Exhibit 99.1
Item 6. Selected Financial Data
The following financial data at December 31, 2012 and 2011 and for each of the three years in the period ended December 31, 2012, 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. Certain amounts have been recast as a result of the Geismar Acquisition. (See Note 1 of Notes to Consolidated Financial Statements.)
| 2012 | 2011 | 2010 | 2009 | 2008 | ||||||||||||||||
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(Millions, except per-unit amounts)
|
||||||||||||||||||||
| Revenues |
$ | 7,320 | $ | 7,714 | $ | 6,459 | $ | 5,149 | $ | 6,703 | ||||||||||
| Net income |
1,232 | 1,511 | 1,188 | 1,063 | 2,103 | |||||||||||||||
| Net income attributable to controlling interests |
1,232 | 1,511 | 1,172 | 1,036 | 2,078 | |||||||||||||||
| Net income per common unit (1) |
1.89 | 3.69 | 2.66 | 2.88 | 3.08 | |||||||||||||||
| Total assets at December 31 (1) |
19,709 | 14,672 | 13,666 | 12,732 | 12,437 | |||||||||||||||
| Short-term notes payable and long-term debt due within one year at December 31 |
- | 324 | 458 | 15 | - | |||||||||||||||
| Long-term debt at December 31 (1)(2) |
8,437 | 6,913 | 6,365 | 2,981 | 2,971 | |||||||||||||||
| Total equity at December 31 (1) |
8,897 | 5,433 | 5,248 | 8,287 | 8,096 | |||||||||||||||
| Cash distributions declared per unit |
3.140 | 2.900 | 2.653 | 2.540 | 2.435 | |||||||||||||||
| (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. |
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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, natural gas liquids (NGLs), and olefins through our gas pipeline and midstream businesses.
Our 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 Federal Energy Regulatory Commission (FERC) and as such, our rates and charges for the transportation of natural gas in interstate commerce, and the extension, expansion or abandonment of jurisdictional facilities and accounting, among other things, are subject to regulation. The rates are established through the FERC’s ratemaking process. Changes in commodity prices and volumes transported have little near-term impact on revenues because the majority of cost of service is recovered through firm capacity reservation charges in transportation rates.
The ongoing strategy of our midstream business 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 production handling and transportation, olefin production, marketing services for NGL, oil and natural gas, as well as storage facilities.
We manage these businesses and analyze our results of operations on a segment basis. Our operations are divided into four business segments: Northeast G&P, Atlantic-Gulf, West, and NGL & Petchem Services.
| • | Northeast G&P is comprised of our midstream gathering and processing business 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. |
| • | 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 60 percent equity investment in Discovery Producer Services LLC (Discovery), and a 51 percent consolidated interest in Constitution Pipeline Company, LLC (Constitution). |
| • | West is comprised of our gathering, processing, and treating operations in New Mexico, Colorado, and Wyoming and our interstate natural gas pipeline, Northwest Pipeline GP (Northwest Pipeline). |
| • | NGL & Petchem Services is comprised of our NGL and natural gas marketing business, and an NGL fractionator and storage facilities near Conway, Kansas, a 50 percent equity investment in Overland Pass Pipeline (OPPL), and an interest in an olefins production facility in Geismar, Louisiana along with a refinery grade propylene splitter and pipelines in the Gulf Coast region. Our interest in an olefins production facility in Geismar, Louisiana and associated assets is a result of a fourth-quarter 2012 acquisition from a subsidiary of The Williams Companies, Inc. (Williams) (the Geismar Acquisition). |
Williams currently holds an approximate 70 percent interest in us, comprised of an approximate 68 percent limited partner interest and all of our 2 percent general partner interest.
Acquisitions
Laser Acquisition
In February 2012, we completed the acquisition of 100 percent of the ownership interests in certain entities from Delphi Midstream Partners, LLC (Laser Acquisition). These entities primarily own the Laser Gathering System, which is comprised of 33 miles of 16-inch natural gas pipeline and associated gathering facilities in the
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Marcellus Shale in Susquehanna County, Pennsylvania, as well as 10 miles of gathering lines in southern New York. This acquisition represents a strategic platform to enhance our expansion in the Marcellus Shale by providing our Northeast G&P customers with both operational flow assurance and marketing flexibility.
Caiman Acquisition
In April 2012, we completed the acquisition of 100 percent of the ownership interest in Caiman Eastern Midstream, LLC (Caiman Acquisition) for consideration valued at approximately $2.3 billion. The transition of operations is complete.
The acquisition provides our Northeast G&P segment with a significant footprint and growth potential in the natural gas liquids-rich Ohio River Valley area of the Marcellus Shale. The existing physical assets that we acquired include a gathering system, two processing facilities and a fractionator located in northern West Virginia and establish our new Ohio Valley Midstream business. In addition to the acquisition cost, we committed a large portion of our 2012 capital expenditures and continue to commit planned capital expenditures in 2013 and beyond for ongoing expansions to the gathering system, processing facilities, and fractionator, which are currently under construction. NGL pipelines are also planned. The assets are anchored by long-term contracted commitments, including 236,000 dedicated gathering acres from 10 producers in West Virginia, Ohio, and Pennsylvania.
Geismar Acquisition
In November 2012, we purchased Williams’ 83.3 percent undivided interest and operatorship of the olefins production facility in Geismar, Louisiana, along with a refinery grade propylene splitter and pipelines in the Gulf region. The acquisition is expected to bring more certainty to cash flows that are currently exposed to volatile ethane prices by shifting the commodity price exposure to ethylene. Located south of Baton Rouge, Louisiana and part of our NGL & Petchem Services segment, the Geismar facility is a light-end NGL cracker with current feedstock volumes of 39,000 barrels per day (bpd) of ethane and 3,000 bpd of propane and annual production of 1.35 billion pounds of ethylene. With the benefit of a $350-$400 million expansion under way and scheduled for completion by late 2013, the facility’s annual ethylene production capacity will grow by 600 million pounds to 1.95 billion pounds. Along with ethane, propane and ethylene, the Geismar facility also produces propylene, butadiene, and debutanized aromatic concentrate (DAC). Prior periods have been recast for this transaction.
Distributions
In January 2013, our general partner’s Board of Directors approved a quarterly distribution to unitholders of $0.8275 per unit, an increase of approximately 2.5 percent over the prior quarter and 8.5 percent over the same period in the prior year. (See Management’s Discussion and Analysis of Financial Condition and Liquidity.)
Overview of 2012
During the second quarter 2012, NGL margins declined sharply largely attributable to a record-warm winter, a slowing global economy, and growing NGL supplies. The downward trend of per-unit NGL margins leveled-off during the second-half of 2012. We have been impacted by this environment as our net income for 2012 decreased by $279 million compared to 2011, primarily due to lower NGL production and marketing margins, higher operating costs and selling, general, and administrative expenses (SG&A), partially offset by an increase in fee revenues and olefin production margins. See additional discussion in Results of Operations.
Our net cash provided by operating activities for 2012 decreased $272 million compared to 2011 primarily due to lower operating income.
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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, as highlighted by the previously discussed acquisitions, as well as the following accomplishments during 2012 through the present:
Northeast G&P
Susquehanna Supply Hub, northeastern Pennsylvania
In February 2012, we completed the Laser Acquisition for $325 million in cash, net of cash acquired in the transaction and subject to certain closing adjustments, and 7,531,381 of our common units valued at $441 million. The gathering system is comprised of 33 miles of 16-inch natural gas pipeline and associated gathering facilities in Susquehanna County, Pennsylvania, as well as 10 miles of gathering pipeline in southern New York. The acquisition is supported by existing long-term gathering agreements that provide acreage dedications and volume commitments.
Our Springville pipeline, a 33-mile, 24-inch diameter natural gas gathering pipeline, connecting a portion of our gathering assets into the Transco pipeline, was placed into service in January 2012, and expansions were completed in the third quarter of 2012 allowing us to deliver approximately 625 MMcf/d into the Transco pipeline. This new take-away capacity allows full use of approximately 1.6 billion cubic feet per day (Bcf/d) of capacity from various compression and dehydration expansion projects to our gathering business in northeastern Pennsylvania’s Marcellus Shale which we acquired at the end of 2010.
In February 2012, our Atlantic-Gulf segment announced a new interstate gas pipeline project. The new 120-mile Constitution Pipeline will connect our gathering system in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and Tennessee Gas Pipeline systems. We currently own 51 percent of Constitution Pipeline with two other parties holding 25 percent and 24 percent, respectively. This project, along with the newly acquired Laser Gathering System and our Springville pipeline, are key steps in our strategy to create the Susquehanna Supply Hub, a major natural gas supply hub in northeastern Pennsylvania. In April 2012, we began the FERC pre-filing process for the Constitution Pipeline and expect to file a FERC application during the second quarter of 2013.
As production in the Marcellus increases and expansion projects are completed, the Susquehanna Supply Hub is expected to reach a natural gas take away capacity of 3 Bcf/d by 2015, including capacity contributions from the Constitution Pipeline.
Ohio Valley Midstream
Several projects were completed in the fourth quarter of 2012 increasing our gathering, processing and fractionating capacities. The Fort Beeler plant complex has 320 million cubic feet per day (MMcf/d) of cryogenic processing capacity currently available with another 200 MMcf/d expected during the first quarter of 2013. The Moundsville fractionator is now in service with approximately 13 thousand barrels per day (Mbbls/d) of NGL handling capacity. An NGL pipeline, connecting the Fort Beeler plant to the Moundsville fractionator has also been completed and is in service.
Utica Shale infrastructure project
In July 2012, we formed Caiman Energy II, LLC with Caiman Energy, LLC and others to develop large-scale natural gas gathering and processing and the associated liquids infrastructure serving oil and gas producers in the Utica shale, primarily in Ohio and northwest Pennsylvania. As a result, through our 47.5 percent ownership, we plan to contribute $380 million through 2014 to fund a portion of Blue Racer Midstream, a joint project formed in December 2012 between Caiman Energy II, LLC and another party.
Atlantic-Gulf
In January 2013, we agreed to sell a 49 percent ownership interest in our Gulfstar FPS™ project to a third party. The transaction is expected to close in second-quarter 2013, at which time we expect the third party will contribute $225 million to fund its proportionate share of the project costs, following with monthly capital contributions to fund its share of ongoing construction.
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NGL & Petchem Services
In the fourth quarter of 2012, we completed the construction of a pipeline which is capable of supplying 12 Mbbls/d of ethane to our Geismar olefins production facility from Discovery’s Paradis fractionator.
Volume impacts in 2012
Due to third-party NGL pipeline capacity restrictions from our Four Corners plants beginning in late September and to unfavorable ethane economics in December, we reduced our recoveries of ethane in our onshore plants, which resulted in 7 percent lower NGL equity sales volumes in the fourth quarter of 2012 compared to the third quarter of 2012.
Our NGL equity sales volumes for the third quarter of 2012 were modestly impacted by maintenance on the Overland Pass Pipeline for approximately 5 days. As a result of the NGL pipeline maintenance, NGL takeaway capacity from our western plants on the Overland Pass Pipeline was reduced, which forced our western plants to reduce NGL recoveries.
In the Gulf Coast, our Mobile Bay plant was shut down for 10 days due to Hurricane Isaac. The plant and offshore platforms were evacuated during the storm. Afterwards, the plant remained shut down due to flooding issues on a third-party pipeline limiting the NGL takeaway capacity. In addition, production into Devils Tower was shut-in for various time periods due to third-party hurricane related issues. These events related to Hurricane Isaac did not have a material impact to our overall NGL production or NGL equity sales.
Volatile commodity prices
Driven primarily by a sharp decline in NGL prices during the second quarter of 2012, followed by increasing natural gas prices in the latter half of 2012, average per-unit NGL margins declined during 2012 and were approximately 23 percent lower in 2012 than in 2011. Because we typically realize lower per-unit margins for ethane versus other NGLs, if we had produced the same mix of ethane and non-ethane NGLs during the fourth quarter of 2012 as we generally have in prior periods, the average per-unit margin in the fourth quarter of 2012 would have been lower. Key factors in the NGL market weakness have been high propane inventories caused by the extremely warm winter and the effect of the propane oversupply on ethane inventories and pricing. Despite an increase in natural gas prices during the latter half of 2012, we have benefited from lower natural gas prices in 2012 than in 2011, driven by abundant natural gas supplies.
NGL margins are defined as NGL revenues less any applicable British thermal unit (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.
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Other activities
Following Williams’ spin-off of WPX Energy, Inc. (WPX) at the end of 2011 and in consideration of the growth plans of the ongoing business, Williams initiated an organizational restructuring evaluation to better align resources to support an ongoing business strategy 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. This effort has resulted in changes in our organizational structure effective January 1, 2013 and, thus, how our underlying businesses will be managed. As a result, our segment reporting structure will change beginning in 2013.
In August 2012, we completed an equity issuance of 8,500,000 common units representing limited partner interests in us at a price of $51.43 per unit. Subsequently, we sold an additional 1,275,000 common units for $51.43 per unit to the underwriters upon the underwriters’ exercise of their option to purchase additional common units. The net proceeds of these transactions were primarily used to repay outstanding borrowings on our senior unsecured revolving credit facility (revolver).
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 revolver 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. A portion of these proceeds was used to repay Transco’s $325 million 8.875 percent senior unsecured notes that matured on July 15, 2012. 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.
In April 2012, we completed an equity issuance of 10 million common units representing limited partner interests in us at a price of $54.56 per unit. Subsequently, we sold an additional 973,368 common units for $54.56 per unit to the underwriters upon the underwriters’ exercise of their option to purchase additional common units.
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Also in April 2012, we sold 16,360,133 common units to Williams for $1 billion. The net proceeds of these transactions were used for general partnership purposes, including funding a portion of the cash purchase price of the Caiman Acquisition.
Outlook for 2013
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 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.
In light of the above, our business plan for 2013 continues to reflect both significant capital investment and growth in distributions. Our planned capital investments for 2013 total approximately $3.75 billion, of which we expect to fund a significant portion through debt and equity issuances. 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; |
| • | Availability of capital; |
| • | Lower than expected levels of cash flow from operations; |
| • | Counterparty credit and performance risk; |
| • | Decreased volumes from third parties served by our midstream business; |
| • | Unexpected significant increases in capital expenditures or delays in capital project execution; |
| • | Lower than anticipated energy commodity prices and margins; |
| • | Changes in the political and regulatory environments; |
| • | Physical damages to facilities, especially damage to offshore facilities by named windstorms. |
We continue to address these risks through maintaining a strong financial position and ample liquidity, as well as managing a diversified portfolio of energy infrastructure assets.
The following factors, among others, could impact our businesses in 2013.
Commodity price changes
| • | We expect a decline in ethane and propane prices and an increase in natural gas prices such that our full year 2013 NGL margins are expected to be lower than our rolling five-year average and 2012 per-unit NGL margins. NGL price changes have historically tracked somewhat with changes in the price of crude oil, although NGL, crude, and natural gas prices are highly volatile, difficult to predict, and are often not highly correlated. NGL margins are highly dependent upon continued demand within the global economy. However, NGL products are currently the preferred feedstock for ethylene and propylene production, which has been shifting away from the more expensive crude-based feedstocks. |
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| • | While per-unit ethylene margins are volatile and highly dependent upon continued demand within the global economy, we believe that our average per-unit ethylene margins will improve over 2012 levels, benefiting from higher ethylene prices and lower ethane and propane feedstock prices. Bolstered by abundant long-term domestic natural gas supplies, we expect to benefit from these dynamics in the broader global petrochemical markets because of our NGL-based olefins production. |
Gathering, processing, and NGL sales volumes
| • | The growth of natural gas supplies supporting our gathering and processing volumes are impacted by producer drilling activities, which are influenced by natural gas prices. |
| • | We anticipate significant growth in our natural gas gathering volumes in our Northeast G&P segment as our infrastructure grows to support drilling activities in the Marcellus Shale region. |
| • | We anticipate equity NGL volumes in 2013 to be lower than 2012 due in part to a change in a customer’s contract in the West segment from percent-of-liquids to fee-based processing, with a portion of the fee representing a share of the associated NGL margins. We also expect lower equity NGL volumes due to periods when we expect it will not be economical to recover ethane. Our expectations of sustained low natural gas prices are expected to discourage producer drilling activities in the West segment and unfavorably impact the supply of natural gas available to gather and process in 2013. |
| • | In our Atlantic-Gulf segment, we expect lower production handling and crude transportation volumes compared to 2012, as production flowing through our Devils Tower facility declines. |
| • | We anticipate higher general and administrative, operating, and depreciation expense supporting our growing operations in the Northeast G&P segment. |
Olefin production volumes
| • | We expect lower ethylene volumes in 2013 as compared to 2012 primarily due to major maintenance planned for 2013. With the completion of our Geismar expansion in the latter part of 2013, as discussed below, we expect growth in production volumes in the fourth quarter of 2013. |
Filing of rate cases
On August 31, 2012, Transco filed a general rate case with the FERC for an overall increase in rates. In September 2012, with the exception of certain rates that reflected a rate decrease, the FERC accepted and suspended our general rate filing to be effective March 1, 2013, subject to refund and the outcome of a hearing. We expect that our new rates, although still subject to refund until the rate case is resolved, will contribute to a modest increase in revenue in 2013. The specific rates that reflected a rate decrease were accepted, without suspension, to be effective October 1, 2012 and will not be subject to refund. The impact of these specific new rates that became effective October 1, 2012 is expected to reduce revenues by approximately $2 million for the period from January 1, 2013 until the remaining rates that are currently suspended become effective on March 1, 2013.
During the first quarter of 2012, Northwest Pipeline filed a Stipulation and Settlement Agreement with the FERC for an increase in their rates. Northwest Pipeline received FERC approval during the second quarter of 2012. The new rates, which as filed are 7.4 percent higher than the formerly applicable rates, became effective January 1, 2013.
Expansion Projects
We expect to invest total capital in 2013 among our business segments as follows:
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| Expansion Capital |
||||||
| Segment: | (Millions) | |||||
| Northeast G&P |
$ | 1,555 | ||||
| Atlantic-Gulf |
$ | 1,195 | ||||
| West |
$ | 250 | ||||
| NGL & Petchem Services |
$ | 400 | ||||
Our ongoing major expansion projects include the following:
Northeast G&P
| • | Expansion of our Susquehanna Supply Hub in northeastern Pennsylvania, as previously discussed. |
| • | Expansions currently under construction 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 is expected to add 200 MMcf/d of processing capacity in the first quarter of 2013. By the end of 2013, we expect our first turbo-expander at our Oak Grove facility to add 200 MMcf/d of processing capacity and additional fractionation capacity at our Moundsville fractionators bringing the NGL handling capacity to approximately 43 Mbbls/d. |
| • | Expansions to our gathering system infrastructure through capital to be invested within our Laurel Mountain equity investment, also in the Marcellus Shale region. |
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. We expect Gulfstar FPS™ to be capable of serving as a central host facility for other deepwater prospects in the area. Construction is underway and the project is expected to be in service in 2014. In January 2013, we agreed to sell a 49 percent ownership interest in our Gulfstar FPS™ project to a third party. The transaction is expected to close in second-quarter 2013, at which time we expect the third party will contribute $225 million to fund its proportionate share of the project costs, following with monthly capital contributions to fund its share of ongoing construction. |
| • | Our equity investee which we operate, Discovery, plans to construct, own, and operate a new 215-mile, 20-inch deepwater lateral pipeline from a third-party floating production facility located in the Keathley Canyon production area in the central deepwater Gulf of Mexico. 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 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. Pre-construction activities have begun; the pipeline is expected to be laid in 2013 and in service in mid-2014. |
| • | In January 2013, we filed an application with the FERC for our Rockaway Delivery Lateral project to construct a three-mile offshore lateral to a distribution system in New York. The capital cost of the project is estimated to be approximately $180 million. We plan to place the project into service during the second half of 2014, with an expected capacity of 647 Mdth/d. |
| • | In December 2012, we filed an application with the FERC for our 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. The capital cost of the project is estimated to be approximately |
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| $300 million. We plan to place the project into service in September 2015, which is expected to increase capacity by 270 Mdth/d. |
| • | In November 2012, we received approval from the FERC for our Northeast Supply Link project to expand our 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 cost of the project is estimated to be $390 million and is expected to increase capacity by 250 Mdth/d. We plan to place the project into service in November 2013. |
| • | In April 2012, we began the FERC pre-filing process for a new interstate gas pipeline project for our Constitution Pipeline. We currently own 51 percent of Constitution Pipeline with two other parties holding 25 percent and 24 percent, respectively. We will be the operator of Constitution Pipeline. The new 120-mile Constitution Pipeline will connect our gathering system in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and Tennessee Gas Pipeline systems. The total cost of the entire project is estimated to be $680 million. We plan to place the project into service in March 2015, with an expected capacity of 650 Mdth/d. The pipeline is fully subscribed with two shippers. We expect to file a FERC application during the second quarter of 2013. |
| • | In August 2011, we received approval from the FERC for our Mid-South project to upgrade compressor facilities and expand our existing natural gas transmission system from Alabama to markets as far north as North Carolina. The cost of the project is estimated to be $200 million. We placed the first phase of the project into service in September 2012, which increased capacity by 95 Mdth/d. We plan to place the second phase of the project into service in June 2013, which is expected to increase capacity by an additional 130 Mdth/d. |
| • | In July 2011, we received approval from the FERC for our Mid-Atlantic Connector project to expand our existing natural gas transmission system from North Carolina to markets as far downstream as Maryland. The capital cost of the project was approximately $60 million. The project was placed into service in the first quarter of 2013, increasing capacity by 142 Mdth/d. |
West
| • | In conjunction with a basin-wide agreement for all gathering and processing services provided by us to WPX in the Piceance basin, we plan to construct a 350 MMcf/d cryogenic natural gas processing plant. The Parachute TXP I plant is expected to be in service in 2014. |
NGL & Petchem Services
| • | An expansion of our Geismar olefins production facility is under way which 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 share of the Geismar production facility to over 88 percent. We expect to complete the expansion in the latter part of 2013. |
| • | Through our equity investment in OPPL, we are participating in the construction of a pipeline connection and capacity expansions, expected to be complete in early 2013, to increase the pipeline’s capacity to the maximum of 255 Mbbls/d, to accommodate new volumes coming from the Bakken Shale in the Williston basin. |
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.
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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 total abandonment costs, which will be capital in nature, will be approximately $92 million, which is expected to be spent through the end of 2013. As of December 31, 2012, we have incurred approximately $69 million in cumulative abandonment costs. This estimate is subject to change as work progresses and additional information becomes known. Management considers these costs to be prudent costs incurred in the abandonment of these caverns and expects to recover these costs, net of insurance proceeds, in future rate filings. To the extent available, the abandonment costs will be funded from the ARO Trust. (See Note 13 of Notes to Consolidated Financial Statements.)
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 and Intangible Assets
At December 31, 2012, our Consolidated Balance Sheet includes $649 million of goodwill and $1.7 billion in intangible assets related to the Laser and Caiman Acquisitions, which were completed earlier in the year.
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, including goodwill, and thus no impairment was recognized. If the carrying value of the reporting unit had exceeded its fair value, a computation of the implied fair value of the goodwill would have been compared with its related carrying value. If the carrying value of the reporting unit goodwill had exceeded the implied fair value of that goodwill, an impairment loss would have been recognized in the amount of the excess.
The fair value of the reporting unit was estimated using an income approach (discounted cash flows). Significant estimates and assumptions in this determination included our estimate of the expected future cash flows associated with the underlying operations. These assumptions include projections of future production volumes and timing, certain energy commodity prices, capital expenditures and recovery provisions, gathering fees, and operating expenses.
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 11.25 percent. We estimate that an increase of approximately 250 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.
Other intangible assets
We evaluate other intangible assets for both changes in the expected remaining useful lives and impairment when events or changes in circumstances indicate, in our management’s judgment, that the estimated useful lives have changed or the carrying value of such assets may not be recoverable. Changes in an estimated remaining useful life would be reflected prospectively through amortization over the revised remaining useful life. When an indicator of impairment has occurred, we compare our management’s estimate of undiscounted future cash flows attributable to the intangible assets to the carrying value of the assets to determine whether an impairment has occurred and we
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apply a probability-weighted approach to consider the likelihood of different cash flow assumptions and possible outcomes. 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. Indicators of potential impairment may include:
| • | Laws prohibiting the production of reserves in the areas where our assets from the Laser and Caiman Acquisitions operate; |
| • | The development of alternative energy sources that would halt the production of reserves in these areas; or |
| • | The loss of or failure to renew customer contracts. A significant portion of the value allocated to these contracts in our purchase price allocation was based on our assumptions regarding our ability and intent to renew or renegotiate existing customer contracts. (See Note 2 of Notes to Consolidated Financial Statements.) |
We have not evaluated our intangible assets for impairment as of December 31, 2012, as there were no indicators of potential impairment.
Equity-method Investments
At December 31, 2012, our Consolidated Balance Sheet includes approximately $1.8 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, 2012.
12
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, 2012. The results of operations by segment are discussed in further detail following this consolidated overview discussion.
| Years Ended December 31, | ||||||||||||||||||||||||||||
|
$ Change |
% Change |
$ Change |
% Change |
|||||||||||||||||||||||||
|
from |
from |
from |
from |
|||||||||||||||||||||||||
|
2012 |
2011* |
2011* |
2011 |
2010* |
2010* |
2010 |
||||||||||||||||||||||
| (Millions)
|
||||||||||||||||||||||||||||
| Revenues: |
||||||||||||||||||||||||||||
| Service revenues |
$ | 2,709 | +192 | +8% | $ | 2,517 | +171 | +7% | $ | 2,346 | ||||||||||||||||||
| Product sales |
4,611 | -586 | -11% | 5,197 | +1,084 | +26% | 4,113 | |||||||||||||||||||||
|
|
|
|
|
|
|
|||||||||||||||||||||||
| Total revenues |
7,320 | 7,714 | 6,459 | |||||||||||||||||||||||||
|
|
|
|
|
|
|
|||||||||||||||||||||||
| Costs and expenses: |
||||||||||||||||||||||||||||
| Product costs |
3,526 | +425 | +11% | 3,951 | -728 | -23% | 3,223 | |||||||||||||||||||||
| Operating and maintenance expenses |
987 | -39 | -4% | 948 | -111 | -13% | 837 | |||||||||||||||||||||
| Depreciation and amortization expenses |
714 | -93 | -15% | 621 | -43 | -7% | 578 | |||||||||||||||||||||
| Selling, general, and administrative expenses |
553 | -147 | -36% | 406 | +2 | - | 408 | |||||||||||||||||||||
| Other (income) expense – net |
23 | -10 | -77% | 13 | -27 | NM | (14) | |||||||||||||||||||||
|
|
|
|
|
|
|
|||||||||||||||||||||||
| Total costs and expenses |
5,803 | 5,939 | 5,032 | |||||||||||||||||||||||||
|
|
|
|
|
|
|
|||||||||||||||||||||||
| Operating income |
1,517 | 1,775 | 1,427 | |||||||||||||||||||||||||
| Equity earnings (losses) |
111 | -31 | -22% | 142 | +33 | +30% | 109 | |||||||||||||||||||||
| Interest expense |
(405) | +10 | +2% | (415) | -51 | -14% | (364) | |||||||||||||||||||||
| Interest income |
3 | +1 | +50% | 2 | -2 | -50% | 4 | |||||||||||||||||||||
| Other income (expense) – net |
6 | -1 | -14% | 7 | -5 | -42% | 12 | |||||||||||||||||||||
|
|
|
|
|
|
|
|||||||||||||||||||||||
| Net income |
1,232 | 1,511 | 1,188 | |||||||||||||||||||||||||
| Less: Net income attributable to noncontrolling interests |
- | - | - | - | +16 | +100% | 16 | |||||||||||||||||||||
|
|
|
|
|
|
|
|||||||||||||||||||||||
| Net income attributable to controlling interests |
$ | 1,232 | $ | 1,511 | $ | 1,172 | ||||||||||||||||||||||
|
|
|
|
|
|
|
|||||||||||||||||||||||
* + = 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.
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 on our recently acquired gathering and processing assets in our Ohio Valley Midstream and Susquehanna Supply Hub businesses 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 volumes, as well as new volumes from natural gas marketing activities.
13
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 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 new 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 new gathering and processing assets acquired in 2012 (see Note 2 of Notes to Consolidated Financial Statements).
The increase in SG&A is primarily due to an increase of $71 million relating to our midstream business reflecting $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 business operations. Also, general corporate expenses increased $66 million in 2012 related to our higher proportionate share of these costs as a result of Williams’ spin-off of WPX, which was completed on December 31, 2011. This increase in general corporate expenses includes $25 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.
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 Midstream, LLC (Laurel Mountain), Aux Sable Liquid Products L.P. (Aux Sable) and Discovery Producer Services LLC (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 an increase in interest capitalized related primarily to gathering and processing construction projects, partially offset by an increase in interest incurred related to increased borrowings (see Note 11 of Notes to Consolidated Financial Statements).
2011 vs. 2010
The increase in service revenues is primarily due to higher gathering and processing fee revenue in the Marcellus Shale related to gathering assets acquired at the end of 2010, in the western deepwater Gulf of Mexico related to assets placed into service in late 2010, and in the Piceance basin as a result of an agreement executed in November 2010. These increases are partially offset by a decline in fee revenue in the eastern deepwater Gulf of Mexico primarily due to natural field declines. Natural gas pipeline transportation revenues increased primarily due to expansion projects placed in service in 2010 and 2011.
The increase in product sales is primarily due to higher marketing and NGL and olefin production revenues as a result of higher average energy commodity prices, partially offset by a decrease in NGL production volumes.
The increase in product costs is primarily due to increased marketing purchases and olefin feedstock costs primarily resulting from higher average energy commodity prices. These increases are partially offset by decreased costs associated with production of NGLs reflecting lower NGL production volumes and lower average natural gas prices.
14
The increase in operating and maintenance expenses is primarily due to increased maintenance expenses and higher property insurance expenses.
The increase in depreciation and amortization expenses is primarily due to assets placed in service late in 2010, along with increased depreciation of a gathering and processing facility, which was idled in 2012.
The unfavorable change in other (income) expense – net within operating income primarily reflects:
| • | $15 million of lower involuntary conversion gains in 2011 as compared to 2010 due to insurance recoveries that are in excess of the carrying value of assets; |
| • | The absence of a $12 million gain in 2010 on the sale of part of our ownership interest in certain Piceance gathering assets; |
| • | $4 million lower sales of base gas from Hester Storage Field in 2011 compared to 2010. |
Partially offsetting the unfavorable change is $8 million related to the net reversal of natural gas transportation project feasibility costs from expense to capital in 2011 (see Note 6 of Notes to Consolidated Financial Statements).
The increase in operating income generally reflects an improved energy commodity price environment in 2011 compared to 2010 and increased fee revenues, partially offset by higher operating costs and an unfavorable change in other (income) expense – net as previously discussed.
Equity earnings (losses) changed favorably primarily due to a $21 million increase from Gulfstream as a result of an increased ownership interest and a $14 million increase from the 2010 acquisition of an additional interest in Overland Pass Pipeline Company LLC (OPPL).
The increase in interest expense is primarily due to the $3.5 billion of senior notes issued in February 2010 and $600 million of senior notes issued in November 2010. In addition, 2010 gathering and processing construction project completions contributed to a decrease in interest capitalized.
Net income attributable to noncontrolling interests decreased due to the merger with Williams Pipeline Partners L.P., which was completed in the third quarter of 2010.
15
Year-Over-Year Operating Results — Segments
Northeast G&P
| Year ended December 31, | ||||||||||||
|
2012 |
2011 | 2010 | ||||||||||
|
(Millions)
|
||||||||||||
| Segment revenues |
$ | 170 | $ | 49 | $ | 2 | ||||||
|
|
|
|
|
|
|
|||||||
| Segment profit (loss) |
$ | (37) | $ | 23 | $ | - | ||||||
|
|
|
|
|
|
|
|||||||
2012 vs. 2011
The increase in segment revenues includes:
| • | 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. |
Segment costs and expenses increased $159 million including:
| • | A $71 million increase in depreciation and amortization of assets and intangibles generally associated with assets acquired in 2012; |
| • | A $42 million increase in other operating costs and expenses also generally associated with assets acquired in 2012; |
| • | 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. |
The unfavorable change in Northeast G&P segment profit (loss) is primarily due to the previously described changes and a $22 million decrease in equity earnings including $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.
2011 vs. 2010
The favorable change in Northeast G&P segment profit (loss) is primarily due to higher fee revenues from new volumes on our gathering assets in the Marcellus Shale in northeastern Pennsylvania, which we acquired at the end of 2010, partially offset by higher maintenance, depreciation and general and administrative expenses related to the acquired assets, and by a $5 million decrease in Laurel Mountain equity earnings.
Atlantic-Gulf
| Year ended December 31, | ||||||||||||
|
2012 |
2011 | 2010 | ||||||||||
|
(Millions)
|
||||||||||||
| Segment revenues |
$ | 2,455 | $ | 2,469 | $ | 2,222 | ||||||
|
|
|
|
|
|
|
|||||||
| Segment profit |
$ | 574 | $ | 585 | $ | 560 | ||||||
|
|
|
|
|
|
|
|||||||
16
2012 vs. 2011
The decrease in segment revenues includes:
| • | 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; |
| • | 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; |
| • | An $8 million increase in marketing revenues reflecting an increase of $73 million driven by higher crude 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. |
Segment costs and expenses decreased by $1 million reflecting the following substantially offsetting variances:
| • | A $44 million decrease in other product cost of goods sold due primarily to a $39 million decrease in system management gas costs (offset in segment revenues); |
| • | A $12 million decrease in costs associated with our equity NGLs primarily due to a 34 percent decrease in average natural gas prices; |
| • | A $20 million increase in other 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; |
| • | A $16 million increase in depreciation resulting from accelerated depreciation of our Canyon Chief gas gathering pipeline in the eastern deepwater Gulf of Mexico and additional Transco assets placed in service in 2011; |
| • | A $12 million increase in general and administrative expenses including increases in employee-related, information technology services and rental costs. |
The decrease in segment profit includes:
| • | A $48 million increase in depreciation, other operating costs and expenses and general and administrative expenses, as previously discussed; |
| • | A $13 million decrease in NGL margins driven primarily by commodity price changes including lower NGL prices, partially offset by lower natural gas prices; |
| • | A $51 million increase in fee revenues, as previously discussed; |
| • | A $2 million increase in equity earnings 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. |
2011 vs. 2010
The increase in segment revenues includes:
17
| • | A $210 million increase in marketing revenues primarily due to higher average NGL and crude prices and significantly higher NGL volumes, partially offset by lower crude volumes. The changes in marketing revenues are offset by similar changes in marketing purchases; |
| • | A $73 million increase in fee revenues primarily due to an increase in transportation revenues associated with expansion projects placed in service during 2010 and 2011 on our interstate natural gas pipeline and to new volumes on our Perdido Norte gas and oil pipelines in the western deepwater Gulf of Mexico, which went into service in late 2010, partially offset by a decline in gathering and transportation fees in the eastern deepwater Gulf of Mexico primarily due to natural field declines; |
| • | A $49 million decrease in revenues from our equity NGLs primarily reflecting a decrease of $81 million associated with a 39 percent decrease in NGL volumes primarily due to a change in a major contract from “keep-whole” to “percent-of-liquids” processing, partially offset by a $32 million increase associated with a 27 percent increase in average NGL per-unit sales prices. |
Segment costs and expenses increased by $239 million including:
| • | A $212 million increase in marketing purchases primarily due to higher average NGL and crude prices and significantly higher NGL volumes, partially offset by lower crude volumes. These changes are offset by similar changes in marketing revenues; |
| • | A $41 million increase in other operating costs and expenses including increased operations and maintenance expense related to the Eminence Storage Field leak and higher pipeline maintenance costs; |
| • | The absence of $20 million in gains recognized in 2010 including involuntary conversion gains due to insurance recoveries in excess of the carrying value of certain Gulf Coast assets which were damaged by Hurricane Ike in 2008 and a favorable contract settlement; |
| • | A $20 million increase in depreciation including additional depreciation expense on our new Perdido Norte pipelines which went into service in late 2010 and on assets placed in service in 2010 and 2011 on our interstate natural gas pipeline; |
| • | A $56 million decrease in costs associated with our equity NGLs reflecting a decrease of $49 million associated with a 39 percent decrease in NGL volumes primarily due to the previously discussed contract change and lower natural gas prices. |
The increase in segment profit includes:
| • | A $73 million increase in fee revenues, as previously discussed; |
| • | A $17 million increase in equity earnings primarily due to the acquisition of an additional interest in Gulfstream in May 2011; |
| • | A $7 million increase in NGL margins related to a $38 million increase from favorable commodity price changes, partially offset by a $31 million decrease driven by lower NGL equity volumes sold primarily due to a contract change, as previously discussed; |
| • | A $61 million increase in other operating costs and expenses and depreciation, as previously discussed; |
| • | The absence of $20 million in gains recognized in 2010, as previously discussed. |
18
West
| Year ended December 31, | ||||||||||||
|
2012 |
2011 | 2010 | ||||||||||
|
(Millions)
|
||||||||||||
| Segment revenues |
$ | 2,201 | $ | 2,690 | $ | 2,288 | ||||||
|
|
|
|
|
|
|
|||||||
| Segment profit |
$ | 980 | $ | 1,181 | $ | 934 | ||||||
|
|
|
|
|
|
|
|||||||
2012 vs. 2011
The decrease in segment revenues includes:
| — | 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; |
| — | A $14 million increase in fee revenues due primarily to higher gas gathering and processing volumes in the Piceance basin. |
Segment costs and expenses decreased $288 million including:
| — | 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; |
| — | 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; |
| — | A $20 million increase in general and administrative expenses including increases in employee-related, information technology services and rental costs. |
The decrease in segment profit includes:
| — | A $217 million decrease in NGL margins driven primarily by commodity price changes including lower NGL prices, partially offset by lower natural gas prices; |
| — | A $14 million increase in fee revenues, as previously discussed. |
2011 vs. 2010
The increase in segment revenues includes:
| — | A $292 million increase in revenues from our equity NGLs primarily reflecting an increase of $241 million associated with a 25 percent increase in average NGL per-unit sales prices and an increase of $51 million associated with a 5 percent increase in equity NGL volumes reflecting new capacity at our Echo Springs plant; |
19
| — | A $72 million increase in marketing revenues primarily due to higher average NGL prices. The changes in marketing revenues are offset by similar changes in marketing purchases; |
| — | A $39 million increase in fee revenues due primarily to higher gas gathering and processing fees in the Piceance basin as a result of an agreement executed in November 2010 and an increase in transportation revenues associated with an expansion project placed in service in 2010 on our interstate natural gas pipeline. |
Segment costs and expenses increased $155 million including:
| — | A $71 million increase in marketing purchases primarily due to higher average NGL prices. These changes are offset by similar changes in marketing revenues; |
| — | A $61 million increase in other operating costs and expenses reflecting $48 million, or 16 percent, higher expenses for maintenance performed on our facilities and $17 million higher depreciation expense primarily due to our Echo Springs expansion, which went into service in late 2010, along with increased depreciation of our Lybrook plant which was idled in January 2012 when the gas was redirected to our Ignacio plant; |
| — | A $15 million increase in costs associated with our equity NGLs primarily due to a 5 percent increase in equity NGL sales volumes, partially offset by lower natural gas prices; |
| — | The absence of a $12 million gain recognized in 2010 associated with the sale of certain assets in Colorado’s Piceance basin. |
The increase in segment profit includes:
| — | A $277 million increase in NGL margins reflecting a $249 million increase from favorable commodity price changes due primarily to a 25 percent increase in average NGL prices and higher NGL equity volumes sold reflecting new capacity at our Echo Springs plant; |
| — | A $39 million increase in fee revenues, as previously discussed; |
| — | A $61 million increase in other operating costs and expenses, as previously discussed; |
| — | A $12 million unfavorable change primarily related to gains recognized in 2010, as previously discussed. |
NGL & Petchem Services
| Year ended December 31, | ||||||||||||
|
2012 |
2011 | 2010 | ||||||||||
| (Millions) | ||||||||||||
| Segment revenues |
$ | 4,221 | $ | 4,719 | $ | 3,551 | ||||||
|
|
|
|
|
|
|
|||||||
| Segment profit |
$ | 295 | $ | 246 | $ | 172 | ||||||
|
|
|
|
|
|
|
|||||||
2012 vs. 2011
The decrease in segment revenues includes:
| • | A $441 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 $77 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 $26 million lower propylene production sales revenues primarily due to 17 percent lower average per-unit sales prices; |
20
| • | A $20 million increase in fee revenues including increases at our Gulf Olefin pipeline systems and Conway storage and fractionation facilities. |
Segment costs and expenses decreased $558 million including:
| • | A $396 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; |
| • | A $183 million decrease in olefin feedstock costs, including $130 million lower ethylene feedstock costs driven by 38 percent lower average per-unit feedstock costs and $28 million lower propylene feedstock costs primarily due to 20 percent lower per-unit feedstock costs; |
| • | A $9 million increase in general and administrative expenses including increases in employee-related and information technology services expenses; |
| • | An $8 million increase in depreciation expense primarily due to accelerated depreciation on assets that will become obsolete with the Geismar expansion project. |
Segment profit increased primarily due to:
| • | A $106 million increase in olefin product margins including $88 million higher ethylene production margins primarily due to 38 percent lower average per-unit feedstock prices, partially offset by 10 percent lower average per-unit sales prices. DAC production margins were also $13 million higher, primarily resulting from higher average per-unit margins primarily driven by lower average per-unit feedstock prices; |
| • | A $20 million increase in fee revenues, as previously discussed; |
| • | A $45 million decrease in margins related to the marketing of NGLs primarily due to the impact of a significant and rapid decline in NGL prices, primarily during the second quarter of 2012, while product was in transit and a $7 million unfavorable change in write-downs of inventories to lower of cost or market. These unfavorable variances compare to periods of increasing prices during 2011; |
| • | An $11 million decrease in equity earnings primarily due to lower equity earnings in Aux Sable Liquid Products L.P (Aux Sable); |
| • | A $9 million increase in general and administrative expenses, as previously discussed; |
| • | An $8 million increase in depreciation expense, as previously discussed. |
2011 vs. 2010
The increase in segment revenues includes:
| • | A $985 million increase in marketing revenues primarily due to higher average NGL and propylene prices. These changes are substantially offset by similar changes in marketing purchases; |
| • | A $167 million increase in olefin sales revenues including $126 million higher ethylene production sales revenues due to 28 percent higher average per-unit sales prices on 6 percent higher volumes primarily resulting from the absence of a four-week plant maintenance outage in 2010; and $30 million higher butadiene and DAC production sales revenues primarily due to higher average per-unit sales prices. |
Segment costs and expenses increased $1,115 million including:
21
| • | A $970 million increase in marketing costs primarily due to higher average NGL and propylene prices. These changes are substantially offset by similar changes in marketing revenues; |
| • | A $117 million increase in olefin feedstock costs including $93 million higher ethylene feedstock costs resulting from higher average per-unit feedstock costs and 6 percent higher volumes and $11 million higher butadiene and DAC feedstock costs primarily due to higher per-unit feedstock costs; |
| • | A $9 million increase in operating and maintenance expense due primarily to higher repairs and maintenance at our Geismar plant. |
Segment profit increased primarily due to:
| • | A $50 million increase in olefin product margins including $33 million higher ethylene production margins due to 27 percent higher per-unit margins on 6 percent higher volumes and $19 million higher butadiene and DAC production margins primarily resulting from higher average per-unit margins; |
| • | A $15 million increase in margins related to the marketing of NGLs and propylene; |
| • | A $21 million increase in equity earnings due primarily to higher equity earnings in OPPL as a result of our purchase of an increased ownership interest in September 2010; |
| • | A $9 million increase in operating and maintenance expense, as previously discussed. |
22
Management’s Discussion and Analysis of Financial Condition and Liquidity
Overview
In 2012, we continued to focus upon growth through disciplined investments. Examples of this growth included:
| • | Expansion of our interstate natural gas pipeline system to meet the demand of growth markets. |
| • | Laser, Caiman, and Geismar Acquisitions, as well as continued investment in our gathering and processing capacity and infrastructure in the Marcellus Shale area, western United States, and deepwater Gulf of Mexico. |
These investments were primarily funded 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 and maintaining investment-grade credit metrics. Our plan for 2013 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, as follows:
| • | Firm demand and capacity reservation transportation revenues under long-term contracts; |
| • | Fee-based revenues from certain gathering and processing services. |
We also note that the addition of the Geismar olefins-production facility is expected to result in a favorable shift in our commodity exposure from ethane to ethylene.
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 for 2013:
| • | We increased our per-unit quarterly distribution with respect to the fourth quarter of 2012 from $0.8075 to $0.8275. We expect to increase quarterly limited partner cash distributions by approximately 9 percent annually. |
| • | We expect to fund capital and investment expenditures, debt service payments, distributions to unitholders and working capital requirements primarily through cash flow from operations, cash and cash equivalents on hand, cash proceeds from common unit and/or long-term debt issuances and utilization of our revolver as needed. Based on a range of market assumptions, we currently estimate our cash flow from operations will be between $1.925 billion and $2.325 billion in 2013. 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 2013. 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; |
| • | Cash proceeds from offerings of our common units and/or long-term debt; |
23
| • | Use of our revolver as needed and available. |
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/or general partner. |
Potential risks associated with our planned levels of liquidity and the planned capital and investment expenditures discussed above include:
| • | Lower than expected levels of cash flow from operations; |
| • | Limited availability of capital due to a change in our financial condition, interest rates, market or industry conditions; |
| • | Sustained reductions in energy commodity margins from expected 2013 levels; |
| • | Physical damages to facilities, especially damage to offshore facilities by named windstorms. |
As of December 31, 2012, we had a working capital deficit (current liabilities in excess of current assets) of $499 million. However, we note the following about our available liquidity.
| Available Liquidity | December 31, 2012 | |||
| (Millions) | ||||
| Cash and cash equivalents |
$ | 20 | ||
| Capacity available under our $2.4 billion five-year revolver |
2,025 | |||
|
|
|
|||
| $ | 2,045 | |||
|
|
|
|||
| (1) | The full amount of the revolver 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 $400 million. Transco and Northwest Pipeline are each able to borrow up to $400 million under the revolver to the extent not otherwise utilized by the other co-borrowers. As of February 25, 2013, $975 million of loans are outstanding under this revolver. At December 31, 2012, we are in compliance with the financial covenants associated with this revolver. (See Note 11 of Notes to Consolidated Financial Statements.) |
Shelf Registration
In February 2012, we filed a shelf registration statement as a well-known seasoned issuer to facilitate unlimited issuances of registered debt and limited partnership unit securities.
24
Distributions from Equity Method Investees
Our equity method investees’ organizational documents require distribution of their available cash to their members on a quarterly basis. In each case, available cash is reduced, in part, by reserves appropriate for operating their respective businesses. Our more significant equity method investees include: Aux Sable, Discovery, Gulfstream, Laurel Mountain, and OPPL.
Debt Offerings
In August 2012, we completed a public offering of $750 million of our 3.35 percent senior unsecured notes due in 2022. We used the $745 million net proceeds to repay outstanding borrowings under our revolver and for general partnership purposes.
In July 2012, Transco received net proceeds of $395 million from the issuance of $400 million of 4.45 percent senior unsecured notes due in 2042. These proceeds were used to repay Transco’s $325 million 8.875 percent notes and for general corporate purposes, including capital expenditures.
Equity Offerings
In August 2012, we completed an equity issuance of 8,500,000 common units representing limited partner interests in us at a price of $51.43 per unit. Subsequently, we sold an additional 1,275,000 common units for $51.43 per unit to the underwriters upon the underwriters’ exercise of their option to purchase additional common units. The net proceeds of $488 million were used to repay outstanding borrowings under our revolver and for general partnership purposes.
In April 2012, we completed an equity issuance of 10,000,000 common units representing limited partner interests in us at a price of $54.56 per unit. Subsequently, we sold an additional 973,368 common units for $54.56 per unit to the underwriters upon the underwriters’ exercise of their option to purchase additional common units. The net proceeds of $581 million were used for general partnership purposes, including the funding of a portion of the cash purchase price of the Caiman Acquisition.
In April 2012, we also issued 16,360,133 common units to Williams for $1 billion, which was used to fund a portion of the cash purchase price of the Caiman Acquisition.
In January 2012, we completed an equity issuance of 7,000,000 common units representing limited partner interests in us at a price of $62.81 per unit. In February 2012, we sold an additional 1,050,000 common units for $62.81 per unit to the underwriters upon the underwriters’ exercise of their option to purchase additional common units. The net proceeds of $490 million were used to fund capital expenditures and for general partnership purposes.
Additionally, we issued equity to the sellers for acquisitions as discussed below.
Acquisitions
In November 2012, we completed the Geismar Acquisition in exchange for aggregate consideration valued at $2.364 billion, including $25 million in cash and 42,778,812 of our common units.
In April 2012, we completed the Caiman Acquisition in exchange for aggregate consideration of $1.72 billion in cash, net of purchase price adjustments, and 11,779,296 of our common units.
In February 2012, we completed the Laser Acquisition in exchange for $325 million in cash, net of cash acquired in the transaction, and 7,531,381 of our common units.
Credit Ratings
The table below presents our current credit ratings and outlook on our senior unsecured long-term debt.
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|
Rating Agency |
Date of Last Change |
Outlook |
Senior Unsecured
Debt Rating | |||
| Standard & Poor’s | March 5, 2012 | Stable | BBB | |||
| Moody’s Investors Service | February 27, 2012 | Stable | Baa2 | |||
| Fitch Ratings | February 9, 2012 | 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, 2012, we estimate that a downgrade to a rating below investment grade could require us to post up to $429 million in additional collateral with third parties.
Capital 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. |
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The following table provides summary information related to our expected capital expenditures for 2013:
| Segment |
Maintenance | Expansion | ||||||||||
|
(Millions)
| ||||||||||||
| Northeast G&P |
$ | 10 | $ | 1,555 | ||||||||
| Atlantic-Gulf |
175 | 1,195 | ||||||||||
| West |
140 | 250 | ||||||||||
| NGL & Petchem Services |
25 | 400 | ||||||||||
|
|
|
|
|
|||||||||
| Total |
$ | 350 | $ | 3,400 | ||||||||
|
|
|
|
|
|||||||||
See Results of Operations – Segments 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 the fourth quarter 2012 distribution to $ 0.8275 per unit, from the third quarter 2012 distribution of $0.8075, which resulted in a fourth-quarter 2012 cash distribution of approximately $442 million that was paid on February 8, 2013, to the general and limited partners of record at the close of business on February 1, 2013.
Williams has agreed to temporarily waive its incentive distribution rights related to the common units issued to Williams and the seller of Caiman Eastern Midstream, LLC, in connection with our acquisition of that entity, through 2013. In connection with the Geismar Acquisition, Williams also agreed to waive $16 million per quarter of incentive distribution rights until the later of December 31, 2013 or 30 days after the Geismar plant expansion is operational. The incentive distribution rights waived relative to distributions paid in 2012 were $24 million.
Sources (Uses) of Cash
| Years Ended December 31, | ||||||||||||
|
2012 |
2011 | 2010 | ||||||||||
|
(Millions) |
||||||||||||
| Net cash provided (used) by: |
||||||||||||
| Operating activities |
$ | 2,018 | $ | 2,290 | $ | 1,922 | ||||||
| Financing activities |
2,412 | (918) | 3,418 | |||||||||
| Investing activities |
(4,573) | (1,396) | (5,306) | |||||||||
|
|
|
|
|
|
|
|||||||
| Increase (decrease) in cash and cash equivalents |
$ | (143) | $ | (24) | $ | 34 | ||||||
|
|
|
|
|
|
|
|||||||
Operating activities
Net cash provided by operating activities decreased $272 million in 2012 as compared to 2011 primarily due to lower operating income.
Net cash provided by operating activities increased $368 million in 2011 as compared to 2010 primarily due to higher operating income.
Financing activities
Significant transactions include:
27
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 revolver 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 revolver 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 revolver mentioned below; |
| • | $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 revolver borrowings from our $1.75 billion unsecured credit facility used to acquire a 24.5 percent interest in Gulfstream from Williams in May 2011. This obligation was transferred to our new $2 billion unsecured credit facility at its inception in June 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. |
2010
| • | $3.5 billion of net proceeds from the issuance of senior unsecured notes; |
| • | $660 million related to quarterly cash distributions paid to limited partner unitholders and our general partner; |
| • | $600 million received from our public offering of senior notes in November 2010 primarily used to fund a portion of the cash consideration paid for the Piceance Acquisition (See Note 1 of Notes to Consolidated Financial Statements.); |
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| • | $437 million received from our September and October 2010 equity offering primarily used to reduce revolver borrowings; |
| • | $430 million received in revolver borrowings from our $1.75 billion unsecured credit facility primarily used to fund our increased ownership in OPPL, a transaction that closed in September 2010; |
| • | $369 million received from our December 2010 equity offering used to reduce revolver borrowings and to fund a portion of our acquisition of certain midstream assets in Pennsylvania’s Marcellus Shale in December 2010; |
| • | $250 million received from revolver borrowings on our $1.75 billion unsecured credit facility in February 2010 to repay a term loan outstanding under our credit agreement which expired at the closing of certain businesses we acquired from Williams; |
| • | $244 million distributed to Williams related to the excess purchase price over the contributed basis of the gathering and processing assets acquired in the Piceance Acquisition; |
| • | $200 million received in revolver borrowings from our $1.75 billion unsecured credit facility primarily used for general partnership purposes and to fund a portion of the cash consideration paid for the Piceance Acquisition; |
| • | $152 million in distributions to Williams primarily related to the Contributed Entities prior to the closing of the Dropdown. (See Note 1 of Notes to Consolidated Financial Statements.) |
Investing activities
Significant transactions include:
2012
| • | $2.1 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 the Laser Acquisition in March 2012; |
| • | $471 million contributed to our equity method investments. |
2011
| • | $1 billion in capital expenditures; |
| • | $174 million related to our acquisition of a 24.5 percent interest in Gulfstream from Williams in May 2011 (See Note 1 of Notes to Consolidated Financial Statements.); |
| • | $137 million contribution to our Laurel Mountain equity investment. |
2010
| • | $3.4 billion related to the cash consideration paid for certain businesses we acquired from Williams; |
| • | $844 million in capital expenditures; |
| • | $458 million related to the Piceance Acquisition; |
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| • | $424 million cash payment for our September 2010 acquisition of an increased interest in OPPL; |
| • | $150 million paid for the purchase of a business in December 2010, consisting primarily of midstream assets in Pennsylvania’s Marcellus Shale. |
Off-Balance Sheet Arrangements and Guarantees of Debt or Other Commitments
We have various other guarantees and commitments which are disclosed in Notes 9, 11, 14, and 15 of Notes to Consolidated Financial Statements. We do not believe these guarantees or the possible fulfillment of them will prevent us from meeting our liquidity needs.
Contractual Obligations
The table below summarizes the maturity dates of our contractual obligations at December 31, 2012:
| 2013 | 2014 -
2015 |
2016 -
2017 |
Thereafter | Total | ||||||||||||||||
| (Millions) | ||||||||||||||||||||
| Long-term debt, including current portion: |
||||||||||||||||||||
| Principal |
$ | - | $ | 750 | $ | 1,535 | $ | 6,168 | $ | 8,453 | ||||||||||
| Interest |
426 | 825 | 710 | 3,323 | 5,284 | |||||||||||||||
| Operating leases (1) |
40 | 66 | 53 | 136 | 295 | |||||||||||||||
| Purchase obligations (2) |
1,569 | 196 | 177 | 495 | 2,437 | |||||||||||||||
| Other long-term obligations |
1 | 1 | - | 1 | 3 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total |
$ | 2,036 | $ | 1,838 | $ | 2,475 | $ | 10,123 | $ | 16,472 | ||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| (1) | Includes a right-of-way agreement with the Jicarilla Apache Nation, which is considered an operating lease. We are required to make a fixed annual payment of $7.5 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 2014 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 2013 based on 2012 gathering volumes is $7.3 million and is included in the table for year 2013. |
| (2) | Includes approximately $1.2 billion in open property, plant and equipment purchase orders. Larger projects include Gulfstar and the Geismar plant expansion. Also includes an estimated $579 million long-term ethane purchase obligation with index-based pricing terms that is reflected in this table at December 31, 2012 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. 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 Results of Operations – Segments). |
Effects of Inflation
Our operations have historically not been materially affected by inflation. Approximately 56 percent of our gross property, plant, and equipment is comprised of our interstate gas pipelines. These assets 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 the remainder of our business, 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
30
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 use of hedging instruments and the fee-based nature of certain of our services.
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 of Notes to Consolidated Financial Statements). We are monitoring these sites in a coordinated effort with other potentially responsible parties, the U.S. Environmental Protection Agency (EPA), or other governmental authorities. We are jointly and severally liable along with unrelated third parties in some of these activities and solely responsible in others. Current estimates of the most likely costs of such activities are approximately $17 million, all of which are included in other accrued liabilities and regulatory liabilities, deferred income and other on the Consolidated Balance Sheet at December 31, 2012. We will seek recovery of approximately $10 million of these accrued costs through future natural gas transmission rates. The remainder of these costs will be funded from operations. During 2012, we paid approximately $4 million for cleanup and/or remediation and monitoring activities. We expect to pay approximately $5 million in 2013 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, 2012, 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 non-attainment 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 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 non-attainment 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.
Additionally, in August 2010, the EPA promulgated National Emission Standards for Hazardous Air Pollutants (NESHAP) regulations that will impact our operations. The emission control additions required to comply with the NESHAP regulations are estimated to include capital costs in the range of $11 million to $13 million through 2013, the compliance date.
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.
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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 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 11 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, 2012 and 2011. 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.
| 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 (2) |
||||||||||||||||||||||||||||||||
| 2012 | 2013 | 2014 | 2015 | 2016 | Thereafter(1) | Total | Fair Value
December 31,
2011 |
|||||||||||||||||||||||||
| (Millions) | ||||||||||||||||||||||||||||||||
| Long-term debt, including current portion: |
||||||||||||||||||||||||||||||||
| Fixed rate |
$ | 325 | $ | - | $ | - | $ | 750 | $ | 375 | $ | 5,787 | $ | 7,237 | $ | 8,170 | ||||||||||||||||
| Interest rate |
5.6% | 5.5% | 5.5% | 5.6% | 5.7% | 5.9% | ||||||||||||||||||||||||||
| (1) | Includes unamortized discount. |
| (2) | The weighted average interest rate at December 31, 2012 was 2.7 percent. |
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. (See Note 14 of Notes to Consolidated Financial Statements.)
We measure the risk in our portfolio using a value-at-risk methodology to estimate the potential one-day loss from adverse changes in the fair value of the portfolio. Value at risk requires a number of key assumptions and is not
33
necessarily representative of actual losses in fair value that could be incurred from the portfolio. Our value-at-risk model uses a Monte Carlo method to simulate hypothetical movements in future market prices and assumes that, as a result of changes in commodity prices, there is a 95 percent probability that the one-day loss in fair value of the portfolio will not exceed the value at risk. The simulation method uses historical correlations and market forward prices and volatilities. In applying the value-at-risk methodology, we do not consider that the simulated hypothetical movements affect the positions or would cause any potential liquidity issues, nor do we consider that changing the portfolio in response to market conditions could affect market prices and could take longer than a one-day holding period to execute. While a one-day holding period has historically been the industry standard, a longer holding period could more accurately represent the true market risk given market liquidity and our own credit and liquidity constraints.
We segregate our derivative contracts into trading and nontrading contracts, as defined in the following paragraphs. We calculate value at risk separately for these two categories. Contracts designated as normal purchases or sales and nonderivative energy contracts have been excluded from our estimation of value at risk.
Trading
Our limited trading portfolio consists of derivative contracts entered into for purposes other than economically hedging our commodity price-risk exposure. At December 31, 2012, we had no trading derivatives in our portfolio. The fair value of our trading derivatives at December 31, 2011, was a net asset of less than $0.1 million. The value at risk for contracts held for trading purposes was zero at December 31, 2012, and less than $0.1 million at December 31, 2011.
Nontrading
Our nontrading portfolio consists of derivative contracts that hedge or could potentially hedge the price risk exposure from natural gas purchase and NGL purchase and sale activities. The fair value of our nontrading derivatives was a net asset of $4 million and $1 million at December 31, 2012 and 2011, respectively. The value at risk for derivative contracts held for nontrading purposes was less than $0.1 million at December 31, 2012 and zero at December 31, 2011. During the year ended December 31, 2012, our value at risk for these contracts ranged from a high of $2.3 million to a low of zero.
Certain of the derivative contracts held for nontrading purposes in 2012 were accounted for as cash flow hedges but realized during the year. As of December 31, 2012, the energy derivative contracts in our portfolio have not been designated as cash flow hedges.
Trading Policy
We have policies and procedures that govern our trading and risk management activities. These policies cover authority and delegation thereof in addition to control requirements, authorized commodities and term and exposure limitations.
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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 sheets of Williams Partners L.P. (the Partnership) as of December 31, 2012 and 2011, 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, 2012. 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 two percent of the Partnership’s assets as of December 31, 2012 and 2011 and the Partnership’s equity earnings in the net income of Gulfstream constituted five and four percent of the Partnership’s net income for the years ended December 31, 2012 and 2011, respectively. Gulfstream’s financial statements were audited by other auditors whose report has been furnished to us, and our opinion on the 2011 and 2012 consolidated financial statements, 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, 2012 and 2011, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2012, 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, 2012, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 27, 2013 expressed an unqualified opinion thereon.
| /s/ Ernst & Young LLP
|
||
| Tulsa, Oklahoma |
||
| February 27, 2013 except as it relates to the matter discussed in the section titled “Organizational restructuring,” set forth in Note 1 and further addressed in Note 16, as to which the date is May 13, 2013 |
35
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, 2012 and 2011, and the related statements of operations, comprehensive income, members’ equity and cash flows for each of the two years in the period ended December 31, 2012. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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, 2012 and 2011, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America.
/s/ Deloitte & Touche LLP
Houston, Texas
February 25, 2013
36
WILLIAMS PARTNERS L.P.
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
| Years Ended December 31, | ||||||||||||
|
2012 |
2011 | 2010 | ||||||||||
| (Millions, except per-unit amounts) | ||||||||||||
| Revenues: |
||||||||||||
| Service revenues |
$ | 2,709 | $ | 2,517 | $ | 2,346 | ||||||
| Product sales |
4,611 | 5,197 | 4,113 | |||||||||
|
|
|
|
|
|
|
|||||||
| Total revenues |
7,320 | 7,714 | 6,459 | |||||||||
|
|
|
|
|
|
|
|||||||
| Costs and expenses: |
||||||||||||
| Product costs |
3,526 | 3,951 | 3,223 | |||||||||
| Operating and maintenance expenses |
987 | 948 | 837 | |||||||||
| Depreciation and amortization expenses |
714 | 621 | 578 | |||||||||
| Selling, general, and administrative expenses |
553 | 406 | 408 | |||||||||
| Other (income) expense — net |
23 | 13 | (14) | |||||||||
|
|
|
|
|
|
|
|||||||
| Total costs and expenses |
5,803 | 5,939 | 5,032 | |||||||||
|
|
|
|
|
|
|
|||||||
| Operating income |
1,517 | 1,775 | 1,427 | |||||||||
|
|
|
|
|
|
|
|||||||
| Equity earnings (losses) |
111 | 142 | 109 | |||||||||
| Interest incurred |
(441) | (426) | (393) | |||||||||
| Interest capitalized |
36 | 11 | 29 | |||||||||
| Interest income |
3 | 2 | 4 | |||||||||
| Other income (expense) — net |
6 | 7 | 12 | |||||||||
|
|
|
|
|
|
|
|||||||
| Net income |
1,232 | 1,511 | 1,188 | |||||||||
| Less: Net income attributable to noncontrolling interests |
- | - | 16 | |||||||||
|
|
|
|
|
|
|
|||||||
| Net income attributable to controlling interests |
$ | 1,232 | $ | 1,511 | $ | 1,172 | ||||||
|
|
|
|
|
|
|
|||||||
| Allocation of net income for calculation of earnings per common unit: |
||||||||||||
| Net income attributable to controlling interests |
$ | 1,232 | $ | 1,511 | $ | 1,172 | ||||||
| Allocation of net income to general partner and Class C units |
587 | 441 | 604 | |||||||||
|
|
|
|
|
|
|
|||||||
| Allocation of net income to common units |
$ | 645 | $ | 1,070 | $ | 568 | ||||||
|
|
|
|
|
|
|
|||||||
| Basic and diluted net income per common unit |
$ | 1.89 | $ | 3.69 | $ | 2.66 | ||||||
| Weighted average number of common units outstanding (thousands) |
341,981 | 290,255 | 213,539 | |||||||||
| Cash distributions per common unit |
$ | 3.205 | $ | 2.960 | $ | 2.720 | ||||||
| Other comprehensive income (loss): |
||||||||||||
| Net unrealized gain (loss) from derivative instruments |
$ | 30 | $ | (17) | $ | (17) | ||||||
| Reclassifications into earnings of net derivative instruments (gain) loss |
(30) | 18 | 12 | |||||||||
|
|
|
|
|
|
|
|||||||
| Other comprehensive income (loss) |
- | 1 | (5) | |||||||||
|
|
|
|
|
|
|
|||||||
| Comprehensive income |
1,232 | 1,512 | 1,183 | |||||||||
| Less: Comprehensive income attributable to noncontrolling interests |
- | - | 16 | |||||||||
|
|
|
|
|
|
|
|||||||
| Comprehensive income attributable to controlling interests |
$ | 1,232 | $ | 1,512 | $ | 1,167 | ||||||
|
|
|
|
|
|
|
|||||||
See accompanying notes.
37
WILLIAMS PARTNERS L.P.
CONSOLIDATED BALANCE SHEET
| December 31, | December 31, | |||||||
| 2012 | 2011 | |||||||
| (Millions) | ||||||||
| ASSETS |
||||||||
| Current assets: |
||||||||
| Cash and cash equivalents |
$ | 20 | $ | 163 | ||||
| Trade accounts and notes receivable |
562 | 564 | ||||||
| Inventories |
173 | 169 | ||||||
| Regulatory assets |
39 | 40 | ||||||
| Other current assets |
56 | 72 | ||||||
|
|
|
|
|
|||||
| Total current assets |
850 | 1,008 | ||||||
| Investments |
1,800 | 1,383 | ||||||
| Property, plant, and equipment – net |
14,287 | 11,822 | ||||||
| Goodwill |
649 | - | ||||||
| Other intangibles |
1,702 | 43 | ||||||
| Regulatory assets, deferred charges, and other |
421 | 416 | ||||||
|
|
|
|
|
|||||
| Total assets |
$ | 19,709 | $ | 14,672 | ||||
|
|
|
|
|
|||||
| LIABILITIES AND EQUITY |
||||||||
| Current liabilities: |
||||||||
| Accounts payable: |
||||||||
| Trade |
$ | 851 | $ | 623 | ||||
| Affiliate |
117 | 68 | ||||||
| Accrued interest |
110 | 105 | ||||||
| Asset retirement obligations |
68 | 66 | ||||||
| Other accrued liabilities |
203 | 172 | ||||||
| Long-term debt due within one year |
- | 324 | ||||||
|
|
|
|
|
|||||
| Total current liabilities |
1,349 | 1,358 | ||||||
| Long-term debt |
8,437 | 6,913 | ||||||
| Asset retirement obligations |
508 | 504 | ||||||
| Regulatory liabilities, deferred income, and other |
518 | 464 | ||||||
| Contingent liabilities and commitments (Note 15) |
||||||||
| Equity: |
||||||||
| Partners’ equity: |
||||||||
| Common units (397,963,199 units outstanding at December 31, 2012 and 290,477,159 units outstanding at December 31, 2011) |
10,372 | 6,810 | ||||||
| General partner |
(1,487) | (1,375) | ||||||
| Accumulated other comprehensive income (loss) |
(2) | (2) | ||||||
|
|
|
|
|
|||||
| Total partners’ equity |
8,883 | 5,433 | ||||||
| Noncontrolling interests in consolidated subsidiaries |
14 | - | ||||||
|
|
|
|
|
|||||
| Total equity |
8,897 | 5,433 | ||||||
|
|
|
|
|
|||||
| Total liabilities and equity |
$ | 19,709 | $ | 14,672 | ||||
|
|
|
|
|
|||||
See accompanying notes.
38
WILLIAMS PARTNERS L.P.
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
| Williams Partners L.P. | ||||||||||||||||||||||||
| Accumulated Other | ||||||||||||||||||||||||
| Limited Partners | General | Comprehensive | Noncontrolling | Total | ||||||||||||||||||||
| Common | Class C | Partner | Income (Loss) | Interests | Equity | |||||||||||||||||||
| (Millions) | ||||||||||||||||||||||||
| Balance – December 31, 2009 |
$ | 1,631 | $ | - | $ | 6,307 | $ | 2 | $ | 347 | $ | 8,287 | ||||||||||||
| Net income |
558 | 156 | 458 | - | 16 | 1,188 | ||||||||||||||||||
| Other comprehensive income (loss) |
- | - | - | (5) | - | (5) | ||||||||||||||||||
| Cash distributions (Note 3) |
(432) | (87) | (141) | - | - | (660) | ||||||||||||||||||
| Distributions to The Williams Companies, Inc. - net |
- | (3,357) | (778) | - | - | (4,135) | ||||||||||||||||||
| Excess of purchase price over contributed basis of business purchase from affiliate |
- | - | (244) | - | - | (244) | ||||||||||||||||||
| Dividends paid to noncontrolling interests |
- | - | - | - | (18) | (18) | ||||||||||||||||||
| Issuance of Class C units |
- | 6,946 | (6,946) | - | - | - | ||||||||||||||||||
| Conversion of Class C units to Common |
3,658 | (3,658) | - | - | - | - | ||||||||||||||||||
| Issuance of units due to Williams Pipeline Partners L.P. merger |
343 | - | - | - | (343) | - | ||||||||||||||||||
| Sales of common units |
806 | - | - | - | - | 806 | ||||||||||||||||||
| Contributions from general partner |
- | - | 29 | - | - | 29 | ||||||||||||||||||
| Other |
- | - | 2 | - | (2) | - | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Balance – December 31, 2010 |
$ | 6,564 | $ | - | $ | (1,313) | $ | (3) | $ | - | $ | 5,248 | ||||||||||||
| Net income |
1,088 | - | 423 | - | - | 1,511 | ||||||||||||||||||
| Other comprehensive income (loss) |
- | - | - | 1 | - | 1 | ||||||||||||||||||
| Cash distributions (Note 3) |
(842) | - | (282) | - | - | (1,124) | ||||||||||||||||||
| Distributions to The Williams Companies, Inc. - net |
- | - | (99) | - | - | (99) | ||||||||||||||||||
| 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 | $ | - | $ | (1,375) | $ | (2) | $ | - | $ | 5,433 | ||||||||||||
| Net income |
672 | - | 560 | - | - | 1,232 | ||||||||||||||||||
| Cash distributions (Note 3) |
(1,056) | - | (384) | - | - | (1,440) | ||||||||||||||||||
| Distributions to The Williams Companies, Inc. - net |
- | - | (42) | - | - | (42) | ||||||||||||||||||
| Sales of common units (Note 12) |
2,559 | - | - | - | - | 2,559 | ||||||||||||||||||
| Issuances of common units related to acquisitions (Note 12) |
1,044 | - | - | - | - | 1,044 | ||||||||||||||||||
| Issuances of common units in common control transactions (Note 12) |
345 | - | (338) | - | - | 7 | ||||||||||||||||||
| Contributions from general partner |
- | - | 93 | - | - | 93 | ||||||||||||||||||
| Contributions to Constitution Pipeline Company, LLC (Note 1) |
- | - | - | - | 14 | 14 | ||||||||||||||||||
| Other |
(2) | - | (1) | - | - | (3) | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Balance - December 31, 2012 |
$ | 10,372 | $ | - | $ | (1,487) | $ | (2) | $ | 14 | $ | 8,897 | ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
See accompanying notes.
39
WILLIAMS PARTNERS L.P.
CONSOLIDATED STATEMENT OF CASH FLOWS
| Years Ended December 31, | ||||||||||||
|
2012 |
2011 | 2010 | ||||||||||
| (Millions) | ||||||||||||
| OPERATING ACTIVITIES: |
||||||||||||
| Net income |
$ | 1,232 | $ | 1,511 | $ | 1,188 | ||||||
| Adjustments to reconcile to net cash provided by operations: |
||||||||||||
| Depreciation and amortization |
714 | 621 | 578 | |||||||||
| Cash provided (used) by changes in current assets and liabilities: |
||||||||||||
| Accounts and notes receivable |
19 | (92) | (33) | |||||||||
| Inventories |
7 | 56 | (67) | |||||||||
| Other current assets and deferred charges |
25 | (7) | 35 | |||||||||
| Accounts payable |
(89) | 138 | 35 | |||||||||
| Accrued liabilities |
(8) | 60 | 105 | |||||||||
| Affiliate accounts receivable and payable – net |
49 | (97) | 81 | |||||||||
| Other, including changes in noncurrent assets and liabilities |
69 | 100 | - | |||||||||
|
|
|
|
|
|
|
|||||||
| Net cash provided by operating activities |
2,018 | 2,290 | 1,922 | |||||||||
|
|
|
|
|
|
|
|||||||
| FINANCING ACTIVITIES: |
||||||||||||
| Proceeds from long-term debt |
2,639 | 1,596 | 5,029 | |||||||||
| Payments of long-term debt |
(1,440) | (1,184) | (1,203) | |||||||||
| Payment of debt issuance costs |
(12) | (16) | (66) | |||||||||
| Proceeds from sales of common units |
2,559 | - | 806 | |||||||||
| General partner contributions |
93 | 31 | 29 | |||||||||
| Dividends paid to noncontrolling interests |
- | - | (18) | |||||||||
| Distributions to limited partners and general partner |
(1,440) | (1,124) | (660) | |||||||||
| Excess of purchase price over contributed basis of business and investment |
- | (123) | (244) | |||||||||
| Distributions to The Williams Companies, Inc. – net |
(17) | (99) | (251) | |||||||||
| Other – net |
30 | 1 | (4) | |||||||||
|
|
|
|
|
|
|
|||||||
| Net cash provided (used) by financing activities |
2,412 | (918) | 3,418 | |||||||||
|
|
|
|
|
|
|
|||||||
| INVESTING ACTIVITIES: |
||||||||||||
| Purchase of businesses and investments from affiliates |
(25) | (174) | (3,884) | |||||||||
| Property, plant and equipment: |
||||||||||||
| Capital expenditures |
(2,112) | (1,005) | (844) | |||||||||
| Net proceeds from dispositions |
22 | 5 | 64 | |||||||||
| Purchases of businesses |
(2,049) | (41) | (150) | |||||||||
| Purchases of and contributions to equity method investments |
(471) | (197) | (476) | |||||||||
| Purchase of ARO trust investments |
(34) | (41) | (47) | |||||||||
| Proceeds from sale of ARO trust investments |
43 | 56 | 31 | |||||||||
| Other – net |
53 | 1 | - | |||||||||
|
|
|
|
|
|
|
|||||||
| Net cash used by investing activities |
(4,573) | (1,396) | (5,306) | |||||||||
|
|
|
|
|
|
|
|||||||
| Increase (decrease) in cash and cash equivalents |
(143) | (24) | 34 | |||||||||
| Cash and cash equivalents at beginning of period |
163 | 187 | 153 | |||||||||
|
|
|
|
|
|
|
|||||||
| Cash and cash equivalents at end of period |
$ | 20 | $ | 163 | $ | 187 | ||||||
|
|
|
|
|
|
|
|||||||
See accompanying notes.
40
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, 2012, Williams owns an approximate 68 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.
Description of Business
Organizational restructuring
Following Williams’ spin-off of WPX Energy, Inc. (WPX) at the end of 2011 and in consideration of the growth plans of the ongoing business, Williams initiated an organizational restructuring evaluation to better align resources to support an overall business strategy 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. As a result of this review, a new structure was implemented effective January 1, 2013, that generally organizes our businesses into geographically based operating areas. We have changed our segment reporting structure to align with the new operating areas resulting from the organizational restructuring, as this is consistent with the manner in which our Chief Operating Decision Maker evaluates performance and makes resource allocation decisions. Beginning in the first quarter of 2013, our reportable segments are Northeast G&P, Atlantic-Gulf, West, and NGL & Petchem Services. These consolidated financial statements and notes have been recast to reflect the revised segment presentation.
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.
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 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 51 percent consolidated interest in Constitution Pipeline Company, LLC (Constitution), 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 GP (Northwest Pipeline).
NGL & Petchem Services is comprised of our natural gas liquid (NGL) and natural gas marketing business, an NGL fractionator and storage facilities near Conway, Kansas, a 50 percent equity investment in Overland Pass Pipeline LLC (OPPL), and an 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.
Basis of Presentation
In February 2010, we closed a transaction (the Dropdown) with Williams and certain of its subsidiaries, pursuant to which Williams contributed to us the ownership interests in a substantial portion of its gas pipeline and midstream businesses to the extent not already owned by us (the Contributed Entities). This contribution was made in exchange for aggregate consideration of $3.5 billion in cash, 203,000,000 of our Class C limited partnership units,
41
WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
which automatically converted into our common limited partnership units in May 2010 and an increase in the capital account of our general partner to allow it to maintain its 2 percent general partner interest.
In November 2010, we acquired a business represented by certain gathering and processing assets in Colorado’s Piceance basin from a former subsidiary of Williams (Piceance Acquisition). The Piceance Acquisition was made in exchange for consideration of $702 million in cash, approximately 1,849,138 of our common units, and an increase in the capital account of our general partner to allow it to maintain its 2 percent general partner ownership interest. These gathering and processing assets are reported in our West reporting segment.
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. These transactions are collectively referred to as the Gulfstream Acquisitions and the investment is reported in our Atlantic-Gulf segment.
In November 2012, we acquired an entity that holds an 83.3 percent undivided interest and operatorship of the 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 operations of this business and the related assets and liabilities 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 $185 million, $133 million and $87 million for the years ended 2012, 2011, and 2010, respectively. This acquisition does not impact historical earnings per unit as pre-acquisition earnings were allocated to our general partner.
The entities and assets acquired in the previously discussed transactions were affiliates of Williams at the time of the acquisitions; therefore, each was accounted for as a common control transaction, similar to a pooling of interests, whereby the assets and liabilities of the acquired entities are combined with ours at their historical amounts. The equity interests acquired in the Gulfstream Acquisitions were combined with our investments as of the date of transfer.
Following the Geismar Acquisition, the NGL & Petchem Services segment includes operations related to the manufacture of olefin products. As a result, revenues within the Consolidated Statement of Comprehensive Income are now presented as service revenues and product sales. We also revised the presentation of certain costs and operating expenses to align product costs with the presentation of our product sales. Costs and operating expenses has been separated into product costs, operating and maintenance expenses, and depreciation and amortization expenses. Selling, general and administrative expenses has also been combined with general corporate expenses, and depreciation and amortization expenses previously presented in selling, general and administrative expenses are now presented in depreciation and amortization expenses. All periods presented have been recast, along with corresponding information presented in the Notes to Consolidated Financial Statements, to reflect this change.
Certain prior period amounts reported within total costs and expenses in the Consolidated Statement of Comprehensive Income have been reclassified to conform to the current presentation. The effect of the correction increased operating and maintenance expenses and decreased selling, general, and administrative expenses, with no net impact on total costs and expenses, operating income or net income. The adjustments were $14 million and $13 million in 2011 and 2010, respectively.
42
WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Variable interest entities (VIEs)
We consolidate the activities of VIEs of which we are the primary beneficiary. The primary beneficiary of a VIE is the entity that has both the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and the obligation to absorb losses or right to receive benefits that could be significant to the VIE. As of December 31, 2012, we have the following consolidated VIEs:
| • | Gulfstar One LLC (Gulfstar) is a consolidated wholly owned subsidiary that, due to certain risk sharing provisions in its customer contracts, is a VIE. We, as construction agent for Gulfstar, will design, construct, and install a proprietary floating-production system, Gulfstar FPSTM, 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. Construction is underway and the project is expected to be in service in 2014. We, in combination with certain advance payments from the producer customers, are currently financing the asset construction. Gulfstar has construction work in process of $532 million and $103 million included in property, plant, and equipment - net as of December 31, 2012 and 2011, respectively, $109 million and $101 million of deferred revenue associated with customer advance payments included in regulatory liabilities, deferred income, and other as of December 31, 2012 and 2011, respectively, and $124 million and $33 million of accounts payable – trade as of December 31, 2012 and 2011, respectively in the Consolidated Balance Sheet. We are committed to the producer customers to construct this system, and we currently estimate the remaining construction cost to be less than $475 million. If the producer customers do not develop the offshore oil and gas fields to be connected to Gulfstar, they will be responsible for the firm price of building the facilities. In January 2013, we agreed to sell a 49 percent ownership interest in our Gulfstar FPS™ project to a third party. The transaction is expected to close in second-quarter 2013, at which time we expect the third party will contribute $225 million to fund its proportionate share of the project costs, following with monthly capital contributions to fund its share of ongoing construction. |
| • | We own a 51 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 over the decisions that most significantly impact Constitution’s economic performance. We, as construction agent for Constitution, will build 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 March 2015 and estimate the total cost of the project to be approximately $680 million, which will be funded with capital contributions from us, along with the other equity partners, proportional to ownership interest. As of December 31, 2012, our Consolidated Balance Sheet includes $8 million of cash and cash equivalents, $24 million of Constitution construction work in progress representing costs incurred to date, included in property, plant and equipment - net and $4 million of accounts payable — trade. |
We have also identified certain interests in VIEs where we are not the primary beneficiary. These include our investments in Laurel Mountain and Discovery. These entities are considered to be VIEs generally due to contractual provisions that transfer certain risks to customers. As certain significant decisions in the management of these entities 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 our investments. (See Note 5).
Summary of Significant Accounting Policies
Principles of consolidation
The consolidated financial statements include the accounts of Williams Partners L.P., OLLC, and our other majority-owned and controlled subsidiaries and investments. We apply the equity method of accounting for investments in unconsolidated companies in which we and our subsidiaries own 20 percent to 50 percent of the
43
WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
voting interest and exercise significant influence over operating and financial policies of the company, or where our majority ownership does not provide us with control due to the significant participatory rights of other owners.
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.
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 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 businesses that are regulated can differ from the accounting requirements for non regulated businesses. 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.
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WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Cash and cash equivalents
Cash and cash equivalents 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 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 9.)
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.
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 an asset and a liability equal to 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. The ARO asset is depreciated in a manner consistent with the depreciation of the underlying physical asset. As regulated entities, Northwest Pipeline and Transco record the ARO asset depreciation offset 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, 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.
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WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Goodwill
Goodwill represents the excess cost over fair value of the 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. Our evaluation includes an assessment of events or circumstances to determine whether it is more likely than not that the fair value of the reporting unit is less than its carrying amount. If so, we further 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. We have goodwill of $649 million at December 31, 2012 in the Consolidated Balance Sheet attributable to our Northeast G&P segment.
Other Intangible Assets
Our identifiable intangible assets are primarily related to gas gathering, processing and fractionation contracts and relationships with customers. We have other intangibles of $1.702 billion and $43 million at December 31, 2012 and 2011, respectively in the Consolidated Balance Sheet primarily attributable to our Northeast G&P segment. Our intangible assets are amortized on a straight-line basis over estimated useful lives. We evaluate these assets for changes in the expected remaining useful lives and would reflect any changes prospectively through amortization over the revised remaining useful life.
Impairment of property, plant, and equipment, other identifiable intangible assets, and investments
We evaluate our property, plant, and equipment and other identifiable intangible assets for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable. When an indicator of impairment has occurred, we compare our management’s estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has occurred and we may apply a probability-weighted approach to consider the likelihood of different cash flow assumptions and possible outcomes including selling in the near term or holding for the remaining estimated useful life. If an impairment of the carrying value has occurred, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value. This evaluation is performed at the lowest level for which separately identifiable cash flows exist.
For assets identified to be disposed of in the future and considered held for sale, we compare the carrying value to the estimated fair value less the cost to sell to determine if recognition of an impairment is required. Until the assets are disposed of, the estimated fair value, which includes estimated cash flows from operations until the assumed date of sale, is recalculated when related events or circumstances change.
We evaluate our investments for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such investments may have experienced an other-than-temporary decline in value. When evidence of loss in value has occurred, we compare our estimate of fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred. If the estimated fair value is less than the carrying value and we consider the decline in value to be other-than-temporary, the excess of the carrying value over the fair value is recognized in the consolidated financial statements as an impairment charge.
Judgments and assumptions are inherent in our management’s estimate of undiscounted future cash flows and an asset’s or investment’s fair value. Additionally, judgment is used to determine the probability of sale with respect to assets considered for disposal.
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WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Contingent liabilities
We record liabilities for estimated loss contingencies, including environmental matters, when we assess that a loss is probable and the amount of the loss can be reasonably estimated. These liabilities are calculated based upon our assumptions and estimates with respect to the likelihood or amount of loss and upon advice of legal counsel, engineers, or other third parties regarding the probable outcomes of the matters. These calculations are made without consideration of any potential recovery from third-parties. We recognize insurance recoveries or reimbursements from others when realizable. Revisions to these liabilities are generally reflected in income when new or different facts or information become known or circumstances change that affect the previous assumptions or estimates.
Cash flows from revolving credit facility
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.
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. 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.
The accounting for the changes in fair value of a commodity derivative can be summarized as follows:
| Derivative Treatment |
Accounting Method | |
|
Normal purchases and normal sales exception |
Accrual accounting | |
| Designated in a qualifying hedging relationship |
Hedge accounting | |
| All other derivatives |
Mark-to-market accounting |
We may elect the normal purchases and normal sales exception for certain short- and long-term purchases and sales of physical energy commodities. Under accrual accounting, any change in the fair value of these derivatives is not reflected on the balance sheet after the initial election of the exception.
We may also designate a hedging relationship for certain commodity derivatives. For a derivative to qualify for designation in a hedging relationship, it must meet specific criteria and we must maintain appropriate documentation. We establish hedging relationships pursuant to our risk management policies. We evaluate the hedging relationships at the inception of the hedge and on an ongoing basis to determine whether the hedging relationship is, and is expected to remain, highly effective in achieving offsetting changes in fair value or cash flows attributable to the underlying risk being hedged. We also regularly assess whether the hedged forecasted transaction is probable of occurring. If a derivative ceases to be or is no longer expected to be highly effective, or if we believe the likelihood of occurrence of the hedged forecasted transaction is no longer probable, hedge accounting is discontinued prospectively, and future changes in the fair value of the derivative are recognized currently in product sales or product costs.
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) 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. Gains or losses deferred in AOCI associated with
47
WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
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 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.
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; |
| • | The ineffective portion of unrealized gains and losses on derivatives that are designated as cash flow hedges. |
Realized gains and losses on derivatives that require physical delivery, as well as natural gas derivatives for NGL processing activities and which are not held for trading purposes nor were entered into as a pre-contemplated buy/sell arrangement, are recorded on a gross basis. In reaching our conclusions on this presentation, we considered whether we act as principal in the transaction; whether we have the risks and rewards of ownership, including credit risk; and whether we have latitude in establishing prices.
Revenues
As a result of the ratemaking process, certain revenues collected by us may be subject to refunds upon the issuance of final orders by the FERC in pending rate proceedings. We record estimates of rate refund liabilities considering our and other third-party regulatory proceedings, advice of counsel and other risks.
Service revenues
Revenues from our gas pipeline businesses include services pursuant to long-term firm transportation and storage agreements. These agreements provide for a reservation charge based on the volume of 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 of our midstream operations 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 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-liquid 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.
We recognize revenue on our olefins business, which produces olefins from purchased feed-stock, when the olefins are sold and delivered.
Interest capitalized
We capitalize interest during construction on major projects with construction periods of at least three 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. 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 federal or state and local income tax purposes. The tax on net income is 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.
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. Additionally, subsequent to April 1, 2010 we consider Class C units as common units for purposes of the calculation. 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 7.) 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.
Note 2. Acquisitions
In addition to the entities and assets acquired in the common control transactions described in Note 1, 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 33 miles of 16-inch natural gas pipeline and associated gathering facilities in the Marcellus Shale in Susquehanna County, Pennsylvania, as well as 10 miles of 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, subject to the final purchase price adjustment, 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 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.
These 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 area. The amount recorded for goodwill in the Caiman Acquisition is preliminary pending final determination of the purchase price adjustment.
The following table presents the allocation of the acquisition-date fair value of the major classes of the net assets, which are presented in the Northeast G&P segment:
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WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
| 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 intangible assets |
2 | 2 | ||||||
| Current liabilities |
(21) | (94) | ||||||
| Noncurrent liabilities |
- | (3) | ||||||
|
|
|
|
|
|||||
| Identifiable net assets acquired |
476 | 1,968 | ||||||
| Goodwill |
290 | 359 | ||||||
|
|
|
|
|
|||||
| $ | 766 | $ | 2,327 | |||||
|
|
|
|
|
|||||
Identifiable intangible assets recognized in the Laser and Caiman Acquisitions are primarily related to gas gathering, processing and fractionation contracts and relationships with customers. The basis for determining the value of these intangible assets is estimated future net cash flows to be derived from acquired customer contracts and relationships, which are offset with appropriate charges for the use of contributory assets and discounted using a risk-adjusted discount rate. Those intangible assets are being amortized on a straight-line basis over an initial 30-year period which represents a portion of the term over which the customer contracts and relationships are expected to contribute to our cash flows.
We expense costs incurred to renew or extend the terms of our gas gathering, processing and fractionation contracts with customers. Approximately 70 percent and 36 percent of the expected future revenues from the customer contracts associated with the Laser and Caiman Acquisitions, respectively, are impacted by our ability and intent to renew or renegotiate existing customer contracts. Based on the estimated future revenues during the current contract periods, the weighted-average periods prior to the next renewal or extension of the existing customer contracts associated with the Laser and Caiman Acquisitions are approximately 9 years and 18 years, respectively.
Revenues and earnings related to the Laser and Caiman Acquisitions included within the Consolidated Statement of Comprehensive Income since the respective acquisition dates are not material. Supplemental pro forma revenue and earnings 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.
Amortization of Other Intangible Assets
Amortization expense related to other intangibles was $43 million, $2 million and zero in 2012, 2011, and 2010, respectively. Accumulated amortization related to other intangibles was $45 million and $2 million at December 31, 2012 and 2011, respectively. The estimated amortization expense for each of the next five succeeding fiscal years is approximately $58 million.
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WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Note 3. 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, for the years ended 2012, 2011, and 2010, is as follows:
| Years Ended December 31, | ||||||||||||
|
2012 |
2011 | 2010 | ||||||||||
| (Millions) | ||||||||||||
| Allocation of net income to general partner: |
||||||||||||
| Net income |
$ | 1,232 | $ | 1,511 | $ | 1,188 | ||||||
| Net income applicable to pre-partnership operations allocated to general partner |
(185) | (133) | (310) | |||||||||
| Net income applicable to noncontrolling interests |
- | - | (16) | |||||||||
| Net reimbursable costs charged directly to general partner |
1 | (2) | (4) | |||||||||
|
|
|
|
|
|
|
|||||||
| Income subject to 2% allocation of general partner interest |
1,048 | 1,376 | 858 | |||||||||
| 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 | 28 | 17 | |||||||||
| Incentive distributions paid to general partner (a) |
355 | 260 | 127 | |||||||||
| Net reimbursable costs charged directly to general partner |
(1) | 2 | 4 | |||||||||
| Pre-partnership net income allocated to general partner interest |
185 | 133 | 310 | |||||||||
|
|
|
|
|
|
|
|||||||
| Net income allocated to general partner |
$ | 560 | $ | 423 | $ | 458 | ||||||
|
|
|
|
|
|
|
|||||||
| Net income |
$ | 1,232 | $ | 1,511 | $ | 1,188 | ||||||
| Net income allocated to general partner |
560 | 423 | 458 | |||||||||
| Net income allocated to Class C limited partners |
- | - | 156 | |||||||||
| Net income allocated to noncontrolling interests |
- | - | 16 | |||||||||
|
|
|
|
|
|
|
|||||||
| Net income allocated to common limited partners |
$ | 672 | $ | 1,088 | $ | 558 | ||||||
|
|
|
|
|
|
|
|||||||
| (a) | 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 limited partner 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 reimbursable 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.
For purposes of calculating the 2010 basic and diluted net income per common unit, the weighted average number of common units outstanding are calculated considering Class C units as common units effective April 1, 2010, and net income allocated to the Class C units prior to that date is based on the distributed earnings paid to the Class C units for first-quarter 2010. For the allocation of 2010 net income for the Consolidated Statement of Changes in Equity, net income was allocated based on the number of days the Class C units were outstanding as Class C units during 2010.
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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 |
Class C
Units |
2% |
Incentive
Distribution
Rights |
Total Cash
Distribution |
||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
| 2/12/2010 |
$ 0.6350 | $ 33 | $ - | $ 1 | $ - | $ 34 | ||||||||||||||||||
| 5/14/2010 (a) |
$ 0.6575 | $ 35 | $ 87 | $ 3 | $ 30 | $ 155 | ||||||||||||||||||
| 8/13/2010 |
$ 0.6725 | $ 172 | $ - | $ 4 | $ 45 | $ 221 | ||||||||||||||||||
| 11/12/2010 |
$ 0.6875 | $ 192 | $ - | $ 5 | $ 53 | $ 250 | ||||||||||||||||||
| 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 | ||||||||||||||||||
| 11/09/2012 |
$ 0.8075 | $ 287 | $ - | $ 8 | $ 99 | $ 394 | ||||||||||||||||||
| 2/08/2013 (b) |
$ 0.8275 | $ 329 | $ - | $ 9 | $ 104 | $ 442 | ||||||||||||||||||
| (a) | Distributions on the Class C units and the additional general partner units issued in connection with the closing of the February 2010 transaction where we acquired certain contributed entities, as well as the related IDR payments, were prorated to reflect the fact that they were not outstanding during the first full quarter period of 2010. |
| (b) | On February 8, 2013, we paid a cash distribution of $0.8275 per unit on our outstanding common units to unitholders of record at the close of business on February 1, 2013. |
The 2012 and 2013 cash distributions paid to our general partner in the table above have been reduced by a total of $49 million resulting from the temporary waiver of IDRs associated with the Caiman and Geismar Acquisitions.
Note 4. 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.
53
WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
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 its former exploration and production business, WPX. Our share of the allocated reorganization-related costs, included in selling, general, and administrative expenses in the Consolidated Statement of Comprehensive Income, is $25 million for the year ended December 31, 2012.
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 olefin and NGL products for resale from Williams Energy Canada, Inc., a subsidiary of Williams, at market prices at the time of purchase. |
| • | 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 years ended December 31, 2011 and 2010 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 years ended December 31, 2011 and 2010 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.
54
WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
| Years Ended December 31, | ||||||||||||
|
2012 |
2011 | 2010 | ||||||||||
| (Millions) | ||||||||||||
| Revenues |
$ | - | $ | 310 | $ | 265 | ||||||
| Product costs |
300 | 802 | 676 | |||||||||
| Operating and maintenance expenses |
||||||||||||
| Employee costs |
269 | 236 | 217 | |||||||||
| Other |
- | 305 | 297 | |||||||||
| Selling, general, and administrative expenses |
||||||||||||
| Employee direct costs |
287 | 232 | 213 | |||||||||
| Employee allocated costs |
184 | 118 | 130 | |||||||||
The accounts payable — affiliate in the Consolidated Balance Sheet represents the payable positions that result from the transactions with affiliates discussed above. Included in the Consolidated Balance sheet are certain obligations of $12 million at December 31, 2011 related to the WPX spin-off. In addition, we have $15 million and $23 million in accounts payable — trade in the Consolidated Balance Sheet with our equity method investees at December 31, 2012 and December 31, 2011, 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 $75 million, $57 million and $38 million for the years ended December 31, 2012, 2011, and 2010, respectively.
Omnibus Agreement
In connection with the Dropdown 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, 2012, 2011 and 2010 were $15 million, $31 million, and $2 million, respectively.
We have a contribution receivable from our general partner of $4 million and $7 million at December 31, 2012 and December 31, 2011, respectively, for amounts reimbursable to us under omnibus agreements. We net this receivable against partners’ equity on the Consolidated Balance Sheet.
55
WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Acquisitions and Equity Issuances
Basis of Presentation in Note 1 includes related party transactions for the Geismar Acquisition, Gulfstream Acquisitions, the Dropdown, and the Piceance Acquisition. Prior to such transactions, these operations participated in Williams’ cash management program under an unsecured promissory note agreement with Williams for both advances to and from Williams. In connection with the acquisitions, the outstanding advances were distributed to Williams at the close of these transactions. These distributions 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.
Note 12 includes a related party transaction for the sale of limited partner units to Williams to partially fund the Caiman Acquisition.
Board of Directors
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. We also recorded $20 million in product sales in the Consolidated Statement of Comprehensive Income from Silverthorne Energy Partners LP primarily for the sale of propane at market prices and $5 million in product costs in the Consolidated Statement of Comprehensive Income from the purchase of propane at market prices for the year ended December 31, 2010.
56
WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Note 5. Investments
Investments accounted for using the equity method include:
| December 31, | ||||||||
|
2012 |
2011 |
|||||||
|
|
|
|||||||
| (Millions) | ||||||||
| OPPL - 50% |
$ | 454 | $ | 433 | ||||
| Gulfstream - 50% |
348 | 355 | ||||||
| Laurel Mountain - 51% (1) |
444 | 291 | ||||||
| Discovery - 60% (1) |
350 | 182 | ||||||
| Other |
204 | 122 | ||||||
|
|
|
|
|
|||||
| $ | 1,800 | $ | 1,383 | |||||
|
|
|
|
|
|||||
| (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 investments and the underlying equity in the net assets of the investees is $59 million at December 31, 2012, primarily related to impairments we previously recognized. These differences are amortized over the expected remaining life of the investees’ underlying assets.
Our equity-method investees’ organizational documents generally require distribution of available cash to equity holders on a quarterly basis. We generally fund our portion of significant expansion or development projects of these investees through additional capital contributions. As of December 31, 2012, our proportionate share of amounts remaining to be spent for specific capital projects already in progress for Discovery and Laurel Mountain totaled $189 million and $55 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.) We contributed $169 million to Discovery in 2012 and $174 million, $137 million and $43 million to Laurel Mountain in 2012, 2011, and 2010, respectively. In addition, in September 2010, we purchased an additional 49 percent ownership interest in OPPL for $424 million.
Dividends and distributions, including those presented below, received from companies accounted for by the equity method were $172 million, $169 million, and $133 million in 2012, 2011, and 2010, respectively. These transactions reduced the carrying value of our investments. These dividends and distributions primarily included:
| Years Ended December 31, | ||||||||||||
|
2012 |
2011 |
2010 |
||||||||||
|
|
|
|||||||||||
| (Millions) | ||||||||||||
| Gulfstream |
$ | 78 | $ | 60 | $ | 39 | ||||||
| Discovery |
21 | 40 | 44 | |||||||||
| Aux Sable Liquid Products L.P. |
28 | 35 | 28 | |||||||||
| OPPL |
28 | 19 | - | |||||||||
57
WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Summarized Financial Position and Results of Operations of All Equity Method Investments
| December 31, | ||||||||
|
2012 |
2011 |
|||||||
|
|
|
|||||||
| (Millions) | ||||||||
| Current assets |
$ | 366 | $ | 293 | ||||
| Noncurrent assets |
5,225 | 4,409 | ||||||
| Current liabilities |
247 | 235 | ||||||
| Noncurrent liabilities |
1,301 | 1,257 | ||||||
| Years Ended December 31, | ||||||||||||
|
2012 |
2011 |
2010 |
||||||||||
|
|
|
|||||||||||
| (Millions) | ||||||||||||
| Gross revenue |
$ | 1,213 | $ | 1,242 | $ | 1,050 | ||||||
| Operating income |
378 | 535 | 506 | |||||||||
| Net income |
309 | 460 | 402 | |||||||||
Note 6. Asset Sales and Other Accruals
The following table presents significant gains or losses reflected in other (income) expense – net within costs and expenses.
| Years Ended December 31, | ||||||||||||
|
2012 |
2011 |
2010 |
||||||||||
| (Millions) | ||||||||||||
| Atlantic-Gulf |
||||||||||||
| Project feasibility costs |
$ | 21 | $ | 10 | $ | 8 | ||||||
| Capitalization of project feasibility costs previously expensed |
(19 | ) | (11 | ) | - | |||||||
| Accrual of regulatory liability related to overcollection of certain employee expenses |
4 | 9 | 10 | |||||||||
| Gain on sale of certain assets |
(6 | ) | - | - | ||||||||
| Involuntary conversion gains |
- | - | (14 | ) | ||||||||
| West |
||||||||||||
| Capitalization of project feasibility costs previously expensed |
- | - | (1 | ) | ||||||||
| Gain on sale of certain assets |
- | - | (12 | ) | ||||||||
| Involuntary conversion gains |
- | (3 | ) | (4 | ) | |||||||
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.
Additional Item
We detected a leak in an underground cavern at our Eminence Storage Field in Mississippi on December 28, 2010. We recorded $2 million, $15 million, and $5 million of charges to operating and maintenance expenses at Atlantic-Gulf during 2012, 2011, and 2010, respectively, primarily related to assessment and monitoring costs incurred to ensure the safety of the surrounding area.
58
WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Note 7. 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.
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 2012, 2011 and 2010 totaled $41 million, $32 million and $31 million, respectively. At the total Williams plan level, the pension plans had a projected benefit obligation of $1.5 billion and $1.4 billion at December 31, 2012 and 2011, respectively. The plans were underfunded by $478 million and $476 million at December 31, 2012 and 2011, 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 cost charged to us by Williams of $4 million in 2012, and a net periodic postretirement benefit credited to us by Williams of $2 million and $4 million for 2011 and 2010, respectively. At the total Williams plan level, the postretirement benefit plans had an accumulated postretirement benefit obligation of $331 million and $339 million at December 31, 2012 and 2011, respectively. The plans were underfunded by $156 million and $180 million at December 31, 2012 and 2011, 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 revenues and collected or refunded through future rate adjustments. A regulatory asset can be recorded only to the extent it is currently funded.
Defined contribution plan
Williams charged us compensation expense of $18 million, $16 million and $15 million in 2012, 2011 and 2010, respectively, for Williams’ matching contributions to this plan.
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, included in SG&A, for the years ended December 31, 2012, 2011 and 2010 was $12 million, $10 million and $12 million, respectively.
59
WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Note 8. Inventories
| December 31, | December 31, | |||||||
|
2012 |
2011 | |||||||
| (Millions) | ||||||||
| Natural gas liquids, olefins, and natural gas in underground storage |
$ | 96 | $ | 99 | ||||
| Materials, supplies, and other |
77 | 70 | ||||||
|
|
|
|
|
|||||
| $ | 173 | $ | 169 | |||||
|
|
|
|
|
|||||
Note 9. Property, Plant and Equipment
| Estimated | Depreciation | |||||||||||||
|
Useful Life (a) |
Rates (a) |
December 31, | ||||||||||||
|
(Years) |
(%) | 2012 | 2011 | |||||||||||
| (Millions) | ||||||||||||||
| Nonregulated: |
||||||||||||||
| Natural gas gathering and processing facilities |
5 - 40 | $ | 7,000 | $ | 6,024 | |||||||||
| Construction in progress |
(b) | 1,599 | 353 | |||||||||||
| Other |
3 - 45 | 745 | 500 | |||||||||||
| Regulated: |
||||||||||||||
| Natural gas transmission facilities |
1.01 - 6.82 | 9,963 | 9,593 | |||||||||||
| Construction in progress |
(b) | 337 | 199 | |||||||||||
| Other |
.18 - 33.33 | 1,418 | 1,391 | |||||||||||
|
|
|
|
|
|||||||||||
| Total property, plant, and equipment, at cost |
$ | 21,062 | $ | 18,060 | ||||||||||
| Accumulated depreciation and amortization |
(6,775) | (6,238) | ||||||||||||
|
|
|
|
|
|||||||||||
| Property, plant, and equipment - net |
$ | 14,287 | $ | 11,822 | ||||||||||
|
|
|
|
|
|||||||||||
| (a) | Estimated useful life and depreciation rates are presented as of December 31, 2012. Depreciation rates for regulated assets are prescribed by the FERC. |
| (b) | Construction in progress balances not yet subject to depreciation. |
Depreciation and amortization expense for property, plant and equipment – net was $670 million, $618 million and $577 million in 2012, 2011 and 2010, respectively.
Regulated property, plant and equipment – net includes approximately $825 million and $865 million at December 31, 2012 and 2011, 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
60
WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
facilities, to dismantle offshore platforms, to cap certain gathering pipelines at the wellhead connection and remove any related surface equipment, and to remove certain components of gas transmission facilities from the ground.
The following table presents the significant changes to our asset retirement obligations:
| December 31, | ||||||||
|
2012 |
2011 | |||||||
|
(Millions) |
||||||||
| Beginning balance |
$ | 570 | $ | 496 | ||||
| Liabilities incurred |
8 | 4 | ||||||
| Liabilities settled |
(44) | (46) | ||||||
| Accretion expense |
43 | 39 | ||||||
| Revisions(1) |
(1) | 77 | ||||||
|
|
|
|
|
|||||
| Ending balance |
$ | 576 | $ | 570 | ||||
|
|
|
|
|
|||||
| (1) | The 2012 revision primarily reflects a decrease in removal cost estimates, which is among several factors 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 revision in 2011 is primarily due to increases in the inflation rate and estimated removal costs. The 2012 and 2011 revisions also include increases of $13 million and $39 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. |
Pursuant to its 2008 rate case settlement, Transco deposits a portion of its collected rates into an external trust (ARO Trust) that is specifically designated to fund future AROs. Transco was also required to make annual deposits into the trust through 2012. (See Note 13.)
61
WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Note 10. Regulatory Assets and Liabilities
The regulatory assets and regulatory liabilities included in the Consolidated Balance Sheet at December 31, 2012 and 2011 are as follows:
| December 31, | ||||||||
|
2012 |
2011 | |||||||
| (Millions) | ||||||||
| Regulatory assets: |
||||||||
| Grossed-up deferred taxes on equity funds used during construction |
$ | 100 | $ | 103 | ||||
| Asset retirement obligations |
135 | 122 | ||||||
| Fuel cost |
30 | 26 | ||||||
| Levelized incremental depreciation |
34 | 33 | ||||||
| Other |
16 | 24 | ||||||
|
|
|
|
|
|||||
| $ | 315 | $ | 308 | |||||
|
|
|
|
|
|||||
| Regulatory liabilities: |
||||||||
| Negative salvage |
$ | 204 | $ | 158 | ||||
| Postretirement benefits other than pension |
42 | 39 | ||||||
| Other |
19 | 9 | ||||||
|
|
|
|
|
|||||
| $ | 265 | $ | 206 | |||||
|
|
|
|
|
|||||
Regulatory assets are included in regulatory assets and regulatory assets, deferred charges and other. Regulatory liabilities are included in other accrued liabilities and regulatory liabilities, deferred income and other. Our regulatory asset and liability balances are recoverable or reimbursable over various periods.
Grossed-up deferred taxes on equity funds used during construction: Regulatory asset balance established to offset the deferred tax for the equity component of the allowance for funds used during the construction of long-lived assets. All amounts were generated during the periods the gas pipelines were taxable entities. Taxes on capitalized funds used during construction and the offsetting deferred income taxes are included in the rate base and are recovered over the depreciable lives of the long lived asset to which they relate.
Asset retirement obligations: Regulatory balance established to offset depreciation of the ARO asset and changes in the ARO liability due to passage of time. The regulatory asset is being recovered through our rates, and is being amortized to expense consistent with the amounts collected in rates.
Fuel cost: This amount represents the difference between the gas retained from our customers and the gas consumed in operations. These amounts are not included in the rate base but are expected to be recovered/refunded in subsequent annual fuel filing periods.
Levelized incremental depreciation: Levelized depreciation allows contract revenue streams to remain constant over the primary contract terms by recognizing lower than book depreciation in the early years and higher than book depreciation in later years. The depreciation component of the levelized incremental rates will equal the accumulated book depreciation by the end of the primary contract terms. The difference between levelized depreciation and straight-line book depreciation is recorded in a FERC approved regulatory asset or liability and is extinguished over the levelization period.
Negative salvage: Transco’s rates include a component designed to recover certain future retirement costs for which we are not required to record an asset retirement obligation. We record a regulatory liability representing the
62
WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
cumulative residual amount of recoveries through rates, and proceeds from the disposition of assets, net of expenditures associated with these retirement costs.
Postretirement benefits other than pension: We seek to recover the actuarially determined cost of postretirement benefits through rates that are set through periodic general rate filings. Any differences between the annual actuarially determined costs and amounts currently being recovered in rates are recorded as regulatory assets or liabilities and collected or refunded through future rate adjustments. These amounts are not included in the rate base.
63
WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Note 11. Debt, Banking Arrangements, and Leases
Long- Term Debt
| December 31, | ||||||||
|
2012 |
2011 |
|||||||
| (Millions) | ||||||||
| Unsecured: |
||||||||
| Transco: |
||||||||
| 8.875% Notes due 2012 |
$ | - | $ | 325 | ||||
| 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 | - | ||||||
| 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 | - | ||||||
| 6.3% Notes due 2040 |
1,250 | 1,250 | ||||||
| Revolving credit loans |
375 | - | ||||||
| Unamortized debt discount |
(16) | (16) | ||||||
|
|
|
|
|
|||||
| Total long-term debt, including current portion |
8,437 | 7,237 | ||||||
| Long-term debt due within one year |
- | (324) | ||||||
|
|
|
|
|
|||||
| Long-term debt |
$ | 8,437 | $ | 6,913 | ||||
|
|
|
|
|
|||||
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.
Credit Facility
In September 2012, we amended our existing $2 billion senior unsecured revolving credit facility to increase the aggregate commitments by $400 million. The maturity date of the amended credit facility is June 3, 2016. This credit facility was also amended to provide that we may request an additional $400 million increase in commitments to be available under certain conditions in the future. This credit facility includes Transco and Northwest Pipeline as
64
WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
co-borrowers and is only available to named borrowers. The full amount of the credit facility is available to us to the extent not otherwise utilized by Transco and Northwest Pipeline. Transco and Northwest Pipeline each have access to borrow up to $400 million under the credit facility to the extent not otherwise utilized by the other co-borrowers. Significant financial covenants include:
| • | 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; |
| • | 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, 2012, we are in compliance with these financial covenants.
Each time funds are borrowed, a 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. We are required to pay a commitment fee (currently 0.20 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. The credit facility contains various covenants that 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.
The credit facility includes customary events of default. 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.
Letter of credit capacity under our credit facility is $1.3 billion. At December 31, 2012, no letters of credit have been issued and $375 million of loans are outstanding under the credit facility.
Issuances and Retirements
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. A portion of these proceeds was used to repay Transco’s $325 million 8.875 percent senior unsecured notes that matured on July 15, 2012. 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.
In August 2011, Transco issued $375 million of 5.4 percent senior unsecured notes due 2041 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 February 2012 and completed in March 2012.
65
WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Other Debt Disclosures
As of December 31, 2012, aggregate minimum maturities of long-term debt (excluding unamortized discount) for each of the next five years are as follows:
| (Millions) | ||||
| 2013 |
$ | - | ||
| 2014 |
$ | - | ||
| 2015 |
$ | 750 | ||
| 2016 |
$ | 750 | ||
| 2017 |
$ | 785 | ||
Cash payments for interest were $417 million in 2012, $398 million in 2011, and $310 million in 2010.
Leases-Lessee
The future minimum annual rentals under non-cancelable operating leases as of December 31, 2012, are payable as follows:
| (Millions) | ||||
| 2013 |
$ | 39 | ||
| 2014 |
34 | |||
| 2015 |
32 | |||
| 2016 |
28 | |||
| 2017 |
25 | |||
| Thereafter |
136 | |||
|
|
|
|||
| Total |
$ | 294 | ||
|
|
|
|||
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 midstream 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 $45 million in 2012, $37 million in 2011, and $34 million in 2010.
Note 12. Partners’ Capital
At December 31, 2012 and 2011, the public held 30 percent and 25 percent, respectively, of our total units outstanding, and affiliates of Williams held the remaining units. Transactions which occurred during 2011 and 2012 are summarized below.
In May 2011, we acquired a 24.5 percent interest in Gulfstream from a subsidiary of Williams. In connection with this transaction, we issued 632,584 of our common units.
On January 30, 2012, we issued 7,000,000 common units representing limited partner interests in us at a price of $62.81 per unit. The net proceeds were used to fund capital expenditures and for other partnership purposes.
On February 17, 2012, we closed the Laser Acquisition. In connection with this transaction, we issued 7,531,381 of our common units. (See Note 2.)
66
WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
On February 28, 2012, we sold an additional 1,050,000 common units, at a price of $62.81 per unit, to the underwriters upon the underwriters’ exercise of their option to purchase additional common units pursuant to our common unit offering in January 2012. The net proceeds were used for general partnership purposes.
On April 10, 2012, we issued 10,000,000 common units representing limited partner interests at a price of $54.56 per unit. On April 26, 2012, we sold an additional 973,368 common units at a price of $54.56 per unit to the underwriters upon the underwriters’ exercise of their option to purchase additional common units. The net proceeds were used for general partnership purposes, including the funding of a portion of the cash purchase price of the Caiman Acquisition. (See Note 2.) We also used $1 billion in proceeds from the April 27, 2012, sale of 16,360,133 common units to Williams to partially fund the Caiman Acquisition.
On April 27, 2012, we closed the Caiman Acquisition. In connection with this transaction, we issued 11,779,296 of our common units. (See Note 2.)
On June 14, 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.)
On August 13, 2012, we completed an equity issuance of 8,500,000 common units representing limited partner interests at a price of $51.43 per unit. On August 20, 2012, we sold an additional 1,275,000 common units at a price of $51.43 per unit to the underwriters upon the underwriters’ exercise of their option to purchase additional common units. The net proceeds were used to repay amounts outstanding under our revolving credit facility and for general partnership purposes.
On November 5, 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.)
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. |
67
WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
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:
| General | ||||
| Quarterly Distribution Target Amount (per unit) |
Unitholders | 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 | ||
Williams has agreed to temporarily waive its IDRs related to the common units it received and for those issued to the seller of Caiman Eastern Midstream, LLC, in connection with our acquisition of that entity, through 2013. In connection with the Geismar Acquisition, Williams also agreed to waive $16 million per quarter of IDRs until the later of December 31, 2013 or 30 days after the Geismar plant expansion is operational.
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.
68
WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Note 13. Fair Value Measurements
The following table presents, by level within the fair value hierarchy, certain of our financial assets and liabilities. The carrying values of cash and cash equivalents, accounts receivable and accounts payable approximate fair value because of the short-term nature of these instruments. Therefore, these assets and liabilities are not presented in the following table.
| Fair Value Measurements Using | ||||||||||||||||||||
| Quoted
|
||||||||||||||||||||
| Prices In
|
||||||||||||||||||||
| Active
|
Significant
|
|||||||||||||||||||
| Markets for
|
Other
|
Significant
|
||||||||||||||||||
| Identical
|
Observable
|
Unobservable
|
||||||||||||||||||
| Carrying | Fair | Assets | Inputs | Inputs | ||||||||||||||||
|
Amount |
Value |
(Level 1) |
(Level 2) |
(Level 3) |
||||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||
| (Millions)
|
||||||||||||||||||||
| 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 | ) | - | ||||||||||||
| Assets (liabilities) at December 31, 2011: |
||||||||||||||||||||
|
Measured on a recurring basis: |
||||||||||||||||||||
| ARO Trust investments |
$ | 25 | $ | 25 | $ | 25 | $ | - | $ | - | ||||||||||
| Energy derivatives assets not designated as hedging instruments |
1 | 1 | 1 | - | - | |||||||||||||||
| Additional disclosures: |
||||||||||||||||||||
| Notes receivable and other |
10 | 10 | N/A | N/A | N/A | |||||||||||||||
| Long-term debt, including current portion |
(7,237 | ) | (8,170 | ) | N/A | N/A | N/A | |||||||||||||
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 2008 rate case settlement, into an external trust (ARO 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 net asset values, 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.
69
WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Energy derivatives: Energy derivatives include commodity based exchange-traded contracts and over-the-counter (OTC) contracts, which consist of physical forwards, futures, and swaps that are measured at fair value on a recurring basis. The fair value amounts are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under the terms of our master netting arrangements. Further, the amounts do not include cash held on deposit in margin accounts that we have received or remitted to collateralize certain derivative positions. Energy derivatives assets are reported in other current assets and regulatory assets, deferred charges, and other in the Consolidated Balance Sheet. Energy derivatives liabilities are reported in 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, 2012 or 2011.
Additional fair value disclosures
Notes receivable and other: The disclosed fair value of our notes receivable is 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, 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.
Note 14. Derivative Instruments and Concentration of Credit Risk
Energy Commodity Derivatives
Risk management activities
We are exposed to market risk from changes in energy commodity prices within our operations. We utilize derivatives to manage our exposure to the variability in expected future cash flows from forecasted purchases and/or sales of natural gas, NGLs and olefins attributable to commodity price risk. The energy commodity derivatives in our current portfolio have not been designated as cash flow hedges or do not qualify for hedge accounting despite hedging our future cash flows on an economic basis.
We produce and sell NGLs and olefins at different locations throughout the United States. We also buy natural gas to satisfy the required fuel and shrink needed to generate NGLs. In addition, we buy NGLs as feedstock to generate olefins. To reduce exposure to a decrease in revenues from fluctuations in NGL and olefin market prices or increases in costs and operating expenses from fluctuations in natural gas and NGL market prices, we may enter into NGL, olefin or natural gas swap agreements, futures contracts, financial or physical forward contracts, and financial
70
WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
option contracts to mitigate the price risk on forecasted sales of NGLs and olefins and purchases of natural gas and NGLs. Those designated as cash flow hedges are expected to be highly effective in offsetting cash flows attributable to the hedged risk during the term of the hedge. However, ineffectiveness may be recognized primarily as a result of locational differences between the hedging derivative and the hedged item.
Volumes
Our energy commodity derivatives are comprised of both contracts to purchase commodities (long positions) and contracts to sell commodities (short positions). Derivative transactions are categorized into two types:
| • | Central hub risk: Financial derivative exposures to Mont Belvieu for NGLs; |
| • | Basis risk: Financial and physical derivative exposures to the difference in value between the central hub and another specific delivery point. |
The following table depicts the notional quantities of the net long (short) positions in our commodity derivatives portfolio as of December 31, 2012. NGLs are presented in barrels.
| Unit of | Central Hub | |||||||||
| Derivative Notional Volumes |
Measure | Risk | Basis Risk | |||||||
| Not Designated as Hedging Instruments |
||||||||||
| NGL & Petchem Services |
Barrels | (185,000) | (38,256,000) | |||||||
Gains (losses)
The following table presents gains and losses for our energy commodity derivatives designated as cash flow hedges, as recognized in AOCI, product sales, or product costs.
| Years ended December 31, | ||||||||||
|
2012 |
2011 |
Classification | ||||||||
| (Millions)
|
||||||||||
| Net gain (loss) recognized in other comprehensive income (loss) (effective portion) |
$ | 30 | $ | (18 | ) | AOCI | ||||
| Net gain (loss) reclassified from accumulated other comprehensive income (loss) into income (effective portion) |
$ | 30 | $ | (18 | ) | Product Sales or Product Costs | ||||
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, by product or service at December 31, 2012 and 2011:
71
WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
| December 31, | ||||||||||
|
2012 |
2011 | |||||||||
|
(Millions)
|
||||||||||
| Receivables by product or service: |
||||||||||
| Sale of NGLs and related products and services |
$ | 393 | $ | 404 | ||||||
| Transportation of natural gas and related products |
|
169 |
|
160 | ||||||
|
|
|
|
|
|||||||
| Total |
$ | 562 | $ | 564 | ||||||
|
|
|
|
|
|||||||
Customers include producers, distribution companies, industrial users, gas marketers and pipelines primarily located in the central, eastern and northwestern United States, Rocky Mountains and the Gulf Coast. As a general policy, collateral is not required for receivables, but customers’ financial condition and credit worthiness are evaluated regularly.
Revenues
In 2012, 2011 and 2010, we had one customer in our NGL & Petchem Services segment that accounted for 14 percent, 17 percent, and 15 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 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, 2012, we have accrued liabilities totaling $17 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. Most 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, and one hour nitrogen dioxide emission limits. 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 biphenyl, 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
72
WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Superfund waste sites. At December 31, 2012, we have accrued liabilities of $10 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, 2012, we have accrued liabilities totaling $7 million for these costs.
Rate Matters
On August 31, 2006, Transco submitted to the FERC a general rate filing (Docket No. RP06-569) principally designed to recover increased costs. The rates became effective March 1, 2007, subject to refund and the outcome of a hearing. All issues in this proceeding except one have been resolved by settlement.
The one issue reserved for litigation or further settlement relates to Transco’s proposal to change the design of the rates for service under one of its storage rate schedules, which was implemented subject to refund on March 1, 2007. A hearing on that issue was held before a FERC Administrative Law Judge (ALJ) in July 2008. In November 2008, the ALJ issued an initial decision in which he determined that Transco’s proposed incremental rate design is unjust and unreasonable. On January 21, 2010, the FERC reversed the ALJ’s initial decision, and approved our proposed incremental rate design. Certain parties have sought rehearing of the FERC’s order and, on April 2, 2012, the FERC denied the rehearing request. On June 1, 2012, one party filed an appeal in the U.S. Court of Appeals for the D.C. Circuit challenging the FERC’s orders approving our rate design proposal.
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 $1.2 billion at December 31, 2012.
73
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.)
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, and equity earnings (losses). 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. 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.
74
WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The following table reflects the reconciliation of segment revenues and segment profit (loss) to 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) | ||||||||||||||||||||||||
| 2012 |
||||||||||||||||||||||||
| Segment revenues: |
||||||||||||||||||||||||
| Service revenues |
||||||||||||||||||||||||
| External |
$ | 168 | $ | 1,371 | $ | 1,067 | $ | 103 | $ | - | $ | 2,709 | ||||||||||||
| Internal |
- | 12 | 5 | - | (17) | - | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Total service revenues |
168 | 1,383 | 1,072 | 103 | (17) | 2,709 | ||||||||||||||||||
| Product sales |
||||||||||||||||||||||||
| External |
2 | 709 | 40 | 3,860 | - | 4,611 | ||||||||||||||||||
| Internal |
- | 363 | 1,089 | 258 | (1,710) | - | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Total product sales |
2 | 1,072 | 1,129 | 4,118 | (1,710) | 4,611 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Total revenues |
$ | 170 | $ | 2,455 | $ | 2,201 | $ | 4,221 | $ | (1,727) | $ | 7,320 | ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Segment profit (loss) |
$ | (37) | $ | 574 | $ | 980 | $ | 295 | $ | - | $ | 1,812 | ||||||||||||
| Less equity earnings (losses) |
(23) | 92 | - | 42 | - | 111 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Segment operating income (loss) |
$ | (14) | $ | 482 | $ | 980 | $ | 253 | $ | - | 1,701 | |||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
| General corporate expenses |
(184) | |||||||||||||||||||||||
|
|
|
|||||||||||||||||||||||
| Operating income |
$ | 1,517 | ||||||||||||||||||||||
|
|
|
|||||||||||||||||||||||
| Other financial information: |
||||||||||||||||||||||||
| Depreciation and amortization |
$ | 76 | $ | 381 | $ | 234 | $ | 23 | - | $ | 714 | |||||||||||||
| 2011 |
||||||||||||||||||||||||
| Segment revenues: |
||||||||||||||||||||||||
| Service revenues |
||||||||||||||||||||||||
| External |
$ | 49 | $ | 1,332 | $ | 1,053 | $ | 83 | $ | - | $ | 2,517 | ||||||||||||
| Internal |
- | - | 4 | - | (4) | - | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Total service revenues |
49 | 1,332 | 1,057 | 83 | (4) | 2,517 | ||||||||||||||||||
| Product sales |
||||||||||||||||||||||||
| External |
- | 606 | 11 | 4,580 | - | 5,197 | ||||||||||||||||||
| Internal |
- | 531 | 1,622 | 56 | (2,209) | - | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Total product sales |
- | 1,137 | 1,633 | 4,636 | (2,209) | 5,197 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Total revenues |
$ | 49 | $ | 2,469 | $ | 2,690 | $ | 4,719 | $ | (2,213) | $ | 7,714 | ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Segment profit (loss) |
$ | 23 | $ | 585 | $ | 1,181 | $ | 246 | $ | - | $ | 2,035 | ||||||||||||
| Less equity earnings (losses) |
(1) | 90 | - | 53 | - | 142 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Segment operating income (loss) |
$ | 24 | $ | 495 | $ | 1,181 | $ | 193 | $ | - | 1,893 | |||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
| General corporate expenses |
(118) | |||||||||||||||||||||||
|
|
|
|||||||||||||||||||||||
| Operating income |
$ | 1,775 | ||||||||||||||||||||||
|
|
|
|||||||||||||||||||||||
| Other financial information: |
||||||||||||||||||||||||
| Depreciation and amortization |
$ | 5 | $ | 365 | $ | 236 | $ | 15 | - | $ | 621 | |||||||||||||
75
WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
| Northeast
G&P |
Atlantic-Gulf | West | NGL &
Petchem
Services |
Eliminations | Total | |||||||||||||||||||
| (Millions) | ||||||||||||||||||||||||
| 2010 |
||||||||||||||||||||||||
| Segment revenues: |
||||||||||||||||||||||||
| Service revenues |
||||||||||||||||||||||||
| External |
$ | 2 | $ | 1,259 | $ | 1,015 | $ | 70 | $ | - | $ | 2,346 | ||||||||||||
| Internal |
- | - | 4 | - | (4) | - | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Total service revenues |
2 | 1,259 | 1,019 | 70 | (4) | 2,346 | ||||||||||||||||||
| Product sales |
||||||||||||||||||||||||
| External |
- | 586 | 51 | 3,476 | - | 4,113 | ||||||||||||||||||
| Internal |
- | 377 | 1,218 | 5 | (1,600) | - | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Total product sales |
- | 963 | 1,269 | 3,481 | (1,600) | 4,113 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Total revenues |
$ | 2 | $ | 2,222 | $ | 2,288 | $ | 3,551 | $ | (1,604) | $ | 6,459 | ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Segment profit (loss) |
$ | - | $ | 560 | $ | 934 | $ | 172 | $ | - | $ | 1,666 | ||||||||||||
| Less equity earnings (losses) |
4 | 73 | - | 32 | - | 109 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Segment operating income (loss) |
$ | (4) | $ | 487 | $ | 934 | $ | 140 | $ | - | 1,557 | |||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
| General corporate expenses |
(130) | |||||||||||||||||||||||
|
|
|
|||||||||||||||||||||||
| Operating income |
$ | 1,427 | ||||||||||||||||||||||
|
|
|
|||||||||||||||||||||||
| Other financial information: |
||||||||||||||||||||||||
| Depreciation and amortization |
$ | - | $ | 345 | $ | 219 | $ | 14 | - | $ | 578 | |||||||||||||
76
WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The following table reflects total assets, investments, and additions to long-lived assets by reporting segment.
| Total Assets
at December 31, |
Investments
at December 31, |
Additions to Long-Lived Assets
at December 31, |
||||||||||||||||||||||||||
|
2012 |
2011 |
2012 |
2011 |
2012 |
2011 |
2010 |
||||||||||||||||||||||
| (Millions) | ||||||||||||||||||||||||||||
| Northeast G&P (1) |
$ | 4,745 | $ | 669 | $ | 511 | $ | 291 | $ | 3,909 | $ | 204 | $ | 172 | ||||||||||||||
| Atlantic-Gulf |
8,734 | 7,992 | 774 | 615 | 1,002 | 650 | 442 | |||||||||||||||||||||
| West |
4,688 | 4,649 | - | - | 360 | 301 | 262 | |||||||||||||||||||||
| NGL & Petchem Services |
1,500 | 1,229 | 515 | 477 | 282 | 103 | 27 | |||||||||||||||||||||
| Other corporate assets |
409 | 461 | - | - | 16 | 25 | 11 | |||||||||||||||||||||
| Eliminations (2) |
(367) | (328) | - | - | - | - | - | |||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
| Total |
$ | 19,709 | $ | 14,672 | $ | 1,800 | $ | 1,383 | $ | 5,569 | $ | 1,283 | $ | 914 | ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
| (1) | 2012 increased primarily due to the Caiman and Laser Acquisitions. (See Note 2.) |
| (2) | Eliminations primarily relate to the intercompany accounts receivable generated by our cash management program. |
Note 17. Subsequent Events (Unaudited)
Information Subsequent to Date of Report of Independent Registered Public Accounting Firm
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 revolver. Following the completion of these transactions, Williams now owns an approximate 66 percent limited partner interest and a 2 percent general partner interest in us.
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 will vary but may not exceed 397 days from the date of issuance. The commercial paper notes will be sold under customary terms in the commercial paper market and will be issued at a discount from par, or, alternatively, will be sold at par and bear varying interest rates on a fixed or floating basis. Proceeds from these notes are expected to be used to fund planned capital expenditures and for other general partnership purposes. We have not yet issued any notes under this commercial paper program.
On April 1, 2013, a third party contributed $187 million to Gulfstar in exchange for a 49 percent ownership interest in Gulfstar. This contribution was based on 49 percent of our estimated cumulative net investment at that date, subject to adjustment within 60 days of the contribution date. The $187 million was then distributed to us. (See Note 1.)
On May 10, 2013, we paid a cash distribution of $0.8475 per unit on our outstanding common units to unitholders of record at the close of business on May 3, 2013. The total cash distributed was $473 million.
As of May 13, 2013, $630 million of loans are outstanding under our credit facility.
77
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) | ||||||||||||||||
| 2012 |
||||||||||||||||
| Revenues |
$ | 1,968 | $ | 1,817 | $ | 1,717 | $ | 1,818 | ||||||||
| Product costs |
974 | 907 | 781 | 864 | ||||||||||||
| Net income |
408 | 243 | 290 | 291 | ||||||||||||
| Basic and diluted net income per common unit |
0.85 | 0.29 | 0.38 | 0.42 | ||||||||||||
| 2011 |
||||||||||||||||
| Revenues |
$ | 1,813 | $ | 1,936 | $ | 1,920 | $ | 2,045 | ||||||||
| Product costs |
930 | 991 | 978 | 1,052 | ||||||||||||
| Net income |
342 | 379 | 378 | 412 | ||||||||||||
| Basic and diluted net income per common unit |
0.81 | 0.91 | 0.91 | 1.05 | ||||||||||||
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.
We have changed the basis for presenting our Consolidated Statement of Comprehensive Income. This included separating costs and operating expenses into product costs, operating and maintenance expenses, and depreciation and amortization expenses. (See Note 1 of Notes to Consolidated Financial Statements.)
On November 5, 2012, we closed the Geismar Acquisition. Summarized quarterly financial data has been retrospectively adjusted to reflect the consolidation of the historical results of the Geismar Acquisition throughout the periods presented. The acquisition did not impact historical earnings per unit as pre-acquisition earnings were allocated to our general partner. Additionally, certain amounts previously reported in selling, general, and administrative expenses were reclassified to operating and maintenance expenses to conform to the current presentation. (See Note 1.) The increases to amounts previously reported were as follows:
| First Quarter |
Second Quarter |
Third Quarter |
Fourth Quarter |
|||||||||||||
| (Millions) | ||||||||||||||||
| 2012 |
||||||||||||||||
| Revenues |
$ | 283 | $ | 234 | $ | 190 | N/A | |||||||||
| Costs and operating expenses |
219 | 178 | 129 | N/A | ||||||||||||
| Net income |
60 | 50 | 53 | N/A | ||||||||||||
| 2011 |
||||||||||||||||
| Revenues |
$ | 234 | $ | 265 | $ | 247 | $ | 239 | ||||||||
| Costs and operating expenses |
198 | 218 | 206 | 219 | ||||||||||||
| Net income |
35 | 41 | 36 | 21 | ||||||||||||
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 6.) |
| • | $11 million of reorganization-related costs, including consulting costs, allocated to us from Williams. (See Note 4.) |
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.)
2011
Net income for first-quarter 2011 includes $11 million related to the reversal of project feasibility costs from expense to capital at Atlantic-Gulf. (See Note 6.)
78