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:
Constitution: Constitution Pipeline Company, LLC
Gulfstar One: Gulfstar One LLC
Northwest Pipeline: Northwest Pipeline, LLC
Transco: Transcontinental Gas Pipe Line Company, LLC
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:
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:
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
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Other:
B/B Splitter: Butylene/Butane splitter
Caiman Acquisition: Our 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: Our 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
NYSE: New York Stock Exchange
Throughput: The volume of product transported or passing through a pipeline, plant, terminal, or other facility
Williams: The Williams Companies, Inc.
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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 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.
2013 | 2012 | 2011 | 2010 | 2009 | ||||||||||||||||
(Millions, except per-unit amounts) | ||||||||||||||||||||
Revenues | $ | 6,835 | $ | 7,471 | $ | 7,916 | $ | 6,625 | $ | 5,264 | ||||||||||
Net income | 1,119 | 1,291 | 1,604 | 1,234 | 1,060 | |||||||||||||||
Net income attributable to controlling interests | 1,116 | 1,291 | 1,604 | 1,218 | 1,033 | |||||||||||||||
Net income per common unit (1) | 1.45 | 1.89 | 3.69 | 2.66 | 2.88 | |||||||||||||||
Total assets at December 31 (1) | 23,571 | 20,678 | 15,486 | 14,295 | 13,281 | |||||||||||||||
Commercial paper and long-term debt due within one year at December 31 (3) | 225 | — | 324 | 458 | 15 | |||||||||||||||
Long-term debt at December 31 (1)(2) | 9,057 | 8,437 | 6,913 | 6,365 | 2,981 | |||||||||||||||
Total equity at December 31 (1) | 11,567 | 9,691 | 6,122 | 5,826 | 8,772 | |||||||||||||||
Cash distributions declared per unit | 3.480 | 3.140 | 2.900 | 2.653 | 2.540 | |||||||||||||||
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(1) | The change in 2012 reflects assets acquired, as well as debt and equity issuances related to the Caiman and Laser Acquisitions. |
(2) | The increase in 2010 reflects borrowings entered into related to an acquisition of certain businesses from Williams. |
(3) | The increase in 2013 reflects borrowings under our commercial paper program initiated in 2013. |
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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 through our gas pipeline and midstream businesses.
Our interstate natural gas pipeline strategy is to create value by maximizing the utilization of our pipeline capacity by providing high quality, low cost transportation of natural gas to large and growing markets. Our gas pipeline businesses’ interstate transmission and storage activities are subject to regulation by the FERC and as such, our rates and charges for the transportation of natural gas in interstate commerce, and the extension, expansion or abandonment of jurisdictional facilities and accounting, among other things, are subject to regulation. The rates are established through the FERC’s ratemaking process. Changes in commodity prices and volumes transported have limited near-term impact on revenues because the majority of cost of service is recovered through firm capacity reservation charges in transportation rates.
The ongoing strategy of our midstream operations is to safely and reliably operate large-scale midstream infrastructure where our assets can be fully utilized and drive low per-unit costs. We focus on consistently attracting new business by providing highly reliable service to our customers. These services include natural gas gathering, processing and treating, NGL fractionation and transportation, crude oil production handling and transportation, olefin production, marketing services for NGL, oil and natural gas, as well as storage facilities.
Our reportable segments are Northeast G&P, Atlantic-Gulf, West, and NGL & Petchem Services.
• | Northeast G&P is comprised of our midstream gathering and processing businesses in the Marcellus and Utica shale regions, as well as a 51 percent equity investment in Laurel Mountain and a 47.5 percent equity investment in Caiman II. |
• | Atlantic-Gulf is comprised of our interstate natural gas pipeline, Transco, and significant natural gas gathering and processing and crude oil production handling and transportation in the Gulf Coast region, as well as a 50 percent equity investment in Gulfstream, a 60 percent equity investment in Discovery, and a 41 percent interest in Constitution (a consolidated entity). |
• | West is comprised of our gathering, processing and treating operations in New Mexico, Colorado, and Wyoming and our interstate natural gas pipeline, Northwest Pipeline. |
• | NGL & Petchem Services is comprised of our 83.3 percent interest in an olefins production facility in Geismar, Louisiana, along with a refinery grade propylene splitter and various petrochemical and feedstock pipelines in the Gulf Coast region, an oil sands offgas processing plant near Fort McMurray, Alberta, and an NGL/olefin fractionation facility and B/B splitter facility at Redwater, Alberta. This segment also includes an NGL and natural gas marketing business, storage facilities and an undivided 50 percent interest in an NGL fractionator near Conway, Kansas, and a 50 percent equity investment in OPPL. |
As of December 31, 2013, Williams holds an approximate 64 percent interest in us, comprised of an approximate 62 percent limited partner interest and all of our 2 percent general partner interest and IDRs.
Unless indicated otherwise, the following discussion and analysis of critical accounting estimates, results of operations, and financial condition and liquidity should be read in conjunction with the consolidated financial statements and notes thereto included in Part II, Item 8 of this document.
Canada Acquisition
On February 28, 2014, we acquired certain of Williams’ Canadian operations for total consideration valued at approximately $1.2 billion. The operations included an oil sands offgas processing plant near Fort McMurray, Alberta, and an NGL/olefin fractionation facility and butylene/butane splitter facility at Redwater, Alberta. We funded the transaction with $25 million of cash (subject to certain closing adjustments), the issuance of 25,577,521 Class D limited-
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partner units, and an increase in the capital account of our general partner to allow it to maintain its 2 percent general partner interest. In lieu of cash distributions, the Class D units 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 Acquisition provides that we can issue additional Class D units to Williams on a quarterly basis through 2015 for up to a total of $200 million in cash for the purpose of funding certain facility expansions. This common control acquisition was treated similar to a pooling of interests whereby the historical results of operations were combined with ours for all periods presented.
Distributions
In January 2014, our general partner’s Board of Directors approved a quarterly distribution to unitholders of $0.8925 per unit, an increase of approximately 2 percent over the prior quarter and 8 percent over the same period in the prior year. We expect to increase limited partner per-unit cash distributions by approximately 6 percent in 2014 and 2015.
Overview
Our results for the year ended December 31, 2013, were unfavorable compared to the prior year primarily due to lower NGL margins driven by reduced ethane recoveries and decreases in average NGL per-unit sales prices, as well as lower olefin margins associated with lost production resulting from the Geismar Incident. These unfavorable impacts were partially offset by growth in fee revenues, primarily from Northeast G&P. 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.
Geismar Incident
On June 13, 2013, an explosion and fire occurred at our 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. This facility is part of our NGL & Petchem Services segment.
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 60-day waiting period 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 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 Comprehensive 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 $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.
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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 losses 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.
Northeast G&P
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.
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.
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-Gulf
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.
Gulfstar One
Effective April 1, 2013, we sold a 49 percent interest in 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
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facility for other deepwater prospects in the area. The project is expected to be in service in the third quarter of 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 Gunflint project has a first oil target of mid-2016, dependent on the producer’s development activities.
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.
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.
NGL & Petchem Services
Overland Pass Pipeline
Through our equity investment in OPPL, we completed the construction of a pipeline connection and capacity expansions 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.
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.
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Volume impacts in 2013
Due to unfavorable ethane economics, we reduced our recoveries of ethane in our domestic 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.
 |
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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 unitholders.
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 growth in distributions. Our planned capital investments for 2014 total approximately $3.6 billion. We also expect approximately 6 percent growth in 2014 per-unit distributions. 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:
• | General economic, financial markets, or industry downturn; |
• | Unexpected significant increases in capital expenditures or delays in capital project execution; |
• | Lower than anticipated or delay in receiving insurance recoveries associated with the Geismar Incident; |
• | Limited availability of capital due to a change in our financial condition, interest rates, market or industry conditions; |
• | Lower than expected levels of cash flow from operations; |
• | Counterparty credit and performance risk; |
• | Decreased volumes from third parties served by our midstream business; |
• | Lower than anticipated energy commodity prices and margins; |
• | Changes in the political and regulatory environments; |
• | Physical damages to facilities, including damage to offshore facilities by named windstorms; |
• | Reduced availability of insurance coverage. |
We continue to address these risks through maintaining a strong financial position and ample liquidity, as well as through managing a diversified portfolio of energy infrastructure assets.
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.
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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 slightly higher overall commodity prices as compared to 2013:
• | 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. |
• | Ethane prices are expected to be somewhat higher due to a modest increase in demand as well as slightly higher natural gas prices. |
• | Propane prices are expected to be higher from an increase in exports and higher natural gas prices. |
• | Propylene prices are expected to be comparable to 2013 prices. |
• | 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.
• | In our Northeast G&P segment, 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. |
• | In our Atlantic-Gulf segment, we anticipate higher natural gas transportation volumes compared to 2013, as a result of expansion projects placed into service at Transco in 2013 and anticipated to be placed in service in 2014. We also expect higher production handling volumes compared to 2013, following the scheduled completion of Gulfstar FPS™ in third quarter 2014. |
• | Our West segment expects an unfavorable impact in equity NGL volumes in 2014 compared to 2013, primarily due to a customer contract that expired in September 2013. |
• | In 2014, we anticipate a continuation of periods when it will not be economical to recover ethane in our domestic businesses. |
• | Our NGL & Petchem Services segment anticipates 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
• | Our NGL & Petchem Services segment 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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• | Our NGL & Petchem Services segment 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
• | In our NGL & Petchem Services segment, we expect to receive insurance recoveries under our business interruption policy related to the Geismar Incident that will favorably impact our operating results in 2014. |
• | We anticipate higher operating expenses in 2014 compared to 2013, including depreciation expense related to our growing operations in our Northeast G&P segment and expansion projects in our Atlantic-Gulf and NGL & Petchem Services segments. |
• | In our Atlantic-Gulf segment, we expect 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.
Expansion Projects
We expect to invest total capital in 2014 among our business segments as follows:
Expansion Capital | |||
Segment: | (Millions) | ||
Northeast G&P | $ | 1,400 | |
Atlantic-Gulf | 1,300 | ||
West | 75 | ||
NGL & Petchem Services | 500 | ||
Our ongoing major expansion projects include the following:
Northeast G&P
• | 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. |
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• | 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. |
Atlantic-Gulf
• | 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 of 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. |
• | 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. |
• | 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. |
• | 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. |
• | 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. |
• | 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 |
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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.
• | In April 2013, we filed an application with the FERC for Transco’s Northeast Connector project to expand our 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. |
• | In January 2013, we filed an application with the FERC for Transco’s Rockaway Delivery Lateral project 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. |
• | In December 2012, we filed an application with the FERC for Transco’s Virginia Southside project to expand our 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. |
West
• | 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. |
NGL & Petchem Services
• | 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. |
• | In association with Williams’ long-term agreement to provide gas processing to a second bitumen upgrader in Canada’s oil sands near Fort McMurray, Alberta, we have a long-term agreement with Williams to provide fractionation service and 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. We will receive a fee based payment from Williams for the fractionation service we provide. |
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 general partner’s 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.
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 our Northeast G&P segment (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 was recognized in 2013. The fair value of the reporting
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unit 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 $2.2 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:
• | Lower than expected cash distributions from investees; |
• | 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.
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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 | $ | 2,914 | +200 | +7% | $ | 2,714 | +196 | +8% | $ | 2,518 | |||||||||||
Product sales | 3,921 | -836 | -18% | 4,757 | -641 | -12% | 5,398 | ||||||||||||||
Total revenues | 6,835 | 7,471 | 7,916 | ||||||||||||||||||
Costs and expenses: | |||||||||||||||||||||
Product costs | 3,027 | +474 | +14% | 3,501 | +433 | +11% | 3,934 | ||||||||||||||
Operating and maintenance expenses | 1,080 | -61 | -6% | 1,019 | -37 | -4% | 982 | ||||||||||||||
Depreciation and amortization expenses | 791 | -57 | -8% | 734 | -97 | -15% | 637 | ||||||||||||||
Selling, general, and administrative expenses | 519 | +64 | +11% | 583 | -152 | -35% | 431 | ||||||||||||||
Other (income) expense – net | 11 | +13 | +54% | 24 | -6 | -33% | 18 | ||||||||||||||
Total costs and expenses | 5,428 | 5,861 | 6,002 | ||||||||||||||||||
Operating income | 1,407 | 1,610 | 1,914 | ||||||||||||||||||
Equity earnings (losses) | 104 | -7 | -6% | 111 | -31 | -22% | 142 | ||||||||||||||
Interest expense | (387 | ) | +17 | +4% | (404 | ) | +11 | +3% | (415 | ) | |||||||||||
Other income (expense) – net | 25 | +9 | +56% | 16 | +7 | +78% | 9 | ||||||||||||||
Income before income taxes | 1,149 | 1,333 | 1,650 | ||||||||||||||||||
Provision (benefit) for income taxes | 30 | +12 | +29% | 42 | +4 | +9% | 46 | ||||||||||||||
Net income | 1,119 | 1,291 | 1,604 | ||||||||||||||||||
Less: Net income attributable to noncontrolling interests | 3 | -3 | NM | — | — | — | — | ||||||||||||||
Net income attributable to controlling interests | $ | 1,116 | $ | 1,291 | $ | 1,604 | |||||||||||||||
* | + = 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 realized NGL per-unit sales prices, as well as a decrease in 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.
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The decrease in Product costs is primarily due to a decrease in 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, scheduled maintenance expenses incurred 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 associated with the businesses acquired in 2012 and depreciation on subsequent infrastructure additions, increased depreciation of certain assets that were decommissioned in the third quarter of 2013 in preparation of the completion of the ethane recovery system, as well as higher depreciation related to the Boreal Pipeline, which was placed into service in 2012. These increases are 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.
The decrease in Selling, general, and administrative expenses (SG&A) is primarily due to a reduction in allocated administrative expenses from Williams reflecting the absence of reorganization related costs incurred in 2012 (see Note 5 – Related Party Transactions of Notes to Consolidated Financial Statements) and the absence of acquisition and transition costs incurred in 2012 (see Note 2 – Acquisitions, Goodwill, and Other Intangible Assets of Notes to Consolidated Financial Statements).
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; |
• | $5 million favorable change in net foreign currency exchange gains. |
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; |
• | $12 million expense recognized in 2013 related to the portion of the Eminence abandonment regulatory asset that will not be recovered in rates. |
The decrease in Operating income generally reflects lower NGL production margins, lower olefin production margins, and higher operating costs, partially offset by increased fee revenues, higher marketing margins, lower SG&A expenses, and the net favorable changes in Other (income) expense – net as described above.
The unfavorable change in Equity earnings (losses) is primarily due to lower equity earnings from Discovery. This increase is partially offset by improved equity earnings from Laurel Mountain.
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Interest expense decreased due to a $36 million increase in Interest capitalized related to construction projects, partially offset by a $19 million increase in Interest incurred primarily due to an increase in borrowings. (See Note 12 – Debt, Banking Arrangements, and Leases of Notes to Consolidated Financial Statements).
Provision (benefit) for income taxes changed favorably primarily due to lower foreign pretax income associated with our Canadian operations, partially offset by Texas franchise tax incurred related to the impact of a second-quarter 2013 tax law change.
2012 vs. 2011
The increase in Service revenues is primarily due to increased gathering and processing fee revenues from higher volumes in the Marcellus Shale, including new volumes from the 2012 Caiman and Laser Acquisitions and higher volumes in the western deepwater Gulf of Mexico and in the Piceance basin. Additionally, natural gas pipeline 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. Marketing revenues also decreased primarily due to significant decreases in NGL and olefin prices, partially offset by higher NGL and crude oil 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 due to a decrease in average natural gas prices. Marketing purchases also decreased primarily resulting from significantly lower average NGL prices, partially offset by higher NGL and crude oil volumes, as well as new volumes from natural gas marketing activities.
The increase in Operating and maintenance expenses is primarily due to increased employee-related benefit costs and increased pipeline maintenance as well as increased maintenance expenses primarily associated with our gathering and processing assets acquired in 2012, 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 our gathering and processing assets acquired in 2012 (see Note 2 – Acquisitions, Goodwill, and Other Intangible Assets of Notes to Consolidated Financial Statements).
The increase in SG&A includes $68 million of higher allocated administrative costs from Williams reflecting our higher proportionate share of these costs and $26 million of reorganization-related costs in 2012 primarily relating to Williams’ engagement of a consulting firm to assist in better aligning resources to support our business strategy following Williams’ spin-off of WPX, which was completed December 31, 2011. SG&A in 2012 also includes $23 million of acquisition and transition-related costs as well as higher employee-related and information technology expenses driven by general growth within our midstream operations.
The decrease in Operating income generally reflects lower NGL production and marketing margins, as well as previously described increases in Operating and maintenance expenses, Depreciation and amortization expenses, and SG&A. Higher fee revenues and olefin production margins partially offset these decreases.
Equity earnings (losses) changed unfavorably primarily reflecting lower operating results at Laurel Mountain, Aux Sable, and Discovery and the impairment of two minor NGL processing plants at Laurel Mountain, partially offset by an increase in equity earnings resulting from the acquisition of an additional 24.5 percent interest in Gulfstream in May 2011.
Interest expense decreased due to a $30 million increase in Interest capitalized related primarily to gathering and processing construction projects, partially offset by a $19 million increase in Interest incurred related to increased borrowings.
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Year-Over-Year Operating Results – Segments
Northeast G&P
Years Ended December 31, | |||||||||||
2013 | 2012 | 2011 | |||||||||
(Millions) | |||||||||||
Service revenues | $ | 335 | $ | 168 | $ | 49 | |||||
Product sales | 166 | 2 | — | ||||||||
Segment revenues | 501 | 170 | 49 | ||||||||
Product costs | 160 | 4 | — | ||||||||
Depreciation and amortization expenses | 132 | 76 | 5 | ||||||||
Other segment costs and expenses | 226 | 104 | 20 | ||||||||
Equity (earnings) losses | 7 | 23 | 1 | ||||||||
Segment profit (loss) | $ | (24 | ) | $ | (37 | ) | $ | 23 | |||
Our Northeast G&P segment includes our Susquehanna Supply Hub (primarily resulting from the acquisition of certain assets in 2010 and the Laser Acquisition in February 2012), our Ohio Valley Midstream business (primarily resulting from the Caiman Acquisition in April 2012), and our equity-method investments in Laurel Mountain and Caiman Energy II.
2013 vs. 2012
Service revenues increased due primarily to $129 million in higher gathering fees associated with 78 percent higher volumes driven by new well connections related to infrastructure additions placed into service in 2012 and 2013, a full year of operations associated with the gathering systems included in the 2012 acquisitions, and increased gathering rates associated with customer contract modifications primarily in the Susquehanna Supply Hub. Service revenues also reflect contributions from the processing and fractionation facilities placed in service in the latter half of 2012 and in 2013 in our Ohio Valley Midstream business.
Product sales in 2013 primarily represent new NGL marketing revenues attributable to the Ohio Valley Midstream business. The changes in marketing revenues are offset by similar changes in marketing purchases, reflected above as product costs.
Depreciation and amortization expenses reflect a full year of expenses in 2013 associated with the acquired businesses and depreciation on subsequent infrastructure additions.
Other segment costs and expenses increased primarily due to higher expenses associated with the acquired businesses and the subsequent growth in these operations. This increase includes approximately $26 million in higher employee-related costs and $19 million in higher outside service operating expenses including $15 million related to pipeline maintenance and repair costs. In addition, 2013 reflects a $25 million accrued loss for a settlement in principle of a producer claim against us and higher allocated support costs due to the relative growth in the businesses. These increases are partially offset by the absence of $23 million related to acquisition and transition costs incurred in 2012.
Equity (earnings) losses changed favorably primarily due to $15 million improved Laurel Mountain equity earnings driven primarily by 55 percent higher gathering volumes, the receipt of an annual minimum volume commitment fee in 2013, and lower leased compression expenses.
The favorable change in Segment profit (loss) is primarily due to an increase in fee revenues in the Susquehanna Supply Hub and Ohio Valley Midstream businesses, improved Laurel Mountain equity earnings and the absence of acquisition and transition costs incurred in 2012. These increases are partially offset by higher costs primarily in our Ohio Valley Midstream business and a $25 million charge associated with the settlement in principle of a producer claim against us.
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2012 vs. 2011
Service revenues increased due to a $118 million increase in fee revenues primarily due to higher volumes in the Marcellus Shale, including new volumes on gathering and processing assets acquired in 2012 in our Ohio Valley Midstream and Susquehanna Supply Hub businesses.
Depreciation and amortization expenses increased due to the assets and intangibles acquired in 2012.
Other segment costs and expenses increased primarily due to a $42 million increase in other operating costs and expenses also generally associated with assets acquired in 2012 and a $40 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.
Equity (earnings) losses changed unfavorably 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 gathering volumes.
The unfavorable change in Segment profit (loss) is primarily due to the previously described increases in depreciation and amortization expenses, other operating costs and general and administrative expenses, and lower Laurel Mountain equity earnings. These changes were partially offset by higher fee revenues.
Atlantic-Gulf
Years Ended December 31, | |||||||||||
2013 | 2012 | 2011 | |||||||||
(Millions) | |||||||||||
Service revenues | $ | 1,424 | $ | 1,383 | $ | 1,332 | |||||
Product sales | 925 | 1,072 | 1,137 | ||||||||
Segment revenues | 2,349 | 2,455 | 2,469 | ||||||||
Product costs | 843 | 956 | 1,005 | ||||||||
Depreciation and amortization expenses | 363 | 381 | 365 | ||||||||
Other segment costs and expenses | 601 | 636 | 604 | ||||||||
Equity (earnings) losses | (72 | ) | (92 | ) | (90 | ) | |||||
Segment profit | $ | 614 | $ | 574 | $ | 585 | |||||
NGL margin | $ | 79 | $ | 113 | $ | 126 | |||||
2013 vs. 2012
Service revenues increased primarily due to a $72 million increase in natural gas transportation fee revenues primarily associated with expansion projects placed in service in 2012 and 2013 and to the implementation of new rates for Transco in March 2013. These increases are partially offset by $34 million lower fee revenues in the eastern Gulf Coast primarily driven by natural declines in Bass Lite and Blind Faith production area volumes.
Product sales decreased primarily due to:
• | A $158 million decrease in marketing revenues reflecting a $120 million decrease in crude oil marketing sales and a $38 million decrease in NGL marketing sales. Crude oil marketing sales decreased primarily due to 25 percent lower crude oil volumes related to natural declines in production areas served by our Mountaineer crude oil pipeline. NGL marketing sales decreased primarily due to lower NGL prices. These changes in marketing revenues are offset by similar changes in marketing purchases. |
• | A $39 million decrease in revenues from our equity NGLs reflecting a decrease of $21 million associated with lower equity NGL sales volumes and a decrease of $18 million associated with lower average realized NGL per-unit sales prices. Equity NGL sales volumes are 29 percent lower driven by 56 percent lower ethane |
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volumes due primarily to unfavorable ethane economics, as previously mentioned, and 7 percent lower non-ethane volumes. Average realized ethane and non-ethane per-unit sales prices decreased by 54 percent and 11 percent, respectively.
• | A $48 million increase in other product sales primarily due to higher system management gas sales from Transco. System management gas sales are offset in Product costs and, therefore, have no impact on Segment profit. |
Product costs decreased primarily due to:
• | A $158 million decrease in crude oil and NGL marketing purchases (offset in Product sales). |
• | A $5 million decrease in costs associated with our equity NGLs primarily due to an $11 million decrease associated with lower natural gas volumes, partially offset by a $6 million increase related to higher per-unit natural gas prices. |
• | A $48 million increase in other product costs primarily due to higher system management gas costs (offset in Product sales). |
Depreciation and amortization expenses decreased primarily reflecting the absence of increased depreciation in 2012 on certain assets in the Gulf Coast region resulting from a change in the estimated useful lives.
Other segment costs and expenses decreased primarily due to lower operating costs, including compressor and pipeline maintenance and repair expenses resulting from the absence of expenses relating to the substantial completion of a natural gas pipeline integrity management plan during 2012, lower project development costs, and insurance recoveries recognized by Transco in 2013 related to the abandonment of certain of its Eminence storage assets. These decreases are partially offset by increased amortization of regulatory assets associated with asset retirement obligations, a decrease in reversals of project feasibility costs from expense to capital associated with expansion projects, and expense recognized in 2013 related to the portion of the Eminence abandonment regulatory asset that is not expected to be recovered in rates.
Equity earnings decreased primarily due to 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. Additionally, charges to write-down two lateral pipelines and electrical equipment in 2013 and the absence of a favorable customer settlement in 2012 decreased our equity earnings from Discovery.
Segment profit increased primarily due to higher service revenues and lower operating and depreciation expenses, partially offset by $34 million lower NGL margins reflecting commodity price changes including lower NGL sales prices coupled with higher per-unit natural gas costs and lower volumes, increased amortization of regulatory assets associated with asset retirement obligations, and lower equity earnings, as previously discussed.
2012 vs. 2011
Service revenues increased due to a $51 million increase in fee revenues primarily due to an increase in transportation revenues associated with expansion projects placed in service during 2011 and 2012 on our interstate natural gas pipeline and higher gas gathering and oil transportation volumes in the western deepwater Gulf of Mexico, including higher volumes on our Perdido Norte natural gas and oil pipelines, partially offset by lower volumes in the eastern deepwater Gulf of Mexico primarily due to natural field declines.
Product sales decreased primarily due to:
• | A $49 million decrease in other product sales due primarily to a $39 million decrease in system management gas sales (offset in Product costs). |
• | A $25 million decrease in revenues from our equity NGLs primarily reflecting a decrease of $37 million associated with an overall 19 percent decrease in average NGL per-unit sales prices. Average ethane and non-ethane per-unit prices decreased by 48 percent and 12 percent, respectively. |
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• | An $8 million increase in marketing revenues reflecting an increase of $73 million driven by higher crude oil volumes and an $86 million increase driven by higher non-ethane volumes, partially offset by a $148 million decrease driven by lower ethane and non-ethane prices. The changes in marketing revenues are offset by similar changes in marketing purchases. |
Product costs decreased primarily due to:
• | A $44 million decrease in other product costs due primarily to a $39 million decrease in system management gas costs (offset in Product sales). |
• | A $12 million decrease in costs associated with our equity NGLs primarily due to a 34 percent decrease in average natural gas prices. |
Depreciation and amortization expenses increased $16 million primarily resulting from accelerated depreciation of our Canyon Station production handling platform in the eastern deepwater Gulf of Mexico and additional Transco assets placed in service in 2011.
Other segment costs and expenses increased primarily due to a $20 million increase in operating costs and expenses including higher employee-related benefits costs, pipeline maintenance costs, and project feasibility costs, partially offset by lower operations and maintenance expense associated with the Eminence Storage Field leak and an increase in reversals of project feasibility costs from expense to capital associated with expansion projects. Additionally, general and administrative expenses increased $12 million primarily due to higher employee-related, information technology services and rental costs.
Equity earnings increased primarily due to an $11 million increase related to the acquisition of an additional interest in Gulfstream in May 2011, partially offset by $12 million lower Discovery equity earnings primarily due to lower NGL margins and volumes.
Segment profit decreased primarily due to a $48 million increase in depreciation, operating costs and expenses and general and administrative expenses, as previously discussed, and a $13 million decrease in NGL margins driven primarily by commodity price changes including lower NGL prices, partially offset by lower natural gas prices. These decreases were partially offset by a $51 million increase in fee revenues, as previously discussed.
West
Years Ended December 31, | |||||||||||
2013 | 2012 | 2011 | |||||||||
(Millions) | |||||||||||
Service revenues | $ | 1,054 | $ | 1,072 | $ | 1,057 | |||||
Product sales | 772 | 1,129 | 1,633 | ||||||||
Segment revenues | 1,826 | 2,201 | 2,690 | ||||||||
Product costs | 380 | 472 | 760 | ||||||||
Depreciation and amortization expenses | 236 | 234 | 236 | ||||||||
Other segment costs and expenses | 469 | 515 | 513 | ||||||||
Segment profit | $ | 741 | $ | 980 | $ | 1,181 | |||||
NGL margin | $ | 369 | $ | 637 | $ | 854 | |||||
2013 vs. 2012
Service revenues decreased primarily due to a $43 million decrease in gathering and processing fee revenues primarily due to a natural decline in production volumes, primarily in the Piceance basin and Four Corners area, and
21
severe winter weather conditions in the first quarter of 2013 which prevented producers from delivering gas. Transportation revenues increased $30 million, primarily related to new rates effective January 1, 2013 at Northwest Pipeline.
Product sales decreased primarily due to:
• | A $314 million decrease in revenues from our equity NGLs primarily reflecting a decrease of $242 million due to lower volumes and a $72 million decrease associated with 10 percent lower average realized non-ethane per-unit sales prices and 42 percent lower average ethane per-unit sales prices. Equity ethane sales volumes are 84 percent lower driven by reduced ethane recoveries and equity non-ethane volumes are 11 percent lower due primarily 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 local severe winter weather conditions in the first quarter of 2013 which prevented producers from delivering gas. |
• | A $46 million decrease in NGL marketing revenues due primarily to 68 percent lower ethane volumes (more than offset in Product costs). |
Product costs decreased primarily due to:
• | A $47 million decrease in NGL marketing purchases (substantially offset in Product sales). |
• | A $44 million decrease in costs associated with our equity NGLs reflecting an $82 million decrease associated with lower natural gas volumes, partially offset by a $38 million increase related to a 32 percent increase in average natural gas prices. |
Other segment costs and expenses decreased primarily due to lower allocated support costs due to relative growth in the other segments, as well as increased operating efficiencies and lower volumes in our Four Corners area which resulted in reduced operating costs, including operating lease payments and materials and supplies.
Segment profit decreased primarily due to $268 million lower NGL margins reflecting lower NGL volumes, lower average NGL prices, and higher average natural gas prices, as well as the decrease in gathering and processing fee revenues, partially offset by lower operating costs in our Four Corners area, lower allocated support expenses, and increased natural gas transportation revenues.
2012 vs. 2011
Service revenues increased primarily due to a $14 million increase in fee revenues resulting from higher gas gathering and processing volumes in the Piceance basin.
Product sales decreased primarily due to:
• | A $343 million decrease in revenues from our equity NGLs primarily reflecting a decrease of $314 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 15 percent, respectively. |
• | A $159 million decrease in marketing revenues primarily due to significantly lower average NGL prices and 11 percent lower NGL volumes. The changes in marketing revenues are offset by similar changes in marketing purchases. |
Product costs decreased primarily due to:
• | A $159 million decrease in marketing purchases primarily due to significantly lower average NGL prices and lower NGL volumes. These changes are offset by similar changes in marketing revenues. |
• | A $126 million decrease in costs associated with our equity NGLs primarily due to a 31 percent decrease in average natural gas prices. |
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Other segment costs and expenses increased primarily due to a $20 million increase in general and administrative expenses including increases in employee-related, information technology services and rental costs, significantly offset by a $19 million decrease in other operating costs and expenses due primarily to lower costs in our Four Corners area related to the consolidation of certain operations.
Segment profit decreased primarily due to a $217 million decrease in NGL margins driven primarily by commodity price changes including lower NGL prices, partially offset by lower natural gas prices. This decrease was partially offset by a $14 million increase in fee revenues, as previously discussed.
NGL & Petchem Services
Years Ended December 31, | |||||||||||
2013 | 2012 | 2011 | |||||||||
(Millions) | |||||||||||
Service revenues | $ | 112 | $ | 108 | $ | 84 | |||||
Product sales | 3,155 | 4,264 | 4,837 | ||||||||
Segment revenues | 3,267 | 4,372 | 4,921 | ||||||||
Product costs | 2,753 | 3,797 | 4,382 | ||||||||
Depreciation and amortization expenses | 60 | 43 | 31 | ||||||||
Other segment (income) costs and expenses | 147 | 184 | 176 | ||||||||
Equity (earnings) losses | (39 | ) | (42 | ) | (53 | ) | |||||
Segment profit | $ | 346 | $ | 390 | $ | 385 | |||||
Olefins margin | $ | 302 | $ | 392 | $ | 299 | |||||
Marketing margin | 21 | (11 | ) | 34 | |||||||
NGL margin | 64 | 74 | 107 | ||||||||
2013 vs. 2012
Product sales decreased primarily due to:
• | A $794 million decrease in marketing revenues due primarily to lower NGL volumes and prices, partially offset by higher natural gas volumes and prices. These changes are more than offset in Product costs. |
• | A $314 million decrease in olefin sales due to $368 million of lower volumes, partially offset by $54 million associated with higher per-unit sales prices. Olefin production volumes are lower at our facilities in the Gulf Coast area 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 olefin 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. |
Product costs decreased primarily due to:
• | An $826 million decrease in NGL marketing purchases partially offset by increased natural gas marketing purchases (substantially offset in Product sales). |
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• | A $224 million decrease in olefin feedstock purchases due to $202 million of lower volumes, as discussed above, the third-party storage facility outage discussed above, and $22 million lower feedstock and fuel costs reflecting 21 percent lower average per-unit ethylene feedstock prices, partially offset by 9 percent higher average per-unit propylene feedstock prices. |
• | A $9 million increase in costs associated with our equity NGLs primarily due to an 18 percent increase in average natural gas prices. |
Depreciation and amortization expenses increased $17 million primarily due to 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.
Other segment (income) costs and expenses improved primarily due to the recognition of $40 million of income associated with 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, a $5 million favorable impact of net foreign currency exchange gains, and the absence of $5 million of furnace repair expenses incurred during 2012. Partially offsetting this favorable impact are $30 million higher Operating and maintenance expenses including $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.
Segment profit decreased primarily due to lower olefin product margins, higher maintenance costs, $13 million of costs incurred under our insurance deductibles, lower NGL margins and higher depreciation expenses, as previously discussed. Partially offsetting these decreases is the $40 million net insurance recovery discussed above, higher marketing margins, $9 million involuntary conversion gains related to a 2012 furnace fire at our Geismar olefins plant, a $5 million favorable impact of net foreign currency exchange gains, and the absence of $5 million of furnace repair expenses incurred during 2012. Olefin margins decreased $91 million at our Geismar plant, including $156 million lower product volumes, partially offset by $41 million higher ethylene prices and $21 million lower ethylene feedstock costs. Marketing margins are $32 million higher primarily due to favorable prices in 2013 and the absence of losses recognized in the second quarter of 2012 which were driven by significant declines in NGL prices while product was in transit. NGL margins are $10 million lower due primarily to a higher average natural gas prices and lower non-ethane prices in Canada.
2012 vs. 2011
Service revenues increased $24 million primarily due to increases at our Gulf Olefin pipeline systems and Conway storage and fractionation facilities.
Product sales decreased primarily due to:
• | A $432 million decrease in marketing revenues primarily due to a significant decrease in NGL and olefin prices, partially offset by higher NGL volumes, as well as new volumes from natural gas marketing activities. |
• | A $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. |
• | A $45 million decrease in NGL sales revenues due primarily to 31 percent lower average per-unit sales prices. |
Product costs decreased primarily due to:
• | A $386 million decrease in marketing costs primarily due to significantly lower average NGL prices, partially offset by higher NGL 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. |
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• | 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 due primarily to lower per-unit feedstock costs, partially offset by higher feedstock volumes. |
• | A $13 million decrease in costs associated with our equity NGLs primarily due to a 27 percent decrease in average natural gas prices in Canada. |
Depreciation and amortization expenses increased $12 million primarily due to accelerated depreciation on assets that will become obsolete with the Geismar expansion project.
Equity earnings decreased primarily due to lower equity earnings from Aux Sable driven by lower gas processing margins.
Segment profit increased primarily due to $93 million higher olefin margins and $24 million in higher service revenues as previously discussed. The increase in olefin margins is primarily ethylene at our Geismar facility driven by significantly lower feedstock costs, partially offset by lower prices for most products. These increases are partially offset by $39 million lower NGL and olefin margins from our Canadian facility due primarily to significantly lower propane prices, partially offset by lower natural gas prices. Marketing margins were $45 million lower due primarily to significant declines in product prices while product was in transit, primarily in the second quarter of 2012, compared to gains driven by increases in product prices while product was in transit during 2011. Also offsetting the increases to segment profit is an $11 million decrease in equity earnings and a $12 million increase in depreciation expense, as previously discussed.
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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-unit distributions. Examples of this growth included:
• | Expansion of our interstate natural gas pipeline system to meet the demand of growth markets; |
• | Continued investment in our gathering and processing capacity and infrastructure in the Marcellus Shale area and the deepwater Gulf of Mexico, as well as expanding our olefins business in the Gulf Coast region; |
• | Total per-unit distributions grew almost 9 percent to $3.415 in 2013 compared to $3.14 in 2012. |
This growth was funded primarily through cash flow from operations and debt and equity offerings.
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, unitholder distributions, and debt service payments while maintaining a sufficient level of liquidity. In particular, we note the following:
• | We increased our per-unit quarterly distribution with respect to the fourth quarter of 2013 from $0.8775 to $0.8925. We expect to increase quarterly limited partner per-unit cash distributions by approximately 6 percent in 2014 and 2015. |
• | We expect to fund working capital requirements, capital and investment expenditures, debt service payments, and distributions to unitholders primarily through cash flow from operations, cash and cash equivalents on hand, issuances of debt and/or equity securities, and utilization of our 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 $2.95 billion and $3.3 billion in 2014. 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. |
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 liquidity include:
• | Cash and cash equivalents on hand; |
• | Cash generated from operations, including cash distributions from our equity-method investees and expected business interruption proceeds related to the Geismar Incident; |
• | Cash proceeds from issuances of debt and/or equity securities; |
• | Use of our credit facility and/or commercial paper program. |
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We anticipate our more significant uses of cash to be:
• | Maintenance and expansion capital expenditures; |
• | Contributions to our equity-method investees to fund their expansion capital expenditures; |
• | Interest on our long-term debt; |
• | Quarterly distributions to our unitholders and general partner. |
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 $804 million. However, we note the following about our available liquidity.
Available Liquidity | December 31, 2013 | ||
(Millions) | |||
Cash and cash equivalents | $ | 110 | |
Capacity available under our $2.5 billion five-year credit facility (expires July 31, 2018), less amounts outstanding under the $2 billion commercial paper program (1) | 2,275 | ||
$ | 2,385 | ||
__________
(1) | The highest amount outstanding during 2013 was $1.085 billion under our commercial paper program. As of February 25, 2014, $900 million is outstanding under our commercial paper program. At December 31, 2013, we are in compliance with the financial covenants associated with this credit facility and commercial paper program. (See Note 12 – Debt, Banking Arrangements, and Leases of Notes to Consolidated Financial Statements.) On July 31, 2013, we amended our $2.4 billion credit facility to increase the aggregate commitments to $2.5 billion and extend the maturity date to July 31, 2018. The full amount of the credit facility is available to us, to the extent not otherwise utilized by Transco and Northwest Pipeline, and may, under certain conditions, be increased by up to an additional $500 million. Transco and Northwest Pipeline are each able to borrow up to $500 million under the credit facility to the extent not otherwise utilized by the other co-borrowers. In managing our available liquidity, we do not expect a maximum outstanding amount under this commercial paper program in excess of the capacity available under our credit facility. |
Commercial Paper
In March 2013, we 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 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, we had $225 million in commercial paper outstanding.
Debt Offering
In November 2013, we 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. We used the net proceeds to repay amounts outstanding under our 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
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businesses. Our more significant equity-method investees include: Aux Sable, Caiman II, Discovery, Gulfstream, Laurel Mountain, and OPPL.
Shelf Registration
In April 2013, we filed a shelf registration statement for the offer and sale from time to time of common units representing limited partner interests in us having an aggregate offering price of up to $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 us 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, we completed an equity issuance of 21,500,000 common units. Subsequently, the underwriters exercised their option to purchase 3,225,000 common units. The net proceeds of approximately $1.2 billion were used to repay amounts outstanding under our commercial paper program, to fund capital expenditures, and for general partnership purposes.
In March 2013, we completed an equity issuance of 14,250,000 common units, including 3,000,000 common units sold to Williams in a private placement. Subsequently, the underwriters exercised their option to purchase 1,687,500 common units. The net proceeds of approximately $760 million were used to repay amounts outstanding under our credit facility.
Credit Ratings
Our ability to borrow money is impacted by our credit ratings. The current ratings are as follows:
Rating Agency | Outlook | Senior Unsecured Debt Rating | ||
Standard & Poor’s | Stable | BBB | ||
Moody’s Investors Service | Stable | Baa2 | ||
Fitch Ratings | Positive | BBB- | ||
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 could require us to post up to $282 million in additional collateral with third parties.
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Capital and Investment Expenditures
Each of our businesses is capital-intensive, requiring investment to upgrade or enhance existing operations and comply with safety and environmental regulations. The capital requirements of these businesses consist primarily of:
• | Maintenance capital expenditures, which are generally not discretionary, including: (1) capital expenditures made to replace partially or fully depreciated assets in order to maintain the existing operating capacity of our assets and to extend their useful lives, (2) expenditures which are mandatory and/or essential to comply with laws and regulations and maintain the reliability of our operations, and (3) certain well connection expenditures. |
• | Expansion capital expenditures, which are generally more discretionary than maintenance capital expenditures, including: (1) expenditures to acquire additional assets to grow our business, to expand and upgrade plant or pipeline capacity and to construct new plants, pipelines and storage facilities, and (2) well connection expenditures which are not classified as maintenance expenditures. |
The following table provides summary information related to our expected capital expenditures, purchases of businesses, and purchases of and contributions to equity-method investments for 2014. Included are gross increases to our property, plant, and equipment, including changes related to accounts payable and accrued liabilities:
Segment | Maintenance | Expansion | Total | |||||||||
(Millions) | ||||||||||||
Northeast G&P | $ | 20 | $ | 1,400 | $ | 1,420 | ||||||
Atlantic-Gulf | 175 | 1,300 | 1,475 | |||||||||
West | 125 | 75 | 200 | |||||||||
NGL & Petchem Services | 20 | 500 | 520 | |||||||||
Total | $ | 340 | $ | 3,275 | $ | 3,615 | ||||||
See Company Outlook - Expansion Projects for discussions describing the general nature of these expenditures.
Cash Distributions to Unitholders
We have paid quarterly distributions to unitholders and our general partner after every quarter since our initial public offering on August 23, 2005. We have increased our quarterly distribution from $0.8775 with respect to the third quarter of 2013 to $0.8925 per unit, which resulted in a fourth quarter 2013 distribution of approximately $556 million that was paid on February 13, 2014, to the general and limited partners of record at the close of business on February 6, 2014. (See Note 4 – Allocation of Net Income and Distributions of Notes to Consolidated Financial Statements.)
Sources (Uses) of Cash
Years Ended December 31, | |||||||||||
2013 | 2012 | 2011 | |||||||||
(Millions) | |||||||||||
Net cash provided (used) by: | |||||||||||
Operating activities | $ | 2,169 | $ | 2,133 | $ | 2,430 | |||||
Financing activities | 1,595 | 2,438 | (884 | ) | |||||||
Investing activities | (3,736 | ) | (4,827 | ) | (1,568 | ) | |||||
Increase (decrease) in cash and cash equivalents | $ | 28 | $ | (256 | ) | $ | (22 | ) | |||
Operating activities
The factors that determine operating activities are largely the same as those that affect Net income, with the exception of noncash expenses such as Depreciation and amortization. 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 and net favorable changes in operating working capital, substantially offset by lower operating income.
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Net cash provided by operating activities decreased $289 million in 2012 as compared to 2011 primarily due to lower operating income.
Financing activities
Significant transactions include:
2013
• | $224 million net proceeds received from commercial paper issuances; |
• | $1.705 billion received from credit facility borrowings; |
• | $994 million net proceeds received from our 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 credit facility borrowings; |
• | $1.962 billion received from our equity offerings, including $143 million received from Williams, which was used to repay credit facility borrowings; |
• | $1.846 billion, including $1.376 billion to Williams, related to quarterly cash distributions paid to limited partner unitholders and our general partner; |
• | $398 million received in contributions from noncontrolling interests; |
• | $221 million in net contributions from Williams related to the Canada Acquisition. |
2012
• | $1.559 billion received from our equity offerings; |
• | $1.44 billion related to quarterly cash distributions paid to limited partner unitholders and our general partner; |
• | $1 billion received from Williams for common units issued, used for the funding of a portion of the cash purchase price of the Caiman Acquisition; |
• | $1.49 billion received in credit facility borrowings for general partnership purposes, including capital expenditures; |
• | $745 million net proceeds received from our August 2012 public offering of $750 million of senior unsecured notes due in 2022; |
• | $395 million net proceeds received from Transco’s July 2012 issuance of $400 million of senior unsecured notes due in 2042; |
• | $1.115 billion of credit facility borrowings paid; |
• | $325 million paid to retire Transco’s 8.875 percent notes upon their maturity on July 15, 2012. |
2011
• | $1.12 billion related to quarterly cash distributions paid to limited partner unitholders and our general partner; |
• | $500 million received from our public offering of senior unsecured notes in November 2011 primarily used to repay borrowings on our credit facility; |
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• | $375 million received from Transco’s 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 our $1.75 billion unsecured credit facility used to acquire a 24.5 percent interest in Gulfstream from Williams in May 2011; |
• | $150 million paid to retire senior unsecured notes that matured in June 2011; |
• | $123 million distributed to Williams related to the excess purchase price over the contributed basis of Gulfstream in May 2011. |
Investing activities
Significant transactions include:
2013
• | $3.316 billion in capital expenditures; |
• | Purchases of and contributions to our equity-method investments of $439 million. |
2012
• | $2.366 billion in capital expenditures; |
• | $1.72 billion paid, net of purchase price adjustments, for the Caiman Acquisition in April 2012; |
• | $325 million paid, net of cash acquired in the transaction, for entities acquired in the Laser Acquisition in March 2012; |
• | $471 million contributed to our equity-method investments. |
2011
• | $1.177 billion in capital expenditures; |
• | $174 million related to our acquisitions of a 24.5 percent interest in Gulfstream from Williams in May 2011; |
• | $137 million contribution 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 12 – Debt, Banking Arrangements, and Leases, Note 14 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk, and Note 15 – 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.
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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 | $ | 6,668 | $ | 9,078 | |||||||||
Interest | 475 | 884 | 728 | 3,731 | 5,818 | ||||||||||||||
Commercial paper | 225 | — | — | — | 225 | ||||||||||||||
Operating leases (1) | 43 | 71 | 60 | 123 | 297 | ||||||||||||||
Purchase obligations (2) | 1,945 | 445 | 419 | 929 | 3,738 | ||||||||||||||
Other obligations | 2 | 1 | — | — | 3 | ||||||||||||||
Total | $ | 2,690 | $ | 2,526 | $ | 2,492 | $ | 11,451 | $ | 19,159 | |||||||||
____________
(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 $1.1 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.) |
Effects of Inflation
Our operations have historically not been materially affected by inflation. Approximately 48 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.
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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 15 – 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 $20 million, all of which are included in Other accrued liabilities and Regulatory assets, deferred charges, and other 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 $13 million for cleanup and/or remediation and monitoring activities. We expect to pay approximately $7 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.
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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 our 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 12 – 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: | ||||||||||||||||||||||||||||||||
Fixed rate | $ | — | $ | 750 | $ | 375 | $ | 785 | $ | 500 | $ | 6,647 | $ | 9,057 | $ | 9,581 | ||||||||||||||||
Interest rate | 5.2 | % | 5.3 | % | 5.3 | % | 5.2 | % | 5.1 | % | 5.6 | % | ||||||||||||||||||||
Variable rate (2) | $ | 225 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 225 | $ | 225 | ||||||||||||||||
Interest rate (3) | ||||||||||||||||||||||||||||||||
2013 | 2014 | 2015 | 2016 | 2017 | Thereafter(1) | Total | Fair Value December 31, 2012 | |||||||||||||||||||||||||
(Millions) | ||||||||||||||||||||||||||||||||
Long-term debt, including current portion: | ||||||||||||||||||||||||||||||||
Fixed rate | $ | — | $ | — | $ | 750 | $ | 375 | $ | 785 | $ | 6,152 | $ | 8,062 | $ | 9,249 | ||||||||||||||||
Interest rate | 5.3 | % | 5.3 | % | 5.3 | % | 5.4 | % | 5.3 | % | 5.6 | % | ||||||||||||||||||||
Variable rate | $ | — | $ | — | $ | — | $ | 375 | $ | — | $ | — | $ | 375 | $ | 375 | ||||||||||||||||
Interest rate (3) | ||||||||||||||||||||||||||||||||
______________
(1) | Includes unamortized discount. |
(2) | Consists of Commercial paper. |
(3) | 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 14 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements.)
34
Foreign Currency Risk
Our foreign operations, whose functional currency is the local currency, are located in Canada. Net assets of our foreign operations were approximately $1 billion and $730 million at December 31, 2013 and 2012, respectively. These investments have the potential to impact our financial position due to fluctuations in the local currency arising from the process of translating the local functional currency into the U.S. dollar. As an example, a 20 percent change in the functional currency against the U.S. dollar would have changed Total partners’ equity by approximately $203 million at December 31, 2013.
35
Item 8. Financial Statements and Supplementary Data
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors of Williams Partners GP LLC,
General Partner of Williams Partners L.P.
and the Limited Partners of Williams Partners L.P.
We have audited the accompanying consolidated balance sheet of Williams Partners L.P. (the “Partnership”) as of December 31, 2013 and 2012, and the related consolidated statements of comprehensive income, changes in 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 Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We did not audit the financial statements of Gulfstream Natural Gas System, L.L.C. (“Gulfstream”) (a limited liability corporation in which the Partnership has a 50 percent interest). The Partnership’s investment in Gulfstream constituted one and two percent, respectively, of the Partnership’s assets as of December 31, 2013 and 2012, and the Partnership’s equity earnings in the net income of Gulfstream constituted six, five and three percent, respectively, of the Partnership’s net income for each of the three years in the period ended December 31, 2013. Gulfstream’s financial statements were audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for Gulfstream, is based solely on the report of the other auditors.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits and the report of other auditors provide a reasonable basis for our opinion.
In our opinion, based on our audits and the report of other auditors, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Williams Partners L.P. at December 31, 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.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Williams Partners L.P.’s internal control over financial reporting as of December 31, 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
May 19, 2014
36
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
37
Williams Partners L.P.
Consolidated Statement of Comprehensive Income
Years Ended December 31, | ||||||||||||
2013 | 2012 | 2011 | ||||||||||
(Millions, except per-unit amounts) | ||||||||||||
Revenues: | ||||||||||||
Service revenues | $ | 2,914 | $ | 2,714 | $ | 2,518 | ||||||
Product sales | 3,921 | 4,757 | 5,398 | |||||||||
Total revenues | 6,835 | 7,471 | 7,916 | |||||||||
Costs and expenses: | ||||||||||||
Product costs | 3,027 | 3,501 | 3,934 | |||||||||
Operating and maintenance expenses | 1,080 | 1,019 | 982 | |||||||||
Depreciation and amortization expenses | 791 | 734 | 637 | |||||||||
Selling, general, and administrative expenses | 519 | 583 | 431 | |||||||||
Other (income) expense – net | 11 | 24 | 18 | |||||||||
Total costs and expenses | 5,428 | 5,861 | 6,002 | |||||||||
Operating income | 1,407 | 1,610 | 1,914 | |||||||||
Equity earnings (losses) | 104 | 111 | 142 | |||||||||
Interest incurred | (477 | ) | (458 | ) | (439 | ) | ||||||
Interest capitalized | 90 | 54 | 24 | |||||||||
Other income (expense) – net | 25 | 16 | 9 | |||||||||
Income before income taxes | 1,149 | 1,333 | 1,650 | |||||||||
Provision (benefit) for income taxes | 30 | 42 | 46 | |||||||||
Net income | 1,119 | 1,291 | 1,604 | |||||||||
Less: Net income attributable to noncontrolling interests | 3 | — | — | |||||||||
Net income attributable to controlling interests | $ | 1,116 | $ | 1,291 | $ | 1,604 | ||||||
Allocation of net income for calculation of earnings per common unit: | ||||||||||||
Net income attributable to controlling interests | $ | 1,116 | $ | 1,291 | $ | 1,604 | ||||||
Allocation of net income to general partner | 505 | 646 | 534 | |||||||||
Allocation of net income to common units | $ | 611 | $ | 645 | $ | 1,070 | ||||||
Basic and diluted net income per common unit | $ | 1.45 | $ | 1.89 | $ | 3.69 | ||||||
Weighted average number of common units outstanding (thousands) | 420,916 | 341,981 | 290,255 | |||||||||
Cash distributions per common unit | $ | 3.480 | $ | 3.205 | $ | 2.960 | ||||||
Other comprehensive income (loss): | ||||||||||||
Cash flow hedging activities: | ||||||||||||
Net unrealized gain (loss) from derivative instruments | $ | 1 | $ | 30 | $ | (17 | ) | |||||
Reclassifications into earnings of net derivative instruments (gain) loss | — | (30 | ) | 18 | ||||||||
Foreign currency translation adjustments | (56 | ) | 20 | (16 | ) | |||||||
Other comprehensive income (loss) | (55 | ) | 20 | (15 | ) | |||||||
Comprehensive income | 1,064 | 1,311 | 1,589 | |||||||||
Less: Comprehensive income attributable to noncontrolling interests | 3 | — | — | |||||||||
Comprehensive income attributable to controlling interests | $ | 1,061 | $ | 1,311 | $ | 1,589 | ||||||
See accompanying notes.
38
Williams Partners L.P.
Consolidated Balance Sheet
December 31, | |||||||
2013 | 2012 | ||||||
(Millions) | |||||||
ASSETS | |||||||
Current assets: | |||||||
Cash and cash equivalents | $ | 110 | $ | 82 | |||
Trade accounts and notes receivable, net | 568 | 589 | |||||
Inventories | 194 | 175 | |||||
Other current assets | 96 | 96 | |||||
Total current assets | 968 | 942 | |||||
Investments | 2,187 | 1,800 | |||||
Property, plant, and equipment – net | 17,625 | 15,156 | |||||
Goodwill | 646 | 649 | |||||
Other intangible assets | 1,642 | 1,702 | |||||
Regulatory assets, deferred charges, and other | 503 | 429 | |||||
Total assets | $ | 23,571 | $ | 20,678 | |||
LIABILITIES AND EQUITY | |||||||
Current liabilities: | |||||||
Accounts payable: | |||||||
Trade | $ | 889 | $ | 937 | |||
Affiliate | 104 | 105 | |||||
Accrued interest | 115 | 110 | |||||
Asset retirement obligations | 64 | 68 | |||||
Other accrued liabilities | 375 | 207 | |||||
Commercial paper | 225 | — | |||||
Total current liabilities | 1,772 | 1,427 | |||||
Long-term debt | 9,057 | 8,437 | |||||
Asset retirement obligations | 497 | 511 | |||||
Regulatory liabilities, deferred income, and other | 678 | 612 | |||||
Contingent liabilities and commitments (Note 15) | |||||||
Equity: | |||||||
Partners’ equity: | |||||||
Common units (438,625,699 units outstanding at December 31, 2013 and 397,963,199 units outstanding at December 31, 2012) | 11,596 | 10,372 | |||||
General partner | (536 | ) | (842 | ) | |||
Accumulated other comprehensive income (loss) | 92 | 147 | |||||
Total partners’ equity | 11,152 | 9,677 | |||||
Noncontrolling interests in consolidated subsidiaries | 415 | 14 | |||||
Total equity | 11,567 | 9,691 | |||||
Total liabilities and equity | $ | 23,571 | $ | 20,678 | |||
See accompanying notes.
39
Williams Partners L.P.
Consolidated Statement of Changes in Equity
Williams Partners L.P. | |||||||||||||||||||
Common Units | General Partner | Accumulated Other Comprehensive Income (Loss) | Noncontrolling Interests | Total Equity | |||||||||||||||
(Millions) | |||||||||||||||||||
Balance – December 31, 2010 | $ | 6,564 | $ | (880 | ) | $ | 142 | $ | — | $ | 5,826 | ||||||||
Net income | 1,088 | 516 | — | — | 1,604 | ||||||||||||||
Other comprehensive income (loss) | — | — | (15 | ) | — | (15 | ) | ||||||||||||
Cash distributions (Note 4) | (842 | ) | (282 | ) | — | — | (1,124 | ) | |||||||||||
Distributions to The Williams Companies, Inc.- net | — | (65 | ) | — | — | (65 | ) | ||||||||||||
Excess of purchase price over contributed basis of investment purchase from affiliate | — | (123 | ) | — | — | (123 | ) | ||||||||||||
Contributions from general partner | — | 31 | — | — | 31 | ||||||||||||||
Other | — | (12 | ) | — | — | (12 | ) | ||||||||||||
Balance – December 31, 2011 | $ | 6,810 | $ | (815 | ) | $ | 127 | $ | — | $ | 6,122 | ||||||||
Net income | 672 | 619 | — | — | 1,291 | ||||||||||||||
Other comprehensive income (loss) | — | — | 20 | — | 20 | ||||||||||||||
Cash distributions (Note 4) | (1,056 | ) | (384 | ) | — | — | (1,440 | ) | |||||||||||
Distributions to the Williams Companies, Inc.- net | — | (16 | ) | — | — | (16 | ) | ||||||||||||
Sales of common units (Note 13) | 2,559 | — | — | — | 2,559 | ||||||||||||||
Issuances of common units related to acquisitions (Note 13) | 1,044 | — | — | — | 1,044 | ||||||||||||||
Issuances of common units in common control transactions (Note 13) | 345 | (338 | ) | — | — | 7 | |||||||||||||
Contributions from general partner | — | 93 | — | — | 93 | ||||||||||||||
Contributions from noncontrolling interest | — | — | — | 14 | 14 | ||||||||||||||
Other | (2 | ) | (1 | ) | — | — | (3 | ) | |||||||||||
Balance – December 31, 2012 | $ | 10,372 | $ | (842 | ) | $ | 147 | $ | 14 | $ | 9,691 | ||||||||
Net income | 660 | 456 | — | 3 | 1,119 | ||||||||||||||
Other comprehensive income (loss) | — | — | (55 | ) | — | (55 | ) | ||||||||||||
Cash distributions (Note 4) | (1,422 | ) | (424 | ) | — | — | (1,846 | ) | |||||||||||
Contributions from The Williams Companies, Inc. - net | — | 221 | — | — | 221 | ||||||||||||||
Sales of common units (Note 13) | 1,962 | — | — | — | 1,962 | ||||||||||||||
Contributions from general partner | — | 78 | — | — | 78 | ||||||||||||||
Contributions from noncontrolling interests | — | — | — | 398 | 398 | ||||||||||||||
Other | 24 | (25 | ) | — | — | (1 | ) | ||||||||||||
Balance – December 31, 2013 | $ | 11,596 | $ | (536 | ) | $ | 92 | $ | 415 | $ | 11,567 | ||||||||
See accompanying notes.
40
Williams Partners L.P.
Consolidated Statement of Cash Flows
Years Ended December 31, | |||||||||||
2013 | 2012 | 2011 | |||||||||
(Millions) | |||||||||||
OPERATING ACTIVITIES: | |||||||||||
Net income | $ | 1,119 | $ | 1,291 | $ | 1,604 | |||||
Adjustments to reconcile to net cash provided by operations: | |||||||||||
Depreciation and amortization | 791 | 734 | 637 | ||||||||
Cash provided (used) by changes in current assets and liabilities: | |||||||||||
Accounts and notes receivable | 21 | 32 | (113 | ) | |||||||
Inventories | (17 | ) | 10 | 56 | |||||||
Other current assets and deferred charges | 25 | 25 | (4 | ) | |||||||
Accounts payable | (32 | ) | (81 | ) | 135 | ||||||
Accrued liabilities | 171 | (23 | ) | 112 | |||||||
Affiliate accounts receivable and payable – net | (1 | ) | 42 | (100 | ) | ||||||
Other, including changes in noncurrent assets and liabilities | 92 | 103 | 103 | ||||||||
Net cash provided by operating activities | 2,169 | 2,133 | 2,430 | ||||||||
FINANCING ACTIVITIES: | |||||||||||
Proceeds from (payments of) commercial paper – net | 224 | — | — | ||||||||
Proceeds from long-term debt | 2,699 | 2,639 | 1,596 | ||||||||
Payments of long-term debt | (2,080 | ) | (1,440 | ) | (1,184 | ) | |||||
Proceeds from sales of common units | 1,962 | 2,559 | — | ||||||||
General partner contributions | 53 | 93 | 31 | ||||||||
Distributions to limited partners and general partner | (1,846 | ) | (1,440 | ) | (1,124 | ) | |||||
Contributions from noncontrolling interests | 398 | 13 | — | ||||||||
Excess of purchase price over contributed basis of business and investment | — | — | (123 | ) | |||||||
Contributions from (distributions to) The Williams Companies, Inc. - net | 221 | 9 | (65 | ) | |||||||
Other – net | (36 | ) | 5 | (15 | ) | ||||||
Net cash provided (used) by financing activities | 1,595 | 2,438 | (884 | ) | |||||||
INVESTING ACTIVITIES: | |||||||||||
Property, plant and equipment: | |||||||||||
Capital expenditures | (3,316 | ) | (2,366 | ) | (1,177 | ) | |||||
Net proceeds from dispositions | 3 | 22 | 5 | ||||||||
Purchases of businesses | — | (2,049 | ) | (41 | ) | ||||||
Purchase of businesses and investments from affiliates | 25 | (25 | ) | (174 | ) | ||||||
Purchases of and contributions to equity method investments | (439 | ) | (471 | ) | (197 | ) | |||||
Purchase of ARO trust investments | (58 | ) | (34 | ) | (41 | ) | |||||
Proceeds from sale of ARO trust investments | 46 | 43 | 56 | ||||||||
Other – net | 3 | 53 | 1 | ||||||||
Net cash used by investing activities | (3,736 | ) | (4,827 | ) | (1,568 | ) | |||||
Increase (decrease) in cash and cash equivalents | 28 | (256 | ) | (22 | ) | ||||||
Cash and cash equivalents at beginning of year | 82 | 338 | 360 | ||||||||
Cash and cash equivalents at end of year | $ | 110 | $ | 82 | $ | 338 | |||||
See accompanying notes.
41
Williams Partners L. P. | ||
Notes to Consolidated Financial Statements | ||
Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies
General
We are a publicly traded Delaware limited partnership. Williams Partners GP LLC, a Delaware limited liability company wholly owned by The Williams Companies, Inc. (Williams), serves as our general partner. As of December 31, 2013, Williams owns an approximate 62 percent limited partner interest, a 2 percent general partner interest and incentive distribution rights (IDRs) in us. All of our activities are conducted through Williams Partners Operating LLC (OLLC), an operating limited liability company (wholly owned by us). Our operations are located in the United States and Canada.
Description of Business
Our operations are located in North America and are organized into the following reportable segments: Northeast G&P, Atlantic-Gulf, West, and NGL & Petchem Services.
Northeast G&P is comprised of our midstream gathering and processing businesses in the Marcellus and Utica shale regions, as well as a 51 percent equity investment in Laurel Mountain Midstream, LLC (Laurel Mountain) and a 47.5 percent equity investment in Caiman Energy II, LLC (Caiman II).
Atlantic-Gulf is comprised of our interstate natural gas pipeline, Transcontinental Gas Pipe Line Company, LLC (Transco), and significant natural gas gathering and processing and crude oil production handling and transportation in the Gulf Coast region, as well as a 50 percent equity investment in Gulfstream Natural Gas System, L.L.C. (Gulfstream), a 41 percent interest in Constitution Pipeline Company, LLC (Constitution) (a consolidated entity), and a 60 percent equity investment in Discovery Producer Services LLC (Discovery).
West is comprised of our gathering, processing, and treating operations in New Mexico, Colorado, and Wyoming and our interstate natural gas pipeline, Northwest Pipeline LLC (Northwest Pipeline).
NGL & Petchem Services is comprised of our 83.3 percent undivided interest in an olefins production facility in Geismar, Louisiana, along with a refinery grade propylene splitter and pipelines in the Gulf Coast region, an oil sands offgas processing plant located near Fort McMurray, Alberta, and a natural gas liquid (NGL)/olefin fractionation facility and butylene/butane splitter facility at Redwater, Alberta. This segment also includes our NGL and natural gas marketing business, storage facilities and an undivided 50 percent interest of an NGL fractionator near Conway, Kansas, and a 50 percent equity investment in Overland Pass Pipeline, LLC (OPPL).
Basis of Presentation
In February 2014, we acquired certain Canadian operations from Williams (Canada Acquisition) for total consideration of $25 million of cash (subject to certain closing adjustments), 25,577,521 Class D limited-partner units, and an increase in the capital account of our general partner to allow it to maintain its 2 percent general partner interest. In lieu of cash distributions, the Class D units will receive quarterly distributions of additional paid-in-kind Class D units. All outstanding Class D units will be convertible to common units beginning in the first quarter of 2016. The contribution agreement governing the Canada Acquisition provides that we can issue additional Class D units to Williams on a quarterly basis through 2015 for up to a total of $200 million in cash for the purpose of funding certain facility expansions. This common control acquisition was treated similar to a pooling of interests whereby the historical results of operations were combined with ours for all periods presented. These Canadian operations are reported in our NGL & Petchem Services segment.
Prior period amounts and disclosures have been recast for this transaction. The effect of recasting our financial statements to account for this transaction increased net income by $49 million, $59 million and $93 million for the years ended 2013, 2012, and 2011, respectively, and also resulted in Foreign currency translation adjustments of $(56)
42
Williams Partners L. P. | ||
Notes to Consolidated Financial Statements – (Continued) | ||
million , $20 million , and $(16) million for the years ended 2013, 2012, and 2011, respectively, reflected within Other comprehensive income (loss). This acquisition does not impact historical earnings per unit as pre-acquisition earnings were allocated to our general partner.
In November 2012, we acquired an entity that holds an 83.3 percent undivided interest in an olefins-production facility in Geismar, Louisiana, and associated assets from Williams for total consideration of 42,778,812 of our limited partner units, $25 million in cash, and an increase in the capital account of our general partner to allow it to maintain its 2 percent general partner interest (Geismar Acquisition). The acquired entity was an affiliate of Williams at the time of the acquisition; therefore, the acquisition was accounted for as a common control transaction, whereby the acquired assets and liabilities were combined with ours at their historical amounts. This common control acquisition was treated similar to a pooling of interests whereby the historical results of operations were combined with ours for all periods presented. In first-quarter 2013, we received $25 million in cash from Williams and Williams waived $4 million in payments on its IDRs with respect to our May 2013 distribution related to a working capital adjustment associated with the acquisition.
In May 2011, we acquired a 24.5 percent equity interest in Gulfstream from a subsidiary of Williams in exchange for aggregate consideration of $297 million of cash, 632,584 of our limited partner units, and an increase in the capital account of our general partner to allow it to maintain its 2 percent general partner interest. In June 2012, we acquired an additional 1 percent interest in Gulfstream from a subsidiary of Williams in exchange for 238,050 of our limited partner units, and an increase in the capital account of our general partner to allow it to maintain its 2 percent general partner interest. The equity interests acquired in these transactions were affiliates of Williams at the time of the acquisitions; therefore, each was accounted for as a common control transaction. The equity interests acquired were combined with our investments as of the date of transfer such that our historical results of operations for periods prior to the acquisitions were unchanged. These transactions are collectively referred to as the Gulfstream Acquisitions and the investment is reported in our Atlantic-Gulf segment.
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; |
• | 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.
43
Williams Partners L. P. | ||
Notes to Consolidated Financial Statements – (Continued) | ||
Common control transactions
Entities and assets acquired from Williams and its affiliates are accounted for as common control transactions whereby the net assets acquired are combined with ours at their historical amounts. If any cash consideration transferred in such a transaction exceeds the carrying value of the net assets acquired, the excess is treated as a capital transaction with our general partner, similar to a dividend. If the carrying value of the net assets acquired exceeds any cash consideration transferred and limited partner units are also issued as consideration, then the limited partner units are recorded at an amount equal to the excess of the carrying value of the net assets acquired over any cash consideration transferred. To the extent that such transactions require prior periods to be recast, historical net equity amounts prior to the transaction date are reflected in the account of the general partner. Cash consideration up to the carrying value of net assets acquired is presented as an investing activity in our Consolidated Statement of Cash Flows. Cash consideration in excess of the carrying value of net assets acquired is presented as a financing activity in our Consolidated Statement of Cash Flows.
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; |
• | Asset retirement obligations; |
• | 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 non regulated 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:
44
Williams Partners L. P. | ||
Notes to Consolidated Financial Statements – (Continued) | ||
December 31, | |||||||
2013 | 2012 | ||||||
(Millions) | |||||||
Current assets reported within Other current assets | $ | 39 | $ | 39 | |||
Noncurrent assets reported within Regulatory assets, deferred charges, and other | 315 | 275 | |||||
Total regulated assets | $ | 354 | $ | 314 | |||
Current liabilities reported within Other accrued liabilities | $ | 19 | $ | 15 | |||
Noncurrent liabilities reported within Regulatory liabilities, deferred income and other | 289 | 250 | |||||
Total regulated liabilities | $ | 308 | $ | 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 an allowance for doubtful accounts. We estimate the allowance for doubtful accounts based on existing economic conditions, the financial condition of our customers, and the amount and age of past due accounts. We consider receivables past due if full payment is not received by the contractual due date. Interest income related to past due accounts receivable is generally recognized at the time full payment is received or collectability is assured. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted.
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 in the Consolidated Statement of Comprehensive 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
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Williams Partners L. P. | ||
Notes to Consolidated Financial Statements – (Continued) | ||
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 Statement of Comprehensive 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 the 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.
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Williams Partners L. P. | ||
Notes to Consolidated Financial Statements – (Continued) | ||
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.
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 facility and commercial paper program
Proceeds and payments related to borrowings under our credit facility are reflected in the financing activities in the Consolidated Statement of Cash Flows on a gross basis. Proceeds and payments related to borrowings under our commercial paper program are reflected in the financing activities in the Consolidated Statement of Cash Flows on a net basis, as the outstanding notes generally have maturity dates less than three months from the date of issuance. (See Note 12 – Debt, Banking Arrangements, and Leases.)
Derivative instruments and hedging activities
We may utilize derivatives to manage a portion of our commodity price risk. These instruments consist primarily of swaps, futures, and forward contracts involving short- and long-term purchases and sales of physical energy commodities. We report the fair value of derivatives, except those for which the normal purchases and normal sales exception has been elected, in Other current assets; Regulatory assets, deferred charges, and other; Other accrued liabilities; or Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet. We determine the current and noncurrent classification based on the timing of expected future cash flows of individual trades. We report these amounts on a gross basis. Additionally, we report cash collateral receivables and payables with our counterparties on a gross basis. See Note 14 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk.
The accounting for the changes in fair value of a commodity derivative can be summarized as follows:
Derivative Treatment | Accounting Method | |
Normal purchases and normal sales exception | Accrual accounting | |
Designated in a qualifying hedging relationship | Hedge accounting | |
All other derivatives | Mark-to-market accounting | |
We may elect the normal purchases and normal sales exception for certain short- and long-term purchases and sales of physical energy commodities. Under accrual accounting, any change in the fair value of these derivatives is not reflected on the balance sheet after the initial election of the exception.
We may also designate a hedging relationship for certain commodity derivatives. For a derivative to qualify for designation in a hedging relationship, it must meet specific criteria and we must maintain appropriate documentation. We establish hedging relationships pursuant to our risk management policies. We evaluate the hedging relationships at the inception of the hedge and on an ongoing basis to determine whether the hedging relationship is, and is expected to remain, highly effective in achieving offsetting changes in fair value or cash flows attributable to the underlying risk being hedged. We also regularly assess whether the hedged forecasted transaction is probable of occurring. If a derivative ceases to be or is no longer expected to be highly effective, or if we believe the likelihood of occurrence of the hedged forecasted transaction is no longer probable, hedge accounting is discontinued prospectively, and future changes in the
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Williams Partners L. P. | ||
Notes to Consolidated Financial Statements – (Continued) | ||
fair value of the derivative are recognized currently in Product sales or Product costs in the Consolidated Statement of Comprehensive 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 Comprehensive 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 Comprehensive 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 Comprehensive Income.
Certain gains and losses on derivative instruments included in the Consolidated Statement of Comprehensive 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 include services pursuant to long-term firm transportation and storage agreements within our interstate natural gas pipeline businesses. These agreements provide for a reservation charge based on the volume of a 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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Williams Partners L. P. | ||
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 in the Consolidated Statement of Comprehensive 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.
Income taxes
We generally are not a taxable entity for income tax purposes, with the exception of Texas franchise tax and foreign income taxes associated with our Canadian operations. Other income taxes on net income are generally borne by individual partners. Net income for financial statement purposes may differ significantly from taxable income of unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under our partnership agreement. The aggregated difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined because information regarding each partner’s tax attributes in us is not available to us.
Foreign 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 the related assets and liabilities. Our management’s judgment and income tax assumptions are used to determine the levels, if any, of valuation allowances associated with deferred tax assets.
Earnings per unit
We use the two-class method to calculate basic and diluted earnings per unit whereby net income, adjusted for items specifically allocated to our general partner, is allocated on a pro-rata basis between unitholders and our general partner. Basic and diluted earnings per unit are based on the average number of common units outstanding. Basic and diluted earnings per unit are equivalent as there are no dilutive securities outstanding.
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Williams Partners L. P. | ||
Notes to Consolidated Financial Statements – (Continued) | ||
Pension and other postretirement benefits
We do not have employees. Certain of the costs charged to us by Williams associated with employees who directly support us include costs related to Williams’ pension and other postretirement benefit plans. (See Note 9 – Benefit Plans.) Although the underlying benefit plans of Williams are single-employer plans, we follow multiemployer plan accounting whereby the amount charged to us, and thus paid by us, is based on our share of net periodic benefit cost.
Foreign currency translation
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 comprehensive 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 Comprehensive Income.
Accumulated Other Comprehensive Income (Loss)
AOCI is substantially comprised of foreign currency translation adjustments. These adjustments did not impact Net income in any of the periods presented.
Note 2 – Acquisitions, Goodwill, and Other Intangible Assets
Business Combinations
In addition to the entities and assets acquired in the common control transactions described in Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies, we note the following additional acquisitions.
On February 17, 2012, we 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 of our 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 our 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.
On April 27, 2012, we 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 of our 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 our 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 by Northeast G&P related to the Caiman Acquisition and are reported in Selling, general, and administrative expenses in the Consolidated Statement of Comprehensive Income.
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Williams Partners L. P. | ||
Notes to Consolidated Financial Statements – (Continued) | ||
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 Northeast G&P 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 Comprehensive 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 Comprehensive 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 our Northeast G&P segment (the reporting unit). 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. 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 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.
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Williams Partners L. P. | ||
Notes to Consolidated Financial Statements – (Continued) | ||
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 | 4 | (3 | ) | 4 | (1 | ) | |||||||||
Total | $ | 1,747 | $ | (105 | ) | $ | 1,747 | $ | (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.
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 our estimated cumulative net investment at that time. The $187 million was then distributed to us. Following this transaction, we own a 51 percent interest in Gulfstar One, a subsidiary that, due to certain risk-sharing provisions in its customer contracts, is a VIE. We are the primary beneficiary because we have the power to direct the activities that most significantly impact Gulfstar One’s economic performance. We, as construction agent for Gulfstar One, are 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. We have received certain advance payments from the producer customers and are 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 us 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, we 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.
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Williams Partners L. P. | ||
Notes to Consolidated Financial Statements – (Continued) | ||
Constitution
We own a 41 percent interest in Constitution, a subsidiary that, due to shipper fixed-payment commitments under its firm transportation contracts, is a VIE. We are the primary beneficiary because we have the power to direct the activities that most significantly impact Constitution’s economic performance. We, as construction agent for Constitution, are building a pipeline connecting our gathering system in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and the Tennessee Gas Pipeline systems. We plan to place the project in service in late 2015 to 2016 and estimate the total remaining construction costs of the project to be less than $600 million, which will be funded with capital contributions from us and the other equity partners, proportional to ownership interest.
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 | $ | 76 | $ | 8 | Cash and cash equivalents | ||||
Construction in progress | 998 | 556 | Property, plant, and equipment, at cost | ||||||
Accounts payable | (120 | ) | (128 | ) | Accounts payable - trade | ||||
Construction retainage | (3 | ) | — | Other accrued liabilities | |||||
Current deferred revenue | (10 | ) | — | Other accrued liabilities | |||||
Noncurrent deferred revenue associated with customer advance payments | (115 | ) | (109 | ) | Regulatory liabilities, deferred income, and other | ||||
Nonconsolidated VIEs
We have also identified certain interests in VIEs for which we are not the primary beneficiary. These include:
Laurel Mountain
Our 51 percent-owned equity-method investment in 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, we are 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
Our 47.5 percent-owned equity-method investment in 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. We are not the primary beneficiary because we do not have the power to direct the activities of Caiman II that most significantly impact its 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, we increased our total commitment for contributions to fund the project from $380 million to $500 million inclusive of contributions made to date which represents our current maximum exposure to loss related to this investment.
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Williams Partners L. P. | ||
Notes to Consolidated Financial Statements – (Continued) | ||
Note 4 – Allocation of Net Income and Distributions
The allocation of net income among our general partner, limited partners, and noncontrolling interests as reflected in the Consolidated Statement of Changes in Equity is as follows:
Years Ended December 31, | |||||||||||
2013 | 2012 | 2011 | |||||||||
(Millions) | |||||||||||
Allocation of net income to general partner: | |||||||||||
Net income | $ | 1,119 | $ | 1,291 | $ | 1,604 | |||||
Net income applicable to pre-partnership operations allocated to general partner | (49 | ) | (244 | ) | (226 | ) | |||||
Net income applicable to noncontrolling interests | (3 | ) | — | — | |||||||
Net costs charged directly to general partner | 1 | 1 | (2 | ) | |||||||
Income subject to 2% allocation of general partner interest | 1,068 | 1,048 | 1,376 | ||||||||
General partner’s share of net income | 2 | % | 2 | % | 2 | % | |||||
General partner’s allocated share of net income before items directly allocable to general partner interest | 21 | 21 | 28 | ||||||||
Priority allocations, including incentive distributions, paid to general partner (1) | 387 | 355 | 260 | ||||||||
Net costs charged directly to general partner | (1 | ) | (1 | ) | 2 | ||||||
Pre-partnership net income allocated to general partner interest | 49 | 244 | 226 | ||||||||
Net income allocated to general partner | $ | 456 | $ | 619 | $ | 516 | |||||
Net income | $ | 1,119 | $ | 1,291 | $ | 1,604 | |||||
Net income allocated to general partner | 456 | 619 | 516 | ||||||||
Net income allocated to noncontrolling interests | 3 | — | — | ||||||||
Net income allocated to common limited partners | $ | 660 | $ | 672 | $ | 1,088 | |||||
____________
(1) | The net income allocated to the general partner’s capital account reflects IDRs paid during the current reporting period. In the calculation of basic and diluted net income per common unit, the net income allocated to the general partner includes IDRs pertaining to the current reporting period but paid in the subsequent period. |
The Net costs charged directly to general partner may include the net of both income and expense items. Under the terms of omnibus agreements, we are reimbursed by our general partner for certain expense items and are required to distribute certain income items to our general partner.
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Williams Partners L. P. | ||
Notes to Consolidated Financial Statements – (Continued) | ||
The following table sets forth the partnership cash distributions paid on the dates indicated, related to the preceding quarter (in millions, except for per unit amounts):
General Partner | ||||||||||||||||||||
Payment Date | Per Unit Distribution | Common Units | 2% | Incentive Distribution Rights | Total Cash Distribution | |||||||||||||||
2/11/2011 | $ | 0.7025 | $ | 204 | $ | 5 | $ | 59 | $ | 268 | ||||||||||
5/13/2011 | 0.7175 | 208 | 5 | 63 | 276 | |||||||||||||||
8/12/2011 | 0.7325 | 213 | 6 | 67 | 286 | |||||||||||||||
11/11/2011 | 0.7475 | 217 | 6 | 71 | 294 | |||||||||||||||
2/10/2012 | 0.7625 | 227 | 6 | 78 | 311 | |||||||||||||||
5/11/2012 | 0.7775 | 268 | 8 | 86 | 362 | |||||||||||||||
8/10/2012 | 0.7925 | 274 | 7 | 92 | 373 | |||||||||||||||
11/9/2012 | 0.8075 | 287 | 8 | 99 | 394 | |||||||||||||||
2/8/2013 | 0.8275 | 329 | 9 | 104 | 442 | |||||||||||||||
5/10/2013 | 0.8475 | 351 | 10 | 112 | 473 | |||||||||||||||
8/09/2013 | 0.8625 | 357 | 11 | 121 | 489 | |||||||||||||||
11/12/2013 | 0.8775 | 385 | 11 | 46 | 442 | |||||||||||||||
2/13/2014 (1) | 0.8925 | 392 | 11 | 153 | 556 | |||||||||||||||
____________
(1) | On February 13, 2014, we paid a cash distribution of $0.8925 per unit on our outstanding common units to unitholders of record at the close of business on February 6, 2014. |
The 2012, 2013, and 2014 cash distributions paid to our general partner in the table above have been reduced by $147 million resulting from the temporary waiver of IDRs associated with certain assets acquired in 2012 and an additional $90 million in IDRs waived by our general partner related to the third quarter 2013 distributions, to support our cash distribution metrics as our large platform of growth projects moves toward completion.
Note 5 – Related Party Transactions
Reimbursement of Expenses of Our General Partner
The employees of our operated assets are employees of Williams. Williams directly charges us for the payroll and benefit costs associated with operations employees and carries the obligations for many employee-related benefits in its financial statements, including the liabilities related to employee retirement, medical plans, and paid time off. Our share of the costs is charged to us through affiliate billings and reflected in Operating and maintenance expenses in the Consolidated Statement of Comprehensive Income.
In addition, employees of Williams provide general and administrative services to us, and we are charged for certain administrative expenses incurred by Williams. These charges are either directly identifiable or allocated to our assets. Direct charges are for goods and services provided by Williams at our request. Allocated charges are based on a three-factor formula, which considers revenues; property, plant, and equipment; and payroll. Our share of direct and allocated administrative expenses is reflected in Selling, general, and administrative expenses in the Consolidated Statement of Comprehensive Income. In management’s estimation, the allocation methodologies used are reasonable and result in a reasonable allocation to us of our costs of doing business incurred by Williams.
In 2012, Williams engaged a consulting firm to assist in better aligning resources to support their business strategy following the December 31, 2011, spin-off of WPX Energy, Inc. (WPX). Our share of the allocated reorganization-related costs, included in Selling, general, and administrative expenses in the Consolidated Statement of Comprehensive Income, is $2 million and $26 million for the years ended December 31, 2013, and December 31, 2012, respectively.
55
Williams Partners L. P. | ||
Notes to Consolidated Financial Statements – (Continued) | ||
Transactions with Affiliates and Equity-Method Investees
Product costs, in the Consolidated Statement of Comprehensive Income, include charges for the following types of transactions with affiliates and equity-method investees:
• | Purchases of NGLs for resale from Discovery at market prices at the time of purchase. |
• | Payments to OPPL for transportation of NGLs from certain natural gas processing plants. |
Transactions with WPX
We consider WPX an affiliate prior to its spin-off from Williams. Revenues, in the Consolidated Statement of Comprehensive Income, for the year ended December 31, 2011 include the following types of transactions we have with WPX prior to this separation:
• | Revenues from transportation and exchange service and rental of communication facilities with WPX. The rates charged to provide sales and services to affiliates are comparable to those that are charged to similarly situated nonaffiliated customers. |
• | Revenues from gathering, treating, and processing services for WPX under several contracts. We believe that the rates charged to provide these services are reasonable as compared to those that are charged to similarly situated nonaffiliated customers. |
Product costs and Operating and maintenance expenses, in the Consolidated Statement of Comprehensive Income, for the year ended December 31, 2011 include charges for the following types of transactions we have with WPX prior to this separation:
• | Purchases of NGLs for resale from WPX at market prices at the time of purchase. |
• | Purchases of natural gas for shrink replacement and fuel from WPX at market prices at the time of purchase or contract execution. |
• | Costs related to a transportation capacity agreement transferred to WPX in a prior year. To the extent that WPX did not utilize this transportation capacity for its needs (primarily transporting third-party gas volumes), we reimbursed WPX for these transportation costs. |
Historically, we periodically entered into derivative contracts with WPX to hedge forecasted NGL sales and natural gas purchases. These contracts were priced based on market rates at the time of execution.
Summary of the related party transactions discussed in all sections above.
Years Ended December 31, | ||||||||||||
2013 | 2012 | 2011 | ||||||||||
(Millions) | ||||||||||||
Revenues | $ | — | $ | — | $ | 310 | ||||||
Product costs | 147 | 171 | 728 | |||||||||
Operating and maintenance expenses: | ||||||||||||
Employee costs | 339 | 275 | 241 | |||||||||
Other | — | — | 305 | |||||||||
Selling, general, and administrative expenses: | ||||||||||||
Employee direct costs | 270 | 308 | 248 | |||||||||
Employee allocated costs | 169 | 190 | 122 | |||||||||
56
Williams Partners L. P. | ||
Notes to Consolidated Financial Statements – (Continued) | ||
The Accounts payable — affiliate in the Consolidated Balance Sheet represents the payable positions that result from the transactions with affiliates discussed above. We also have $13 million and $15 million in Accounts payable — trade in the Consolidated Balance Sheet with our equity-method investees at December 31, 2013 and December 31, 2012, respectively.
Operating Agreements with Equity-Method Investees
We have operating agreements with certain equity-method investees. These operating agreements typically provide for reimbursement or payment to us for certain direct operational payroll and employee benefit costs, materials, supplies, and other charges and also for management services. Williams supplied a portion of these services, primarily those related to employees since we do not have any employees, to certain equity-method investees. The total gross charges to equity-method investees for these fees included in the Consolidated Statement of Comprehensive Income are $67 million, $75 million and $57 million for the years ended December 31, 2013, 2012, and 2011, respectively.
Omnibus Agreement
In February 2010, we entered into an omnibus agreement with Williams. Under this agreement, Williams is obligated to reimburse us for (i) amounts incurred by us or our subsidiaries for repair or abandonment costs for damages to certain facilities caused by Hurricane Ike, up to a maximum of $10 million, (ii) maintenance capital expenditure amounts incurred by us or our subsidiaries for certain U.S. Department of Transportation projects, up to a maximum of $50 million, and (iii) an amount based on the amortization over time of deferred revenue amounts that relate to cash payments received by Williams prior to the closing of the contribution transaction for services to be rendered by us in the future at the Devils Tower floating production platform. In addition, we will be obligated to pay to Williams the proceeds of certain sales of natural gas recovered from the Hester storage field pursuant to the FERC order dated March 7, 2008, approving a settlement agreement. Net amounts received under this agreement for the years ended December 31, 2013, 2012 and 2011 were $12 million, $15 million, and $31 million, respectively.
We have a contribution receivable from our general partner of $3 million and $4 million at December 31, 2013 and December 31, 2012, respectively, for amounts reimbursable to us under omnibus agreements. We net this receivable against Total partners’ equity in the Consolidated Balance Sheet.
Acquisitions and Equity Issuances
Basis of Presentation in Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies includes related party transactions for the Geismar, Gulfstream, and Canada Acquisitions. Prior to the acquisition, Geismar operations were included in Williams’ cash management program under an unsecured promissory note agreement with Williams for both advances to and from Williams. In connection with the Geismar Acquisition, the outstanding advances were distributed to Williams at the close of the transaction. The distribution had no impact on our assets or liabilities. Changes in the advances to Williams are presented as Distributions to The Williams Companies, Inc.- net in the Consolidated Statement of Changes in Equity. The Canadian operations previously participated in Williams’ cash management program under a credit agreement with Williams. Net changes in amounts due to/from Williams prior to the Canada Acquisition are reflected within Distributions to/Contributions from The Williams Companies, Inc. - net within the Consolidated Statement of Changes in Equity.
Note 13 – Partners’ Capital includes related party transactions for the sale of limited partner units to Williams in March 2013 and April 2012.
Board of Directors
A member of Williams’ 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 Consolidated Statement of Comprehensive 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.
57
Williams Partners L. P. | ||
Notes to Consolidated Financial Statements – (Continued) | ||
Mr. H. Michael Krimbill, a member of our Board of Directors until his term completion in August 2012, has served as the Chief Executive Officer of NGL Energy Partners LP, formerly Silverthorne Energy Partners LP, and as a director of its general partner since 2010. We recorded $61 million and $62 million in Product sales in the Consolidated Statement of Comprehensive Income from NGL Energy Partners LP primarily for the sale of propane at market prices and $13 million and $9 million in Product costs in the Consolidated Statement of Comprehensive Income for the purchase of propane at market prices for the years ended December 31, 2012 and 2011, respectively.
Note 6 – Investments
Investments accounted for using the equity method consist of:
December 31, | |||||||
2013 | 2012 | ||||||
(Millions) | |||||||
OPPL - 50% | $ | 452 | $ | 454 | |||
Gulfstream - 50% | 333 | 348 | |||||
Discovery - 60% (1) | 527 | 350 | |||||
Laurel Mountain - 51% (1) | 481 | 444 | |||||
Caiman II - 47.5% | 256 | 67 | |||||
Other | 138 | 137 | |||||
$ | 2,187 | $ | 1,800 | ||||
____________
(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. |
The difference between the carrying value of our equity-method investments and the underlying equity in the net assets of the investees is $60 million at December 31, 2013, primarily related to impairments we previously recognized. These differences are amortized over the expected remaining life of the investees’ underlying assets.
We generally fund our portion of significant expansion or development projects of these investees through additional capital contributions. As of December 31, 2013, our proportionate share of amounts remaining to be spent for specific capital projects already in progress for Discovery, Laurel Mountain, and Caiman II totaled $244 million, $72 million, and $119 million, respectively.
We acquired a 1 percent and 24.5 percent interest in Gulfstream from a subsidiary of Williams in June 2012 and May 2011, respectively. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies.) 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.
58
Williams Partners L. P. | ||
Notes to Consolidated Financial Statements – (Continued) | ||
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 $154 million, $172 million, and $169 million in 2013, 2012, and 2011, respectively. These transactions reduced the carrying value of our investments. These dividends and distributions primarily included:
Years Ended December 31, | |||||||||||
2013 | 2012 | 2011 | |||||||||
(Millions) | |||||||||||
Gulfstream | $ | 81 | $ | 78 | $ | 60 | |||||
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 | $ | 412 | $ | 366 | |||
Noncurrent assets | 5,956 | 5,225 | |||||
Current liabilities | (264 | ) | (247 | ) | |||
Noncurrent liabilities | (1,305 | ) | (1,301 | ) | |||
Years Ended December 31, | |||||||||||
2013 | 2012 | 2011 | |||||||||
(Millions) | |||||||||||
Gross revenue | $ | 1,333 | $ | 1,213 | $ | 1,242 | |||||
Operating income | 367 | 378 | 535 | ||||||||
Net income | 291 | 309 | 460 | ||||||||
59
Williams Partners L. P. | ||
Notes to Consolidated Financial Statements – (Continued) | ||
Note 7 – 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) | ||||||||||||
Northeast G&P | ||||||||||||
Settlement in principle of a producer claim | $ | 25 | $ | — | $ | — | ||||||
Atlantic-Gulf | ||||||||||||
Amortization of regulatory asset 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 | ) | — | — | ||||||||
Project feasibility costs | 4 | 21 | 10 | |||||||||
Capitalization of project feasibility costs previously expensed | (1 | ) | (19 | ) | (11 | ) | ||||||
NGL & Petchem Services | ||||||||||||
Net insurance recoveries associated with the Geismar Incident | (40 | ) | — | — | ||||||||
The reversals of project feasibility costs from expense to capital 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 our 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 NGL & Petchem Services during 2013 of costs under our insurance deductibles in Operating and maintenance expenses in the Consolidated Statement of Comprehensive 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 Comprehensive 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 Comprehensive Income.
60
Williams Partners L. P. | ||
Notes to Consolidated Financial Statements – (Continued) | ||
Additional Item
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 Atlantic-Gulf during 2013, 2012, and 2011, respectively, primarily related to assessment and monitoring costs incurred to ensure the safety of the surrounding area.
Note 8 – Provision (Benefit) for Income Taxes
The Provision (benefit) for income taxes includes:
Years Ended December 31, | |||||||||||
2013 | 2012 | 2011 | |||||||||
(Millions) | |||||||||||
Current: | |||||||||||
State | $ | 2 | $ | 11 | $ | 3 | |||||
Foreign | (22 | ) | 26 | 32 | |||||||
(20 | ) | 37 | 35 | ||||||||
Deferred: | |||||||||||
State | 15 | — | — | ||||||||
Foreign | 35 | 5 | 11 | ||||||||
50 | 5 | 11 | |||||||||
Total provision (benefit) | $ | 30 | $ | 42 | $ | 46 | |||||
Reconciliations from the Provision (benefit) for income taxes 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 at statutory rate | $ | 402 | $ | 467 | $ | 577 | |||||
Increases (decreases) in taxes resulting from: | |||||||||||
Income not subject to federal tax | (402 | ) | (467 | ) | (577 | ) | |||||
State income taxes | 17 | 11 | 3 | ||||||||
Foreign operations — net | 13 | 31 | 43 | ||||||||
Provision (benefit) for income taxes | $ | 30 | $ | 42 | $ | 46 | |||||
The 2013 state deferred provision includes $15 million related to the impact of a second-quarter 2013 Texas franchise tax law change.
Income before income taxes includes $61 million, $96 million, and $136 million of foreign income in 2013, 2012, and 2011, respectively.
Deferred tax liabilities, attributable to the taxable temporary differences from property, plant, and equipment, were $117 million and $72 million in 2013 and 2012, respectively.
Cash payments for income taxes (net of refunds) were $2 million, $54 million, and $35 million in 2013, 2012, and 2011, respectively.
As of December 31, 2013, we do not have any material unrecognized tax benefits.
61
Williams Partners L. P. | ||
Notes to Consolidated Financial Statements – (Continued) | ||
Tax years after 2009 are subject to examination by the Texas Comptroller. Generally, tax returns for our Canadian entities are open to audit for tax years after 2007. Williams has indemnified us for any adjustments to foreign tax returns filed prior to the Canada Acquisition.
Note 9 – Benefit Plans
Certain of the benefit costs charged to us by Williams associated with employees who directly support us are described below. Additionally, allocated corporate expenses from Williams to us also include amounts related to these same employee benefits, which are not included in the amounts presented below.
Defined Benefit Pension plans
Williams has noncontributory defined benefit pension plans (Williams Pension Plan, Williams Inactive Employees Pension Plan and The Williams Companies Retirement Restoration Plan) that provide pension benefits for its eligible employees. Pension costs charged to us by Williams for 2013, 2012, and 2011 totaled $44 million, $41 million, and $32 million, respectively. At the total Williams plan level, the pension plans had a projected benefit obligation of $1.4 billion and $1.5 billion at December 31, 2013 and 2012, respectively. The plans were underfunded by $143 million and $478 million at December 31, 2013 and 2012, respectively.
Postretirement benefits other than pensions
Williams provides certain retiree health care and life insurance benefits for eligible participants. Generally, employees that were employed by Williams on or before December 31, 1991 or December 31, 1995, if they were employees or retirees of Transco Energy Company and its subsidiaries are eligible for subsidized retiree medical benefits. The cost charged to us for the plans anticipates future cost-sharing that is consistent with Williams’ expressed intent to increase the retiree contribution level, generally in line with health care cost increases. We recognized a net periodic postretirement benefit credited to us by Williams of $4 million in 2013 and $2 million in 2011, and a net periodic postretirement benefit cost charged to us by Williams of $4 million in 2012. At the total Williams plan level, the postretirement benefit plans had an accumulated postretirement benefit obligation of $213 million and $331 million at December 31, 2013 and 2012, respectively. The plans were underfunded by $12 million and $156 million at December 31, 2013 and 2012, respectively.
Any differences between the annual expense and amounts currently being recovered in rates by our FERC-regulated gas pipelines are recorded as an adjustment to expense and collected or refunded through future rate adjustments.
Defined contribution plans
Williams charged us compensation expense of $16 million, $19 million, and $17 million in 2013, 2012, and 2011, respectively, for Williams’ contributions to these plans.
Employee Stock-Based Compensation Plan information
The Williams Companies, Inc. 2007 Incentive Plan (Plan) provides for Williams common-stock-based awards to both employees and nonmanagement directors. The Plan permits the granting of various types of awards including, but not limited to, stock options and deferred stock. Awards may be granted for no consideration other than prior and future services or based on certain financial performance targets being achieved.
Williams bills us directly for compensation expense related to stock-based compensation awards based on the fair value of the awards.
Total stock-based compensation expense for the years ended December 31, 2013, 2012, and 2011 was $12 million, $13 million and $11 million, respectively.
62
Williams Partners L. P. | ||
Notes to Consolidated Financial Statements – (Continued) | ||
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 | ||||
Note 11 – Property, Plant and Equipment
Estimated | Depreciation | ||||||||||
Useful Life (1) | Rates (1) | December 31, | |||||||||
(Years) | (%) | 2013 | 2012 | ||||||||
(Millions) | |||||||||||
Nonregulated: | |||||||||||
Natural gas gathering and processing facilities | 5 - 40 | $ | 9,172 | $ | 7,694 | ||||||
Construction in progress | Not applicable | 2,727 | 1,870 | ||||||||
Other | 3 - 45 | 964 | 780 | ||||||||
Regulated: | |||||||||||
Natural gas transmission facilities | 1.2 - 6.97 | 10,633 | 9,963 | ||||||||
Construction in progress | Not applicable | 273 | 337 | ||||||||
Other | 1.35 - 33.33 | 1,293 | 1,418 | ||||||||
Total property, plant, and equipment, at cost | $ | 25,062 | $ | 22,062 | |||||||
Accumulated depreciation and amortization | (7,437 | ) | (6,906 | ) | |||||||
Property, plant, and equipment — net | $ | 17,625 | $ | 15,156 | |||||||
______________________
(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 $729 million, $690 million and $634 million in 2013, 2012, and 2011, respectively.
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.
63
Williams Partners L. P. | ||
Notes to Consolidated Financial Statements – (Continued) | ||
The following table presents the significant changes to our asset retirement obligations (ARO):
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 14 – 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.
64
Williams Partners L. P. | ||
Notes to Consolidated Financial Statements – (Continued) | ||
Note 12 – 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 | ||||||
Williams Partners L.P.: | ||||||||
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 | ||||||
Unamortized debt discount | (21 | ) | (16 | ) | ||||
Long-term debt | $ | 9,057 | $ | 8,437 | ||||
The terms of our senior unsecured notes are governed by indentures that contain covenants that, among other things, limit: (1) our ability and the ability of our subsidiaries to create liens securing indebtedness and (2) mergers, consolidations, and sales of assets. The indentures also contain customary events of default, upon which the trustee or the holders of the senior unsecured notes may declare all outstanding senior unsecured notes to be due and payable immediately.
65
Williams Partners L. P. | ||
Notes to Consolidated Financial Statements – (Continued) | ||
The following table presents aggregate minimum maturities of long-term debt (excluding 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, we 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. We used the net proceeds to repay amounts outstanding under our commercial paper program, to fund capital expenditures, and for general partnership purposes.
In August 2012, we completed a public offering of $750 million of 3.35 percent senior unsecured notes due 2022. We used the net proceeds to repay outstanding borrowings on our 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 Facility
In July 2013, we amended our $2.4 billion credit facility to increase the aggregate commitments to $2.5 billion and extend the maturity date to July 31, 2018. Additionally, Transco and Northwest Pipeline are each able to borrow up to $500 million under the amended credit facility to the extent not otherwise utilized by the other co-borrowers. Our credit facility 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 $2.5 billion credit facility is $1.3 billion, no letters of credit have been issued, and no loans are outstanding under our credit facility.
Our significant financial covenants require our ratio of debt to EBITDA (each as defined in the credit facility) must 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, we are required to maintain 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, we are in compliance with these financial covenants.
The credit agreement governing our credit facility contains 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 0.175 percent) based on the unused portion of the credit facility. The applicable margin and the commitment fee are determined for each borrower by reference to a pricing schedule based on such borrower’s senior unsecured long-term debt ratings. |
66
Williams Partners L. P. | ||
Notes to Consolidated Financial Statements – (Continued) | ||
• | 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 the credit facility, the lenders will be able to terminate the commitments for all borrowers and accelerate the maturity of any loans of the defaulting borrower under the credit facility agreement and exercise other rights and remedies. |
Commercial Paper Program
In March 2013, we 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 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, $225 million of Commercial paper is 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 $366 million in 2013, $381 million in 2012, and $387 million in 2011.
Leases-Lessee
The future minimum annual rentals under noncancelable operating leases, are payable as follows:
December 31, 2013 | |||
(Millions) | |||
2014 | $ | 42 | |
2015 | 36 | ||
2016 | 35 | ||
2017 | 31 | ||
2018 | 29 | ||
Thereafter | 123 | ||
Total | $ | 296 | |
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 $51 million in 2013, $46 million in 2012, and $38 million in 2011.
67
Williams Partners L. P. | ||
Notes to Consolidated Financial Statements – (Continued) | ||
Note 13 – Partners’ Capital
At December 31, 2013 and 2012, the public held 36 percent and 30 percent, respectively, of our total units outstanding, and affiliates of Williams held the remaining units. Transactions which occurred during 2013 and 2012 are summarized below.
In March 2013, we completed an equity issuance of 14,250,000 common units, including 3,000,000 common units sold to Williams in a private placement. Subsequently, the underwriters exercised their option to purchase an additional 1,687,500 common units. The net proceeds of approximately $760 million were used to repay amounts outstanding under our credit facility.
In August 2013, we completed an equity issuance of 21,500,000 common units. Subsequently, the underwriters exercised their option to purchase an additional 3,225,000 common units. The net proceeds of approximately $1.2 billion were used to repay amounts outstanding under our commercial paper program, to fund capital expenditures and for general partnership purposes.
In January 2012, we issued 7,000,000 common units. The net proceeds of approximately $426 million were used to fund capital expenditures and for other partnership purposes.
In February 2012, we closed the Laser Acquisition. In connection with this transaction, we issued 7,531,381 of our common units. (See Note 2 – Acquisitions, Goodwill, and Other Intangible Assets.)
In February 2012, the underwriters exercised their option to purchase an additional 1,050,000 common units pursuant to our common unit offering in January 2012. The net proceeds of approximately $64 million were used for general partnership purposes.
In April 2012, we issued 10,000,000 common units. Subsequently, the underwriters exercised their option to purchase an additional 973,368 common units. The net proceeds of approximately $581 million were used for general partnership purposes, including the funding of a portion of the cash purchase price of the Caiman Acquisition. (See Note 2 – Acquisitions, Goodwill, and Other Intangible Assets.) We also used $1 billion in proceeds from an April 2012 sale of 16,360,133 common units to Williams to partially fund the Caiman Acquisition.
In April 2012, we closed the Caiman Acquisition. In connection with this transaction, we issued 11,779,296 of our common units. (See Note 2 – Acquisitions, Goodwill, and Other Intangible Assets.)
In June 2012, we acquired a 1 percent interest in Gulfstream from a subsidiary of Williams. In connection with this transaction, we issued 238,050 of our common units. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies.)
In August 2012, we completed an equity issuance of 8,500,000 common units. Subsequently, the underwriters exercised their option to purchase an additional 1,275,000 common units. The net proceeds of approximately $488 million were used to repay amounts outstanding under our revolving credit facility and for general partnership purposes.
In November 2012, we closed the Geismar Acquisition with Williams. In connection with this transaction, we issued 42,778,812 of our common units. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies.)
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Williams Partners L. P. | ||
Notes to Consolidated Financial Statements – (Continued) | ||
Limited Partners’ Rights
Significant rights of the limited partners include the following:
• | Right to receive distributions of available cash within 45 days after the end of each quarter. |
• | No limited partner shall have any management control over our business and affairs; the general partner shall conduct, direct and manage our activities. |
• | The general partner may be removed if such removal is approved by the unitholders holding at least 66 2/3 percent of the outstanding units voting as a single class, including units held by our general partner and its affiliates. |
Incentive Distribution Rights
Our general partner is entitled to incentive distributions if the amount we distribute to unitholders with respect to any quarter exceeds specified target levels shown below:
Quarterly Distribution Target Amount (per unit) | Unitholders | General Partner | ||
Minimum quarterly distribution of $0.35 | 98% | 2% | ||
Up to $0.4025 | 98 | 2 | ||
Above $0.4025 up to $0.4375 | 85 | 15 | ||
Above $0.4375 up to $0.5250 | 75 | 25 | ||
Above $0.5250 | 50 | 50 | ||
See Note 4 – Allocation of Net Income and Distributions for information regarding IDR waivers.
In the event of liquidation, all property and cash in excess of that required to discharge all liabilities will be distributed to the unitholders and our general partner in proportion to their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.
Issuances of Additional Partnership Securities
Our partnership agreement allows us to issue additional partnership securities for any partnership purpose at any time and from time to time for consideration and on terms and conditions as our general partner determines, all without the approval of any limited partners.
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Williams Partners L. P. | ||
Notes to Consolidated Financial Statements – (Continued) | ||
Note 14 – 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 | 7 | 7 | 1 | 6 | — | ||||||||||||||
Long-term debt | (9,057 | ) | (9,581 | ) | — | (9,581 | ) | — | |||||||||||
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 | 11 | 10 | 2 | 8 | — | ||||||||||||||
Long-term debt | (8,437 | ) | (9,624 | ) | — | (9,624 | ) | — | |||||||||||
Fair Value Methods
We use the following methods and assumptions in estimating the fair value of our financial instruments:
Assets and liabilities measured at fair value on a recurring basis
ARO Trust investments: Transco deposits a portion of its collected rates, pursuant to its rate case settlement, into an external trust that is specifically designated to fund future asset retirement obligations. The ARO Trust invests in a portfolio of actively traded mutual funds that are measured at fair value on a recurring basis based on quoted prices in an active market, is classified as available-for-sale, and is reported in Regulatory assets, deferred charges, and other in the Consolidated Balance Sheet. Both realized and unrealized gains and losses are ultimately recorded as regulatory assets or liabilities.
Energy derivatives: Energy derivatives include commodity based exchange-traded contracts and over-the-counter (OTC) contracts, which consist of physical forwards, futures, and swaps that are measured at fair value on a recurring
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Williams Partners L. P. | ||
Notes to Consolidated Financial Statements – (Continued) | ||
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 Regulatory assets, deferred charges, and other in the Consolidated Balance Sheet. Energy derivatives liabilities are reported in Other accrued liabilities and Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet.
Reclassifications of fair value between Level 1, Level 2, and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. No transfers between Level 1 and Level 2 occurred during the years ended December 31, 2013 or 2012.
Additional fair value disclosures
Notes receivable and other: The disclosed fair value of our notes receivable 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 Trade 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.
Guarantees
We are required by our revolving credit agreement to indemnify lenders for certain taxes required to be withheld from payments due to the lenders and for certain tax payments made by the lenders. The maximum potential amount of future payments under these indemnifications is based on the related borrowings and such future payments cannot currently be determined. These indemnifications generally continue indefinitely unless limited by the underlying tax regulations and have no carrying value. We have never been called upon to perform under these indemnifications and have no current expectation of a future claim.
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 | $ | 406 | |||
Transportation of natural gas and related products | 193 | 169 | |||||
Other | 34 | 14 | |||||
Total | $ | 568 | $ | 589 | |||
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.
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Williams Partners L. P. | ||
Notes to Consolidated Financial Statements – (Continued) | ||
Revenues
In 2013, 2012 and 2011, we had one customer in our NGL & Petchem Services segment that accounted for 9 percent, 14 percent, and 17 percent of our consolidated revenues, respectively.
Note 15 – Contingent Liabilities and Commitments
Environmental Matters
We are a participant in certain environmental activities in various stages including assessment studies, cleanup operations and remedial processes at certain sites, some of which we currently do not own. We are monitoring these sites in a coordinated effort with other potentially responsible parties, the U.S. Environmental Protection Agency (EPA), and other governmental authorities. We are jointly and severally liable along with unrelated third parties in some of these activities and solely responsible in others. Certain of our subsidiaries have been identified as potentially responsible parties at various Superfund and state waste disposal sites. In addition, these subsidiaries have incurred, or are alleged to have incurred, various other hazardous materials removal or remediation obligations under environmental laws. As of December 31, 2013, we have accrued liabilities totaling $20 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.
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.
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.
Geismar Incident
As a result of the previously discussed Geismar Incident, there were two fatalities and numerous individuals (including affiliate employees and contractors) reported injuries, which varied from minor to serious. We are cooperating with the Chemical Safety Board and the 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.
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Williams Partners L. P. | ||
Notes to Consolidated Financial Statements – (Continued) | ||
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.
Rate Matters
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 Other 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.
Other
In addition to the foregoing, various other proceedings are pending against us which are incidental to our operations.
Summary
We estimate that for all matters for which we are able to reasonably estimate a range of loss, including those noted above and others that are not individually significant, our aggregate reasonably possible losses beyond amounts accrued for all of our contingent liabilities 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. We disclose all significant matters for which we are unable to reasonably estimate a range of possible loss.
Commitments
Commitments for construction and acquisition of property, plant and equipment are approximately $1.4 billion at December 31, 2013.
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Williams Partners L. P. | ||
Notes to Consolidated Financial Statements – (Continued) | ||
Note 16 – Segment Disclosures
Our reportable segments are Northeast G&P, Atlantic-Gulf, West, and NGL & Petchem Services. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies.)
Performance Measurement
We currently evaluate segment operating performance based on 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 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies. Intersegment revenues primarily represent the sale of NGLs from our natural gas processing plants to our marketing business and 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 | $ | 6,685 | $ | 150 | $ | 6,835 | |||||||
2012 | 7,320 | 151 | 7,471 | ||||||||||
2011 | 7,714 | 202 | 7,916 | ||||||||||
Long-lived assets: | |||||||||||||
2013 | $ | 18,776 | $ | 1,137 | $ | 19,913 | |||||||
2012 | 16,637 | 870 | 17,507 | ||||||||||
2011 | 11,866 | 583 | 12,449 | ||||||||||
Long-lived assets are comprised of property, plant, and equipment, goodwill, and other intangible assets.
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Williams Partners L. P. | ||
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 as reported in the Consolidated Statement of Comprehensive Income. It also presents other financial information related to long-lived assets.
Northeast G&P | Atlantic- Gulf | West | NGL & Petchem Services | Eliminations | Total | ||||||||||||||||||
(Millions) | |||||||||||||||||||||||
2013 | |||||||||||||||||||||||
Segment revenues: | |||||||||||||||||||||||
Service revenues | |||||||||||||||||||||||
External | $ | 335 | $ | 1,414 | $ | 1,053 | $ | 112 | $ | — | $ | 2,914 | |||||||||||
Internal | — | 10 | 1 | — | (11 | ) | — | ||||||||||||||||
Total service revenues | 335 | 1,424 | 1,054 | 112 | (11 | ) | 2,914 | ||||||||||||||||
Product sales | |||||||||||||||||||||||
External | 166 | 830 | 64 | 2,861 | — | 3,921 | |||||||||||||||||
Internal | — | 95 | 708 | 294 | (1,097 | ) | — | ||||||||||||||||
Total product sales | 166 | 925 | 772 | 3,155 | (1,097 | ) | 3,921 | ||||||||||||||||
Total revenues | $ | 501 | $ | 2,349 | $ | 1,826 | $ | 3,267 | $ | (1,108 | ) | $ | 6,835 | ||||||||||
Segment profit (loss) | $ | (24 | ) | $ | 614 | $ | 741 | $ | 346 | $ | 1,677 | ||||||||||||
Less: | |||||||||||||||||||||||
Equity earnings (losses) | (7 | ) | 72 | — | 39 | 104 | |||||||||||||||||
Income (loss) from investments | — | — | — | (3 | ) | (3 | ) | ||||||||||||||||
Segment operating income (loss) | $ | (17 | ) | $ | 542 | $ | 741 | $ | 310 | 1,576 | |||||||||||||
General corporate expenses | (169 | ) | |||||||||||||||||||||
Operating income | $ | 1,407 | |||||||||||||||||||||
Other financial information: | |||||||||||||||||||||||
Depreciation and amortization | $ | 132 | $ | 363 | $ | 236 | $ | 60 | $ | — | $ | 791 | |||||||||||
2012 | |||||||||||||||||||||||
Segment revenues: | |||||||||||||||||||||||
Service revenues | |||||||||||||||||||||||
External | $ | 168 | $ | 1,371 | $ | 1,067 | $ | 108 | $ | — | $ | 2,714 | |||||||||||
Internal | — | 12 | 5 | — | (17 | ) | — | ||||||||||||||||
Total service revenues | 168 | 1,383 | 1,072 | 108 | (17 | ) | 2,714 | ||||||||||||||||
Product sales | |||||||||||||||||||||||
External | 2 | 709 | 40 | 4,006 | — | 4,757 | |||||||||||||||||
Internal | — | 363 | 1,089 | 258 | (1,710 | ) | — | ||||||||||||||||
Total product sales | 2 | 1,072 | 1,129 | 4,264 | (1,710 | ) | 4,757 | ||||||||||||||||
Total revenues | $ | 170 | $ | 2,455 | $ | 2,201 | $ | 4,372 | $ | (1,727 | ) | $ | 7,471 | ||||||||||
Segment profit (loss) | $ | (37 | ) | $ | 574 | $ | 980 | $ | 390 | $ | 1,907 | ||||||||||||
Less: | |||||||||||||||||||||||
Equity earnings (losses) | (23 | ) | 92 | — | 42 | 111 | |||||||||||||||||
Income (loss) from investments | — | — | — | (4 | ) | (4 | ) | ||||||||||||||||
Segment operating income (loss) | $ | (14 | ) | $ | 482 | $ | 980 | $ | 352 | 1,800 | |||||||||||||
General corporate expenses | (190 | ) | |||||||||||||||||||||
Operating income | $ | 1,610 | |||||||||||||||||||||
Other financial information: | |||||||||||||||||||||||
Depreciation and amortization | $ | 76 | $ | 381 | $ | 234 | $ | 43 | $ | — | $ | 734 | |||||||||||
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Williams Partners L. P. | ||
Notes to Consolidated Financial Statements – (Continued) | ||
Northeast G&P | Atlantic- Gulf | West | NGL & Petchem Services | Eliminations | Total | ||||||||||||||||||
(Millions) | |||||||||||||||||||||||
2011 | |||||||||||||||||||||||
Segment revenues: | |||||||||||||||||||||||
Service revenues | |||||||||||||||||||||||
External | $ | 49 | $ | 1,332 | $ | 1,053 | $ | 84 | $ | — | $ | 2,518 | |||||||||||
Internal | — | — | 4 | — | (4 | ) | — | ||||||||||||||||
Total service revenues | 49 | 1,332 | 1,057 | 84 | (4 | ) | 2,518 | ||||||||||||||||
Product sales | |||||||||||||||||||||||
External | — | 606 | 11 | 4,781 | — | 5,398 | |||||||||||||||||
Internal | — | 531 | 1,622 | 56 | (2,209 | ) | — | ||||||||||||||||
Total product sales | — | 1,137 | 1,633 | 4,837 | (2,209 | ) | 5,398 | ||||||||||||||||
Total revenues | $ | 49 | $ | 2,469 | $ | 2,690 | $ | 4,921 | $ | (2,213 | ) | $ | 7,916 | ||||||||||
Segment profit (loss) | $ | 23 | $ | 585 | $ | 1,181 | $ | 385 | $ | 2,174 | |||||||||||||
Less: | |||||||||||||||||||||||
Equity earnings (losses) | (1 | ) | 90 | — | 53 | 142 | |||||||||||||||||
Income (loss) from investments | — | — | — | (4 | ) | (4 | ) | ||||||||||||||||
Segment operating income (loss) | $ | 24 | $ | 495 | $ | 1,181 | $ | 336 | 2,036 | ||||||||||||||
General corporate expenses | (122 | ) | |||||||||||||||||||||
Operating income | $ | 1,914 | |||||||||||||||||||||
Other financial information: | |||||||||||||||||||||||
Depreciation and amortization | $ | 5 | $ | 365 | $ | 236 | $ | 31 | $ | — | $ | 637 | |||||||||||
The following table reflects Total assets, Investments, and Additions to long-lived assets by reportable segment:
Total Assets at December 31, | Investments at December 31, | Additions to Long-Lived Assets at December 31, | |||||||||||||||||||||||||
2013 | 2012 | 2013 | 2012 | 2013 | 2012 | 2011 | |||||||||||||||||||||
(Millions) | |||||||||||||||||||||||||||
Northeast G&P (1) | $ | 6,229 | $ | 4,745 | $ | 737 | $ | 511 | $ | 1,376 | $ | 3,909 | $ | 204 | |||||||||||||
Atlantic-Gulf | 10,007 | 8,734 | 930 | 774 | 1,072 | 1,002 | 650 | ||||||||||||||||||||
West | 4,767 | 4,688 | — | — | 210 | 360 | 301 | ||||||||||||||||||||
NGL & Petchem Services | 3,035 | 2,469 | 520 | 515 | 746 | 571 | 314 | ||||||||||||||||||||
Other corporate assets | 147 | 409 | — | — | 5 | 16 | 25 | ||||||||||||||||||||
Eliminations (2) | (614 | ) | (367 | ) | — | — | — | — | — | ||||||||||||||||||
Total | $ | 23,571 | $ | 20,678 | $ | 2,187 | $ | 1,800 | $ | 3,409 | $ | 5,858 | $ | 1,494 | |||||||||||||
(1) | 2012 Additions to long-lived assets includes the Caiman and Laser Acquisitions. (See Note 2 – Acquisitions, Goodwill, and Other Intangible Assets.) |
(2) | Eliminations primarily relate to the intercompany accounts receivable generated by our cash management program. |
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Williams Partners L. P. | ||
Notes to Consolidated Financial Statements – (Continued) | ||
Note 17 – Subsequent Events
In March 2014 we 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 our commercial paper program, to fund capital expenditures, and for general partnership purposes.
As of May 19, 2014, $370 million is outstanding under our commercial paper program.
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Williams Partners L.P.
Quarterly Financial Data
(Unaudited)
Summarized quarterly financial data are as follows:
First Quarter | Second Quarter | Third Quarter | Fourth Quarter | |||||||||||||
(Millions, except per-unit amounts) | ||||||||||||||||
2013 | ||||||||||||||||
Revenues | $ | 1,806 | $ | 1,763 | $ | 1,618 | $ | 1,648 | ||||||||
Product costs | 790 | 801 | 710 | 726 | ||||||||||||
Net income | 344 | 272 | 285 | 218 | ||||||||||||
Net income attributable to controlling interests | 344 | 271 | 284 | 217 | ||||||||||||
Basic and diluted net income per common unit | 0.50 | 0.31 | 0.52 | 0.12 | ||||||||||||
2012 | ||||||||||||||||
Revenues | $ | 2,015 | $ | 1,843 | $ | 1,747 | $ | 1,866 | ||||||||
Product costs | 962 | 900 | 771 | 868 | ||||||||||||
Net income | 435 | 251 | 300 | 305 | ||||||||||||
Net income attributable to controlling interests | 435 | 251 | 300 | 305 | ||||||||||||
Basic and diluted net income per common unit | 0.85 | 0.29 | 0.38 | 0.42 | ||||||||||||
The sum of earnings per unit for the four quarters may not equal the total earnings per unit for the year due to changes in the average number of common units outstanding and rounding.
2013
Net income for fourth-quarter 2013 includes:
• | $16 million accrued loss associated with a settlement in principle of a producer claim against us at Northeast G&P (see Note 7 – Other Income and Expenses); |
• | $14 million in expenses associated with the Geismar Incident at NGL & Petchem Services (see Note 7 – Other Income and Expenses). |
Net income for third-quarter 2013 includes:
• | $9 million accrued loss associated with a contingent liability related to a producer claim against us at Northeast G&P (see Note 7 – Other Income and Expenses); |
• | $50 million of income associated with insurance recoveries related to the Geismar Incident at NGL & Petchem Services (see Note 7 – Other Income and Expenses). |
Net income for second-quarter 2013 includes $12 million of income related to an insurance recovery associated with the Eminence abandonment regulatory asset that will not be recovered through rates at Atlantic-Gulf. (See Note 7 – Other Income and Expenses.)
2012
Net income for fourth-quarter 2012 includes:
• | $18 million related to the reversal of project feasibility costs from expense to capital at Atlantic-Gulf (see Note 7 – Other Income and Expenses); |
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Williams Partners L.P.
Quarterly Financial Data – (Continued)
(Unaudited)
• | $11 million of reorganization-related costs, including consulting costs, allocated to us from Williams (see Note 5 – Related Party Transactions). |
Net income for second-quarter 2012 includes $21 million of Caiman and Laser acquisition and transition-related costs at Northeast G&P. (See Note 2 – Acquisitions, Goodwill, and Other Intangible Assets.)
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