ($111), $19 and $89 in 2013, 2012 and 2011, respectively (Note 9) | | 189 |
| | (30 | ) | | (152 | ) |
| Amortization of actuarial (gain) loss included in net periodic benefit cost, net of taxes of ($23), ($22) and ($16) in 2013, 2012 and 2011, respectively | | 38 |
| | 39 |
| | 27 |
|
| Equity Securities: | | | | | | |
| Unrealized gain (loss) on equity securities, net of taxes of ($2) in 2011 | | — |
| | — |
| | 3 |
|
| Reclassifications into earnings of (gain) loss on sale of equity securities, net of taxes of $2 in 2012 | | — |
| | (3 | ) | | — |
|
| Other comprehensive income (loss) | | 198 |
| | 27 |
| | (88 | ) |
| Comprehensive income (loss) | | 866 |
| | 1,092 |
| | 573 |
|
| Less: Comprehensive income (loss) attributable to noncontrolling interests | | 238 |
| | 206 |
| | 285 |
|
| Comprehensive income (loss) attributable to The Williams Companies, Inc. | | $ | 628 |
| | $ | 886 |
| | $ | 288 |
|
See accompanying notes.
The Williams Companies, Inc.
Consolidated Balance Sheet
|
| | | | | | | | |
| | | December 31, |
| | | 2013 | | 2012 |
| | | (Millions, except per-share amounts) |
| ASSETS | | | | |
| Current assets: | | | | |
| Cash and cash equivalents | | $ | 681 |
| | $ | 839 |
|
| Accounts and notes receivable, net: | | | | |
| Trade and other | | 600 |
| | 620 |
|
| Income tax receivable | | 74 |
| | 68 |
|
| Deferred income tax asset | | 27 |
| | 117 |
|
| Inventories | | 194 |
| | 175 |
|
| Other current assets and deferred charges | | 107 |
| | 105 |
|
| Total current assets | | 1,683 |
| | 1,924 |
|
| | | | | |
| Investments | | 4,360 |
| | 3,987 |
|
| Property, plant, and equipment – net | | 18,210 |
| | 15,467 |
|
| Goodwill | | 646 |
| | 649 |
|
| Other intangible assets | | 1,644 |
| | 1,704 |
|
| Regulatory assets, deferred charges, and other | | 599 |
| | 596 |
|
| Total assets | | $ | 27,142 |
| | $ | 24,327 |
|
| | | | | |
| LIABILITIES AND EQUITY | | | | |
| Current liabilities: | | | | |
| Accounts payable | | $ | 960 |
| | $ | 920 |
|
| Accrued liabilities | | 797 |
| | 628 |
|
| Commercial paper | | 225 |
| | — |
|
| Long-term debt due within one year | | 1 |
| | 1 |
|
| Total current liabilities | | 1,983 |
| | 1,549 |
|
| | | | | |
| Long-term debt | | 11,353 |
| | 10,735 |
|
| Deferred income taxes | | 3,529 |
| | 2,841 |
|
| Other noncurrent liabilities | | 1,356 |
| | 1,775 |
|
| Contingent liabilities and commitments (Note 17) | |
| |
|
| | | | | |
| Equity: | | | | |
| Stockholders’ equity: | | | | |
Common stock (960 million shares authorized at $1 par value; 718 million shares issued at December 31, 2013 and 716 million shares issued at December 31, 2012) | | 718 |
| | 716 |
|
| Capital in excess of par value | | 11,599 |
| | 11,134 |
|
| Retained deficit | | (6,248 | ) | | (5,695 | ) |
| Accumulated other comprehensive income (loss) | | (164 | ) | | (362 | ) |
| Treasury stock, at cost (35 million shares of common stock) | | (1,041 | ) | | (1,041 | ) |
| Total stockholders’ equity | | 4,864 |
| | 4,752 |
|
| Noncontrolling interests in consolidated subsidiaries | | 4,057 |
| | 2,675 |
|
| Total equity | | 8,921 |
| | 7,427 |
|
| Total liabilities and equity | | $ | 27,142 |
| | $ | 24,327 |
|
See accompanying notes.
The Williams Companies, Inc.
Consolidated Statement of Changes in Equity
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | The Williams Companies, Inc., Stockholders | | | | |
| | Common Stock | | Capital in Excess of Par Value | | Retained Deficit | | Accumulated Other Comprehensive Income (Loss) | | Treasury Stock | | Total Stockholders’ Equity | | Noncontrolling Interests | | Total |
| | (Millions) |
| Balance – December 31, 2010 | $ | 620 |
| | $ | 7,784 |
| | $ | (478 | ) | | $ | (82 | ) | | $ | (1,041 | ) | | $ | 6,803 |
| | $ | 1,331 |
| | $ | 8,134 |
|
| Net income (loss) | — |
| | — |
| | 376 |
| | — |
| | — |
| | 376 |
| | 285 |
| | 661 |
|
| Other comprehensive income (loss) | — |
| | — |
| | — |
| | (88 | ) | | — |
| | (88 | ) | | — |
| | (88 | ) |
| Cash dividends – common stock (Note 14) | — |
| | — |
| | (457 | ) | | — |
| | — |
| | (457 | ) | | — |
| | (457 | ) |
| Dividends and distributions to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (214 | ) | | (214 | ) |
| Issuance of common stock from debentures conversion | 1 |
| | 13 |
| | — |
| | — |
| | — |
| | 14 |
| | — |
| | 14 |
|
| Stock-based compensation and related common stock issuances, net of tax | 4 |
| | 104 |
| | — |
| | — |
| | — |
| | 108 |
| | — |
| | 108 |
|
| Changes in Williams Partners L.P. ownership interests, net | — |
| | 18 |
| | — |
| | — |
| | — |
| | 18 |
| | (30 | ) | | (12 | ) |
| Distribution of WPX Energy, Inc. to stockholders (Note 4) | — |
| | — |
| | (5,261 | ) | | (219 | ) | | — |
| | (5,480 | ) | | (81 | ) | | (5,561 | ) |
| Other | 1 |
| | 1 |
| | — |
| | — |
| | — |
| | 2 |
| | (1 | ) | | 1 |
|
| Balance – December 31, 2011 | 626 |
| | 7,920 |
| | (5,820 | ) | | (389 | ) | | (1,041 | ) | | 1,296 |
| | 1,290 |
| | 2,586 |
|
| Net income (loss) | — |
| | — |
| | 859 |
| | — |
| | — |
| | 859 |
| | 206 |
| | 1,065 |
|
| Other comprehensive income (loss) | — |
| | — |
| | — |
| | 27 |
| | — |
| | 27 |
| | — |
| | 27 |
|
| Cash dividends – common stock (Note 14) | — |
| | — |
| | (742 | ) | | — |
| | — |
| | (742 | ) | | — |
| | (742 | ) |
| Dividends and distributions to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (387 | ) | | (387 | ) |
| Issuance of common stock from debentures conversion | 1 |
| | 5 |
| | — |
| | — |
| | — |
| | 6 |
| | — |
| | 6 |
|
| Stock-based compensation and related common stock issuances, net of tax | 6 |
| | 98 |
| | — |
| | — |
| | — |
| | 104 |
| | — |
| | 104 |
|
| Sales of limited partner units of Williams Partners L.P. | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 1,559 |
| | 1,559 |
|
| Issuances of limited partner units of Williams Partners L.P. related to acquisitions | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 1,044 |
| | 1,044 |
|
| Changes in Williams Partners L.P. ownership interest, net | — |
| | 699 |
| | — |
| | — |
| | — |
| | 699 |
| | (1,115 | ) | | (416 | ) |
| Sales of common stock (Note 14) | 83 |
| | 2,412 |
| | — |
| | — |
| | — |
| | 2,495 |
| | — |
| | 2,495 |
|
| Reconsolidation of noncontrolling interest in Wilpro entities (Note 4) | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 65 |
| | 65 |
|
| Contributions from noncontrolling interest | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 14 |
| | 14 |
|
| Other | — |
| | — |
| | 8 |
| | — |
| | — |
| | 8 |
| | (1 | ) | | 7 |
|
| Balance – December 31, 2012 | 716 |
| | 11,134 |
| | (5,695 | ) | | (362 | ) | | (1,041 | ) | | 4,752 |
| | 2,675 |
| | 7,427 |
|
| Net income (loss) | — |
| | — |
| | 430 |
| | — |
| | — |
| | 430 |
| | 238 |
| | 668 |
|
| Other comprehensive income (loss) | — |
| | — |
| | — |
| | 198 |
| | — |
| | 198 |
| | — |
| | 198 |
|
| Cash dividends – common stock (Note 14) | — |
| | — |
| | (982 | ) | | — |
| | — |
| | (982 | ) | | — |
| | (982 | ) |
| Dividends and distributions to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (489 | ) | | (489 | ) |
| Issuance of common stock from debentures conversion | — |
| | 1 |
| | — |
| | — |
| | — |
| | 1 |
| | — |
| | 1 |
|
| Stock-based compensation and related common stock issuances, net of tax | 2 |
| | 54 |
| | — |
| | — |
| | — |
| | 56 |
| | — |
| | 56 |
|
| Sales of limited partner units of Williams Partners L.P. | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 1,819 |
| | 1,819 |
|
| Changes in ownership of consolidated subsidiaries, net | — |
| | 409 |
| | — |
| | — |
| | — |
| | 409 |
| | (652 | ) | | (243 | ) |
| Contributions from noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 467 |
| | 467 |
|
| Other | — |
| | 1 |
| | (1 | ) | | — |
| | — |
| | — |
| | (1 | ) | | (1 | ) |
| Balance – December 31, 2013 | $ | 718 |
| | $ | 11,599 |
| | $ | (6,248 | ) | | $ | (164 | ) | | $ | (1,041 | ) | | $ | 4,864 |
| | $ | 4,057 |
| | $ | 8,921 |
|
See accompanying notes.
The Williams Companies, Inc.
Consolidated Statement of Cash Flows
|
| | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2013 | | 2012 | | 2011 |
| | | (Millions) |
| OPERATING ACTIVITIES: | | | | | | |
| Net income (loss) | | $ | 668 |
| | $ | 1,065 |
| | $ | 661 |
|
| Adjustments to reconcile to net cash provided (used) by operating activities: | | | | | | |
| Depreciation, depletion, and amortization | | 815 |
| | 756 |
| | 1,614 |
|
| Provision (benefit) for deferred income taxes | | 424 |
| | 206 |
| | (179 | ) |
| Provision for loss on investments, property, and other assets | | — |
| | — |
| | 882 |
|
| Net (gain) loss on dispositions of assets | | 28 |
| | (52 | ) | | (1 | ) |
| Gain on reconsolidation of Wilpro entities (Note 4) | | — |
| | (144 | ) | | — |
|
| Amortization of stock-based awards | | 37 |
| | 36 |
| | 52 |
|
| Early debt retirement costs | | — |
| | — |
| | 271 |
|
| Cash provided (used) by changes in current assets and liabilities: | | | | | | |
| Accounts and notes receivable | | 35 |
| | 27 |
| | (197 | ) |
| Inventories | | (17 | ) | | 5 |
| | 60 |
|
| Other current assets and deferred charges | | 25 |
| | 29 |
| | (15 | ) |
| Accounts payable | | (35 | ) | | (110 | ) | | 250 |
|
| Accrued liabilities | | 175 |
| | — |
| | 51 |
|
| Other, including changes in noncurrent assets and liabilities | | 62 |
| | 17 |
| | (10 | ) |
| Net cash provided (used) by operating activities | | 2,217 |
| | 1,835 |
| | 3,439 |
|
| FINANCING ACTIVITIES: | | | | | | |
| Proceeds from (payments of) commercial paper – net | | 224 |
| | — |
| | — |
|
| Proceeds from long-term debt | | 2,699 |
| | 3,486 |
| | 3,172 |
|
| Payments of long-term debt | | (2,081 | ) | | (1,468 | ) | | (2,055 | ) |
| Proceeds from issuance of common stock | | 18 |
| | 2,550 |
| | 49 |
|
| Proceeds from sale of limited partner units of consolidated partnership | | 1,819 |
| | 1,559 |
| | — |
|
| Dividends paid | | (982 | ) | | (742 | ) | | (457 | ) |
| Dividends and distributions paid to noncontrolling interests | | (489 | ) | | (349 | ) | | (214 | ) |
| Distributions paid to noncontrolling interests on sale of Wilpro assets (Note 4) | | — |
| | (38 | ) | | — |
|
| Contributions from noncontrolling interests | | 467 |
| | 13 |
| | — |
|
| Cash of WPX Energy, Inc. at spin-off | | — |
| | — |
| | (526 | ) |
| Premiums paid on early debt retirements | | — |
| | — |
| | (254 | ) |
| Other – net | | 2 |
| | 25 |
| | (57 | ) |
| Net cash provided (used) by financing activities | | 1,677 |
| | 5,036 |
| | (342 | ) |
| INVESTING ACTIVITIES: | | | | | | |
| Capital expenditures (1) | | (3,572 | ) | | (2,529 | ) | | (2,796 | ) |
| Purchases of and contributions to equity method investments | | (455 | ) | | (2,651 | ) | | (211 | ) |
| Purchases of businesses | | (6 | ) | | (2,049 | ) | | (41 | ) |
| Proceeds from dispositions of investments | | — |
| | 79 |
| | 16 |
|
| Cash of Wilpro entities upon reconsolidation (Note 4) | | — |
| | 121 |
| | — |
|
| Other – net | | (19 | ) | | 108 |
| | 29 |
|
| Net cash provided (used) by investing activities | | (4,052 | ) | | (6,921 | ) | | (3,003 | ) |
| Increase (decrease) in cash and cash equivalents | | (158 | ) | | (50 | ) | | 94 |
|
| Cash and cash equivalents at beginning of year | | 839 |
| | 889 |
| | 795 |
|
| Cash and cash equivalents at end of year | | $ | 681 |
| | $ | 839 |
| | $ | 889 |
|
| _________ | | | | | | |
| (1) Increases to property, plant, and equipment | | $ | (3,653 | ) | | $ | (2,755 | ) | | $ | (2,953 | ) |
| Changes in related accounts payable and accrued liabilities | | 81 |
| | 226 |
| | 157 |
|
| Capital expenditures | | $ | (3,572 | ) | | $ | (2,529 | ) | | $ | (2,796 | ) |
See accompanying notes.
|
| | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements |
| |
Note 1 – Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies
Description of Business
We are a Delaware corporation whose common stock is listed and traded on the New York Stock Exchange. Our operations are located principally in the United States and are organized into the Williams Partners, Williams NGL & Petchem Services, and Access Midstream Partners reportable segments. All remaining business activities are included in Other.
Williams Partners consists of our consolidated master limited partnership, Williams Partners L.P. (WPZ), and includes gas pipeline and domestic midstream businesses. The gas pipeline businesses primarily consist of two interstate natural gas pipelines, which are Transcontinental Gas Pipe Line Company, LLC (Transco) and Northwest Pipeline LLC (Northwest Pipeline), a 50 percent equity investment in Gulfstream Natural Gas System, L.L.C. (Gulfstream), and a 41 percent interest in Constitution Pipeline Company, LLC (Constitution) (a consolidated entity). WPZ’s midstream operations are composed of significant, large-scale operations in the Rocky Mountain and Gulf Coast regions, operations in the Marcellus Shale region, and various equity investments in domestic natural gas gathering and processing assets and natural gas liquid (NGL) fractionation and transportation assets. WPZ’s midstream assets also include an NGL fractionator and storage facilities near Conway, Kansas, as well as an NGL light-feed olefins cracker in Geismar, Louisiana, along with associated ethane and propane pipelines, a refinery grade splitter in Louisiana, an oil sands offgas processing plant located near Fort McMurray, Alberta, and an NGL/olefin fractionation facility and butylene/butane splitter facility at Redwater, Alberta.
Williams NGL & Petchem Services consists primarily of a 50 percent interest in Bluegrass Pipeline Company LLC (Bluegrass Pipeline) (a consolidated entity) (see Note 19 – Subsequent Events) and certain domestic olefins pipeline assets and Canadian facilities under development.
Access Midstream Partners consists of our equity investment in Access Midstream Partners, L.P. (ACMP). As of December 31, 2013, this investment includes an indirect 50 percent interest in Access Midstream Partners, GP, L.L.C. (Access GP), including incentive distribution rights, and a 23 percent limited partner interest in ACMP. ACMP is a publicly traded master limited partnership that provides gathering, treating, and compression services to producers under long-term, fee-based contracts. Access GP is the general partner of ACMP.
Other includes other business activities that are not operating segments, as well as corporate operations.
Basis of Presentation
Canada dropdown
In February 2014, we contributed certain Canadian operations to WPZ (Canada Dropdown) for total consideration of $25 million of cash from WPZ (subject to certain closing adjustments), 25,577,521 WPZ Class D limited-partner units, and an increase in the capital account of its general partner to allow us to maintain our 2 percent general partner interest. In lieu of cash distributions, the Class D units will receive quarterly distributions of additional paid-in-kind Class D units. All Class D units outstanding will be convertible to common units beginning in the first quarter of 2016. The contribution agreement governing the Canada Dropdown provides that WPZ can issue additional Class D units to us on a quarterly basis through 2015 for up to a total of $200 million in cash for the purpose of funding certain facility expansions. These operations were previously reported within the Williams NGL & Petchem Services segment, but are now reported within Williams Partners. Segment disclosures for all periods presented have been recast for this transaction.
Consolidated master limited partnership
During the first quarter of 2013, WPZ completed equity issuances of 15,937,500 common units representing limited partner interests, including 3,000,000 common units sold to us in a private placement transaction. In the third quarter
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
of 2013, WPZ completed equity issuances of 24,725,000 common units representing limited partner interests. Following these transactions, we own approximately 64 percent of the interests in WPZ, including the interests of the general partner, which is wholly owned by us, and incentive distribution rights as of December 31, 2013.
The previously described equity issuances by WPZ had the combined net impact of increasing our Noncontrolling interests in consolidated subsidiaries by $1.169 billion, Capital in excess of par value by $408 million and Deferred income taxes by $242 million in the Consolidated Balance Sheet.
WPZ is self-funding and maintains separate lines of bank credit and cash management accounts. WPZ also initiated its commercial paper program in the first quarter of 2013. (See Note 13 – Debt, Banking Arrangements, and Leases.) Cash distributions from WPZ to us, including any associated with our incentive distribution rights, occur through the normal partnership distributions from WPZ to all partners.
Discontinued operations
On December 31, 2011, we completed the tax-free spin-off of our 100 percent interest in WPX Energy, Inc. (WPX), to our stockholders. The spin-off was completed by means of a special stock dividend, which consisted of a distribution of one share of WPX common stock for every three shares of our common stock. For periods prior to the spin-off, the accompanying Consolidated Statement of Income reflects the results of operations of our former exploration and production business as discontinued operations. The Consolidated Statement of Comprehensive Income and the Consolidated Statement of Cash Flows for 2011 includes the results of our former exploration and production business. (See Note 4 – Discontinued Operations.)
The discontinued operations presented in the accompanying consolidated financial statements and notes reflect gains in 2012 associated with certain of our former Venezuela operations. (See Note 4 – Discontinued Operations.)
Unless indicated otherwise, the information in the Notes to Consolidated Financial Statements relates to our continuing operations.
Related party transaction
A member of our Board of Directors, who was elected in 2013, is also the current chairman, president, and chief executive officer of an energy services company that is a customer of ours. We recorded $131 million in Service revenues in the Consolidated Statement of Income from this company for transportation and storage of natural gas for the year ended December 31, 2013. This board member does not have any material interest in any transactions between the energy services company and us and he had no role in any such transactions.
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 ventures in which we own an undivided interest. Management 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; |
|
| | | | |
| The Williams Companies, Inc. |
| 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 in entities over which we exercise significant influence but do not control.
Equity-method investment basis differences
Differences between the cost of our equity 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 Income 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; |
| |
| • | Realization of deferred income tax assets; |
| |
| • | Depreciation and/or amortization of equity-method investment basis differences; |
| |
| • | Asset retirement obligations; |
| |
| • | Pension and postretirement valuation variables; |
| |
| • | Acquisition related purchase price allocations. |
These estimates are discussed further throughout these notes.
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 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. 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 postretirement benefits. Our current and noncurrent regulatory asset and liability balances for the years ended December 31, 2013 and 2012 are as follows:
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| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
|
| | | | | | | |
| | December 31, |
| | 2013 | | 2012 |
| | (Millions) |
Current assets reported within Other current assets and deferred charges | $ | 39 |
| | $ | 39 |
|
Noncurrent assets reported within Regulatory assets, deferred charges, and other | 353 |
| | 366 |
|
| Total regulated assets | $ | 392 |
| | $ | 405 |
|
| | | | |
Current liabilities reported within Accrued liabilities | $ | 19 |
| | $ | 15 |
|
Noncurrent liabilities reported within Other noncurrent liabilities | 329 |
| | 250 |
|
| Total regulated liabilities | $ | 348 |
| | $ | 265 |
|
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 the 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.
Inventory valuation
All Inventories in the Consolidated Balance Sheet are stated at the lower of cost or market. The cost of inventories is primarily determined using the average-cost method.
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 a declining balance method. (See Note 11 – Property, Plant, and Equipment.)
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 Income.
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. We measure changes in the liability due to passage of time by applying an interest method of allocation. 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
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| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
Statement of Income, except for regulated entities, for which the liability is offset by a regulatory asset as management expects to recover amounts in future rates. 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 in the Consolidated Balance Sheet represents the excess cost over fair value of the net assets of businesses 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.
Other intangible assets
Our identifiable intangible assets are primarily related to gas gathering, processing and fractionation contracts, and relationships with customers. 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.
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.
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| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
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 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 facilities and commercial paper program
Proceeds and payments related to borrowings under our credit facilities 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 13 – Debt, Banking Arrangements, and Leases.)
Treasury stock
Treasury stock purchases are accounted for under the cost method whereby the entire cost of the acquired stock is recorded as Treasury stock in the Consolidated Balance Sheet. Gains and losses on the subsequent reissuance of shares are credited or charged to Capital in excess of par value in the Consolidated Balance Sheet using the average-cost method.
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 physical energy commodities. We report the fair value of derivatives, except for 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; Accrued liabilities, or Other noncurrent liabilities 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 16 – 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
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| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
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 Income.
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 Income. 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 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 Income 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 Income.
Certain gains and losses on derivative instruments included in the Consolidated Statement of Income 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. In reaching our conclusions on this presentation, we considered whether we act as principal in the transaction; whether we have the risks and rewards of ownership, including credit risk; and whether we have latitude in establishing prices.
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 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 and processing services and are performed under volumetric-based fee contracts. These revenues are recorded when services have been performed.
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.
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| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
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.
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 business has processing and fractionation operations where we retain certain NGLs and olefins from an upgrader’s offgas stream and we recognize revenues when the fractionated products are 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. The latter is included in Other income (expense) – net below Operating income (loss) in the Consolidated Statement of Income. 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 stock-based awards
We recognize compensation expense on employee stock-based awards, net of estimated forfeitures, on a straight-line basis. (See Note 15 – Stock-Based Compensation.)
Pension and other postretirement benefits
The funded status of each of the pension and other postretirement benefit plans is recognized separately in the Consolidated Balance Sheet as either an asset or liability. The funded status is the difference between the fair value of plan assets and the plan’s benefit obligation. The plans’ benefit obligations and net periodic benefit costs are actuarially determined and impacted by various assumptions and estimates. (See Note 9 – Employee Benefit Plans.)
The discount rates are determined separately for each of our pension and other postretirement benefit plans based on an approach specific to our plans. The year-end discount rates are determined considering a yield curve comprised of high-quality corporate bonds and the timing of the expected benefit cash flows of each plan.
The expected long-term rates of return on plan assets are determined by combining a review of the historical returns within the portfolio, the investment strategy included in the plans’ investment policy statement, and capital market projections for the asset classes in which the portfolio is invested, as well as the weighting of each asset class.
Unrecognized actuarial gains and losses and unrecognized prior service costs and credits are deferred and recorded in accumulated other comprehensive income or, for Transco and Northwest Pipeline, as a regulatory asset or liability, until amortized as a component of net periodic benefit cost. Unrecognized actuarial gains and losses in excess of 10
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| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
percent of the greater of the benefit obligation or the market-related value of plan assets are amortized over the participants’ average remaining future years of service, which is approximately 12 years for our pension plans and approximately 8 years for our other postretirement benefit plans. Unrecognized prior service costs and credits for the other postretirement benefit plans are amortized on a straight line basis over the average remaining years of service to eligibility for eligible plan participants, which is approximately 5 years.
The expected return on plan assets component of net periodic benefit cost is calculated using the market-related value of plan assets. For our pension plans, the market-related value of plan assets is equal to the fair value of plan assets adjusted to reflect the amortization of gains or losses associated with the difference between the expected and actual return on plan assets over a 5-year period. Additionally, the market-related value of assets may be no more than 110 percent or less than 90 percent of the fair value of plan assets at the beginning of the year. The market-related value of plan assets for our other postretirement benefit plans is equal to the unadjusted fair value of plan assets at the beginning of the year.
Income taxes
We include the operations of our domestic corporate subsidiaries and income from our domestic subsidiary partnerships in our consolidated federal income tax return and also file tax returns in various foreign and state jurisdictions as required. Deferred income taxes are computed using the liability method and are provided on all temporary differences between the financial basis and the tax basis of our 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 share
Basic earnings (loss) per common share in the Consolidated Statement of Income is based on the sum of the weighted-average number of common shares outstanding and vested restricted stock units. Diluted earnings (loss) per common share in the Consolidated Statement of Income includes any dilutive effect of stock options, nonvested restricted stock units, and convertible debt, unless otherwise noted. Beginning in 2012, we have unvested service-based restricted stock units that contain a nonforfeitable right to dividends during the vesting period and are considered participating securities. Basic and diluted earnings (loss) per common share are calculated using the two-class method and the treasury-stock method. Whichever method results in the most dilutive earnings (loss) per common share is reported.
Foreign currency translation
Certain of our foreign subsidiaries use the Canadian dollar as their functional currency. Assets and liabilities of such foreign subsidiaries are translated at the spot rate in effect at the applicable reporting date, and the combined statements of income are translated into the U.S. dollar at the average exchange rates in effect during the applicable period. The resulting cumulative translation adjustment is recorded as a separate component of AOCI.
Transactions denominated in currencies other than the functional currency are recorded based on exchange rates at the time such transactions arise. Subsequent changes in exchange rates when the transactions are settled result in transaction gains and losses which are reflected in the Consolidated Statement of Income.
Note 2 – Acquisitions, Goodwill, and Other Intangible Assets
Business Combinations
On February 17, 2012, WPZ completed the acquisition of 100 percent of the ownership interests in certain entities from Delphi Midstream Partners, LLC, in exchange for $325 million in cash, net of cash acquired in the transaction, and 7,531,381 WPZ common units valued at $441 million (Laser Acquisition). The fair value of the common units issued as part of the consideration paid was determined on the basis of the closing market price of WPZ’s common units on the acquisition date, adjusted to reflect certain time-based restrictions on resale. The acquired entities primarily own the Laser Gathering System, which is comprised of a natural gas pipeline and associated gathering facilities in the Marcellus Shale in Susquehanna County, Pennsylvania, as well as gathering lines in southern New York.
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| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
On April 27, 2012, WPZ completed the acquisition of 100 percent of the ownership interests in Caiman Eastern Midstream, LLC, from Caiman Energy, LLC in exchange for $1.72 billion in cash and 11,779,296 WPZ common units valued at $603 million (Caiman Acquisition). The fair value of the common units issued as part of the consideration paid was determined on the basis of the closing market price of WPZ’s common units on the acquisition date, adjusted to reflect certain time-based restrictions on resale. The acquired entity operates a gathering and processing business in northern West Virginia, southwestern Pennsylvania, and eastern Ohio. Acquisition transaction costs of $16 million were incurred during 2012 related to the Caiman Acquisition and are reported in Selling, general, and administrative expenses at Williams Partners in the Consolidated Statement of Income.
The following table presents the allocation of the acquisition-date fair value of the major classes of the net assets, which are included in the Williams Partners segment:
|
| | | | | | | |
| | Laser | | Caiman |
| | (Millions) |
| Assets held-for-sale | $ | 18 |
| | $ | — |
|
| Other current assets | 3 |
| | 16 |
|
| Property, plant, and equipment | 158 |
| | 656 |
|
| Intangible assets: | | | |
| Customer contracts | 316 |
| | 1,141 |
|
| Customer relationships | — |
| | 250 |
|
| Other | 2 |
| | 2 |
|
| Current liabilities | (21 | ) | | (94 | ) |
| Noncurrent liabilities | — |
| | (3 | ) |
| Identifiable net assets acquired | 476 |
| | 1,968 |
|
| Goodwill | 290 |
| | 356 |
|
| | $ | 766 |
| | $ | 2,324 |
|
Revenues and earnings related to the Laser and Caiman Acquisitions included within the Consolidated Statement of Income in 2012 are not material. Supplemental pro forma revenue and earnings for the pre-acquisition periods reflecting these acquisitions as if they had occurred as of January 1, 2011, are not materially different from the information presented in our accompanying Consolidated Statement of Income (since the historical operations of these acquisitions were insignificant relative to our historical operations) and are, therefore, not presented.
Goodwill and Other Intangible Assets
Goodwill
The Laser and Caiman Acquisitions were accounted for as business combinations which, among other things, require assets acquired and liabilities assumed to be measured at their acquisition-date fair values. The excess of cost over those fair values was recorded as goodwill and allocated to WPZ’s Northeast gathering and processing business (the reporting unit) within the Williams Partners segment. Goodwill recognized in the acquisitions relates primarily to enhancing our strategic platform for expansion in the Marcellus and Utica shale plays in the Appalachian basin area. Substantially all of the goodwill is expected to be deductible for tax purposes. Our annual goodwill impairment review did not result in a goodwill impairment in 2013.
Other Intangible Assets
Other intangible assets primarily relate to gas gathering, processing and fractionation contracts and relationships with customers recognized in the Laser and Caiman Acquisitions. The basis for determining the value of these intangible assets was estimated future net cash flows to be derived from acquired customer contracts and relationships, which were offset with appropriate charges for the use of contributory assets and discounted using a risk-adjusted discount
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| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
rate. The 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 customer contracts and relationships are expected to contribute to our cash flows.
The gross carrying amount and accumulated amortization of Other intangible assets at December 31 are as follows:
|
| | | | | | | | | | | | | | | |
| | 2013 | | 2012 |
| | Gross Carrying Amount | | Accumulated Amortization | | Gross Carrying Amount | | Accumulated Amortization |
| | (Millions) |
| Customer contracts | $ | 1,493 |
| | $ | (88 | ) | | $ | 1,493 |
| | $ | (38 | ) |
| Customer relationships | 250 |
| | (14 | ) | | 250 |
| | (6 | ) |
| Other | 6 |
| | (3 | ) | | 6 |
| | (1 | ) |
| Total | $ | 1,749 |
| | $ | (105 | ) | | $ | 1,749 |
| | $ | (45 | ) |
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 customer contracts associated with the Laser and Caiman Acquisitions were approximately 9 years and 18 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 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 investments required.
The aggregate amortization expense related to Other intangible assets was $60 million, $43 million, and $2 million in 2013, 2012 and 2011, respectively. The estimated amortization expense for each of the next five succeeding fiscal years is approximately $60 million.
Purchase of Investment
On December 20, 2012, we purchased an indirect interest in Access GP and limited partner interests in ACMP (collectively referred to as Access Midstream Partners) for approximately $2.19 billion in cash, including transaction costs. We own a 50 percent interest in Access Midstream Ventures, L.L.C., which owns Access GP and its 2 percent general partner interest in ACMP and incentive distribution rights. Also as part of this transaction, we purchased approximately 24 percent of ACMP’s outstanding limited partnership units. ACMP is a publicly traded master limited partnership listed on the New York Stock Exchange that owns, operates, develops, and acquires natural gas gathering systems and other midstream energy assets, which bolsters our position in the Marcellus and Utica shale plays and adds diversity via the Eagle Ford, Haynesville, Barnett, Mid-Continent, and Niobrara areas.
We account for these acquired interests as equity-method investments. The initial difference between the cost of our investment and our proportional share of the underlying equity in the net assets of Access Midstream Partners of $1.27 billion is primarily related to property, plant, and equipment, as well as customer-based intangible assets and goodwill. The portions of the difference related to the property, plant, and equipment and customer-based intangible assets are being depreciated or amortized as appropriate on a straight-line basis as an adjustment to our equity earnings from the investment in Access Midstream Partners over an initial weighted-average period of approximately 18 years.
Our investment in Access Midstream Partners is disclosed as a separate reportable segment. See Note 18 – Segment Disclosures.
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| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
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Note 3 – Variable Interest Entities
Consolidated VIEs
As of December 31, 2013, we consolidate the following VIEs:
Gulfstar One
During the second quarter of 2013, a third party contributed $187 million to Gulfstar One LLC (Gulfstar One) in exchange for a 49 percent ownership interest in Gulfstar One. This contribution was based on 49 percent of WPZ’s estimated cumulative net investment at that time. The $187 million was then distributed to WPZ. Following this transaction, WPZ owns a 51 percent interest in Gulfstar One, a subsidiary that, due to certain risk-sharing provisions in its customer contracts, is a VIE. WPZ is the primary beneficiary because it has the power to direct the activities that most significantly impact Gulfstar One’s economic performance. WPZ, as construction agent for Gulfstar One, is designing, constructing, and installing a proprietary floating-production system, Gulfstar FPS™, and associated pipelines which will initially provide production handling and gathering services for the Tubular Bells oil and gas discovery in the eastern deepwater Gulf of Mexico. The project is expected to be in service in the third quarter of 2014. WPZ has received certain advance payments from the producer customers and is committed to the producer customers to construct this system. The current estimate of the total remaining construction costs is less than $325 million, which will be funded with capital contributions from WPZ and the other equity partner, proportional to ownership interest. The producer customers will be responsible for the firm price of building the facilities if they do not develop the offshore oil and gas fields to be connected to Gulfstar One. In December 2013, WPZ committed an additional $134 million to Gulfstar One to fund an expansion of the system that will provide production handling, gathering, and processing services for the Gunflint oil and gas discovery in the eastern deepwater Gulf of Mexico. The expansion project is expected to be in service in 2016. The other equity partner has an option to participate in the funding of the expansion project on a proportional basis.
Constitution
WPZ owns a 41 percent interest in Constitution, a subsidiary that, due to shipper fixed-payment commitments under its firm transportation contracts, is a VIE. WPZ is the primary beneficiary because it has the power to direct the activities that most significantly impact Constitution’s economic performance. WPZ, as construction agent for Constitution, is building a pipeline connecting our gathering system in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and the Tennessee Gas Pipeline systems. WPZ plans to place the project in service in late 2015 to 2016 and estimates the total remaining construction costs of the project to be less than $600 million, which will be funded with capital contributions from WPZ and the other equity partners, proportional to ownership interest.
Bluegrass Pipeline
We own a 50 percent interest in Bluegrass Pipeline, a subsidiary that, due to insufficient equity to finance activities during its development stage, is a VIE. As of December 31, 2013, we are the primary beneficiary because we have the power to direct the activities of the project that most significantly impact its economic performance until the first developmental stage milestone is met as we have the power to direct whether the project moves forward. We and our partner plan to construct an NGL pipeline connecting processing facilities in the Marcellus and Utica shale-gas areas in the northeastern United States to growing petrochemical and export markets in the gulf coast area of the United States. Pre-construction activities are under way and the project is now planned to be in service in mid-to-late 2016. This development stage entity was operating under a preliminary activities budget that governed the spending levels through February 28, 2014. Prior to that time, certain elections by either partner could change the relative ownership of the entity, impact the continued development of the project, and/or revise the determination of the primary beneficiary. In February 2014, we agreed with our partner to, among other things, extend the preliminary activities period to March 31, 2014, and change certain rights between the partners that could impact the continued development of the project. We will evaluate the impact of those changes on our determination of the primary beneficiary in the first quarter of 2014. The remaining amount for spending under the preliminary activities budget through March 31, 2014, is less than
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| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
$85 million, and will be funded by us and our partner, proportional to ownership interest. Continued investment in this project beyond the preliminary activities stage will require additional significant capital contributions.
As of December 31, 2013, our Consolidated Balance Sheet includes approximately $113 million of capitalized project development costs associated with the Bluegrass Pipeline, included within Construction in progress in the table below. Completion of this project is subject to execution of customer contracts sufficient to support the project. We are in discussions with potential customers regarding commitments to the pipeline and these discussions have not yet yielded sufficient commitments to satisfy this condition. As a result, we evaluated the capitalized project costs for impairment as of December 31, 2013, and determined that no impairment was necessary. Our evaluation considered probability-weighted scenarios of undiscounted future net cash flows, including reasonably possible scenarios assuming the construction and operation of the pipeline under differing levels of commitments from customers and the possibility that the project does not proceed. It is reasonably possible that the probability-weighted estimate of undiscounted future net cash flows may change in the near term, resulting in the write-down of this asset to fair value, which could result in all of the capitalized project development costs being expensed. Such changes in estimates could result from lack of sufficient commitments from potential customers, lack of approval of the project by our partner, lack of executed regulatory approvals and unexpected changes in forecasted costs, and other factors impacting project economics. (See Note 19 – Subsequent Events.)
The following table presents amounts included in our Consolidated Balance Sheet that are for the use or obligation of these VIEs, which are joint projects in the development and construction phase:
|
| | | | | | | | | |
| | December 31, | | |
| 2013 | | 2012 |
| Classification |
| (Millions) |
|
|
| Assets (liabilities): |
|
|
|
|
|
| Cash and cash equivalents | $ | 122 |
| | $ | 8 |
|
| Cash and cash equivalents |
| Construction in progress | 1,111 |
| | 556 |
|
| Property, plant and equipment, at cost |
| Accounts payable | (145 | ) | | (128 | ) |
| Accounts payable |
| Construction retainage | (3 | ) | | — |
|
| Accrued liabilities |
| Current deferred revenue | (10 | ) | | — |
| | Accrued liabilities |
| Noncurrent deferred revenue associated with customer advance payments | (115 | ) | | (109 | ) |
| Other noncurrent liabilities |
Nonconsolidated VIEs
We have also identified certain interests in VIEs for which we are not the primary beneficiary. These include:
Laurel Mountain
WPZ’s 51 percent-owned equity-method investment in Laurel Mountain Midstream, LLC (Laurel Mountain) is considered to be a VIE generally due to contractual provisions that transfer certain risks to customers. As decisions about the activities that most significantly impact the economic performance of this entity require a unanimous vote of all members, WPZ is not the primary beneficiary. Our maximum exposure to loss is limited to the carrying value of this investment, which was $481 million at December 31, 2013.
Caiman II
WPZ’s 47.5 percent-owned equity-method investment in Caiman Energy II, LLC (Caiman II) has been determined to be a VIE because it has insufficient equity to finance activities during the construction stage of the Blue Racer Midstream joint project, which is an expansion to gathering and processing and the associated liquids infrastructure serving oil and gas producers in the Utica shale primarily in Ohio and northwest Pennsylvania. WPZ is not the primary beneficiary because it does not have the power to direct the activities of Caiman II that most significantly impact its
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
economic performance. At December 31, 2013, the carrying value of our investment in Caiman II was $256 million, which substantially reflects our contributions to that date. In January 2014, WPZ increased its total commitment for contributions to fund the project from $380 million to $500 million inclusive of contributions made to date, which represents WPZ’s current maximum exposure to loss related to this investment.
Moss Lake
Our equity-method investments in Moss Lake Fractionation LLC and Moss Lake LPG Terminal LLC (collectively referred to as Moss Lake) are VIEs because they have insufficient equity to finance activities during their development stage. We currently own 50 percent of these joint projects which plan to construct a new large-scale fractionation plant, expand natural gas liquids storage facilities in Louisiana and construct a pipeline connecting these facilities to the Bluegrass Pipeline. Additionally, Moss Lake plans to construct a new liquefied petroleum gas (LPG) terminal. We are not the primary beneficiary because we do not have the power to direct the majority of the activities of Moss Lake that most significantly impact its economic performance at this stage. The carrying value of our investments in Moss Lake at December 31, 2013, was $12 million, which represents our contributions to date. These development stage entities were operating under a preliminary activities budget that governed the spending levels through February 28, 2014. Prior to that time, certain elections by either partner could change the relative ownership of the entities, impact the continued development of the project, and/or revise the determination of the primary beneficiary. In February 2014, we agreed with our partner to, among other things, extend the preliminary activities period to March 31, 2014, and change certain rights between the partners that could impact the continued development of these projects. We will evaluate the impact of those changes on our determination of the primary beneficiary in the first quarter of 2014. The amount we may spend in order to fund our proportional share of the preliminary activities budget through March 31, 2014, is less than $25 million. Continued investment in this project beyond the preliminary activities stage will require additional significant capital contributions. (See Note 19 – Subsequent Events.)
Note 4 – Discontinued Operations
On December 31, 2011, we completed the tax-free spin-off of our 100 percent interest in WPX to our stockholders. (See Note 1 – Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies.)
The following table reflects summarized results of discontinued operations. The summarized results of discontinued operations for 2013 reflect an unfavorable ruling associated with our former Alaska refinery related to the Trans-Alaska Pipeline System Quality Bank. The summarized results of discontinued operations for 2012 primarily include a gain on reconsolidation following the sale of certain of our former Venezuela operations, whose facilities were expropriated by the Venezuelan government in May 2009. The summarized results of discontinued operations for 2011 reflect the results of operations of our former exploration and production business as discontinued operations.
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
Summarized Results of Discontinued Operations
|
| | | | | | | | | | | |
| | Years Ended December 31, |
| | 2013 | | 2012 | | 2011 |
| | (Millions) |
| Revenues | $ | — |
| | $ | — |
| | $ | 3,997 |
|
| Income (loss) from discontinued operations before gain on reconsolidation, impairments, and income taxes | $ | (15 | ) | | $ | (16 | ) | | $ | 223 |
|
| Gain on reconsolidation | — |
| | 144 |
| | — |
|
| Impairments | — |
| | — |
| | (755 | ) |
| (Provision) benefit for income taxes | 4 |
| | 8 |
| | 115 |
|
| Income (loss) from discontinued operations | $ | (11 | ) | | $ | 136 |
| | $ | (417 | ) |
| | | | | | |
| Income (loss) from discontinued operations: | | | | | |
| Attributable to noncontrolling interests | $ | — |
| | $ | — |
| | $ | 10 |
|
| Attributable to The Williams Companies, Inc. | $ | (11 | ) | | $ | 136 |
| | $ | (427 | ) |
Revenues and Income (loss) from discontinued operations before gain on reconsolidation, impairments, and income taxes for 2011 primarily reflect the results of operations of our discontinued exploration and production business. Results for 2011 additionally include $42 million of transaction costs related to the spin-off.
Gain on reconsolidation for 2012 is related to our majority ownership in entities (the Wilpro entities) that owned and operated the El Furrial and PIGAP II gas compression facilities prior to their expropriation by the Venezuelan government in May 2009. We deconsolidated the Wilpro entities in 2009. In 2012, the El Furrial and PIGAP II assets were sold as part of a settlement related to the 2009 expropriation of these assets. Upon closing, the lenders that had provided financing for these operations were repaid in full, and the Wilpro entities received $98 million in cash and the right to receive quarterly cash installments of $15 million (receivable) plus interest through the first quarter of 2016. Following the settlement and repayment in full of the lenders, we reestablished control and, therefore, reconsolidated the Wilpro entities and recognized the gain on reconsolidation. This gain reflected our share of the cash, including cash received in the settlement, and the estimated fair value of the receivable held by the Wilpro entities at the time of reconsolidation. (See Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk.)
To determine the fair value of the receivable at the time of reconsolidation, we considered both quantitative (income) and qualitative (market) approaches. Under our quantitative approach, we calculated the net present value of a probability-weighted set of cash flows utilizing assumptions based on contractual terms, historical payment patterns by the counterparty under similar circumstances, our likelihood of using arbitration if the counterparty does not perform, and discount rates. Our qualitative analysis utilized information as to how similar notes might be valued. This analysis also reduced the value due to its limited marketability as the payment terms are embedded within the overall settlement agreement. Both analyses resulted in similar fair values. Ultimately we determined the fair value of the receivable to be $88 million at the time of reconsolidation, utilizing a probability-weighted cash flow analysis with a discount rate of approximately 12 percent and a probability of default ranging from 15 percent to 100 percent. Utilizing different assumptions regarding the collectability of the receivable and discount rates could have resulted in a materially different fair value.
Impairments in 2011 reflect $367 million and $180 million of impairments of capitalized costs of certain natural gas producing properties of our discontinued exploration and production business in the Powder River basin and the Barnett Shale, respectively, $29 million of write-downs to estimates of fair value less costs to sell the assets of our discontinued exploration and production business in the Arkoma basin, and an impairment of $179 million in connection with the spin-off of WPX to reflect the difference between the carrying value of our investment in WPX and the estimated fair value of WPX at the time of spin-off. (See further discussion below regarding the determination of the fair value of WPX.) These nonrecurring fair value measurements fell within Level 3 of the fair value hierarchy.
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
For our assessment of the carrying value of our natural gas producing properties, we utilized estimates of future cash flows, in certain cases including purchase offers received. Significant judgments and assumptions in these assessments include estimates of natural gas reserve quantities, estimates of future natural gas prices using a forward NYMEX curve adjusted for locational basis differentials, drilling plans, expected capital costs, and an applicable discount rate commensurate with risk of the underlying cash flow estimates.
(Provision) benefit for income taxes for 2011 includes a $26 million net tax benefit associated with the write-down of certain indebtedness related to our former power operations.
Impairment of our investment in WPX
In conjunction with accounting for the spin-off of WPX, we evaluated whether there was an indicator of impairment of the carrying value of the investment at the date of the spin-off. Because the market capitalization of WPX as determined by its closing stock price on December 30, 2011, pursuant to the “when issued” trading market was less than our investment in WPX, we determined that an indicator of impairment was present and conducted an evaluation of the fair value of our investment in WPX at the date of the spin-off.
To determine the fair value at the time of spin-off, we considered several valuation approaches to derive a range of fair value estimates. These included consideration of the “when issued” stock price at December 30, 2011, an income approach, and a market approach. While the “when issued” stock price approach utilized the most observable inputs of the three approaches, we noted that the short trading duration, low trading volumes, and lack of liquidity in the “when issued” market, among other factors, served to limit this input in being solely determinative of the fair value of WPX. As such, we also considered the other valuation approaches in estimating the overall fair value of WPX, though giving preferential weighting to the “when issued” stock price approach.
Key variables and assumptions included the application of a control premium of up to 30 percent to the December 30, 2011 “when issued” trading value based on transactions involving energy companies. For the income approach, we estimated the fair value of WPX using a discounted cash flow analysis of its oil and natural gas reserves, primarily adjusted for long-term debt. Implicit in this approach was the use of forward market prices and discount rates that considered the risk of the respective reserves. After-tax discount rates assumed to be used by market participants were an average of 11.25 percent for proved reserves, 13.25 percent to 15.25 percent for probable reserves, and 15.25 percent to 18.25 percent for possible reserves. For the market approach, we considered multiples of cash flows derived from the value of comparable companies utilizing their respective traded stock prices, adjusted for a control premium consistent with levels noted above. Using these methodologies, we computed a range of estimated fair values from $4.5 billion to $6.7 billion. After giving preferential weighting to the “when issued” valuation, we computed an estimated fair value of approximately $5.5 billion.
As a result of this evaluation, we recorded an impairment charge which is nondeductible for tax purposes. This amount served to reduce the investment basis of the net assets accounted for as a dividend upon the spin-off at December 31, 2011.
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
Energy Commodity Derivatives Gains and Losses
The following table presents pre-tax gains and losses for our former exploration and production business’ energy commodity derivatives.
|
| | | | | |
| | Year Ended December 31, 2011 | | Classification |
| | (Millions) | | |
| Designated as cash flow hedges: | | | |
| Net gain (loss) recognized in other comprehensive income (loss) (effective portion) | $ | 413 |
| | AOCI |
| Net gain (loss) reclassified from accumulated other comprehensive income (loss) into income (effective portion) | $ | 332 |
| | Income (loss) from discontinued operations |
| Not designated as cash flow hedges: | | | |
| Gain (loss) recognized in income | $ | 30 |
| | Income (loss) from discontinued operations |
Note 5 – Investing Activities
Investing Income
|
| | | | | | | | | | | |
| | Years Ended December 31, |
| | 2013 | | 2012 | | 2011 |
| | (Millions) |
| Equity earnings (losses) (1) | $ | 134 |
| | $ | 111 |
| | $ | 155 |
|
| Income (loss) from investments (1) | 28 |
| | 49 |
| | 7 |
|
| Interest income and other | 53 |
| | 28 |
| | 6 |
|
| Total investing income | $ | 215 |
| | $ | 188 |
| | $ | 168 |
|
__________
| |
| (1) | Items also included in Segment profit (loss). (See Note 18 – Segment Disclosures.) |
Equity earnings (losses)
In December 2012, we acquired certain interests in Access Midstream Partners for approximately $2.19 billion in cash. (See Note 2 – Acquisitions, Goodwill, and Other Intangible Assets.) Equity earnings (losses) in 2013 includes $93 million of equity earnings recognized from Access Midstream Partners, offset by $63 million noncash amortization of the difference between the cost of our investment and our underlying share of the net assets of Access Midstream Partners.
Income (loss) from investments
Included in Income (loss) from investments for 2013 is a $31 million gain resulting from Access Midstream Partners’ equity issuances during 2013. These equity issuances resulted in the dilution of our limited partner interest from approximately 24 percent to 23 percent, which is accounted for as though we sold a portion of our investment.
In 2010, we sold our 50 percent interest in Accroven SRL (Accroven) to the state-owned oil company, Petróleos de Venezuela S.A. (PDVSA). Income (loss) from investments in 2012 and 2011 includes gains of $53 million and $11 million, respectively, from the sale. Payments were recognized upon receipt, as future collections were not reasonably assured.
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
Interest income and other
Interest income and other includes $50 million and $7 million of interest income for 2013 and 2012, respectively, associated with a receivable related to the sale of certain former Venezuela assets. (See Note 4 – Discontinued Operations). The 2013 amount reflects a current year increase in yield associated with a revision in our estimate of the cash flows expected to be received as a result of continued timely payment by the counterparty.
Additionally, Interest income and other for 2012 includes $10 million of interest related to the 2010 sale of Accroven discussed above.
Investments |
| | | | | | | |
| | December 31, |
| | 2013 | | 2012 |
| | (Millions) |
| Equity method: | | | |
| Access Midstream Partners — 24% | $ | 2,161 |
| | $ | 2,187 |
|
| Overland Pass Pipeline Company LLC (OPPL) — 50% | 452 |
| | 454 |
|
| Gulfstream — 50% | 333 |
| | 348 |
|
| Discovery Producer Services LLC (Discovery) — 60% (1) | 527 |
| | 350 |
|
| Laurel Mountain — 51% (1) | 481 |
| | 444 |
|
| Caiman II — 47.5% | 256 |
| | 67 |
|
| Other | 150 |
| | 137 |
|
| | $ | 4,360 |
| | $ | 3,987 |
|
_________
| |
| (1) | We account for these investments under the equity method due to the significant participatory rights of our partners such that we do not control or are otherwise not the primary beneficiary of the investments. |
Related party transactions
We have purchases from our equity-method investees included in Product costs in the Consolidated Statement of Income of $161 million, $186 million, and $234 million for the years ended 2013, 2012, and 2011, respectively. We have $13 million and $15 million included in Accounts payable in the Consolidated Balance Sheet with our equity-method investees at December 31, 2013 and 2012, respectively.
WPZ has operating agreements with certain equity-method investees. These operating agreements typically provide for reimbursement or payment to WPZ for certain direct operational payroll and employee benefit costs, materials, supplies, and other charges and also for management services. We supplied a portion of these services, primarily those related to employees since WPZ does not have any employees, to certain equity-method investees. The total gross charges to equity-method investees for these fees included in the Consolidated Statement of Income are $67 million, $75 million and $57 million for the years ended 2013, 2012, and 2011, respectively.
Equity-method investments
We have differences between the carrying value of our equity-method investments and the underlying equity in the net assets of the investees of $1.13 billion at December 31, 2013. This difference primarily relates to our investment in Access Midstream Partners resulting from property, plant, and equipment, as well as customer-based intangible assets and goodwill. (See Note 2 – Acquisitions, Goodwill, and Other Intangible Assets.)
We generally fund our portion of significant expansion or development projects of these investees, except for Access Midstream Partners which is expected to be self-funding, through additional capital contributions. As of December 31, 2013, our proportionate share of amounts remaining to be spent for specific capital projects already in
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
progress for Discovery, Laurel Mountain, and Caiman II totaled $244 million, $72 million, and $119 million, respectively.
We contributed $193 million and $169 million to Discovery in 2013 and 2012, respectively; $42 million, $174 million, and $137 million to Laurel Mountain in 2013, 2012 and 2011, respectively; and $192 million and $69 million, to Caiman II in 2013 and 2012, respectively.
Our equity-method investees’ organizational documents generally require distribution of available cash to equity holders on a quarterly basis. Dividends and distributions, including those presented below, received from companies accounted for by the equity method were $247 million, $173 million, and $193 million in 2013, 2012, and 2011, respectively. These transactions reduced the carrying value of our investments. These dividends and distributions primarily included:
|
| | | | | | | | | | | |
| | 2013 | | 2012 | | 2011 |
| | (Millions) |
| Access Midstream Partners | $ | 93 |
| | $ | — |
| | $ | — |
|
| Gulfstream | 81 |
| | 79 |
| | 84 |
|
| Discovery | 12 |
| | 21 |
| | 40 |
|
| Aux Sable Liquid Products L.P. | 20 |
| | 28 |
| | 35 |
|
| OPPL | 27 |
| | 28 |
| | 19 |
|
Summarized Financial Position and Results of Operations of All Equity-Method Investments
|
| | | | | | | |
| | December 31, |
| | 2013 | | 2012 |
| | (Millions) |
| Assets (liabilities): | | | |
| Current assets | $ | 689 |
| | $ | 582 |
|
| Noncurrent assets | 13,621 |
| | 11,571 |
|
| Current liabilities | (573 | ) | | (507 | ) |
| Noncurrent liabilities | (4,563 | ) | | (3,807 | ) |
| Noncontrolling interest | (254 | ) | | (112 | ) |
|
| | | | | | | | | | | |
| | Years Ended December 31, |
| | 2013 | | 2012 | | 2011 |
| | (Millions) |
| Gross revenue | $ | 2,406 |
| | $ | 1,821 |
| | $ | 1,808 |
|
| Operating income | 699 |
| | 557 |
| | 747 |
|
| Net income | 627 |
| | 488 |
| | 654 |
|
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
Note 6 – Other Income and Expenses
The following table presents significant gains or losses reflected in Other (income) expense – net within Costs and expenses:
|
| | | | | | | | | | | |
| | Years Ended December 31, |
| | 2013 | | 2012 | | 2011 |
| | (Millions) |
| Williams Partners | | | | | |
| Net insurance recoveries associated with the Geismar Incident | $ | (40 | ) | | $ | — |
| | $ | — |
|
| Amortization of regulatory assets associated with asset retirement obligations | 30 |
| | 7 |
| | 6 |
|
| Write-off of the Eminence abandonment regulatory asset not recoverable through rates | 12 |
| | — |
| | — |
|
| Insurance recoveries associated with the Eminence abandonment | (16 | ) | | — |
| | — |
|
| Settlement in principle of a producer claim | 25 |
| | — |
| | — |
|
| Project feasibility costs | 4 |
| | 21 |
| | 10 |
|
| Capitalization of project feasibility costs previously expensed | (1 | ) | | (19 | ) | | (11 | ) |
| Williams NGL & Petchem Services | | | | | |
| Gulf Liquids litigation contingency accrual reduction (see Note 17) | — |
| | — |
| | (19 | ) |
| Write-off of an abandoned project | 20 |
| | — |
| | — |
|
The reversals of project feasibility costs from expense to capital at Williams Partners are associated with natural gas pipeline expansion projects. These reversals were made upon determining that the related projects were probable of development. These costs are now included in the capital costs of the projects, which we believe are probable of recovery through the project rates.
On June 13, 2013, an explosion and fire occurred at WPZ’s Geismar olefins plant. The fire was extinguished on the day of the incident. The incident (Geismar Incident) rendered the facility temporarily inoperable and resulted in significant human, financial and operational effects.
We have substantial insurance coverage for repair and replacement costs, lost production, and additional expenses related to the incident as follows:
| |
| • | Property damage and business interruption coverage with a combined per-occurrence limit of $500 million and retentions (deductibles) of $10 million per occurrence for property damage and a waiting period of 60 days per occurrence for business interruption; |
| |
| • | General liability coverage with per-occurrence and aggregate annual limits of $610 million and retentions (deductibles) of $2 million per occurrence; |
| |
| • | Workers’ compensation coverage with statutory limits and retentions (deductibles) of $1 million total per occurrence. |
We have expensed $13 million at Williams Partners during 2013 of costs under our insurance deductibles in Operating and maintenance expenses in the Consolidated Statement of Income. Recoveries under our business interruption policy will be recognized upon resolution of any contingencies with the insurer associated with the claim. Through December 31, 2013, we have recognized $50 million of insurance recoveries related to this incident as a gain to Other (income) expense – net within Costs and expenses in our Consolidated Statement of Income. During the fourth quarter of 2013, we incurred $10 million of covered insurable expenses in excess of our retentions (deductibles) which partially offset the $50 million gain included in Other (income) expense – net within Costs and expenses in our Consolidated Statement of Income.
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
Additional Items
We detected a leak in an underground cavern at our Eminence Storage Field in Mississippi on December 28, 2010. We recorded $3 million, $2 million, and $15 million of charges to Operating and maintenance expenses at Williams Partners during 2013, 2012, and 2011, respectively, primarily related to assessment and monitoring costs incurred to ensure the safety of the surrounding area.
We engaged a consulting firm in 2012 to assist in better aligning resources to support our business strategy following the spin-off of WPX. In 2012, we recorded $26 million of reorganization-related costs, including consulting costs, to Selling, general, and administrative expenses.
In conjunction with the Gulf Liquids litigation contingency accrual reduction noted in the table above, Williams NGL & Petchem Services also reduced an accrual for the associated interest of $14 million in 2011, which is reflected in Interest incurred. (See Note 17 – Contingent Liabilities and Commitments.)
In conjunction with the completion of a tender offer for a portion of our debt in the fourth quarter of 2011, we incurred $271 million of Early debt retirement costs, consisting primarily of cash premiums.
Note 7 – Provision (Benefit) for Income Taxes
The Provision (benefit) for income taxes from continuing operations includes:
|
| | | | | | | | | | | |
| | Years Ended December 31, |
| | 2013 | | 2012 | | 2011 |
| | (Millions) |
| Current: | | | | | |
| Federal | $ | (17 | ) | | $ | 91 |
| | $ | 181 |
|
| State | 7 |
| | 17 |
| | 13 |
|
| Foreign | (13 | ) | | 40 |
| | (6 | ) |
| | (23 | ) | | 148 |
| | 188 |
|
| Deferred: | | | | | |
| Federal | 348 |
| | 220 |
| | (61 | ) |
| State | 40 |
| | (13 | ) | | (14 | ) |
| Foreign | 36 |
| | 5 |
| | 11 |
|
| | 424 |
| | 212 |
| | (64 | ) |
| Total provision (benefit) | $ | 401 |
| | $ | 360 |
| | $ | 124 |
|
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
Reconciliations from the Provision (benefit) for income taxes from continuing operations at the federal statutory rate to the recorded Provision (benefit) for income taxes are as follows:
|
| | | | | | | | | | | |
| | Years Ended December 31, |
| | 2013 | | 2012 | | 2011 |
| | (Millions) |
| Provision (benefit) at statutory rate | $ | 378 |
| | $ | 451 |
| | $ | 421 |
|
| Increases (decreases) in taxes resulting from: | | | | | |
| Impact of nontaxable noncontrolling interests | (78 | ) | | (72 | ) | | (96 | ) |
| State income taxes (net of federal benefit) | 26 |
| | 2 |
| | 11 |
|
| Foreign operations — net | (32 | ) | | (36 | ) | | (14 | ) |
| Federal settlements | — |
| | — |
| | (109 | ) |
| International revised assessments | — |
| | — |
| | (38 | ) |
| Taxes on undistributed earnings of foreign subsidiaries - net | 99 |
| | — |
| | (66 | ) |
| Other — net | 8 |
| | 15 |
| | 15 |
|
| Provision (benefit) for income taxes | $ | 401 |
| | $ | 360 |
| | $ | 124 |
|
The 2013 state deferred provision includes $10 million, net of federal benefit, related to the impact of a second-quarter Texas franchise tax law change.
Income (loss) from continuing operations before income taxes includes $119 million, $196 million, and $173 million of foreign income in 2013, 2012, and 2011, respectively.
On October 30, 2013, WPZ announced its intent to pursue an agreement to acquire certain of our Canadian operations. As a result, we no longer consider the undistributed earnings from these foreign operations to be permanently reinvested and thus recognized $99 million of deferred income tax expense in continuing operations and $24 million of deferred tax benefit in AOCI during the fourth quarter of 2013. As a result of this transaction, we estimate approximately $111 million will be characterized as a current income tax liability in the first quarter of 2014.
During the third quarter of 2011, associated with a ruling received from the Internal Revenue Service (IRS) related to our plan to separate our exploration and production business through an initial public offering and subsequent tax-free spin-off, and following a certain internal reorganization, we recognized a deferred tax benefit of $66 million as we considered the undistributed earnings of certain foreign operations to be permanently reinvested.
During the course of audits of our business by domestic and foreign tax authorities, we frequently face challenges regarding the amount of taxes due. These challenges include questions regarding the timing and amount of deductions and the allocation of income among various tax jurisdictions. In evaluating the liability associated with our various filing positions, we apply the two step process of recognition and measurement. In association with this liability, we record an estimate of related interest and tax exposure as a component of our tax provision. The impact of this accrual is included within other — net in our reconciliation of the tax provision to the federal statutory rate.
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
Significant components of deferred tax liabilities and deferred tax assets are as follows:
|
| | | | | | | |
| | December 31, |
| | 2013 | | 2012 |
| | (Millions) |
| Deferred tax liabilities: | | | |
| Undistributed earnings of foreign subsidiaries | $ | 75 |
| | $ | — |
|
| Investments | 3,765 |
| | 3,218 |
|
| Other | — |
| | 34 |
|
| Total deferred tax liabilities | 3,840 |
| | 3,252 |
|
| Deferred tax assets: | | | |
| Accrued liabilities | 126 |
| | 313 |
|
| Federal tax credits | 108 |
| | 74 |
|
| State losses and credits | 194 |
| | 195 |
|
| Other | 91 |
| | 90 |
|
| Total deferred tax assets | 519 |
| | 672 |
|
| Less valuation allowance | 181 |
| | 144 |
|
| Net deferred tax assets | 338 |
| | 528 |
|
| Overall net deferred tax liabilities | $ | 3,502 |
| | $ | 2,724 |
|
The valuation allowance at December 31, 2013 and 2012 serves to reduce the available deferred tax assets to an amount that will, more likely than not, be realized. The amounts presented in the table above are, with respect to state items, before any federal benefit. The change from prior year for the state losses and credits is primarily due to increases in losses and credits generated in the current and prior years less losses and credits utilized in the current year. We have loss and credit carryovers in multiple state taxing jurisdictions. These attributes generally expire between 2014 and 2033 with some carryovers having indefinite carryforward periods. In the case of the valuation allowance, the change is due to the ongoing evaluation process of the losses and credits anticipated to be realized in future years. The federal tax credits currently have no expiration dates.
During 2013, we received cash refunds (net of payments) for income taxes of $50 million. Cash payments for income taxes (net of refunds and including discontinued operations) were $198 million and $296 million in 2012 and 2011, respectively.
As of December 31, 2013, we had approximately $66 million of unrecognized tax benefits. If recognized, income tax expense would be reduced by $70 million, including the effect of these changes on other tax attributes, with state income tax amounts included net of federal tax effect. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:
|
| | | | | | | |
| | 2013 | | 2012 |
| | (Millions) |
| Balance at beginning of period | $ | 58 |
| | $ | 38 |
|
| Additions based on tax positions related to the current year | 4 |
| | 4 |
|
| Additions for tax positions of prior years | 18 |
| | 22 |
|
| Reductions for tax positions of prior years | (2 | ) | | (6 | ) |
| Settlement with taxing authorities | (12 | ) | | — |
|
| Balance at end of period | $ | 66 |
| | $ | 58 |
|
We recognize related interest and penalties as a component of income tax provision. Total interest and penalties recognized as part of income tax provision were expense of $9 million for 2013, and benefits of $7 million and $56
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
million for 2012 and 2011, respectively. Approximately $16 million and $7 million of interest and penalties primarily relating to uncertain tax positions have been accrued as of December 31, 2013 and 2012, respectively.
During the next 12 months, we do not expect ultimate resolution of any unrecognized tax benefit associated with domestic or international matters to have a material impact on our unrecognized tax benefit position.
During the first quarter of 2011, we finalized settlements for 1997 through 2008 on certain contested matters with the IRS that resulted in a 2011 tax benefit of approximately $109 million. In July and August 2011, we made cash payments to the IRS of $82 million and $77 million, respectively, related to these settlements. During the first and fourth quarters of 2011, we received revised assessments on an international matter that resulted in a 2011 tax benefit of approximately $38 million. In the first quarter of 2012, we received a cash refund for the revised assessments of $21 million.
During the first quarter of 2013, we finalized a settlement with the IRS on tax matters related to the IRS’s examination of our 2009 and 2010 consolidated corporate income tax returns. We recorded a tax provision of approximately $2 million related to these matters during the third quarter of 2012. With respect to the examined years, we made cash payments of $12 million to the IRS in February 2013.
Tax years after 2010 are subject to examination by the IRS. The statute of limitations for most states expires one year after expiration of the IRS statute. Generally, tax returns for our Venezuelan and Canadian entities are open to audit for tax years after 2007, although Venezuela is subject to certain contractual limitations. A reassessment of a Canadian audit for the years 2007 through 2010 is still outstanding as of December 31, 2013. The impact of this reassessment is not expected to be material.
On September 13, 2013, the IRS issued final regulations providing guidance on the treatment of amounts paid to acquire, produce or improve tangible property and proposed regulations providing guidance on the dispositions of such property. The implementation date for these regulations is January 1, 2014. Changes for tax treatment elected by us or required by the regulations will generally be effective prospectively; however, implementation of many of the regulations’ provisions will require a calculation of the cumulative effect of the changes on prior years, and it is expected that such amount will have to be included in the determination of our taxable income in 2014, or possibly over a four-year period beginning in 2014. The IRS is expected to issue additional procedural guidance regarding 2014 tax return filing requirements and how the requirements may be implemented for the gas transmission and distribution industry. Since the changes will affect the timing for deducting expenditures for tax purposes, the impact of implementation will be reflected in the amount of income taxes payable or receivable, cash flows from operations and deferred taxes beginning in 2014, with no net tax provision effect. Pending the issuance of additional procedural guidance from the IRS, we cannot at this time estimate the impact of implementing the regulations.
With the spin-off of WPX on December 31, 2011, WPX entered into a tax sharing agreement with us under which we are generally liable for all U.S. federal, state, local and foreign income taxes attributable to WPX with respect to taxable periods ending on or before the distribution date. We are also principally responsible for managing any income tax audits by the various tax jurisdictions for pre-spin-off periods. In 2012, we prepared pro forma tax returns for each tax period in which WPX or any of its subsidiaries were combined or consolidated with us. In the first quarter of 2013, we reimbursed WPX a net $2 million for the additional losses shown on the pro forma tax returns, offset by a reduction in the tax resulting from the 2009 to 2010 IRS settlement.
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
Note 8 – Earnings (Loss) Per Common Share from Continuing Operations |
| | | | | | | | | | | |
| | Years Ended December 31, |
| | 2013 | | 2012 | | 2011 |
| | (Dollars in millions, except per-share amounts; shares in thousands) |
| Income (loss) from continuing operations attributable to The Williams Companies, Inc. available to common stockholders for basic and diluted earnings (loss) per common share | $ | 441 |
| | $ | 723 |
| | $ | 803 |
|
| Basic weighted-average shares | 682,948 |
| | 619,792 |
| | 588,553 |
|
| Effect of dilutive securities: | | | | | |
| Nonvested restricted stock units | 1,995 |
| | 2,694 |
| | 4,332 |
|
| Stock options | 2,149 |
| | 2,608 |
| | 3,374 |
|
| Convertible debentures | 93 |
| | 392 |
| | 1,916 |
|
| Diluted weighted-average shares | 687,185 |
| | 625,486 |
| | 598,175 |
|
| Earnings (loss) per common share from continuing operations: | | | | | |
| Basic | $ | .65 |
| | $ | 1.17 |
| | $ | 1.36 |
|
| Diluted | $ | .64 |
| | $ | 1.15 |
| | $ | 1.34 |
|
Beginning in 2012, we have nonvested service-based restricted stock units that contain a nonforfeitable right to dividends during the vesting period and are considered participating securities. Dividends associated with these participating securities were $2 million and $1 million for 2013 and 2012, respectively, and have been subtracted from Income (loss) from continuing operations attributable to The Williams Companies, Inc. available to common stockholders for basic and diluted earnings (loss) per common share in the calculation of earnings (loss) per common share.
Note 9 – Employee Benefit Plans
We have noncontributory defined benefit pension plans in which all eligible employees participate. Currently, eligible employees earn benefits primarily based on a cash balance formula. Various other formulas, as defined in the plan documents, are utilized to calculate the retirement benefits for plan participants not covered by the cash balance formula. At the time of retirement, participants may elect, to the extent they are eligible for the various options, to receive annuity payments, a lump sum payment, or a combination of a lump sum and annuity payments. In addition to our pension plans, we currently provide subsidized retiree medical and life insurance benefits (other postretirement benefits) to certain eligible participants. Generally, employees hired after December 31, 1991, are not eligible for the subsidized retiree medical benefits, except for participants that were employees or retirees of Transco Energy Company on December 31, 1995, and other miscellaneous defined participant groups. For the periods presented, certain of these other postretirement benefit plans, particularly the subsidized retiree medical benefit plans, provide for retiree contributions and contain other cost-sharing features such as deductibles, co-payments, and co-insurance. The accounting for these plans anticipates future cost-sharing that is consistent with our expressed intent to increase the retiree contribution level generally in line with health care cost increases. Effective January 1, 2014, subsidized retiree medical benefits for eligible participants age 65 and older will be paid through contributions to health reimbursement accounts. The impact of this plan change is reflected in the December 31, 2013, other postretirement benefit obligation.
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
Funded Status
The following table presents the changes in benefit obligations and plan assets for pension benefits and other postretirement benefits for the years indicated.
|
| | | | | | | | | | | | | | | |
| | Pension Benefits | | Other Postretirement Benefits |
| | 2013 | | 2012 | | 2013 | | 2012 |
| | (Millions) |
| Change in benefit obligation: | | | | | | | |
| Benefit obligation at beginning of year | $ | 1,549 |
| | $ | 1,441 |
| | $ | 331 |
| | $ | 339 |
|
| Service cost | 44 |
| | 39 |
| | 2 |
| | 3 |
|
| Interest cost | 51 |
| | 55 |
| | 11 |
| | 13 |
|
| Plan participants’ contributions | — |
| | — |
| | 6 |
| | 5 |
|
| Benefits paid | (87 | ) | | (75 | ) | | (19 | ) | | (20 | ) |
| Medicare Part D subsidy | — |
| | — |
| | 4 |
| | 3 |
|
| Plan amendment | — |
| | — |
| | (59 | ) | | (6 | ) |
| Actuarial loss (gain) | (173 | ) | | 98 |
| | (63 | ) | | (6 | ) |
| Settlements | — |
| | (9 | ) | | — |
| | — |
|
| Benefit obligation at end of year | 1,384 |
| | 1,549 |
| | 213 |
| | 331 |
|
| Change in plan assets: | | | | | | | |
| Fair value of plan assets at beginning of year | 1,071 |
| | 965 |
| | 175 |
| | 159 |
|
| Actual return on plan assets | 165 |
| | 111 |
| | 31 |
| | 18 |
|
| Employer contributions | 92 |
| | 79 |
| | 8 |
| | 13 |
|
| Plan participants’ contributions | — |
| | — |
| | 6 |
| | 5 |
|
| Benefits paid | (87 | ) | | (75 | ) | | (19 | ) | | (20 | ) |
| Settlements | — |
| | (9 | ) | | — |
| | — |
|
| Fair value of plan assets at end of year | 1,241 |
| | 1,071 |
| | 201 |
| | 175 |
|
| Funded status — underfunded | $ | (143 | ) | | $ | (478 | ) | | $ | (12 | ) | | $ | (156 | ) |
| Accumulated benefit obligation | $ | 1,359 |
| | $ | 1,519 |
| | | | |
The underfunded status of our pension plans and other postretirement benefit plans presented in the previous table are recognized in the Consolidated Balance Sheet within the following accounts:
|
| | | | | | | |
| | December 31, |
| | 2013 | | 2012 |
| | (Millions) |
| Underfunded pension plans: | | | |
| Current liabilities | $ | 1 |
| | $ | 3 |
|
| Noncurrent liabilities | 142 |
| | 475 |
|
| Underfunded other postretirement benefit plans: | | | |
| Current liabilities | 8 |
| | 8 |
|
| Noncurrent liabilities | 4 |
| | 148 |
|
The plan assets within our other postretirement benefit plans are intended to be used for the payment of benefits for certain groups of participants. The Current liabilities for the other postretirement benefit plans represent the current portion of benefits expected to be payable in the subsequent year for the groups of participants whose benefits are not expected to be paid from plan assets.
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
The pension plans’ benefit obligation Actuarial loss (gain) of $(173) million in 2013 and $98 million in 2012 are primarily due to the impact of changes in the discount rates utilized to calculate the benefit obligations. In 2013, these rates increased, while in 2012 these rates decreased, as compared to those of the preceding year.
The 2013 benefit obligation Actuarial loss (gain) of $(63) million for our other postretirement benefit plans is primarily due to the impact of an increase in the discount rates utilized to calculate the benefit obligation as well as favorable claims experience. The Plan amendment for the other postretirement benefit plans of $(59) million in 2013 reflects a change in the plans to provide subsidized retiree medical benefits through defined annual contributions to health reimbursement accounts for eligible participants age 65 and older effective January 1, 2014. The 2012 benefit obligation Actuarial loss (gain) of $(6) million for our other postretirement benefit plans is primarily due to changes to claims experience and health care cost trend rates, offset by the impact of a decrease in the discount rates utilized to calculate the benefit obligation.
At December 31, 2013 and 2012, all of our pension plans had a projected benefit obligation and accumulated benefit obligation in excess of plan assets.
Pre-tax amounts not yet recognized in Net periodic benefit cost at December 31 are as follows:
|
| | | | | | | | | | | | | | | |
| | Pension Benefits | | Other Postretirement Benefits |
| | 2013 | | 2012 | | 2013 | | 2012 |
| | (Millions) |
Amounts included in Accumulated other comprehensive income (loss): | | | | | | | |
| Prior service (cost) credit | $ | — |
| | $ | (1 | ) | | $ | 26 |
| | $ | 7 |
|
| Net actuarial loss | (491 | ) | | (828 | ) | | (11 | ) | | (35 | ) |
| Amounts included in regulatory assets/liabilities associated with Transco and Northwest Pipeline: | | | | | | | |
| Prior service credit | N/A |
| | N/A |
| | $ | 42 |
| | $ | 14 |
|
| Net actuarial loss | N/A |
| | N/A |
| | (2 | ) | | (67 | ) |
In addition to the regulatory assets/liabilities included in the previous table, differences in the amount of actuarially determined Net periodic benefit cost for our other postretirement benefit plans and the other postretirement benefit costs recovered in rates for Transco and Northwest Pipeline are deferred as a regulatory asset or liability. We have regulatory liabilities of $44 million at December 31, 2013 and $38 million at December 31, 2012 related to these deferrals. These amounts will be reflected in future rates based on the rate structures of these gas pipelines.
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
Net Periodic Benefit Cost
Net periodic benefit cost for the years ended December 31 consist of the following:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Benefits | | Other Postretirement Benefits |
| | 2013 | | 2012 | | 2011 | | 2013 | | 2012 | | 2011 |
| | (Millions) |
| Components of net periodic benefit cost: | | | | | | | | | | | |
| Service cost | $ | 44 |
| | $ | 39 |
| | $ | 41 |
| | $ | 2 |
| | $ | 3 |
| | $ | 2 |
|
| Interest cost | 51 |
| | 55 |
| | 64 |
| | 11 |
| | 13 |
| | 15 |
|
| Expected return on plan assets | (61 | ) | | (64 | ) | | (77 | ) | | (9 | ) | | (9 | ) | | (10 | ) |
| Amortization of prior service cost (credit) | 1 |
| | 1 |
| | 1 |
| | (12 | ) | | (7 | ) | | (11 | ) |
| Amortization of net actuarial loss | 60 |
| | 53 |
| | 38 |
| | 4 |
| | 8 |
| | 3 |
|
| Net actuarial loss from settlements | — |
| | 5 |
| | 4 |
| | — |
| | — |
| | — |
|
| Reclassification to regulatory liability | — |
| | — |
| | — |
| | 2 |
| | — |
| | 1 |
|
| Net periodic benefit cost | $ | 95 |
| | $ | 89 |
| | $ | 71 |
| | $ | (2 | ) | | $ | 8 |
| | $ | — |
|
Included in Net periodic benefit cost in 2011 in the previous table is cost associated with active and former employees that supported WPX’s operations (See Note 4 – Discontinued Operations). This cost was directly charged to WPX and is included in Income (loss) from discontinued operations. These amounts totaled $8 million in 2011 for our pension plans and totaled less than $1 million in 2011 for our other postretirement benefit plans.
Items Recognized in Other Comprehensive Income (Loss) and Regulatory Assets/Liabilities
Other changes in plan assets and benefit obligations recognized in Other comprehensive income (loss) before taxes for the years ended December 31 consist of the following:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Benefits |
| Other Postretirement Benefits |
| | 2013 |
| 2012 |
| 2011 |
| 2013 |
| 2012 |
| 2011 |
| | (Millions) |
Other changes in plan assets and benefit obligations recognized in Other comprehensive income (loss): |
|
|
|
|
|
|
|
|
|
|
|
| Net actuarial gain (loss) | $ | 277 |
|
| $ | (51 | ) |
| $ | (220 | ) |
| $ | 23 |
|
| $ | 2 |
|
| $ | (21 | ) |
| Prior service credit | — |
|
| — |
|
| — |
|
| 23 |
|
| 2 |
|
| 2 |
|
| Amortization of prior service cost (credit) | 1 |
|
| 1 |
|
| 1 |
|
| (4 | ) |
| (3 | ) |
| (4 | ) |
| Amortization of net actuarial loss and loss from settlements | 60 |
|
| 58 |
|
| 42 |
|
| 1 |
|
| 3 |
|
| 1 |
|
Other changes in plan assets and benefit obligations recognized in Other comprehensive income (loss) | $ | 338 |
|
| $ | 8 |
|
| $ | (177 | ) |
| $ | 43 |
|
| $ | 4 |
|
| $ | (22 | ) |
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
Other changes in plan assets and benefit obligations for our other postretirement benefit plans associated with Transco and Northwest Pipeline are recognized in regulatory assets/liabilities. Amounts recognized in regulatory assets/ liabilities for the years ended December 31 consist of the following:
|
| | | | | | | | | | | | |
| | | 2013 | | 2012 | | 2011 |
| | | (Millions) |
| | | | | | | |
| Net actuarial gain (loss) | | $ | 62 |
| | $ | 13 |
| | $ | (39 | ) |
| Prior service credit | | 36 |
| | 4 |
| | 1 |
|
| Amortization of prior service credit | | (8 | ) | | (4 | ) | | (7 | ) |
| Amortization of net actuarial loss | | 3 |
| | 5 |
| | 2 |
|
Pre-tax amounts expected to be amortized in Net periodic benefit cost in 2014 are as follows:
|
| | | | | | | |
| | Pension Benefits | | Other Postretirement Benefits |
| | (Millions) |
Amounts included in Accumulated other comprehensive income (loss): | | | |
| Prior service cost (credit) | $ | — |
| | $ | (8 | ) |
| Net actuarial loss | 38 |
| | — |
|
| Amounts included in regulatory assets/liabilities associated with Transco and Northwest Pipeline: | | | |
| Prior service credit | N/A |
| | $ | (12 | ) |
| Net actuarial loss | N/A |
| | — |
|
Key Assumptions
The weighted-average assumptions utilized to determine benefit obligations as of December 31 are as follows:
|
| | | | | | | | | | | |
| | Pension Benefits | | Other Postretirement Benefits |
| | 2013 | | 2012 | | 2013 | | 2012 |
| Discount rate | 4.68 | % | | 3.43 | % | | 4.80 | % | | 3.77 | % |
| Rate of compensation increase | 4.56 |
| | 4.57 |
| | N/A | | N/A |
The weighted-average assumptions utilized to determine Net periodic benefit cost for the years ended December 31 are as follows:
|
| | | | | | | | | | | | | | | | | |
| | Pension Benefits | | Other Postretirement Benefits |
| | 2013 | | 2012 | | 2011 | | 2013 | | 2012 | | 2011 |
| Discount rate | 3.43 | % | | 3.98 | % | | 5.19 | % | | 3.97 | % | | 4.22 | % | | 5.35 | % |
| Expected long-term rate of return on plan assets | 5.90 |
| | 6.30 |
| | 7.50 |
| | 5.26 |
| | 5.71 |
| | 6.54 |
|
| Rate of compensation increase | 4.57 |
| | 4.52 |
| | 5.00 |
| | N/A | | N/A | | N/A |
The increase in discount rates from December 31, 2012 to December 31, 2013 is primarily due to the general market increase in yields on long-term, high-quality corporate debt securities. The expected long-term rates of return on plan assets assumptions decreased in 2013 as a result of a decrease in the forward-looking capital market projections.
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
The mortality assumptions used to determine the obligations for our pension and other postretirement benefit plans are the estimate of expected mortality rates for the participants in these plans. The selected mortality tables are among the most recent tables available and include projected mortality improvements.
The assumed health care cost trend rate for 2014 is 7.2 percent. This rate decreases to 5.0 percent by 2023. A one-percentage-point change in assumed health care cost trend rates would have the following effects:
|
| | | | | | | |
| | Point increase | | Point decrease |
| | (Millions) |
| Effect on total of service and interest cost components | $ | 1 |
| | $ | (1 | ) |
| Effect on other postretirement benefit obligation | 7 |
| | (6 | ) |
Plan Assets
The investment policy for our pension and other postretirement benefit plans provides for an investment strategy in accordance with the Employee Retirement Income Security Act (ERISA), which governs the investment of the assets in a diversified portfolio. The plans follow a policy of diversifying the investments across various asset classes and investment managers. Additionally, the investment returns on approximately 40 percent of the other postretirement benefit plan assets are subject to income tax; therefore, certain investments are managed in a tax efficient manner.
The pension plans’ target asset allocation range at December 31, 2013 was 54 percent to 66 percent equity securities, which includes the commingled investment funds invested in equity securities, and 36 percent to 44 percent fixed income securities, including the fixed income commingled investment fund, and cash management funds. Within equity securities, the target range for U.S. equity securities is 37 percent to 45 percent and international equity securities is 17 percent to 21 percent. The asset allocation continues to be weighted toward equity securities since the obligations of the pension and other postretirement benefit plans are long-term in nature and historically equity securities have outperformed other asset classes over long periods of time.
Equity security investments are restricted to high-quality, readily marketable securities that are actively traded on the major U.S. and foreign national exchanges. Investment in Williams’ securities or an entity in which Williams has a majority ownership is prohibited in the pension plans except where these securities may be owned in a commingled investment fund in which the plans’ trusts invest. No more than 5 percent of the total stock portfolio valued at market may be invested in the common stock of any one corporation.
The following securities and transactions are not authorized: unregistered securities, commodities or commodity contracts, short sales or margin transactions, or other leveraging strategies. Investment strategies using the direct holding of options or futures require approval and, historically, have not been used; however, these instruments may be used in commingled investment funds. Additionally, real estate equity and natural resource property investments are generally restricted.
Fixed income securities are generally restricted to high-quality, marketable securities that may include, but are not necessarily limited to, U.S. Treasury securities, U.S. government guaranteed and nonguaranteed mortgage-backed securities, government and municipal bonds, and investment grade corporate securities. The overall rating of the fixed income security assets is generally required to be at least “A,” according to the Moody’s or Standard & Poor’s rating systems. No more than 5 percent of the total fixed income portfolio may be invested in the fixed income securities of any one issuer with the exception of bond index funds and U.S. government guaranteed and agency securities.
During 2013, ten active investment managers and one passive investment manager managed substantially all of the pension plans’ funds and four active investment managers and one passive investment manager managed the other postretirement benefit plans’ funds. Each of the managers had responsibility for managing a specific portion of these assets and each investment manager was responsible for 1 percent to 15 percent of the assets.
The pension and other postretirement benefit plans’ assets are held primarily in equity securities, including commingled investment funds invested in equity securities, and fixed income securities, including a commingled fund
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
invested in fixed income securities. Within the plans’ investment securities, there are no significant concentrations of risk because of the diversity of the types of investments, diversity of the various industries, and the diversity of the fund managers and investment strategies. Generally, the investments held in the plans are publicly traded, therefore, minimizing liquidity risk in the portfolio.
The fair values of our pension plan assets at December 31, 2013 and 2012 by asset class are as follows:
|
| | | | | | | | | | | | | | | |
| | 2013 |
| Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1) | | Significant
Other
Observable
Inputs
(Level 2) | | Significant
Unobservable
Inputs
(Level 3) | | Total |
| | (Millions) |
| Pension assets: | | | | | | | |
| Cash management fund | $ | 23 |
| | $ | — |
| | $ | — |
| | $ | 23 |
|
| Equity securities: | | | | | | | |
| U.S. large cap | 211 |
| | — |
| | — |
| | 211 |
|
| U.S. small cap | 146 |
| | — |
| | — |
| | 146 |
|
| International developed markets large cap growth | — |
| | 59 |
| | — |
| | 59 |
|
| Preferred stock | 2 |
| | — |
| | — |
| | 2 |
|
| Commingled investment funds: | | | | | | | |
| Equities — U.S. large cap (1) | — |
| | 179 |
| | — |
| | 179 |
|
| Equities — International small cap (2) | — |
| | 24 |
| | — |
| | 24 |
|
| Equities — Emerging markets value (3) | — |
| | 34 |
| | — |
| | 34 |
|
| Equities — Emerging markets growth (4) | — |
| | 19 |
| | — |
| | 19 |
|
| Equities — International developed markets large cap value (5) | — |
| | 100 |
| | — |
| | 100 |
|
| Fixed income — Corporate bonds (6) | — |
| | 140 |
| | — |
| | 140 |
|
| Fixed income securities (7): | | | | | | | |
| U.S. Treasury securities | 30 |
| | — |
| | — |
| | 30 |
|
| Mortgage-backed securities | — |
| | 67 |
| | — |
| | 67 |
|
| Corporate bonds | — |
| | 200 |
| | — |
| | 200 |
|
| Insurance company investment contracts and other | — |
| | 7 |
| | — |
| | 7 |
|
| Total assets at fair value at December 31, 2013 | $ | 412 |
| | $ | 829 |
| | $ | — |
| | $ | 1,241 |
|
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
|
| | | | | | | | | | | | | | | |
| | 2012 |
| | Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1) | | Significant
Other
Observable
Inputs
(Level 2) | | Significant
Unobservable
Inputs
(Level 3) | | Total |
| | (Millions) |
| Pension assets: | | | | | | | |
| Cash management fund | $ | 21 |
| | $ | — |
| | $ | — |
| | $ | 21 |
|
| Equity securities: | | | | | | | |
| U.S. large cap | 169 |
| | — |
| | — |
| | 169 |
|
| U.S. small cap | 115 |
| | — |
| | — |
| | 115 |
|
| International developed markets large cap growth | 1 |
| | 61 |
| | — |
| | 62 |
|
| Emerging markets growth | 3 |
| | 18 |
| | — |
| | 21 |
|
| Preferred stock | 6 |
| | — |
| | — |
| | 6 |
|
| Commingled investment funds: | | | | | | | |
| Equities — U.S. large cap (1) | — |
| | 146 |
| | — |
| | 146 |
|
| Equities — Emerging markets value (3) | — |
| | 33 |
| | — |
| | 33 |
|
| Equities — International developed markets large cap value (5) | — |
| | 83 |
| | — |
| | 83 |
|
| Fixed income — Corporate bonds (6) | — |
| | 150 |
| | — |
| | 150 |
|
| Fixed income securities (7): | | | | | | | |
| U.S. Treasury securities | 22 |
| | — |
| | — |
| | 22 |
|
| Mortgage-backed securities | — |
| | 68 |
| | — |
| | 68 |
|
| Corporate bonds | — |
| | 171 |
| | — |
| | 171 |
|
| Insurance company investment contracts and other | — |
| | 4 |
| | — |
| | 4 |
|
| Total assets at fair value at December 31, 2012 | $ | 337 |
| | $ | 734 |
| | $ | — |
| | $ | 1,071 |
|
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
The fair values of our other postretirement benefits plan assets at December 31, 2013 and 2012 by asset class are as follows:
|
| | | | | | | | | | | | | | | |
| | 2013 |
| | Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1) | | Significant
Other
Observable
Inputs
(Level 2) | | Significant
Unobservable
Inputs
(Level 3) | | Total |
| | (Millions) |
| Other postretirement benefit assets: | | | �� | | | | |
| Cash management funds | $ | 13 |
| | $ | — |
| | $ | — |
| | $ | 13 |
|
| Equity securities: | | | | | | | |
| U.S. large cap | 52 |
| | — |
| | — |
| | 52 |
|
| U.S. small cap | 29 |
| | — |
| | — |
| | 29 |
|
| International developed markets large cap growth | — |
| | 15 |
| | — |
| | 15 |
|
| Emerging markets growth | 1 |
| | 1 |
| | — |
| | 2 |
|
| Commingled investment funds: | | | | | | | |
| Equities — U.S. large cap (1) | — |
| | 18 |
| | — |
| | 18 |
|
| Equities — International small cap (2) | — |
| | 2 |
| | — |
| | 2 |
|
| Equities — Emerging markets value (3) | — |
| | 4 |
| | — |
| | 4 |
|
| Equities — Emerging markets growth (4) | — |
| | 2 |
| | — |
| | 2 |
|
| Equities — International developed markets large cap value (5) | — |
| | 10 |
| | — |
| | 10 |
|
| Fixed income — Corporate bonds (6) | — |
| | 14 |
| | — |
| | 14 |
|
| Fixed income securities (8): | | | | | | | |
| U.S. Treasury securities | 3 |
| | — |
| | — |
| | 3 |
|
| Government and municipal bonds | — |
| | 10 |
| | — |
| | 10 |
|
| Mortgage-backed securities | — |
| | 7 |
| | — |
| | 7 |
|
| Corporate bonds | — |
| | 20 |
| | — |
| | 20 |
|
| Total assets at fair value at December 31, 2013 | $ | 98 |
| | $ | 103 |
| | $ | — |
| | $ | 201 |
|
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
|
| | | | | | | | | | | | | | | |
| | 2012 |
| | Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1) | | Significant
Other
Observable
Inputs
(Level 2) | | Significant
Unobservable
Inputs
(Level 3) | | Total |
| | (Millions) |
| Other postretirement benefit assets: | | | | | | | |
| Cash management funds | $ | 14 |
| | $ | — |
| | $ | — |
| | $ | 14 |
|
| Equity securities: | | | | | | | |
| U.S. large cap | 42 |
| | — |
| | — |
| | 42 |
|
| U.S. small cap | 21 |
| | — |
| | — |
| | 21 |
|
| International developed markets large cap growth | — |
| | 13 |
| | — |
| | 13 |
|
| Emerging markets growth | 1 |
| | 4 |
| | — |
| | 5 |
|
| Preferred stock | 1 |
| | — |
| | — |
| | 1 |
|
| Commingled investment funds: | | | | | | | |
| Equities — U.S. large cap (1) | — |
| | 15 |
| | — |
| | 15 |
|
| Equities — Emerging markets value (3) | — |
| | 3 |
| | — |
| | 3 |
|
| Equities — International developed markets large cap value (5) | — |
| | 9 |
| | — |
| | 9 |
|
| Fixed income — Corporate bonds (6) | — |
| | 15 |
| | — |
| | 15 |
|
| Fixed income securities (8): | | | | | | | |
| U.S. Treasury securities | 2 |
| | — |
| | — |
| | 2 |
|
| Government and municipal bonds | — |
| | 10 |
| | — |
| | 10 |
|
| Mortgage-backed securities | — |
| | 7 |
| | — |
| | 7 |
|
| Corporate bonds | — |
| | 18 |
| | — |
| | 18 |
|
| Total assets at fair value at December 31, 2012 | $ | 81 |
| | $ | 94 |
| | $ | — |
| | $ | 175 |
|
____________
| |
| (1) | The stated intent of this fund is to invest primarily in equity securities comprising the Standard & Poor’s 500 Index. The investment objective of the fund is to approximate the performance of the Standard & Poor’s 500 Index over the long term. The fund manager retains the right to restrict withdrawals from the fund so as not to disadvantage other investors in the fund. |
| |
| (2) | The stated intent of this fund is to invest in equity securities of international small capitalization companies for the purpose of capital appreciation. The fund invests primarily in equity securities of non-U.S. issuers and other Depository Receipts listed on globally recognized exchanges. The fund may also invest up to 15 percent of its net asset value in emerging markets. The plans’ trustee is required to notify the fund manager 10 days prior to a withdrawal from the fund. For any redemption made within 180 days of contribution, the fund reserves the right to charge a 1.5 percent redemption fee. The fund also reserves the right to make all or a portion of redemptions in-kind rather than in cash or in a combination of cash and in-kind. |
| |
| (3) | The stated intent of this fund is to invest in equity securities of international emerging markets for the purpose of capital appreciation. The fund invests primarily in common stocks in the financial, consumer goods, information technology, energy, telecommunications, materials, and industrial sectors. The plans’ trustee is required to notify the fund manager 10 days prior to a withdrawal from the fund. The fund manager retains the right to restrict withdrawals from the fund so as not to disadvantage other investors in the fund. |
| |
| (4) | The stated intent of this fund is to invest mainly in equity securities of emerging market companies, or those companies that derive a significant portion of their revenues or profits from emerging economies for the purpose of long-term capital growth. The plans’ trustee is required to notify the fund manager 15 days prior to a withdrawal |
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
from the fund as of the last day of any month. The fund reserves the right to suspend and compel withdrawals. The fund also reserves the right to make all or a portion of redemptions in-kind rather than in cash or in a combination of cash and in-kind.
| |
| (5) | The stated intent of this fund is to invest in a diversified portfolio of international equity securities for the purpose of capital appreciation. The fund invests primarily in common stocks in the consumer goods, financial, health care, industrial, materials, energy, and information technology sectors. The plans’ trustee is required to notify the fund manager 10 days prior to a withdrawal from the fund. The fund manager retains the right to restrict withdrawals from the fund so as not to disadvantage other investors in the fund. |
| |
| (6) | The stated intent of this fund is to invest in U.S. Corporate bonds and U.S. Treasury securities. The fund is managed to closely match the characteristics of a long-term corporate bond index fund and seeks to maintain an average credit quality target of A- or above and a maximum 10 percent allocation to BBB rated securities. The fund’s target duration is approximately 20 years. The trustee of the fund reserves the right to delay the processing of deposits or withdrawals in order to ensure that securities transactions will be carried out in an orderly manner. |
| |
| (7) | The weighted-average credit quality rating of the pension assets fixed income security portfolio is investment grade with a weighted-average duration of approximately 6 years for 2013 and 2012. |
| |
| (8) | The weighted-average credit quality rating of the other postretirement benefit assets fixed income security portfolio is investment grade with a weighted-average duration of approximately 5 years for 2013 and 2012. |
The fair value measurement level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement of an asset.
Shares of the cash management funds are valued at fair value based on published market prices as of the close of business on the last business day of the year, which represents the net asset values of the shares held.
The fair values of equity securities traded on U.S. exchanges are derived from quoted market prices as of the close of business on the last business day of the year. The fair values of equity securities traded on foreign exchanges are also derived from quoted market prices as of the close of business on an active foreign exchange on the last business day of the year. However, the valuation requires translation of the foreign currency to U.S. dollars and this translation is considered an observable input to the valuation.
The fair value of all commingled investment funds are determined based on the net asset values per unit of each of the funds. The net asset values per unit represent the aggregate value of the funds assets at fair value less liabilities, divided by the number of units outstanding.
The fair value of fixed income securities, except U.S. Treasury notes and bonds, are determined using pricing models. These pricing models incorporate observable inputs such as benchmark yields, reported trades, broker/dealer quotes, and issuer spreads for similar securities to determine fair value. The U.S. Treasury notes and bonds are valued at fair value based on closing prices on the last business day of the year reported in the active market in which the security is traded.
The investment contracts with insurance companies are valued at fair value by discounting the cash flow of a bond using a yield to maturity based on an investment grade index or comparable index with a similar maturity value, maturity period, and nominal coupon rate.
There have been no significant changes in the preceding valuation methodologies used at December 31, 2013 and 2012. Additionally, there were no transfers or reclassifications of investments between Level 1 and Level 2 from December 2012 to December 2013. If transfers between levels had occurred, the transfers would have been recognized as of the end of the period.
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
Plan Benefit Payments and Employer Contributions
Following are the expected benefits to be paid by the plans. These estimates are based on the same assumptions previously discussed and reflect future service as appropriate. The actuarial assumptions are based on long-term expectations and include, but are not limited to, assumptions as to average expected retirement age and form of benefit payment. Actual benefit payments could differ significantly from expected benefit payments if near-term participant behaviors differ significantly from the actuarial assumptions.
|
| | | | | | | |
| | Pension Benefits | | Other Postretirement Benefits |
| | (Millions) |
| 2014 | $ | 88 |
| | $ | 15 |
|
| 2015 | 96 |
| | 15 |
|
| 2016 | 102 |
| | 16 |
|
| 2017 | 103 |
| | 16 |
|
| 2018 | 109 |
| | 17 |
|
| 2019-2023 | 591 |
| | 74 |
|
In 2014, we expect to contribute approximately $60 million to our tax-qualified pension plans and approximately $3 million to our nonqualified pension plans, for a total of approximately $63 million, and approximately $8 million to our other postretirement benefit plans.
Defined Contribution Plans
We also maintain defined contribution plans for the benefit of substantially all of our employees. Generally, plan participants may contribute a portion of their compensation on a pre-tax and after-tax basis in accordance with the plans’ guidelines. We match employees’ contributions up to certain limits. Our matching contributions charged to expense were $27 million in 2013, $25 million in 2012, and $28 million in 2011. Included in 2011 is $5 million in matching contributions for employees that supported WPX’s operations that were directly charged to WPX and included in Income (loss) from discontinued operations.
Note 10 – Inventories
|
| | | | | | | |
| | December 31, |
| | 2013 | | 2012 |
| | (Millions) |
| Natural gas liquids, olefins, and natural gas in underground storage | $ | 111 |
| | $ | 97 |
|
| Materials, supplies, and other | 83 |
| | 78 |
|
| | $ | 194 |
| | $ | 175 |
|
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
Note 11 – Property, Plant, and Equipment
|
| | | | | | | | | | | |
| | Estimated Useful Life (1) (Years) | | Depreciation Rates (1) (%) | | |
| December 31, |
| 2013 |
| 2012 |
| | | | | | (Millions) |
| Nonregulated: | | | | | | | |
| Natural gas gathering and processing facilities | 5 - 40 | | | | $ | 9,185 |
| | $ | 7,727 |
|
| Construction in progress | Not applicable | | | | 3,123 |
| | 1,997 |
|
| Other | 3 - 45 | | | | 1,316 |
| | 1,103 |
|
| Regulated: | | | | | | | |
| Natural gas transmission facilities | | | 1.20 - 6.97 | | 10,633 |
| | 9,963 |
|
| Construction in progress | | | Not applicable | | 273 |
| | 337 |
|
| Other | | | 1.35 - 33.33 | | 1,293 |
| | 1,419 |
|
| Total property, plant, and equipment, at cost | | | | | 25,823 |
| | 22,546 |
|
| Accumulated depreciation and amortization | | | | | (7,613 | ) | | (7,079 | ) |
| Property, plant, and equipment — net | | | | | $ | 18,210 |
| | $ | 15,467 |
|
__________
| |
| (1) | Estimated useful life and depreciation rates are presented as of December 31, 2013. Depreciation rates for regulated assets are prescribed by the FERC. |
Depreciation and amortization expense for Property, plant, and equipment – net was $752 million in 2013, $712 million in 2012, and $658 million in 2011.
Regulated Property, plant, and equipment – net includes approximately $785 million and $825 million at December 31, 2013 and 2012, 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.
Asset Retirement Obligations
Our accrued obligations relate to underground storage caverns, offshore platforms, fractionation and compression facilities, gas gathering well connections and pipelines, and gas transmission 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, 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 Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
The following table presents the significant changes to our asset retirement obligations (ARO), of which $497 million and $511 million are included in Other noncurrent liabilities with the remaining current portion in Accrued liabilities at December 31, 2013 and 2012, respectively.
|
| | | | | | | |
| | December 31, |
| | 2013 | | 2012 |
| | (Millions) |
| Beginning balance | $ | 579 |
| | $ | 573 |
|
| Liabilities incurred | 8 |
| | 8 |
|
| Liabilities settled (1) | (31 | ) | | (44 | ) |
| Accretion expense | 53 |
| | 43 |
|
| Revisions (2) | (48 | ) | | (1 | ) |
| Ending balance | $ | 561 |
| | $ | 579 |
|
______________
| |
| (1) | For 2013 and 2012, liabilities settled include $25 million and $31 million, respectively, related to the abandonment of certain of Transco’s natural gas storage caverns that are associated with a leak in 2010. |
| |
| (2) | Several factors are considered in the annual review process, including inflation rates, current estimates for removal cost, discount rates, and the estimated remaining life of the assets. The 2013 revision primarily reflects increases in the estimated remaining useful life of the assets. The 2012 revision primarily reflects a decrease in removal cost estimates. The 2013 and 2012 revisions also include increases of $9 million and $13 million, respectively, related to changes in the timing and method of abandonment on certain of Transco’s natural gas storage caverns that were associated with a leak in 2010. |
Transco is entitled to collect in rates the amounts necessary to fund its ARO. All funds received for such retirements are deposited into an external trust account dedicated to funding its ARO (ARO Trust). (See Note 16 – 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.
Note 12 – Accrued Liabilities
|
| | | | | | | |
| | December 31, |
| | 2013 | | 2012 |
| | (Millions) |
| Interest on debt | $ | 167 |
| | $ | 148 |
|
| Employee costs | 127 |
| | 137 |
|
| Estimated rate refund liability | 98 |
| | — |
|
| Asset retirement obligations | 64 |
| | 68 |
|
| Other, including other loss contingencies | 341 |
| | 275 |
|
| | $ | 797 |
| | $ | 628 |
|
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
Note 13 – Debt, Banking Arrangements, and Leases
Long-Term Debt |
| | | | | | | |
| | December 31, |
| | 2013 | | 2012 |
| | (Millions) |
| Unsecured: | | | |
| Transco: | | | |
| 6.4% Notes due 2016 | $ | 200 |
| | $ | 200 |
|
| 6.05% Notes due 2018 | 250 |
| | 250 |
|
| 7.08% Debentures due 2026 | 8 |
| | 8 |
|
| 7.25% Debentures due 2026 | 200 |
| | 200 |
|
| 5.4% Notes due 2041 | 375 |
| | 375 |
|
| 4.45% Notes due 2042 | 400 |
| | 400 |
|
| Northwest Pipeline: |
| | |
| 7% Notes due 2016 | 175 |
| | 175 |
|
| 5.95% Notes due 2017 | 185 |
| | 185 |
|
| 6.05% Notes due 2018 | 250 |
| | 250 |
|
| 7.125% Debentures due 2025 | 85 |
| | 85 |
|
| WPZ: |
| | |
| 3.8% Notes due 2015 | 750 |
| | 750 |
|
| 7.25% Notes due 2017 | 600 |
| | 600 |
|
| 5.25% Notes due 2020 | 1,500 |
| | 1,500 |
|
| 4.125% Notes due 2020 | 600 |
| | 600 |
|
| 4% Notes due 2021 | 500 |
| | 500 |
|
| 3.35% Notes due 2022 | 750 |
| | 750 |
|
| 4.5% Notes due 2023 | 600 |
| | — |
|
| 6.3% Notes due 2040 | 1,250 |
| | 1,250 |
|
| 5.8% Notes due 2043 | 400 |
| | — |
|
| Credit facility loans | — |
|
| 375 |
|
| The Williams Companies, Inc.: |
| | |
| 7.875% Notes due 2021 | 371 |
| | 371 |
|
| 3.7% Notes due 2023 | 850 |
| | 850 |
|
| 7.5% Debentures due 2031 | 339 |
| | 339 |
|
| 7.75% Notes due 2031 | 252 |
| | 252 |
|
| 8.75% Notes due 2032 | 445 |
| | 445 |
|
| Various — 5.5% to 10.25% Notes and Debentures due 2019 to 2033 | 55 |
| | 57 |
|
| Other, including secured capital lease obligations | 1 |
| | 2 |
|
| Net unamortized debt discount | (37 | ) | | (33 | ) |
| Total long-term debt, including current portion | 11,354 |
| | 10,736 |
|
| Long-term debt due within one year | (1 | ) | | (1 | ) |
| Long-term debt | $ | 11,353 |
| | $ | 10,735 |
|
Certain of our debt agreements contain covenants that restrict or limit, among other things, our ability to create liens supporting indebtedness, sell assets, and incur additional debt. Default of these agreements could also restrict our ability to make certain distributions or repurchase equity.
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
The following table presents aggregate minimum maturities of long-term debt (excluding net unamortized discount) for each of the next five years:
|
| | | |
| | December 31, 2013 |
| | (Millions) |
| 2014 | $ | — |
|
| 2015 | 750 |
|
| 2016 | 375 |
|
| 2017 | 785 |
|
| 2018 | 500 |
|
Issuances and retirements
In November 2013, WPZ completed a public offering of $600 million of 4.5 percent senior unsecured notes due 2023 and $400 million of 5.8 percent senior unsecured notes due 2043. WPZ used the net proceeds to repay amounts outstanding under its commercial paper program, to fund capital expenditures, and for general partnership purposes.
In December 2012, we completed a public offering of $850 million of 3.7 percent senior unsecured notes due 2023. We used the net proceeds to finance a portion of our investment in Access Midstream Partners.
In August 2012, WPZ completed a public offering of $750 million of 3.35 percent senior unsecured notes due 2022. WPZ used the net proceeds to repay outstanding borrowings on its senior unsecured revolving credit facility and for general partnership purposes.
In July 2012, Transco issued $400 million of 4.45 percent senior unsecured notes due 2042 to investors in a private debt placement. An offer to exchange these unregistered notes for substantially identical new notes that are registered under the Securities Act of 1933, as amended, was commenced in November 2012 and completed in December 2012. A portion of the proceeds from the issuance of these notes was used to repay Transco’s $325 million of 8.875 percent senior unsecured notes that matured on July 15, 2012.
Credit Facilities
On July 31, 2013, we amended our $900 million and WPZ’s $2.4 billion credit facilities to increase the aggregate commitments to $1.5 billion and $2.5 billion, respectively and extend the maturity dates for both credit facilities to July 31, 2018. Additionally, Transco and Northwest Pipeline are each able to borrow up to $500 million under the amended WPZ credit facility to the extent not otherwise utilized by the other co-borrowers. Both credit facilities may also, under certain conditions, be increased up to an additional $500 million. As a result of the modifications, the previously deferred fees and costs related to these facilities are being amortized over the term of the new arrangements.
At December 31, 2013, letter of credit capacity under our $1.5 billion and WPZ’s $2.5 billion credit facilities is $700 million and $1.3 billion, respectively. At December 31, 2013, no letters of credit have been issued and no loans are outstanding on these credit facilities. We have issued letters of credit totaling $16 million as of December 31, 2013, under certain bilateral bank agreements.
Our significant financial covenants require our ratio of debt to EBITDA (each as defined in the credit facility) to be no greater than 4.5 to 1. For the fiscal quarter and the two following fiscal quarters in which one or more acquisitions for a total aggregate purchase price equal to or greater than $50 million has been executed, we are required to maintain a ratio of debt to EBITDA of no greater than 5 to 1. At December 31, 2013, we are in compliance with these financial covenants.
WPZ's significant financial covenants require its ratio of debt to EBITDA (each as defined in the credit facility) to be no greater than 5 to 1. For the fiscal quarter and the two following fiscal quarters in which one or more acquisitions for a total aggregate purchase price equal to or greater than $50 million has been executed, WPZ is required to maintain
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
a ratio of debt to EBITDA of no greater than 5.5 to 1. In addition, 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. At December 31, 2013, WPZ is in compliance with these financial covenants.
The credit agreements governing our and WPZ’s respective credit facilities both contain the following terms and conditions:
| |
| • | Each time funds are borrowed, the applicable borrower may choose from two methods of calculating interest: a fluctuating base rate equal to Citibank N.A.’s alternate base rate plus an applicable margin or a periodic fixed rate equal to LIBOR plus an applicable margin. The applicable borrower is required to pay a commitment fee (currently 0.225 percent for our agreement and 0.175 percent for the WPZ agreement) based on the unused portion of its respective 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. |
| |
| • | Various covenants may limit, among other things, a borrower’s and its material subsidiaries’ ability to grant certain liens supporting indebtedness, a borrower’s ability to merge or consolidate, sell all or substantially all of its assets, enter into certain affiliate transactions, make certain distributions during an event of default, make investments, and allow any material change in the nature of its business. |
| |
| • | If an event of default with respect to a borrower occurs under its respective credit facility, the lenders will be able to terminate the commitments for the respective borrowers and accelerate the maturity of any loans of the defaulting borrower under the respective credit facility agreement and exercise other rights and remedies. |
Commercial Paper Program
In March 2013, WPZ initiated a commercial paper program. The program allows a maximum outstanding amount at any time of $2 billion of unsecured commercial paper notes. 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 WPZ’s commercial paper outstanding in Current liabilities in the Consolidated Balance Sheet, as the outstanding notes at December 31, 2013, have maturity dates less than three months from the date of issuance. At December 31, 2013, WPZ has $225 million in Commercial paper outstanding at a weighted average interest rate of 0.42 percent.
Cash Payments for Interest (Net of Amounts Capitalized)
Cash payments for interest (net of amounts capitalized) were $472 million in 2013, $479 million in 2012, and $573 million in 2011.
Restricted Net Assets of Subsidiaries
We have considered the guidance in the Securities and Exchange Commission’s Regulation S-X related to restricted net assets of subsidiaries. In accordance with Rule 4-08(e) of Regulation S-X, we have determined that certain net assets of our subsidiaries are considered restricted under this guidance and exceed 25 percent of our consolidated net assets. Substantially all of these restricted net assets relate to the net assets of WPZ, which are technically considered restricted under this accounting rule due to terms within WPZ’s partnership agreement that govern the partnership’s assets. Our interest in WPZ’s net assets that are considered to be restricted at December 31, 2013 was $6.5 billion.
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
Leases-Lessee
The future minimum annual rentals under noncancelable operating leases, are payable as follows:
|
| | | |
| | December 31, 2013 |
| | (Millions) |
| 2014 | $ | 53 |
|
| 2015 | 47 |
|
| 2016 | 43 |
|
| 2017 | 36 |
|
| 2018 | 30 |
|
| Thereafter | 123 |
|
| Total | $ | 332 |
|
Under our right-of-way agreement with the Jicarilla Apache Nation, we make annual payments of approximately $8 million and an additional annual payment which varies depending on the prior year’s per-unit NGL margins and the volume of gas gathered by our gathering facilities subject to the agreement. Depending primarily on the per-unit NGL margins for any given year, the additional annual payments could exceed the fixed amount. This agreement expires March 31, 2029.
Total rent expense was $58 million in 2013, $56 million in 2012, and $49 million in 2011.
Note 14 – Stockholders' Equity
Cash dividends declared per common share were $1.4375, $1.19625 and $.775 for 2013, 2012, and 2011, respectively.
In April 2012, we issued approximately 30 million shares of common stock in a public offering at a price of $30.59 per share. We used the net proceeds of $887 million to fund a portion of the purchase of additional WPZ common units in connection with WPZ's Caiman Acquisition. (See Note 2 – Acquisitions, Goodwill, and Other Intangible Assets.)
In December 2012, we issued approximately 53 million shares of common stock in a public offering at a price of $31 per share. We used the net proceeds of $1.6 billion to fund a portion of the purchase of an equity interest in ACMP. (See Note 2 – Acquisitions, Goodwill, and Other Intangible Assets.)
We maintain a Stockholder Rights Plan, as amended and restated on September 21, 2004, and further amended May 18, 2007 and October 12, 2007, under which each outstanding share of our common stock has a right (as defined in the plan) attached. Under certain conditions, each right may be exercised to purchase, at an exercise price of $50 (subject to adjustment), one two-hundredth of a share of Series A Junior Participating Preferred Stock. The rights may be exercised only if an Acquiring Person acquires (or obtains the right to acquire) 15 percent or more of our common stock or commences an offer for 15 percent or more of our common stock. The plan contains a mechanism to divest of shares of common stock if such stock in excess of 14.9 percent was acquired inadvertently or without knowledge of the terms of the rights. The rights, which until exercised do not have voting rights, expire in September 2014 and may be redeemed at a price of $.01 per right prior to their expiration, or within a specified period of time after the occurrence of certain events. In the event a person becomes the owner of more than 15 percent of our common stock, each holder of a right (except an Acquiring Person) shall have the right to receive, upon exercise, our common stock having a value equal to two times the exercise price of the right. In the event we are engaged in a merger, business combination, or 50 percent or more of our assets, cash flow or earnings power is sold or transferred, each holder of a right (except an Acquiring Person) shall have the right to receive, upon exercise, common stock of the acquiring company having a value equal to two times the exercise price of the right.
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
AOCI
The following table presents the changes in AOCI by component, net of income taxes:
|
| | | | | | | | | | | | | | | |
| | Cash Flow Hedges | | Foreign Currency Translation | | Pension and Other Post Retirement Benefits | | Total |
| | (Millions) |
| Balance at December 31, 2012 | $ | (1 | ) | | $ | 169 |
| | $ | (530 | ) | | $ | (362 | ) |
Other comprehensive income (loss) before reclassifications | 1 |
| | (41 | ) | | 203 |
| | 163 |
|
Amounts reclassified from accumulated other comprehensive income (loss) | (1 | ) | | — |
| | 36 |
| | 35 |
|
| Other comprehensive income (loss) | — |
| | (41 | ) | | 239 |
| | 198 |
|
| Balance at December 31, 2013 | $ | (1 | ) | | $ | 128 |
| | $ | (291 | ) | | $ | (164 | ) |
Reclassifications out of AOCI are presented in the following table by component for the year ended December 31, 2013:
|
| | | | | | |
| Component | | Reclassifications | | Classification |
| | | (Millions) | | |
| Cash flow hedges: | | | | |
| Energy commodity contracts | | $ | (1 | ) | | Product sales |
| Total cash flow hedges | | (1 | ) | | |
| | | | | |
| Pension and other postretirement benefits: | | | | |
| Amortization of prior service cost (credit) included in net periodic benefit cost | | (3 | ) | | Note 9 – Employee Benefit Plans |
| Amortization of actuarial (gain) loss included in net periodic benefit cost | | 61 |
| | Note 9 – Employee Benefit Plans |
| Total pension and other postretirement benefits | | 58 |
| | |
| | | | | |
| Reclassifications before income tax | | 57 |
| | |
| Income tax benefit | | (22 | ) | | Provision (benefit) for income taxes |
| Reclassifications during the period | | $ | 35 |
| | |
Note 15 – Stock-Based Compensation
Plan Information
On May 17, 2007, our stockholders approved a plan that provides common-stock-based awards to both employees and nonmanagement directors and reserved 19 million new shares for issuance. On May 20, 2010, our stockholders approved an amendment and restatement of the 2007 plan to increase by 11 million the number of new shares authorized for making awards under the plan, among other changes. The plan permits the granting of various types of awards including, but not limited to, restricted stock units and stock options. At December 31, 2013, 24 million shares of our common stock were reserved for issuance pursuant to existing and future stock awards, of which 14 million shares were available for future grants.
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
Additionally, on May 17, 2007, our stockholders approved an Employee Stock Purchase Plan (ESPP) which authorizes up to 2 million new shares of our common stock to be available for sale under the plan. The ESPP enables eligible participants to purchase our common stock through payroll deductions not exceeding an annual amount of $15,000 per participant. The ESPP provides for offering periods during which shares may be purchased and continues until the earliest of (1) the Board of Directors terminates the ESPP, (2) the sale of all shares available under the ESPP, or (3) the tenth anniversary of the date the Plan was approved by the stockholders. Offering periods are from January through June and from July through December. Generally, all employees are eligible to participate in the ESPP, with the exception of executives and international employees. The number of shares eligible for an employee to purchase during each offering period is limited to 750 shares. The purchase price of the stock is 85 percent of the lower closing price of either the first or the last day of the offering period. The ESPP requires a one-year holding period before the stock can be sold. Employees purchased 203 thousand shares at an average price of $27.62 per share during 2013. Approximately 413 thousand shares were available for purchase under the ESPP at December 31, 2013.
Total stock-based compensation expense for the years ended December 31, 2013, 2012, and 2011 was $37 million, $36 million, and $52 million, respectively, of which $18 million is included in Income (loss) from discontinued operations for 2011. Total income tax benefit recognized related to the total stock-based compensation expense for the years ended December 31, 2013, 2012, and 2011 was $14 million, $13 million, and $19 million, respectively. Measured but unrecognized stock-based compensation expense at December 31, 2013, was $44 million, which does not include the effect of estimated forfeitures of $1 million. This amount is comprised of $4 million related to stock options and $40 million related to restricted stock units. These amounts are expected to be recognized over a weighted-average period of 1.8 years.
Stock Options
Stock options are valued at the date of award, which does not precede the approval date. The purchase price per share for stock options may not be less than the market price of the underlying stock on the date of grant. Stock options generally become exercisable over a three-year period from the date of grant. Stock options generally expire ten years after the grant.
The following summary reflects stock option activity and related information for the year ended December 31, 2013:
|
| | | | | | | | | | |
| Stock Options | Options | | Weighted- Average Exercise Price | | Aggregate Intrinsic Value |
| | (Millions) | | | | (Millions) |
| Outstanding at December 31, 2012 | 6.9 |
| | $ | 19.10 |
| | |
| Granted | 0.9 |
| | $ | 33.57 |
| | |
| Exercised | (1.1 | ) | | $ | 13.34 |
| | |
| Outstanding at December 31, 2013 | 6.7 |
| | $ | 21.82 |
| | $ | 112 |
|
| Exercisable at December 31, 2013 | 5.0 |
| | $ | 18.70 |
| | $ | 98 |
|
The total intrinsic value of options exercised during the years ended December 31, 2013, 2012, and 2011 was $23 million, $69 million, and $55 million, respectively; and the tax benefit realized was $9 million, $25 million, and $21 million, respectively. Cash received from stock option exercises was $13 million, $50 million, and $45 million during 2013, 2012, and 2011, respectively. The weighted-average remaining contractual life for stock options outstanding and exercisable at December 31, 2013, was 5.1 years and 3.9 years, respectively.
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
The estimated fair value at date of grant of options for our common stock granted in each respective year, using the Black-Scholes option pricing model, is as follows:
|
| | | | | | | | | | | |
| | 2013 | | 2012 | | 2011 |
| Weighted-average grant date fair value of options for our common stock granted during the year, per share | $ | 5.94 |
| | $ | 5.65 |
| | $ | 6.28 |
|
| Weighted-average assumptions: | | | | | |
| Dividend yield | 4.3 | % | | 3.7 | % | | 3.6 | % |
| Volatility | 29.7 | % | | 30.0 | % | | 34.6 | % |
| Risk-free interest rate | 1.4 | % | | 1.3 | % | | 2.8 | % |
| Expected life (years) | 6.5 |
| | 6.5 |
| | 6.5 |
|
The expected dividend yield is based on the 2013 dividend forecast and the grant-date market price of our stock. As a result of the 2011 spin-off of WPX, the historical volatility of our stock is not expected to be as representative of expected future volatility. Expected volatility is now based on the average of our peer group 10-year historical volatility adjusted by a ratio of our implied volatility to the average of our peer group’s implied volatility. The adjustment is made because the difference in implied volatility between our peer group and us may indicate that we are expected to be more volatile than our peer group average. The risk-free interest rate is based on the U.S. Treasury Constant Maturity rates as of the grant date. The expected life of the option is based on historical exercise behavior and expected future experience.
Nonvested Restricted Stock Units
The following summary reflects nonvested restricted stock unit activity and related information for the year ended December 31, 2013.
|
| | | | | | |
| Restricted Stock Units Outstanding | Shares | | Weighted- Average Fair Value* |
| | (Millions) | | |
| Nonvested at December 31, 2012 | 3.9 |
| | $ | 22.49 |
|
| Granted | 1.2 |
| | $ | 30.43 |
|
| Forfeited | (0.1 | ) | | $ | 27.27 |
|
| Vested | (1.5 | ) | | $ | 17.82 |
|
| Nonvested at December 31, 2013 | 3.5 |
| | $ | 27.16 |
|
______________
| |
| * | Performance-based shares are valued utilizing a Monte Carlo valuation method using measures of total shareholder return. All other shares are valued at the grant-date market price or the grant-date market price less dividends projected to be paid over the vesting period. Restricted stock units generally vest after three years. |
|
| | | | | | | | | | | |
| Value of Restricted Stock Units | 2013 | | 2012 | | 2011 |
| Weighted-average grant date fair value of restricted stock units granted during the year, per share | $ | 30.43 |
| | $ | 20.61 |
| | $ | 23.31 |
|
| Total fair value of restricted stock units vested during the year ($’s in millions) | $ | 27 |
| | $ | 22 |
| | $ | 35 |
|
Performance-based shares granted under the Plan represent 32 percent of nonvested restricted stock units outstanding at December 31, 2013. These grants may be earned at the end of a three-year period based on actual performance against a performance target. Based on the extent to which certain financial targets are achieved, vested shares may range from zero percent to 200 percent of the original grant amount.
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| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
Note 16 – 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, 2013: | | | | | | | | | |
| Measured on a recurring basis: | | | | | | | | | |
| ARO Trust investments | $ | 33 |
| | $ | 33 |
| | $ | 33 |
| | $ | — |
| | $ | — |
|
| Energy derivatives assets not designated as hedging instruments | 3 |
| | 3 |
| | — |
| | — |
| | 3 |
|
| Energy derivatives liabilities not designated as hedging instruments | (3 | ) | | (3 | ) | | — |
| | (1 | ) | | (2 | ) |
| Additional disclosures: | | | | | | | | | |
| Notes receivable and other | 77 |
| | 140 |
| | 1 |
| | 6 |
| | 133 |
|
| Long-term debt (1) | (11,353 | ) | | (11,971 | ) | | — |
| | (11,971 | ) | | — |
|
| Guarantee | (32 | ) | | (29 | ) | | — |
| | (29 | ) | | — |
|
| Assets (liabilities) at December 31, 2012: | | | | | | | | | |
| Measured on a recurring basis: | | | | | | | | | |
| ARO Trust investments | $ | 18 |
| | $ | 18 |
| | $ | 18 |
| | $ | — |
| | $ | — |
|
| Energy derivatives assets not designated as hedging instruments | 5 |
| | 5 |
| | — |
| | — |
| | 5 |
|
| Energy derivatives liabilities not designated as hedging instruments | (1 | ) | | (1 | ) | | — |
| | — |
| | (1 | ) |
| Additional disclosures: | | | | | | | | | |
| Notes receivable and other | 95 |
| | 138 |
| | 2 |
| | 8 |
| | 128 |
|
| Long-term debt (1) | (10,734 | ) | | (12,388 | ) | | — |
| | (12,388 | ) | | — |
|
| Guarantee | (33 | ) | | (31 | ) | | — |
| | (31 | ) | | — |
|
________________
(1) Excludes capital leases
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.
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| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
Energy derivatives: Energy derivatives include commodity based exchange-traded contracts and over-the-counter (OTC) 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 Accrued liabilities and Other noncurrent liabilities 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, 2013 or 2012.
Additional fair value disclosures
Notes receivable and other: Notes receivable and other includes a receivable related to the sale of certain former Venezuela assets (see Note 4 – Discontinued Operations). The disclosed fair value of this receivable is determined by an income approach. We calculated the net present value of a probability-weighted set of cash flows utilizing assumptions based on contractual terms, historical payment patterns by the counterparty, future probabilities of default, our likelihood of using arbitration if the counterparty does not perform, and discount rates. We determined the fair value of the receivable to be $97 million at December 31, 2013. The carrying value of this receivable is $35 million at December 31, 2013. The current and noncurrent portions are reported in Accounts and notes receivable, net and Regulatory assets, deferred charges, and other, respectively, in the Consolidated Balance Sheet.
Notes receivable and other also includes a receivable from our former affiliate, WPX (see Note 17 – Contingent Liabilities and Commitments) and other notes receivable. The disclosed fair value of these receivables is primarily determined by an income approach which considers the underlying contract amounts and our assessment of our ability to recover these amounts. The current portion is reported in Accounts and notes receivable, net and the noncurrent portion is reported in Regulatory assets, deferred charges, and other in the Consolidated Balance Sheet.
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.
Guarantee: The guarantee represented in the table consists of a guarantee we have provided in the event of nonpayment by our previously owned communications subsidiary, Williams Communications Group (WilTel), on a lease performance obligation that extends through 2042.
To estimate the disclosed fair value of the guarantee, an estimated default rate is applied to the sum of the future contractual lease payments using an income approach. The estimated default rate is determined by obtaining the average cumulative issuer-weighted corporate default rate based on the credit rating of WilTel’s current owner and the term of the underlying obligation. The default rate is published by Moody’s Investors Service. This guarantee is reported in Accrued liabilities in the Consolidated Balance Sheet.
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.
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
Regarding our previously described guarantee of WilTel’s lease performance, the maximum potential exposure is approximately $35 million, and $36 million at December 31, 2013 and 2012, respectively. Our exposure declines systematically throughout the remaining term of WilTel’s obligation.
We have provided guarantees in the event of nonpayment by our previously owned subsidiary, WPX, on certain contracts, primarily a natural gas purchase contract extending through 2023. We estimate the maximum undiscounted potential future payment obligation under these remaining guarantees is approximately $69 million at December 31, 2013. Our recorded liability for these guarantees, which considers our estimate of the fair value of the guarantees, is insignificant.
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.
Accounts and notes receivable
The following table summarizes concentration of receivables, net of allowances.
|
| | | | | | | |
| | December 31, |
| | 2013 | | 2012 |
| | (Millions) |
| NGLs, natural gas, and related products and services | $ | 341 |
| | $ | 411 |
|
| Transportation of natural gas and related products | 193 |
| | 170 |
|
| Income tax receivable | 74 |
| | 68 |
|
| Other | 66 |
| | 39 |
|
| Total | $ | 674 |
| | $ | 688 |
|
Customers include producers, distribution companies, industrial users, gas marketers and pipelines primarily located in the continental United States and Canada. As a general policy, collateral is not required for receivables, but customers’ financial condition and credit worthiness are evaluated regularly.
Revenues
In 2013, 2012, and 2011, we had one customer in our Williams Partners segment that accounted for 9 percent, 14 percent and 17 percent of our consolidated revenues, respectively.
Note 17 – Contingent Liabilities and Commitments
Indemnification of WPX Matters
We have agreed to indemnify our former affiliate, WPX and its subsidiaries, related to the following matters. In connection with this indemnification, we have accrued asset and liability balances associated with these matters, and as a result, have an indirect exposure to future developments in these matters.
Issues resulting from California energy crisis
WPX’s former power business was engaged in power marketing in various geographic areas, including California. Prices charged for power by WPX and other traders and generators in California and other western states in 2000 and 2001 were challenged in various proceedings, including those before the FERC. WPX has entered into settlements with the State of California (State Settlement), major California utilities (Utilities Settlement), and others that substantially resolved each of these issues with these parties.
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| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
Although the State Settlement and Utilities Settlement resolved a significant portion of the refund issues among the settling parties, WPX continues to have potential refund exposure to nonsettling parties, including various California end users that did not participate in the Utilities Settlement. WPX and certain California utilities have agreed in principle to resolve WPX’s collection of accrued interest from counterparties as well as WPX’s payment of accrued interest on refund amounts. On December 23, 2013, the parties submitted their settlement to the FERC for regulatory approval. The settlement will resolve most of WPX’s legal issues arising from the 2000-2001 California Energy Crisis. We currently have a net receivable from WPX related to these matters.
Reporting of natural gas-related information to trade publications
Direct and indirect purchasers of natural gas in various states filed class actions against WPX and others alleging the manipulation of published gas price indices and seeking unspecified amounts of damages. Such actions were transferred to the Nevada federal district court for consolidation of discovery and pre-trial issues.
In 2011, the Nevada district court granted WPX’s joint motions for summary judgment to preclude the plaintiffs’ state law claims because the federal Natural Gas Act gives the FERC exclusive jurisdiction to resolve those issues. The court also denied the plaintiffs’ class certification motion as moot. The plaintiffs appealed the court’s ruling and on April 10, 2013, the Ninth Circuit Court of Appeals reversed the district court and remanded the cases to the district court to permit the plaintiffs to pursue their state antitrust claims for natural gas sales that were not subject to FERC jurisdiction under the Natural Gas Act. On August 26, 2013, WPX and the other defendants filed their petition for a writ of certiorari with the U.S. Supreme Court. Because of the uncertainty around the remaining pending unresolved issues, including an insufficient description of the purported classes and other related matters, we cannot reasonably estimate a range of potential exposures at this time. However, it is reasonably possible that the ultimate resolution of these items and our related indemnification obligation could result in future charges that may be material to our results of operations.
Other Legal Matters
Geismar Incident
As a result of the previously discussed Geismar Incident, there were two fatalities and numerous individuals (including employees and contractors) reported injuries, which varied from minor to serious. WPZ is cooperating with the Chemical Safety Board, and the U.S. Environmental Protection Agency (EPA) regarding their investigations of 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 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. We and the EPA continue to discuss such preliminary determinations, and the EPA could issue penalties pertaining to final determinations. On December 11, 2013, the Occupational Safety and Health Administration (OSHA) issued Citations for the June 13, 2013 incident, which included a Notice of Penalty for $99,000. Although we and OSHA continue settlement negotiations, we are contesting the citation. On June 28, 2013, the Louisiana Department of Environmental Quality (LDEQ) issued a Consolidated Compliance Order & Notice of Potential Penalty to Williams Olefins, L.L.C. that consolidates claims of unpermitted emissions and other deviations under the Clean Air Act that the parties had been negotiating since 2010 and alleged unpermitted emissions arising from the Geismar Incident. Negotiations with the LDEQ are ongoing. Any potential fines and penalties from these agencies would not be covered by our insurance policy. Additionally, multiple lawsuits, including class actions for alleged offsite impacts, property damage, and personal injury, have been filed against various of our subsidiaries.
Due to the ongoing investigation into the cause of the incident, and the limited information available associated with the filed lawsuits, which do not specify any amounts for claimed damages, we cannot reasonably estimate a range of potential loss related to these contingencies at this time.
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| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
Gulf Liquids litigation
Gulf Liquids, one of our subsidiaries, contracted with Gulsby Engineering Inc. (Gulsby) and Gulsby-Bay (a joint venture between Gulsby and Bay Ltd.) for the construction of certain gas processing plants in Louisiana. National American Insurance Company (NAICO) and American Home Assurance Company provided payment and performance bonds for the projects. In 2001, the contractors and sureties filed multiple cases in Louisiana and Texas against Gulf Liquids and us.
In 2006, at the conclusion of the consolidated trial of the asserted contract and tort claims, the jury returned its actual and punitive damages verdict against us and Gulf Liquids. Based on our interpretation of the jury verdicts, we recorded a charge based on our estimated exposure for actual damages of approximately $68 million plus potential interest of approximately $20 million. In addition, we concluded that it was reasonably possible that any ultimate judgment might have included additional amounts of approximately $199 million in excess of our accrual, which primarily represented our estimate of potential punitive damage exposure under Texas law.
From May through October 2007, the court entered seven post-trial orders in the case (interlocutory orders) which, among other things, overruled the verdict award of tort and punitive damages as well as any damages against us. The court also denied the plaintiffs’ claims for attorneys’ fees. On January 28, 2008, the court issued its judgment awarding damages against Gulf Liquids of approximately $11 million in favor of Gulsby and approximately $4 million in favor of Gulsby-Bay. Gulf Liquids, Gulsby, Gulsby-Bay, Bay Ltd., and NAICO appealed the judgment. In February 2009, we settled with certain of these parties and reduced our accrued liability as of December 31, 2008, by $43 million, including $11 million of interest. On February 17, 2011, the Texas Court of Appeals upheld the dismissals of the tort and punitive damages claims. As a result, we reduced our accrued liability as of December 31, 2011 by $33 million, including $14 million of interest. The Texas Court of Appeals also reversed and remanded the remaining claims for further proceedings. None of the parties filed a petition for review in the Texas Supreme Court. On May 8, 2012, the Texas Court of Appeals issued its mandate remanding the original breach of contract claims involving Gulsby and attorney fee claims (the remaining claims) to trial court. Trial is set for October 14, 2014.
Alaska refinery contamination litigation
In January 2010, James West filed a class action lawsuit in state court in Fairbanks, Alaska on behalf of individual property owners whose water contained sulfolane contamination allegedly emanating from the Flint Hills Oil Refinery in North Pole, Alaska. The suit named our subsidiary, Williams Alaska Petroleum Inc. (WAPI), and Flint Hills Resources Alaska, LLC (FHRA), a subsidiary of Koch Industries, Inc., as defendants. We owned and operated the refinery until 2004 when we sold it to FHRA. We and FHRA have made claims under the pollution liability insurance policy issued in connection with the sale of the North Pole refinery to FHRA. We and FHRA also filed claims against each other seeking, among other things, contractual indemnification alleging that the other party caused the sulfolane contamination.
In 2011, we and FHRA settled the James West claim. We and FHRA subsequently filed motions for summary judgment on the other’s claims. On November 5, 2013, the court ruled that the applicable statute of limitations bars all FHRA’s claims against us and dismissed those claims with prejudice. FHRA has asked the court to reconsider and clarify its ruling, and we anticipate that FHRA will appeal the court’s decision.
We currently estimate that our reasonably possible loss exposure in this matter could range from an insignificant amount up to $32 million, although uncertainties inherent in the litigation process, expert evaluations, and jury dynamics might cause our exposure to exceed that amount.
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
Independent of the litigation matter described in the preceding paragraphs, the Alaska Department of Environmental Conservation (ADEC) indicated that it views FHRA and us as responsible parties. During the first quarter of 2013 and again on December 23, 2013, ADEC informed FHRA and us that it intends to enter a compliance order to address the environmental remediation of sulfolane and other possible contaminants including cleanup work outside the refinery’s boundaries to be performed in 2014. In addition, ADEC will seek from each of FHRA and us an adequate financial performance guarantee for the benefit of ADEC. As such, we will likely be required to contribute some amount, whether to reimburse the State, to reimburse FHRA, or to comply with an ADEC order. Due to the ongoing assessment of the level and extent of sulfolane contamination and the ultimate cost of remediation and division of costs between the named responsible parties, we are unable to estimate a range of liability at this time.
Other
On August 31, 2012, Transco submitted to the FERC a general rate filing principally designed to recover increased costs and to comply with the terms of the settlement in its prior rate proceedings. The new rates became effective March 1, 2013, subject to refund and the outcome of the hearing. On August 27, 2013, Transco filed a stipulation and agreement with the FERC proposing to resolve all issues in this proceeding without the need for a hearing (Agreement). On December 6, 2013, the FERC issued an order approving the Agreement without modifications. Pursuant to its terms, the Agreement will become effective March 1, 2014. We have provided a reserve for rate refunds of $98 million, in Accrued liabilities, which we believe is adequate for required refunds as of December 31, 2013, under the Agreement. Refunds will be made on or before April 30, 2014.
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 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 of December 31, 2013, we have accrued liabilities totaling $47 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 ground level ozone, one hour nitrogen dioxide emission limits, and new air quality standards impacting storage vessels, pressure valves, and compressors. We are unable to estimate the costs of asset additions or modifications necessary to comply with these new regulations due to uncertainty created by the various legal challenges to these regulations and the need for further specific regulatory guidance.
Continuing operations
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, 2013, we have accrued liabilities of $13 million for these costs. We expect that these costs will be recoverable through rates.
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
We also accrue environmental remediation costs for natural gas underground storage facilities, primarily related to soil and groundwater contamination. At December 31, 2013, we have accrued liabilities totaling $7 million for these costs.
Former operations, including operations classified as discontinued
We have potential obligations in connection with assets and businesses we no longer operate. These potential obligations include the indemnification of the purchasers of certain of these assets and businesses for environmental and other liabilities existing at the time the sale was consummated. Our responsibilities relate to the operations of the assets and businesses described below.
| |
| • | Former agricultural fertilizer and chemical operations and former retail petroleum and refining operations; |
| |
| • | Former petroleum products and natural gas pipelines; |
| |
| • | Former petroleum refining facilities; |
| |
| • | Former exploration and production and mining operations; |
| |
| • | Former electricity and natural gas marketing and trading operations. |
At December 31, 2013, we have accrued environmental liabilities of $27 million related to these matters.
Other Divestiture Indemnifications
Pursuant to various purchase and sale agreements relating to divested businesses and assets, we have indemnified certain purchasers against liabilities that they may incur with respect to the businesses and assets acquired from us. The indemnities provided to the purchasers are customary in sale transactions and are contingent upon the purchasers incurring liabilities that are not otherwise recoverable from third parties. The indemnities generally relate to breach of warranties, tax, historic litigation, personal injury, property damage, environmental matters, right of way and other representations that we have provided.
At December 31, 2013, other than as previously disclosed, we are not aware of any material claims involving the indemnities; thus, we do not expect any of the indemnities provided pursuant to the sales agreements to have a material impact on our future financial position. Any claim for indemnity brought against us in the future may have a material adverse effect on our results of operations in the period in which the claim is made.
In addition to the foregoing, various other proceedings are pending against us which are incidental to our operations.
Summary
We have disclosed our estimated range of reasonably possible losses for certain matters above, as well as 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 $1.5 billion at December 31, 2013.
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
Note 18 – Segment Disclosures
Our reportable segments are Williams Partners, Williams NGL & Petchem Services, and Access Midstream Partners. All remaining business activities are included in Other. (See Note 1 – Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies.)
Our segment presentation of Williams Partners is reflective of the parent-level focus by our chief operating decision-maker, considering the resource allocation and governance provisions associated with this master limited partnership structure. WPZ maintains a capital and cash management structure that is separate from ours. WPZ is self-funding and maintains its own lines of bank credit and cash management accounts. These factors, coupled with a different cost of capital from our other businesses, serve to differentiate the management of this entity as a whole.
Our segment presentation of Access Midstream Partners reflects the significant size of this investment and the economic opportunities it represents in major unconventional producing areas that add diversity to our current asset base.
Performance Measurement
We currently evaluate segment operating performance based upon Segment profit (loss) from operations, which includes Segment revenues from external and internal customers, segment costs and expenses, Equity earnings (losses) and Income (loss) from investments. General corporate expenses represent Selling, general, and administrative expenses that are not allocated to our segments. The accounting policies of the segments are the same as those described in Note 1 – Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies. Intersegment revenues are generally accounted for at current market prices as if the sales were to unaffiliated third parties.
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: | | | | | | |
| | 2013 | $ | 6,703 |
| $ | 157 |
| $ | 6,860 |
|
| | 2012 | | 7,335 |
| | 151 |
| | 7,486 |
|
| | 2011 | | 7,728 |
| | 202 |
| | 7,930 |
|
| | | | | | | | |
| Long-lived assets: | | | | | | |
| | 2013 | $ | 19,260 |
| $ | 1,240 |
| $ | 20,500 |
|
| | 2012 | | 16,940 |
| | 880 |
| | 17,820 |
|
| | 2011 | | 12,041 |
| | 583 |
| | 12,624 |
|
Long-lived assets are comprised of property, plant, and equipment, goodwill, and other intangible assets.
As discussed in Note 1 – Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies and Note 4 – Discontinued Operations, our former exploration and production business was spun-off on December 31, 2011 and has been reported as discontinued operations in all prior periods presented. Revenues derived from intercompany sales to our former exploration and production business, previously reported as internal, are now shown as external. These sales were $310 million for the year ended 2011. In addition, costs attributable to activities with our former exploration and production business, previously reported as internal, are now shown as external. Such costs were $845 million for the year ended 2011. We continue to recognize revenue as we provide certain gathering, processing, and treating services to WPX under long term agreements.
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
The following table reflects the reconciliation of Segment revenues and Segment profit (loss) to Total revenues and Operating income (loss) as reported in the Consolidated Statement of Income and Other financial information related to Long-lived assets.
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Williams Partners | | Williams NGL & Petchem Services | | Access Midstream Partners | | Other | | Eliminations | | Total |
| | (Millions) |
| 2013 |
| Segment revenues: | | | | | | | | | | | |
| Service revenues | | | | | | | | | | | |
| External | $ | 2,914 |
| | $ | — |
| | $ | — |
| | $ | 25 |
| | $ | — |
| | $ | 2,939 |
|
| Internal | — |
| | — |
| | — |
| | 11 |
| | (11 | ) | | — |
|
| Total service revenues | 2,914 |
| | — |
| | — |
| | 36 |
| | (11 | ) | | 2,939 |
|
| Product sales | | | | | | | | | | | |
| External | 3,921 |
| | — |
| | — |
| | — |
| | — |
| | 3,921 |
|
| Internal | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Total product sales | 3,921 |
| | — |
| | — |
| | — |
| | — |
| | 3,921 |
|
| Total revenues | $ | 6,835 |
| | $ | — |
| | $ | — |
| | $ | 36 |
| | $ | (11 | ) | | $ | 6,860 |
|
| Segment profit (loss) | $ | 1,677 |
| | $ | (32 | ) | | $ | 61 |
| | $ | (5 | ) | | | | $ | 1,701 |
|
| Less: | | | | | | | | | | | |
| Equity earnings (losses) | 104 |
| | — |
| | 30 |
| | — |
| | | | 134 |
|
| Income (loss) from investments | (3 | ) | | — |
| | 31 |
| | — |
| | | | 28 |
|
| Segment operating income (loss) | $ | 1,576 |
| | $ | (32 | ) | | $ | — |
| | $ | (5 | ) | | | | 1,539 |
|
| General corporate expenses | | | | | | | | | | | (164 | ) |
| Operating income (loss) | | | | | | | | | | | $ | 1,375 |
|
| | | | | | | | | | | | |
| Other financial information: | | | | | | | | | | | |
| Additions to long-lived assets | $ | 3,409 |
| | $ | 295 |
| | $ | — |
| | $ | 27 |
| | $ | — |
| | $ | 3,731 |
|
| Depreciation and amortization | 791 |
| | — |
| | — |
| | 24 |
| | — |
| | 815 |
|
| | | | | | | | | | | | |
| 2012 |
| Segment revenues: | | | | | | | | | | | |
| Service revenues | | | | | | | | | | | |
| External | $ | 2,714 |
| | $ | — |
| | $ | — |
| | $ | 15 |
| | $ | — |
| | $ | 2,729 |
|
| Internal | — |
| | — |
| | — |
| | 12 |
| | (12 | ) | | — |
|
| Total service revenues | 2,714 |
| | — |
| | — |
| | 27 |
| | (12 | ) | | 2,729 |
|
| Product sales | | | | | | | | | | | |
| External | 4,757 |
| | — |
| | — |
| | — |
| | — |
| | 4,757 |
|
| Internal | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Total product sales | 4,757 |
| | — |
| | — |
| | — |
| | — |
| | 4,757 |
|
| Total revenues | $ | 7,471 |
| | $ | — |
| | $ | — |
| | $ | 27 |
| | $ | (12 | ) | | $ | 7,486 |
|
| Segment profit (loss) | $ | 1,907 |
| | $ | (3 | ) | | $ | — |
| | $ | 56 |
| | | | $ | 1,960 |
|
| Less: | | | | | | | | | | | |
| Equity earnings (losses) | 111 |
| | — |
| | — |
| | — |
| | | | 111 |
|
| Income (loss) from investments | (4 | ) | | — |
| | — |
| | 53 |
| | | | 49 |
|
| Segment operating income (loss) | $ | 1,800 |
| | $ | (3 | ) | | $ | — |
| | $ | 3 |
| | | | 1,800 |
|
| General corporate expenses | | | | | | | | | | | (188 | ) |
| Operating income (loss) | | | | | | | | | | | $ | 1,612 |
|
| | | | | | | | | | | | |
| Other financial information: | | | | | | | | | | | |
| Additions to long-lived assets | $ | 5,851 |
| | $ | 136 |
| | $ | — |
| | $ | 31 |
| | $ | — |
| | $ | 6,018 |
|
| Depreciation and amortization | 734 |
| | — |
| | — |
| | 22 |
| | — |
| | 756 |
|
| | | | | | | | | | | | |
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Williams Partners | | Williams NGL & Petchem Services | | Access Midstream Partners | | Other | | Eliminations | | Total |
| | (Millions) |
| 2011 | | | | | | | | | | | |
| Segment revenues: | | | | | | | | | | | |
| Service revenues | | | | | | | | | | | |
| External | $ | 2,518 |
| | $ | — |
| | $ | — |
| | $ | 14 |
| | $ | — |
| | $ | 2,532 |
|
| Internal | — |
| | — |
| | — |
| | 11 |
| | (11 | ) | | — |
|
| Total service revenues | 2,518 |
| | — |
| | — |
| | 25 |
| | (11 | ) | | 2,532 |
|
| Product sales | | | | | | | | | | | |
| External | 5,398 |
| | — |
| | — |
| | — |
| | — |
| | 5,398 |
|
| Internal | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Total product sales | 5,398 |
| | — |
| | — |
| | — |
| | — |
| | 5,398 |
|
| Total revenues | $ | 7,916 |
| | $ | — |
| | $ | — |
| | $ | 25 |
| | $ | (11 | ) | | $ | 7,930 |
|
| Segment profit (loss) | $ | 2,174 |
| | $ | 18 |
| | $ | — |
| | $ | 24 |
| | | | $ | 2,216 |
|
| Less: | | | | | | | | | | | |
| Equity earnings (losses) | 142 |
| | — |
| | — |
| | 13 |
| | | | 155 |
|
| Income (loss) from investments | (4 | ) | | — |
| | — |
| | 11 |
| | | | 7 |
|
| Segment operating income (loss) | $ | 2,036 |
| | $ | 18 |
| | $ | — |
| | $ | — |
| | | | 2,054 |
|
| General corporate expenses | | | | | | | | | | | (187 | ) |
| Operating income (loss) | | | | | | | | | | | $ | 1,867 |
|
| | | | | | | | | | | | |
| Other financial information: | | | | | | | | | | | |
| Additions to long-lived assets | $ | 1,484 |
| | $ | — |
| | $ | — |
| | $ | 46 |
| | $ | — |
| | $ | 1,530 |
|
| Depreciation and amortization | 637 |
| | — |
| | — |
| | 24 |
| | — |
| | 661 |
|
| | | | | | | | | | | | |
The following table reflects Total assets and Equity method investments by reportable segments:
|
| | | | | | | | | | | | | | | | |
| | | Total Assets | | Equity Method Investments |
| | | December 31, 2013 | | December 31, 2012 | | December 31, 2013 | | December 31, 2012 |
| | | (Millions) |
| Williams Partners | | $ | 23,571 |
| | $ | 20,678 |
| | $ | 2,187 |
|
| $ | 1,800 |
|
| Williams NGL & Petchem Services | | 486 |
| | 146 |
| | 12 |
| | — |
|
| Access Midstream Partners | | 2,161 |
| | 2,187 |
| | 2,161 |
| | 2,187 |
|
| Other | | 1,359 |
| | 1,787 |
| | — |
| | — |
|
| Eliminations | | (435 | ) | | (471 | ) | | — |
| | — |
|
| Total | | $ | 27,142 |
| | $ | 24,327 |
| | $ | 4,360 |
| | $ | 3,987 |
|
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
Note 19 – Subsequent Events (Unaudited)
Information Subsequent to February 26, 2014 Date of Independent Registered Public Accounting Firm Report
On February 16, 2014, we and our partner executed an amendment to the governing documents that removed our power to direct whether the Bluegrass Pipeline (see Note 3 – Variable Interest Entities) moved forward. As a result, we determined that we were no longer the primary beneficiary as of that date and we deconsolidated the Bluegrass Pipeline and began reporting our 50 percent interest as an equity-method investment. There was no gain or loss recognized upon deconsolidation. Completion of the Bluegrass Pipeline is subject to execution of customer contracts sufficient to support the project. Although discussions with potential customers continue, we have not received sufficient executed customer commitments to support the continued development of the project. Considering this and other factors, our management decided in April 2014 to discontinue further funding of the project at this time. Given these developments, the capitalized project development costs at the Bluegrass Pipeline entity, as well as the Moss Lake entities, were written off as of March 31, 2014, and as a result, we recognized $70 million in related equity losses in the first quarter of 2014.
In March 2014, WPZ completed a registered offering of debt securities consisting of $1 billion of 4.3 percent senior notes due 2024 and $500 million of 5.4 percent senior notes due 2044. The proceeds were used to repay amounts outstanding under WPZ’s commercial paper program, to fund capital expenditures, and for general partnership purposes.
As of May 22, 2014, $370 million is outstanding under WPZ’s commercial paper program.
The Williams Companies Inc.
Quarterly Financial Data
(Unaudited)
Summarized quarterly financial data are as follows:
|
| | | | | | | | | | | | | | | |
| | First Quarter | | Second Quarter | | Third Quarter | | Fourth Quarter |
| | (Millions, except per-share amounts) |
| 2013 | |
| Revenues | $ | 1,810 |
| | $ | 1,767 |
| | $ | 1,623 |
| | $ | 1,660 |
|
| Product costs | 790 |
| | 801 |
| | 710 |
| | 726 |
|
| Income (loss) from continuing operations | 231 |
| | 200 |
| | 198 |
| | 50 |
|
| Net income (loss) | 230 |
| | 192 |
| | 197 |
| | 49 |
|
| Amounts attributable to The Williams Companies, Inc.: | | | | | | | |
| Income (loss) from continuing operations | 162 |
| | 149 |
| | 143 |
| | (13 | ) |
| Net income (loss) | 161 |
| | 142 |
| | 141 |
| | (14 | ) |
| Basic earnings (loss) per common share: | | | | | | | |
| Income (loss) from continuing operations | .24 |
| | .22 |
| | .21 |
| | (.02 | ) |
| Diluted earnings (loss) per common share: | | | | | | | |
| Income (loss) from continuing operations | .23 |
| | .22 |
| | .20 |
| | (.02 | ) |
| | | | | | | | |
| 2012 | | | | | | | |
| Revenues | $ | 2,019 |
| | $ | 1,846 |
| | $ | 1,752 |
| | $ | 1,869 |
|
| Product costs | 957 |
| | 900 |
| | 771 |
| | 868 |
|
| Income (loss) from continuing operations | 359 |
| | 166 |
| | 200 |
| | 204 |
|
| Net income (loss) | 495 |
| | 165 |
| | 203 |
| | 202 |
|
| Amounts attributable to The Williams Companies, Inc.: | | | | | | | |
| Income (loss) from continuing operations | 287 |
| | 133 |
| | 152 |
| | 151 |
|
| Net income (loss) | 423 |
| | 132 |
| | 155 |
| | 149 |
|
| Basic earnings (loss) per common share: | | | | | | | |
| Income (loss) from continuing operations | .48 |
| | .21 |
| | .25 |
| | .23 |
|
| Diluted earnings (loss) per common share: | | | | | | | |
| Income (loss) from continuing operations | .47 |
| | .21 |
| | .25 |
| | .23 |
|
The sum of earnings per share for the four quarters may not equal the total earnings per share for the year due to changes in the average number of common shares outstanding and rounding.
2013
Net income for fourth-quarter 2013 includes the following pre-tax items:
| |
| • | $20 million write-off of an abandoned project at Williams NGL & Petchem Services (see Note 6 – Other Income and Expenses); |
| |
| • | $16 million accrued loss associated with a settlement in principle of a producer claim against us at Williams Partners (see Note 6 – Other Income and Expenses); |
| |
| • | $13 million interest income on the note receivable related to the sale of certain former Venezuela assets (see Note 5 – Investing Activities); |
| |
| • | $14 million in expenses associated with the Geismar Incident at Williams Partners (see Note 6 – Other Income and Expenses). |
Net income for fourth-quarter 2013 also includes $99 million of deferred income tax expense incurred on undistributed earnings of our foreign operations that are no longer considered permanently reinvested (see Note 7 – Provision (Benefit) for Income Taxes).
The Williams Companies Inc.
Quarterly Financial Data – (Continued)
(Unaudited)
Net income for third-quarter 2013 includes the following pre-tax items:
| |
| • | $9 million accrued loss associated with a contingent liability related to a producer claim against us at Williams Partners (see Note 6 – Other Income and Expenses); |
| |
| • | $50 million gain associated with insurance recoveries related to the Geismar Incident at Williams Partners (see Note 6 – Other Income and Expenses); |
| |
| • | $11 million of interest income associated with a receivable related to the sale of certain former Venezuela assets (see Note 5 – Investing Activities). |
Net income for second-quarter 2013 includes the following pre-tax items:
| |
| • | $12 million of income related to an insurance recovery associated with the Eminence abandonment regulatory asset that will not be recovered through rates at Williams Partners (see Note 6 – Other Income and Expenses); |
| |
| • | $26 million gain resulting from Access Midstream Partners' equity issuance (see Note 5 – Investing Activities); |
| |
| • | $13 million of interest income associated with a receivable related to the sale of certain former Venezuela assets (see Note 5 – Investing Activities); |
| |
| • | $12 million charge resulting from an unfavorable ruling associated with our former Alaska refinery related to the Trans-Alaska Pipeline System Quality Bank (see summarized results of discontinued operations at Note 4 – Discontinued Operations). |
Net income for first-quarter 2013 includes $13 million of interest income associated with a receivable related to the sale of certain former Venezuela assets (see Note 5 – Investing Activities).
2012
Net income for fourth-quarter 2012 includes the following pre-tax items:
| |
| • | $18 million related to the reversal of project feasibility costs from expense to capital at Williams Partners (see Note 6 – Other Income and Expenses); |
| |
| • | $12 million of reorganization-related costs including engaging a consulting firm in 2012 to assist in better aligning resources to support our business strategy following the spin-off of WPX (see Note 6 – Other Income and Expenses). |
Net income for second-quarter 2012 includes $21 million of Caiman and Laser acquisition and transition-related costs at Williams Partners (see Note 2 – Acquisitions, Goodwill, and Other Intangible Assets).
Net income for first-quarter 2012 includes the following pre-tax items:
| |
| • | $63 million of income, including $10 million of interest, related to the sale of our 50 percent interest in Accroven (see Note 5 – Investing Activities); |
| |
| • | $144 million of gain on reconsolidation related to our majority ownership in the Wilpro entities (see summarized results of discontinued operations at Note 4 – Discontinued Operations). |
The Williams Companies, Inc.
Schedule I — Condensed Financial Information of Registrant
Statement of Comprehensive Income (Parent)
|
| | | | | | | | | | | |
| | Years Ended December 31, |
| | 2013 | | 2012 | | 2011 |
| | (Millions, except per-share amounts) |
| Equity in earnings of consolidated subsidiaries | $ | 1,564 |
| | $ | 1,895 |
| | $ | 1,962 |
|
| Equity earnings from investment in Access Midstream Partners | 30 |
| | — |
| | — |
|
| Interest incurred — external | (156 | ) | | (128 | ) | | (186 | ) |
| Interest incurred — affiliate | (722 | ) | | (816 | ) | | (622 | ) |
| Interest income — affiliate | 71 |
| | 84 |
| | 84 |
|
| Early debt retirement costs | — |
| | — |
| | (271 | ) |
| Other income (expense) — net | 32 |
| | 3 |
| | (45 | ) |
| Income from continuing operations before income taxes | 819 |
| | 1,038 |
| | 922 |
|
| Provision for income taxes | 378 |
| | 315 |
| | 119 |
|
| Income (loss) from continuing operations | 441 |
| | 723 |
| | 803 |
|
| Income (loss) from discontinued operations | (11 | ) | | 136 |
| | (427 | ) |
| Net income (loss) | $ | 430 |
| | $ | 859 |
| | $ | 376 |
|
| Basic earnings (loss) per common share: | | | | | |
| Income (loss) from continuing operations | $ | .65 |
| | $ | 1.17 |
| | $ | 1.36 |
|
| Income (loss) from discontinued operations | (.02 | ) | | .22 |
| | (.72 | ) |
| Net income (loss) | $ | .63 |
| | $ | 1.39 |
| | $ | .64 |
|
| Weighted-average shares (thousands) | 682,948 |
| | 619,792 |
| | 588,553 |
|
| Diluted earnings (loss) per common share: | | | | | |
| Income (loss) from continuing operations | $ | .64 |
| | $ | 1.15 |
| | $ | 1.34 |
|
| Income (loss) from discontinued operations | (.02 | ) | | .22 |
| | (.71 | ) |
| Net income (loss) | $ | .62 |
| | $ | 1.37 |
| | $ | .63 |
|
| Weighted-average shares (thousands) | 687,185 |
| | 625,486 |
| | 598,175 |
|
| Other comprehensive income (loss): | | | | | |
| Equity in other comprehensive income (loss) of consolidated subsidiaries | $ | (41 | ) | | $ | 21 |
| | $ | 35 |
|
| Other comprehensive income (loss) attributable to The Williams Companies, Inc. | 239 |
| | 6 |
| | (123 | ) |
| Other comprehensive income (loss) | 198 |
| | 27 |
| | (88 | ) |
| Comprehensive income (loss) attributable to The Williams Companies, Inc. | $ | 628 |
| | $ | 886 |
| | $ | 288 |
|
See accompanying notes.
The Williams Companies, Inc.
Schedule I — Condensed Financial Information of Registrant – (Continued)
Balance Sheet (Parent)
|
| | | | | | | |
| | December 31, |
| | 2013 | | 2012 |
| | (Millions) |
| ASSETS | | | |
| Current assets: | | | |
| Cash and cash equivalents | $ | 282 |
| | $ | 340 |
|
| Other current assets and deferred charges | 167 |
| | 229 |
|
| Total current assets | 449 |
| | 569 |
|
| Investments in and advances to consolidated subsidiaries | 19,162 |
| | 16,686 |
|
| Investment in Access Midstream Partners | 2,161 |
| | 2,187 |
|
| Property, plant, and, equipment — net | 68 |
| | 62 |
|
| Other noncurrent assets | 34 |
| | 117 |
|
| Total assets | $ | 21,874 |
| | $ | 19,621 |
|
| LIABILITIES AND STOCKHOLDERS’ EQUITY | | | |
| Current liabilities: | | | |
| Accounts payable | $ | 26 |
| | $ | 29 |
|
| Long-term debt due within one year | 1 |
| | 1 |
|
| Other current liabilities | 147 |
| | 122 |
|
| Total current liabilities | 174 |
| | 152 |
|
| Long-term debt | 2,296 |
| | 2,298 |
|
| Notes payable — affiliates | 10,830 |
| | 8,938 |
|
| Pension, other postretirement, and other noncurrent liabilities | 282 |
| | 712 |
|
| Deferred income taxes | 3,428 |
| | 2,769 |
|
| Contingent liabilities and commitments |
| |
|
| Equity: | | | |
| Common stock | 718 |
| | 716 |
|
| Other stockholders’ equity | 4,146 |
| | 4,036 |
|
| Total stockholders’ equity | 4,864 |
| | 4,752 |
|
| Total liabilities and stockholders’ equity | $ | 21,874 |
| | $ | 19,621 |
|
See accompanying notes.
The Williams Companies, Inc.
Schedule I — Condensed Financial Information of Registrant – (Continued)
Statement of Cash Flows (Parent)
|
| | | | | | | | | | | |
| | Years Ended December 31, |
| | 2013 | | 2012 | | 2011 |
| | (Millions) |
| NET CASH FLOWS PROVIDED (USED) BY OPERATING ACTIVITIES | $ | 19 |
| | $ | (11 | ) | | $ | (286 | ) |
| | | | | | |
| FINANCING ACTIVITIES: | | | | | |
| Proceeds from long-term debt | — |
| | 848 |
| | 75 |
|
| Payments of long-term debt | (1 | ) | | (28 | ) | | (871 | ) |
| Changes in notes payable to affiliates | 1,892 |
| | 520 |
| | (590 | ) |
| Tax benefit of stock-based awards | 19 |
| | 44 |
| | 22 |
|
| Premiums paid on early debt retirement | — |
| | — |
| | (254 | ) |
| Proceeds from issuance of common stock | 18 |
| | 2,550 |
| | 49 |
|
| Dividends paid | (982 | ) | | (742 | ) | | (457 | ) |
| Other — net | (3 | ) | | (7 | ) | | (5 | ) |
| Net cash provided (used) by financing activities | 943 |
| | 3,185 |
| | (2,031 | ) |
| | | | | | |
| INVESTING ACTIVITIES: | | | | | |
| Capital expenditures | (23 | ) | | (18 | ) | | (28 | ) |
| Purchase of investment in Access Midstream Partners | (4 | ) | | (2,179 | ) | | — |
|
| Changes in investments in and advances to consolidated subsidiaries | (985 | ) | | (953 | ) | | 2,553 |
|
| Other — net | (8 | ) | | 24 |
| | (18 | ) |
| Net cash provided (used) by investing activities | (1,020 | ) | | (3,126 | ) | | 2,507 |
|
| Increase (decrease) in cash and cash equivalents | (58 | ) | | 48 |
| | 190 |
|
| Cash and cash equivalents at beginning of year | 340 |
| | 292 |
| | 102 |
|
| Cash and cash equivalents at end of year | $ | 282 |
| | $ | 340 |
| | $ | 292 |
|
See accompanying notes.
The Williams Companies, Inc.
Schedule I — Condensed Financial Information of Registrant – (Continued)
Notes to Financial Information (Parent)
Note 1. Guarantees
In addition to the guarantees disclosed in the accompanying consolidated financial statements in Item 8, we have financially guaranteed the performance of certain consolidated subsidiaries. The duration of these guarantees varies and we estimate the maximum undiscounted potential future payment obligation related to these guarantees as of December 31, 2013, is approximately $3.8 billion.
Note 2. Cash Dividends Received
We receive dividends and distributions either directly from our subsidiaries or indirectly through dividends received by subsidiaries and subsequent transfers of cash to us through our corporate cash management system. The total of such receipts ultimately related to dividends and distributions for the years ended December 31, 2013, 2012 and 2011 was approximately $1.5 billion, $1.1 billion, and $1.2 billion, respectively.
The Williams Companies, Inc.
Schedule II — Valuation and Qualifying Accounts
|
| | | | | | | | | | | | | | | | | | | |
| | | | Additions | | | | |
| | Beginning Balance | | Charged (Credited) To Costs and Expenses | | Other | | Deductions | | Ending Balance |
| | (Millions) |
| 2013 | | | | | | | | | |
| Allowance for doubtful accounts — accounts and notes receivable (1) | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Deferred tax asset valuation allowance (1) | 144 |
| | 37 |
| | — |
| | — |
| | 181 |
|
| 2012 | | | | | | | | | |
| Allowance for doubtful accounts — accounts and notes receivable (1) | 1 |
| | — |
| | — |
| | 1 |
| (3) | — |
|
| Deferred tax asset valuation allowance (1) | 145 |
| | (1 | ) | | — |
| | — |
| | 144 |
|
| 2011 | | | | | | | | | |
| Allowance for doubtful accounts — accounts and notes receivable (2) | 15 |
| | 1 |
| | — |
| | 15 |
| (4) | 1 |
|
| Deferred tax asset valuation allowance (5) | 249 |
| | (33 | ) | | — |
| | 71 |
| (4) | 145 |
|
_______________________
(1) Deducted from related assets.
(2) Deducted from related assets, primarily included in assets of discontinued operations.
(3) Represents balances written off, reclassifications, and recoveries.
(4) Includes balance deductions due to the spin-off of our exploration and production business on December 31,
2011.
(5) Deducted primarily from related assets, with a portion included in assets of discontinued operations.
