EXHIBIT 99.1
Item 6.Selected Financial Data
The following financial data at December 31, 2009 and 2008, and for each of the three years in the period ended December 31, 2009 is derived from our audited financial statements included in Item 8 of this Exhibit 99.1 and should be read in conjunction with the other financial information included in this Exhibit 99.1. The following financial data at December 31, 2007, 2006, and 2005, and for the years ended December 31, 2006 and 2005, has been prepared from our accounting records. As described in Item 8.01 of this Exhibit 99.1, certain of our historical periods results of operations and balances have been retrospectively adjusted as a result of the Dropdown.
2009 | 2008 | 2007 | 2006 | 2005 | ||||||||||||||||||||
(Millions, except per-unit amounts) | ||||||||||||||||||||||||
Revenues | $ | 4,512 | $ | 5,762 | $ | 5,616 | $ | 4,711 | $ | 3,994 | ||||||||||||||
Income before cumulative effect of change in accounting principle | 1,031 | 2,102 | 1,449 | 822 | 553 | |||||||||||||||||||
Net income | 1,031 | 2,102 | 1,449 | 822 | 552 | |||||||||||||||||||
Net income attributable to controlling interests | 1,004 | 2,077 | 1,449 | 822 | 552 | |||||||||||||||||||
Income before cumulative effect of change in accounting principle per limited partner unit: | ||||||||||||||||||||||||
Common unit | $ | 2.88 | $ | 3.08 | $ | 1.99 | $ | 1.73 | $ | .49 | (1) | |||||||||||||
Subordinated unit | N/A | N/A | $ | 1.99 | $ | 1.73 | $ | .49 | (1) | |||||||||||||||
Net income per limited partner unit: | ||||||||||||||||||||||||
Common unit | $ | 2.88 | $ | 3.08 | $ | 1.99 | $ | 1.73 | $ | .44 | (1) | |||||||||||||
Subordinated unit | N/A | N/A | $ | 1.99 | $ | 1.73 | $ | .44 | (1) | |||||||||||||||
Total assets at December 31 | $ | 11,984 | $ | 11,676 | $ | 11,064 | $ | 10,297 | $ | 9,473 | ||||||||||||||
Short-term notes payable and long-term debt due within one year at December 31 | 15 | — | 75 | 253 | 8 | |||||||||||||||||||
Long-term debt at December 31 (2) | 2,981 | 2,971 | 2,821 | 2,386 | 1,513 | |||||||||||||||||||
Total equity at December 31 | 7,627 | 7,389 | 5,867 | 5,472 | 5,991 | |||||||||||||||||||
Cash dividends declared per unit | $ | 2.540 | $ | 2.435 | $ | 2.045 | $ | 1.605 | $ | 0.1484 |
(1) | Commencing on August 23, 2005, the date of our initial public offering. | |
(2) | Does not reflect borrowings entered into in February 2010 related to the Dropdown. |
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Item 7.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Please read the following discussion of our financial condition and results of operations in conjunction with the supplemental consolidated financial statements and related notes included elsewhere herein. |
Recent Developments
The Dropdown
On February 17, 2010, we closed a transaction with our general partner, our operating company, The Williams Companies, Inc. (Williams) and certain subsidiaries of Williams, pursuant to which Williams contributed to us the ownership interests in the entities that make up Williams’ Gas Pipeline and Midstream Gas & Liquids businesses, to the extent not already owned by us, including Williams’ limited and general partner interests in Williams Pipeline Partners L.P. (WMZ), but excluding Williams’ Canadian, Venezuelan and olefin operations and 25.5% of Gulfstream Natural Gas System, L.L.C. (Gulfstream). Such contributed entities are hereafter referred to as the “Contributed Entities.” This contribution was made in exchange for aggregate consideration of:
• | $3.5 billion in cash, less certain expenses incurred by us relating to our acquisition of the Contributed Entities. This cash consideration was financed through the private issuance of $3.5 billion of senior unsecured notes. | ||
• | 203 million of our Class C limited partnership units, which are identical to our common limited partnership units except that for the distribution with respect to the first quarter of 2010 they will receive a prorated quarterly distribution since they were not outstanding during the full quarterly period. The Class C units will automatically convert into our common limited partnership units following the record date for the distribution with respect to the first quarter of 2010. | ||
• | an increase in the capital account of our general partner to allow it to maintain its 2% general partner interest. |
The transactions described in the preceding paragraph are referred to as the “Dropdown.”
After the consummation of the Dropdown, our operations are divided into two business segments: Gas Pipeline and Midstream Gas & Liquids. All of the operations we conducted prior to the Dropdown are reported within the Midstream Gas & Liquids segment. The Contributed Entities’ business activities are included in our two business segments as follows:
• | Gas Pipeline includes Transcontinental Gas Pipe Line Company, LLC (Transco) and Northwest Pipeline GP (Northwest Pipeline), which own and operate a combined total of approximately 13,900 miles of pipelines with a total annual throughput of approximately 2,700 TBtu of natural gas and peak-day delivery capacity of approximately 12 MMdt of natural gas. Gas Pipeline also holds interests in joint venture interstate and intrastate natural gas pipeline systems including a 24.5% interest in Gulfstream, which owns an approximate 745-mile pipeline with the capacity to transport approximately 1.26 million Dth per day of natural gas. | ||
• | Midstream Gas & Liquids includes the natural gas gathering, processing and treating facilities located primarily in the Rocky Mountain and Gulf Coast regions of the United States and natural gas and crude oil gathering and transportation facilities in the Gulf Coast region of the United States. |
WMZ Exchange Offer
We have also announced our intention to launch an exchange offer for the publicly traded common units of WMZ at a future date (the WMZ Exchange Offer) at a fixed exchange ratio of 0.7584 of our common units for each WMZ common unit. The ratio is based on closing prices on the New York Stock Exchange on Friday, January 15, 2010, the business date before our intention to make the exchange offer was announced, of $23.35 for WMZ and $30.79 for us. The exact timing of the launch will be based upon the filing of necessary offering documents with the Securities and Exchange Commission and upon market conditions. Please read “Business and Properties — Recent Events — WMZ Exchange Offer” of our Annual Report filed on Form 10-K for the year ended December 31, 2009 for more information.
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New Credit Facility
In connection with the Dropdown, we entered into a new $1.75 billion senior unsecured revolving three-year credit facility with Transco and Northwest Pipeline, as co-borrowers with borrowing sublimits of $400 million each, and Citibank, N.A. as administrative agent, and other lenders named therein (New Credit Facility). The New Credit Facility replaced our previous $450 million senior unsecured credit agreement. At the closing of the Dropdown, we borrowed $250 million under the New Credit Facility to repay the term loan outstanding under our previously existing credit facility.
Overview of 2009
The following discussion of our results of operations reflects our business which has been recast to include the impacts of the Dropdown discussed above and as reflected in the supplemental consolidated financial statements and related notes included elsewhere herein.
Our operating results throughout the second half of 2009 demonstrated significant continued improvement from the difficult circumstances experienced during the last quarter of 2008 and the first half of 2009 when low NGL commodity prices and hurricane-related damages significantly decreased the profitability of our gathering and processing businesses. These circumstances resulted in lower operating income in 2009 compared to 2008. During 2009, Williams provided us with significant, additional support, which assisted us in maintaining a higher level of cash retention and a stronger overall liquidity position. Williams waived its incentive distribution rights (IDRs) related to the 2009 distribution periods. These waived IDRs represented approximately $29.0 million, on an annual basis. In addition, our omnibus agreement with Williams was amended to increase the aggregate amount of the credit we could receive related to certain general and administrative expenses for 2009. Williams’ additional support during 2009 combined with the improved commodity environment in the second half of 2009 allowed us to maintain our prior per-unit level of cash distributions throughout 2009.
Critical Accounting Policies and Estimates
Our financial statements reflect the selection and application of accounting policies that require management to make significant estimates and assumptions. The selection of these policies has been discussed with the audit committee of the board of directors of our general partner. We believe that the following are the more critical judgment areas in the application of our accounting policies that currently affect our financial condition and results of operations.
Impairments of Long-Lived Assets and Investments
We evaluate our long-lived assets for impairment when we believe events or changes in circumstances indicate that we may not be able to recover the carrying value. Our computations utilize judgments and assumptions that may include the estimated fair value of the asset, undiscounted future cash flows, discounted future cash flows, and the current and future economic environment in which the asset is operated.
In addition to those long-lived assets for which impairment charges were recorded (please read Note 5, Asset Sales, Impairments and Other Accruals, of our Notes to Supplemental Consolidated Financial Statements included elsewhere herein), certain others were reviewed for which no impairment was required. These reviews included certain of Midstream’s Gulf Coast assets, which were evaluated for impairment utilizing judgments and assumptions including future volumes, fees and margins. These underlying variables are subjective and susceptible to change. The use of alternate judgments and/or assumptions could result in the recognition of different levels of impairment charges in the supplemental consolidated financial statements. Based on our evaluation, we are not currently aware of any significant assets that are approaching impairment thresholds.
Contingent Liabilities
We record liabilities for estimated loss contingencies, including environmental matters, when we determine that a loss is probable and the amount of the loss can be reasonably estimated. Revisions to contingent liabilities are generally reflected in income when new or different facts or information become known or circumstances change that affect the previous assumptions with respect to the likelihood or amount of loss. Liabilities for contingent losses are based upon our assumptions and estimates and upon advice of legal counsel, engineers, or other third parties regarding the probable outcomes of the matter. As new developments occur or more
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information becomes available, our assumptions and estimates of these liabilities may change. Changes in our assumptions and estimates or outcomes different from our current assumptions and estimates could materially affect future results of operations for any particular quarterly or annual period. Please read Note 19, Contingent Liabilities and Commitments, in our Notes to Supplemental Consolidated Financial Statements included elsewhere herein.
Results of Operations
Consolidated Overview
The following table and discussion summarize our consolidated results of operations for the three years ended December 31, 2009 and reflect the consummation of the Dropdown. The results of operations by segment are discussed in further detail following this consolidated overview discussion and relate to the segment tables in Note 20, Segment Disclosures, in our Notes to Supplemental Consolidated Financial Statements included elsewhere herein.
Years Ended December 31, | ||||||||||||||||||||
% Change | % Change | |||||||||||||||||||
from | from | |||||||||||||||||||
2009 | 2008(1) | 2008 | 2007(1) | 2007 | ||||||||||||||||
(Millions) | ||||||||||||||||||||
Revenues | $ | 4,512 | (22 | )% | $ | 5,762 | +3 | % | $ | 5,616 | ||||||||||
Costs and expenses: | ||||||||||||||||||||
Costs and operating expenses | 3,031 | +27 | % | 4,143 | (6 | )% | 3,893 | |||||||||||||
Selling, general and administrative expense | 289 | (7 | )% | 270 | (3 | )% | 262 | |||||||||||||
Other (income) expense — net | (35 | ) | NM | 9 | NM | (20 | ) | |||||||||||||
General corporate expenses | 105 | (14 | )% | 92 | +6 | % | 98 | |||||||||||||
Total costs and expenses | 3,390 | +25 | % | 4,514 | (7 | )% | 4,233 | |||||||||||||
Operating income | 1,122 | (10 | )% | 1,248 | (10 | )% | 1,383 | |||||||||||||
Equity earnings | 81 | +7 | % | 76 | (4 | )% | 79 | |||||||||||||
Interest accrued — net | (201 | ) | +4 | % | (209 | ) | (4 | )% | (201 | ) | ||||||||||
Interest income | 20 | (20 | )% | 25 | — | 25 | ||||||||||||||
Other income — net | 13 | +30 | % | 10 | (47 | )% | 19 | |||||||||||||
Income before income taxes | 1,035 | (10 | )% | 1,150 | (12 | )% | 1,305 | |||||||||||||
Provision (benefit) for income taxes | 4 | NM | (952 | ) | NM | (144 | ) | |||||||||||||
Net income | 1,031 | (51 | )% | 2,102 | +45 | % | 1,449 | |||||||||||||
Less: Net income attributable to noncontrolling interests | 27 | (8 | )% | 25 | NM | — | ||||||||||||||
Net income attributable to controlling interests | $ | 1,004 | (52 | )% | $ | 2,077 | +43 | % | $ | 1,449 | ||||||||||
(1) | + = Favorable Change; ( ) = Unfavorable Change; NM = A percentage calculation is not meaningful due to change in signs, a zero-value denominator or a percentage change greater than 200. |
2009 vs. 2008
Our consolidated results in 2009 declined compared to 2008. These results reflect a rapid decline in energy commodity prices that began in the fourth quarter of 2008 as a result of the weakened economy. Energy commodity prices have generally improved during 2009, but not to levels experienced early in 2008.
Revenuesdecreased due primarily to lower commodity prices for NGL and crude oil sales and lower marketing revenues at Midstream.
Costs and operating expensesdecreased primarily due to lower commodity prices for NGL and crude oil marketing purchases and natural gas associated with NGL production at Midstream.
Selling, general and administrative expensesincreased due primarily to higher employee-related expenses.
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Other (income) expense — netwithinoperating incomein 2009 includes a $40 million gain on the sale of our Cameron Meadows NGL processing plant at Midstream.
Other (income) expense — netwithinoperating incomein 2008 includes:
• | Gain of $10 million on the sale of certain south Texas assets at Gas Pipeline; | ||
• | Income of $17 million resulting from involuntary conversion gains at Midstream; | ||
• | Expense of $23 million related to project development costs at Gas Pipeline; and | ||
• | Expense of $17 million related to impairments and other asset writedowns at Midstream. |
General corporate expensesallocated from Williams increased due primarily to higher Williams’ employee-related expenses.
The decrease inoperating incomegenerally reflects an overall unfavorable energy commodity price environment in 2009 compared to 2008 and other changes as previously discussed.
Provision (benefit) for income taxeschanged unfavorably due primarily to the impact in 2008 of Transco’s conversion to a single member limited liability company. As a result of that conversion, all of Transco’s deferred taxes were eliminated through income, and Transco no longer provided for income taxes. Please read Note 7, Provision (Benefit) for Income Taxes, of our Notes to Supplemental Consolidated Financial Statements included elsewhere herein for a reconciliation of the effective tax rates compared to the federal statutory rate for both years and a discussion of the conversion of Transco to a single member limited liability company.
2008 vs. 2007
Our income before income taxes for 2008 decreased compared to 2007. These results were influenced considerably by favorable results in the first three quarters of the year, followed by a sharp decline in the fourth quarter due to a rapid decline in energy commodity prices.
Revenuesincreased slightly due primarily to Midstream’s higher commodity sales prices and fee revenues, partially offset by lower volumes. In addition, Gas Pipeline’s transportation revenue increased following implementation of Transco’s new rates.
Costs and operating expensesincreased due primarily to Midstream’s higher natural gas costs associated with our NGL production businesses and higher repair costs, depreciation expense and employee-related expenses.
Other (income) expense — netwithinoperating incomein 2007 includes:
• | Income of $18 million associated with payments received for a terminated firm transportation agreement on Northwest Pipeline’s Grays Harbor lateral; | ||
• | Income of $17 million associated with a change in estimate related to a regulatory liability at Northwest Pipeline; | ||
• | Income of $12 million related to a favorable litigation outcome at Midstream; and | ||
• | Expense of $18 million related to impairments of offshore assets and other asset writedowns at Midstream. |
The decrease inoperating incomereflects decreasedoperating incomeat Midstream primarily due to a sharp decline in energy commodity prices in the latter part of 2008, combined with other changes previously discussed.
Provision (benefit) for income taxeschanged favorably due primarily to impacts in 2008 and 2007 of the conversion of Transco and Northwest Pipeline to single member limited liability companies on December 31, 2008 and October 1, 2007, respectively. As a result of the conversion, all deferred taxes were eliminated through income, and Transco and Northwest Pipeline no longer provided for income taxes. Please read Note 7, Provision (Benefit) for Income Taxes, of our Notes to Supplemental Consolidated Financial
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Statements included elsewhere herein for a reconciliation of the effective tax rates compared to the federal statutory rate for both years and a discussion of the conversion of Transco and Northwest Pipeline to single member limited liability companies.
Net income attributable to noncontrolling interestsincreased in 2008 due to WMZ’s initial public offering.
Results of Operations — Segment
In conjunction with the impacts of the Dropdown discussed above, we are now organized into Gas Pipeline and Midstream segments. Our management evaluates performance based on segment profit from operations.
Gas Pipeline
Overview
Gas Pipeline’s strategy to create value focuses on maximizing the utilization of our pipeline capacity by providing high quality, low cost transportation of natural gas to large and growing markets.
Gas Pipeline’s 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.
Gas Pipeline master limited partnership
At December 31, 2009, we own approximately 47.7% of WMZ, including 100% of the general partner and incentive distribution rights. Considering the presumption of control of the general partner, we consolidate WMZ within our Gas Pipeline segment. Gas Pipeline’s segment profit includes 100% of WMZ’s segment profit.
Significant events of 2009 include:
Completed Expansion Projects
Gulfstream Phase IV
In September 2007, our 24.5 percent-owned equity investee, Gulfstream, received FERC approval to construct 17.8 miles of 20-inch pipeline and to install a new compressor facility. The pipeline expansion was placed into service in the fourth quarter of 2008, and the compressor facility was placed into service in January 2009. The expansion increased capacity by 155 Mdt/d. Gulfstream’s cost of this project was $190 million.
Sentinel
In August 2008, we received FERC approval to construct an expansion in the northeast United States. The cost of the project was $229 million. We placed Phase I into service in December 2008 increasing capacity by 40 Mdt/d. Phase II provided an additional 102 Mdt/d and was placed into service in November 2009.
Colorado Hub Connection
In April 2009, we received approval from the FERC to construct a 27-mile pipeline to provide increased access to the Rockies’ natural gas supplies. Construction began in June 2009 and the project was placed into service in November 2009. We combined lateral capacity with existing mainline capacity to provide approximately 363 Mdt/d of firm transportation from various receipt points for delivery to Ignacio, Colorado. The cost of the project was $60 million.
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Outlook for 2010
In addition to the various in-progress expansion projects discussed below in “Capital Expenditures,” we have several other proposed projects to meet customer demands. Subject to regulatory approvals, construction of some of these projects could begin as early as 2010.
Year-Over-Year Operating Results
Years Ended December 31, | ||||||||||||
2009 | 2008 | 2007 | ||||||||||
(Millions) | ||||||||||||
Segment revenues | $ | 1,591 | $ | 1,637 | $ | 1,623 | ||||||
Segment profit | $ | 635 | $ | 661 | $ | 649 | ||||||
2009 vs. 2008
Segment revenuesdecreased primarily due to a $53 million decrease in revenues from lower transportation imbalance settlements in 2009 compared to 2008 (offset incosts and operating expenses), partially offset by a $17 million increase in other service revenues and expansion projects placed into service by Transco.
Costs and operating expensesdecreased $27 million, or 3%, primarily due to a $53 million decrease in costs associated with lower transportation imbalance settlements in 2009 compared to 2008 (offset insegment revenues) and $11 million of income from an adjustment of state franchise taxes. Partially offsetting these decreases is a $13 million increase in depreciation expense due primarily to projects placed into service, a $10 million increase in transportation-related fuel expense resulting from less favorable recovery from customers due to pricing differences, and $7 million higher employee-related expenses.
Selling, general and administrative expensesincreased $6 million, or 4%, primarily due to an increase in pension expense.
Other (income) expense — netreflects the absence of a $10 million gain on the sale of certain south Texas assets and a $9 million gain on the sale of excess inventory gas, both of which were recorded by Transco in 2008. Partially offsetting these unfavorable changes was $16 million lower project development costs in 2009.
Segment profitdecreased primarily due to the previously described changes, partially offset by higher equity earnings from Gulfstream.
2008 vs. 2007
Segment revenuesincreased primarily due to a $52 million increase in transportation revenues resulting primarily from Transco’s new rates, which were approved by the FERC as part of a general rate case and became effective March 2007, and expansion projects that Transco placed into service in the fourth quarter of 2007. In addition,segment revenuesincreased $28 million due to transportation imbalance settlements (offset incosts and operating expenses). Partially offsetting these increases is the absence of $59 million associated with a 2007 sale of excess inventory gas (offset incosts and operating expenses).
Costs and operating expensesdecreased $11 million, or 1%, primarily due to the absence of $59 million associated with a 2007 sale of excess inventory gas (offset insegment revenues). The decrease is partially offset by an increase in costs of $28 million associated with transportation imbalance settlements (offset insegment revenues) and higher rental expense related to the Parachute lateral that was transferred to Midstream in December 2007.
Other (income) expense — netchanged unfavorably by $31 million primarily due to the absence of $18 million of income recognized in 2007 associated with payments received for a terminated firm transportation agreement on Northwest Pipeline’s Grays Harbor lateral and the absence of $17 million of income recorded in 2007 for a change in estimate related to a regulatory liability at Northwest Pipeline. In addition, project development costs were $21 million higher in 2008. Partially offsetting these unfavorable changes was a $10 million gain on the sale of certain south Texas assets, and a $9 million gain on the sale of excess inventory gas, both of which were recorded by Transco in 2008.
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The increase insegment profitis primarily due to the previously described changes and higher equity earnings from Gulfstream.
Midstream Gas & Liquids
Overview of 2009
Midstream’s ongoing strategy 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.
Significant events during 2009 include the following:
Cameron Meadows Plant
In November 2009, we sold our Cameron Meadows plant and recognized a pre-tax gain of $40 million. This plant sustained hurricane damage twice in recent years and was therefore considered incongruent with our strategy of providing the most reliable service in the industry.
Willow Creek
The Willow Creek facility in western Colorado began processing natural gas production and extracting NGLs in early August and achieved full processing operations in September. Currently, the 450-million-cubic-feet-per-day (MMcf/d) gas processing plant primarily processes Williams’ Exploration & Production segment’s wellhead production, has a peak capacity of 30,000 barrels of NGLs per day, and is recovering approximately 20,000 barrels per day. In the current processing arrangement with Williams’ Exploration & Production segment, Midstream receives a volumetric-based processing fee and a percent of the NGLs extracted.
Laurel Mountain Midstream, LLC
In June 2009, we completed the formation of a new joint venture in the Marcellus Shale located in southwest Pennsylvania. Our partner in the venture contributed its existing Appalachian basin gathering system, which currently has an average throughput of approximately 100 MMcf/d. In exchange for a 51% interest in the venture, we contributed $100 million and issued a $26 million note payable. We account for this investment under the equity method due to the significant participatory rights of our partner such that we do not control the investment. We have transitioned operational control from our partner to us.
Volatile commodity prices
NGL prices, especially ethane prices, have generally improved during 2009, following significant declines in the fourth quarter of 2008 as a result of the weakened economy. Our NGL margins also benefited from a period of declining natural gas prices during 2009. While average annual per-unit NGL margins in 2009 were still significantly lower than 2008, they improved during 2009 to levels currently above the rolling five-year average per-unit margin. We continued to benefit from favorable natural gas price differentials in the Rocky Mountain area, although the differentials narrowed during 2009. These differentials contributed to realized per-unit margins that were generally greater than that of the industry benchmarks for natural gas processed in the Henry Hub area and for NGLs fractionated and sold at Mont Belvieu, Texas.
NGL margins are defined as NGL revenues less any applicable BTU replacement cost, plant fuel, and third-party transportation and fractionation. Per-unit NGL margins are calculated based on sales of our own equity volumes at the processing plants.
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![(PERFORMANCE GRAPH)](https://capedge.com/proxy/8-K/0000950123-10-036288/c56960c5696001.gif)
Hurricane Impact to Insurance Coverage
While our insurance expense has increased modestly in 2009 compared to 2008, the overall level of coverage on our offshore assets in the Gulf Coast region against named windstorm events has substantially decreased, including the absence of coverage on certain of our assets. (Please read Note 10, Property, Plant and Equipment, of Notes to Supplemental Consolidated Financial Statements included elsewhere herein.)
Outlook for 2010
The following factors could impact our business in 2010.
Commodity price changes
• | NGL, crude and natural gas prices are highly volatile and difficult to predict. However, we expect per-unit NGL margins in 2010 to be higher than our average per-unit margins in 2009 and our rolling five-year average per-unit NGL margins. NGL price changes have historically tracked somewhat with changes in the price of crude oil. Margins in our NGL business are highly dependent upon continued demand within the global economy. Although forecasted domestic and global demand for polyethylene, or plastics, has been impacted by the weakness in the global economy, NGL products are currently the preferred |
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feedstock for ethylene and propylene production, which are the building blocks of polyethylene. Propylene and ethylene production processes have increasingly shifted from the more expensive crude-based feedstocks to NGL-based feedstocks. Bolstered by abundant long-term domestic natural gas supplies, we expect to benefit from these dynamics in the broader global petrochemical markets. As natural gas pipeline transportation capacity increases in the Rocky Mountain area, we anticipate that historically favorable natural gas price differentials in that area will decline. |
• | As part of our efforts to manage commodity price risks, we continue to evaluate our commodity hedging strategies. To reduce the exposure to changes in market prices, we have entered into NGL swap agreements to fix the prices of a small portion of our anticipated NGL sales for 2010. In addition, we have entered into financial contracts to fix the price of a portion of our shrink gas requirements for 2010. |
Gathering, processing, and NGL sales volumes
• | The growth of natural gas supplies supporting our gathering and processing volumes are impacted by producer drilling activities. Our customers are generally large producers, and we have not experienced and do not anticipate an overall significant decline in volumes due to reduced drilling activity. | ||
• | In the onshore region, we expect higher fee revenues, NGL volumes, depreciation expense and operating expenses in 2010 compared to 2009 as our Willow Creek facility moves into a full year of operation, and our expansion at Echo Springs is completed late in 2010. | ||
• | We expect fee revenues, NGL volumes, depreciation expense, and operating expenses in our offshore Gulf Coast region to increase from 2009 levels as our new Perdido Norte expansion begins start-up operations in the first quarter of 2010. Increases from our Perdido Norte expansion are expected to be partially offset by lower volumes in other Gulf Coast areas due to expected changes in gas processing contracts, as described below, and natural declines. | ||
• | Certain of our gas processing contracts contain provisions that allow customers to periodically elect processing services on either a fee basis, keep-whole, or percent-of-liquids basis. If customers switch from keep-whole to fee-based processing, this would reduce our NGL equity sales volumes. |
Year-Over-Year Operating Results
Years Ended December 31, | ||||||||||||
2009 | 2008 | 2007 | ||||||||||
(Millions) | ||||||||||||
Segment revenues | $ | 2,928 | $ | 4,135 | $ | 3,997 | ||||||
Segment profit (loss): | ||||||||||||
Gathering & processing | $ | 637 | $ | 841 | $ | 897 | ||||||
NGL marketing and other | 114 | (7 | ) | 86 | ||||||||
Indirect general and administrative expense | (78 | ) | (79 | ) | (72 | ) | ||||||
Total | $ | 673 | $ | 755 | $ | 911 | ||||||
In order to provide additional clarity, this discussion and analysis of Midstream’s operating results separately reflects the portion of general and administrative expense not allocated to an asset group asindirect general and administrative expense. These charges represent any overhead cost not directly attributable to one of the specific asset groups noted in this discussion.
2009 vs. 2008
The decrease insegment revenuesis largely due to:
• | A $716 million decrease in revenues associated with the production of NGLs primarily due to lower average NGL prices. |
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• | A $513 million decrease in marketing revenues primarily due to lower average NGL and crude prices, partially offset by higher NGL volumes. |
These decreases are partially offset by a $60 million increase in fee revenues primarily due to higher volumes resulting from connecting new supplies in the deepwater Gulf of Mexico in the latter part of 2008 and new fees for processing Williams’ Exploration & Production segment’s natural gas production at Willow Creek.
Segment costs and expensesdecreased $1,125 million, or 33%, primarily as a result of:
• | A $643 million decrease in marketing purchases primarily due to lower average NGL and crude prices, including the absence of a $9 million charge in 2008 to write down the value of NGL inventories, partially offset by higher NGL volumes. | ||
• | A $435 million decrease in costs associated with the production of NGLs primarily due to lower average natural gas prices. | ||
• | A $40 million gain on the 2009 sale of our Cameron Meadows processing plant. | ||
• | The absence of $17 million of charges in 2008 related to an impairment, asset abandonments, and asset retirement obligations. |
The decrease in Midstream’ssegment profitreflects the previously described changes insegment revenuesandsegment costs and expenses. A more detailed analysis of the segment profit of certain Midstream operations is presented as follows.
Gathering & processing
The decrease ingathering & processing segment profitincludes a $193 million decrease in the onshore region and an $11 million decrease in the Gulf Coast region.
The decrease in our onshore region’ssegment profitincludes:
• | A $213 million decrease in NGL margins due to a significant decrease in average NGL prices, partially offset by a significant decrease in production costs reflecting lower natural gas prices. NGL equity volumes were slightly higher as both periods were impacted by significant volume changes. Current year volumes include the unfavorable impact of certain producers electing to convert, in accordance with those gas processing agreements, from keep-whole to fee-based processing at the beginning of 2009. Prior year NGL equity volumes sold were unusually low primarily due to an increase in inventory as we transitioned from product sales at the plant to shipping volumes through a pipeline for sale downstream, lower ethane recoveries to accommodate restrictions on the volume of NGLs we could deliver into the pipelines and hurricane-related disruptions at a third-party fractionation facility at Mont Belvieu, Texas, which resulted in an NGL inventory build-up. Lower NGL transportation costs in the onshore region due to the transition from our previous shipping arrangement to transportation on the Overland Pass pipeline also favorably impacted NGL margins in 2009. | ||
• | An $8 million decrease in involuntary conversion gains related to our Ignacio plant. These insurance recoveries in both years were used to rebuild the plant. | ||
• | A $39 million increase in fee revenues primarily due to new fees for processing Williams’ Exploration & Production segment’s natural gas production at Willow Creek, unusually low gathering and processing volumes in the first quarter of 2008 related to severe winter weather conditions, and producers converting from keep-whole to fee-based processing in the first quarter of 2009. |
The decrease in the Gulf Coast region’ssegment profitincludes:
• | A $68 million decrease in NGL margins reflecting lower average NGL prices and lower volumes. Lower production costs reflecting lower natural gas prices partially offset these decreases. Both periods were impacted by unfavorable volume changes. Current year volumes include the unfavorable impact of periods of reduced NGL recoveries during the first quarter due to unfavorable NGL economics and natural declines in production sources. Prior year volumes were unusually low primarily due to periods of reduced NGL recoveries during the fourth quarter and as a result of hurricanes in the third quarter. |
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• | A $40 million gain in 2009 on the sale of our Cameron Meadows processing plant, partially offset by the absence of a $5 million involuntary conversion gain in 2008 related to our Cameron Meadows plant. | ||
• | $26 million higher fee revenues primarily due to higher volumes resulting from connecting new supplies in the Blind Faith prospect in the deepwater in the latter part of 2008. | ||
• | The absence of $16 million of charges in 2008 related to an impairment, asset abandonments, and asset retirement obligations. | ||
• | An $11 million increase in depreciation primarily due to our Blind Faith pipeline extensions that came into service during the latter part of 2008. |
NGL marketing and other
The significant components of the increase insegment profitof our NGL marketing and other operations include:
• | $124 million in higher margins related to the marketing of NGLs primarily due to favorable changes in pricing while product was in transit during 2009 as compared to significant unfavorable changes in pricing while product was in transit in 2008 and the absence of a $9 million charge in 2008 to write down the value of NGL inventories. |
2008 vs. 2007
The increase insegment revenuesis largely due to:
• | A $163 million increase in revenues associated with the production of NGLs primarily due to higher average NGL prices, partially offset by lower volumes. Lower volumes resulted from reduced ethane recoveries at the plants during the third and fourth quarters of 2008 compared to higher volumes during 2007 as we transitioned from shipping volumes through a pipeline for sale downstream to product sales at the plant. | ||
• | A $48 million increase in fee-based revenues primarily due to the onshore region, the deepwater Gulf Coast region and at our Conway fractionation and storage facilities. |
These increases are partially offset by an $85 million decrease in marketing revenues primarily due to lower volumes, partially offset by higher prices.
Segment costs and expensesincreased $286 million, or 9%, primarily as a result of:
• | A $191 million increase in costs associated with the production of NGLs primarily due to higher average natural gas prices. | ||
• | A $73 million increase in operating costs including higher depreciation, repair costs and property insurance deductibles related to the hurricanes, gas transportation expenses in the eastern Gulf of Mexico, and employee costs. | ||
• | A $12 million increase in marketing purchases primarily due to a $9 million charge in 2008 to write down the value of NGL inventories. | ||
• | The absence of a $12 million favorable litigation outcome in 2007. |
These increases are partially offset by:
• | A $16 million favorable change due to higher involuntary conversion gains in 2008 related to insurance recoveries in excess of the carrying value of our Ignacio and Cameron Meadows plants. |
The decrease in Midstream’ssegment profitreflects the previously described changes insegment revenuesandsegment costs and expenses. A more detailed analysis of the segment profit of certain Midstream operations is presented as follows.
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Gathering & processing
The decrease ingathering & processing segment profitincludes a $49 million decrease in the onshore region and a $7 million decrease in the Gulf Coast region.
The decrease in our onshore region’ssegment profitincludes:
• | A $45 million decrease in NGL margins due to a significant increase in costs associated with the production of NGLs reflecting higher natural gas prices and lower volumes sold. The decrease in volumes sold is primarily due to restricted transportation capacity, unfavorable ethane economics, an increase in inventory during 2008, hurricane-related disruptions at a third-party fractionation facility, and lower equity volumes as processing agreements change from keep-whole to fee-based. These decreases were partially offset by a full year of production from the fifth train at our Opal processing plant, which began production in the first quarter of 2007. | ||
• | A $35 million increase in operating costs driven by higher turbine and engine overhaul expenses, depreciation expense and employee costs. | ||
• | The absence of a $12 million favorable litigation outcome in 2007. | ||
• | A $24 million increase in fee revenues including new lease revenues from Gas Pipeline for the Parachute lateral transferred to Midstream in December 2007. | ||
• | A $12 million involuntary conversion gain in 2008 related to our Ignacio plant. These insurance recoveries were used to rebuild the plant. |
The decrease in the Gulf Coast region’ssegment profitis primarily due to $39 million higher operating costs including higher depreciation, gas transportation expenses and hurricane repair and property insurance deductibles. These increased expenses are partially offset by $18 million higher NGL margins and $8 million higher fee revenues primarily due to connecting new supplies in the deepwater.
NGL marketing and other
The significant components of the decrease insegment profitof our NGL marketing and other operations include $95 million in lower margins related to the marketing of NGLs primarily due to the impact of a significant and rapid decline in NGL prices during the fourth quarter of 2008 on a higher volume of product inventory in transit. This also includes a $9 million charge in 2008 to write down the value of NGL inventories.
Management’s Discussion and Analysis of Financial Condition and Liquidity
Overview
The following discussion of our financial condition and liquidity reflects our business which has been recast to include the impacts of the February 17, 2010 Dropdown discussed above in “Recent Developments — The Dropdown” and as reflected in the supplemental consolidated financial statements and related notes included elsewhere herein.
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Outlook
For 2010, we expect operating results and cash flows to improve from 2009 levels due to the impact of expected higher energy commodity prices and the start-up of certain expansion capital projects. However, as previously mentioned, energy commodity prices are volatile and difficult to predict. 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 substantially insulated from unfavorable commodity price movements, as follows:
• | Firm demand and capacity reservation transportation revenues under long-term contracts at Gas Pipeline; | ||
• | Fee-based revenues from certain gathering and processing services at Midstream; | ||
• | Hedged NGL sales and natural gas purchases for a portion of activities at Midstream. |
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, and debt service payments while maintaining a sufficient level of liquidity. In particular, we note the following expectations for 2010:
• | We expect to increase our per-unit quarterly distribution from $0.6350 to $0.6575 beginning with the distribution with respect to first quarter of 2010. | ||
• | 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 revolving credit facilities as needed. |
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 2010. 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; | ||
• | Capital contributions from Williams pursuant to the omnibus agreement; and | ||
• | Use of credit facilities, as needed and available. |
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We anticipate our more significant uses of cash to be:
• | Maintenance and expansion capital expenditures; | ||
• | Contributions to our equity-method investees to fund their expansion capital expenditures; | ||
• | Interest on our long-term debt; and | ||
• | 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. | ||
• | Sustained reductions in energy commodity prices from expected 2010 levels. | ||
• | Exposure associated with our efforts to resolve regulatory and litigation issues (Please read Note 19, Commitments and Contingencies, of our Notes to Supplemental Consolidated Financial Statements). | ||
• | Physical damages to facilities, especially damage to offshore facilities by named windstorms for which our aggregate policy limit is $37.5 million in the event of a material loss. |
Available Liquidity
February 18, 2010 | ||||
(In millions) | ||||
Cash and cash equivalents | $ | 117 | ||
Available capacity under our $1.75 billion three-year senior unsecured credit facility (expires February 15, 2013) | 1,500 | |||
$ | 1,617 | |||
Shelf Registration
On October 28, 2009, we filed a shelf registration statement as a well-known seasoned issuer that allows us to issue an unlimited amount of registered debt and limited partnership unit securities.
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 Liquid Products, Discovery, Gulfstream and Laurel Mountain.
Omnibus Agreement with Williams
In connection with the closing of the Dropdown, we entered into a separate omnibus agreement with Williams. Pursuant to this omnibus agreement, Williams is obligated to indemnify us from and against or 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 in respect of certain U.S. Department of Transportation projects, up to a maximum aggregate amount of $50 million, and (iii) an amount based on the amortization over time of deferred revenue amounts that relate to cash payments received prior to the closing of the Dropdown for services to be rendered by us in the future at the Devils Tower floating production platform located in Mississippi Canyon Block 773. In addition, we will be
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obligated to pay to Williams the net 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 in Docket No. RP06-569.
Credit Facilities
At December 31, 2009, we had a $450 million senior unsecured credit agreement (Credit Agreement) with Citibank, N.A. as administrative agent, comprised of a $200 million revolving credit facility available for borrowings and letters of credit and a $250 million term loan. In connection with the Dropdown, we terminated the Credit Agreement and entered into a new $1.75 billion three-year senior unsecured revolving credit facility (New Credit Facility) with Transco and Northwest Pipeline, as co-borrowers, and Citibank, N.A. as the administrative agent, and certain other lenders named therein. The full amount of the New Credit Facility is available to us, to the extent not otherwise utilized by Transco and Northwest Pipeline, and may be increased by up to an additional $250 million. Transco and Northwest Pipeline are each able to borrow up to $400 million under the New Credit Facility to the extent not otherwise utilized by us. At the closing of the Dropdown, we borrowed $250 million under the New Credit Facility to repay the $250 million term loan outstanding under the Credit Agreement.
Interest on borrowings under the New Credit Facility is payable at rates per annum equal to, at the option of the borrower: (1) a fluctuating base rate equal to Citibank, N.A.’s adjusted base rate plus the applicable margin or (2) a periodic fixed rate equal to LIBOR plus the applicable margin. The adjusted base rate will be the highest of (i) the federal funds rate plus 0.5%, (ii) Citibank N.A.’s publicly announced base rate and (iii) one-month LIBOR plus 1.0%. We pay a commitment fee (currently 0.5%) based on the unused portion of the New Credit Facility. The applicable margin and the commitment fee are determined by reference to a pricing schedule based on a borrower’s senior unsecured debt ratings.
The New Credit Facility contains various covenants that limit, among other things, a borrower’s and its respective subsidiaries’ ability to incur indebtedness, grant certain liens supporting indebtedness, merge or consolidate, sell all or substantially all of its assets, enter into certain affiliate transactions, make certain distributions during an event of default and allow any material change in the nature of its business.
In addition, we are required to maintain a ratio of debt to EBITDA (each as defined in the New Credit Facility) of no greater than 5.00 to 1.00 for us and our consolidated subsidiaries. For each of Transco and Northwest Pipeline and their respective consolidated subsidiaries, the ratio of debt to capitalization (defined as net worth plus debt) is not permitted to be greater than 55%. Each of the above ratios will be tested, beginning June 30, 2010, at the end of each fiscal quarter, and the debt to EBITDA ratio will be measured on a rolling four-quarter basis.
The New Credit Facility includes customary events of default, including events of default relating to non-payment of principal, interest or fees, inaccuracy of representations and warranties in any material respect when made or when deemed made, violation of covenants, cross-payment defaults, cross acceleration, bankruptcy and insolvency events, certain unsatisfied judgments and a change of control. If an event of default with respect to a borrower occurs under the New Credit Facility, the lenders will be able to terminate the commitments for all borrowers and accelerate the maturity of the loans of the defaulting borrower under the New Credit Facility and exercise other rights and remedies.
We also had a $20 million revolving credit facility with Williams as the lender at December 31, 2009. The facility was available exclusively to fund working capital borrowings. This credit facility was terminated in connection with the Dropdown.
Credit ratings
The table below presents our current credit ratings and outlook on our senior unsecured long-term debt.
Senior Unsecured | ||||||
Rating Agency | Date of Last Change | Outlook | Debt Rating | |||
Standard & Poor’s | January 12, 2010 | Positive | BBB- | |||
Moody’s Investor Service | February 17, 2010 | Stable | Baa3 | |||
Fitch Ratings | February 2, 2010 | Stable | BBB- |
The ratings changes noted above reflect the announcement and completion of the Dropdown.
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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. A “Ba” rating indicates an obligation that is judged to have speculative elements and is subject to substantial credit risk. 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 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 Fitch, a rating of “BBB” or above indicates an investment grade rating. A rating below “BBB” is considered speculative grade. A “BB” rating from Fitch indicates that there is a possibility of credit risk developing, particularly as the result of adverse economic change over time; however, business or financial alternatives may be available to allow financial commitments to be met. 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 assign us investment grade ratings even if we meet or exceed their current criteria for investment grade ratios.
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, include (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 and (2) certain well connection expenditures and expenditures which are mandatory and/or essential for maintaining the reliability of our operations; and | ||
• | Expansion capital expenditures, which are generally more discretionary than maintenance capital expenditures, include (1) expenditures to acquire additional assets to grow our business, to expand and upgrade plant or pipeline capacity and to construct new plants, pipelines and storage facilities and (2) well connection expenditures which are not classified as maintenance expenditures. |
The following table provides summary information related to our expected capital expenditures for 2010 (in millions):
Maintenance | Expansion | |||||||||||||||||||||||
Segment | Low | Midpoint | High | Low | Midpoint | High | ||||||||||||||||||
Gas Pipeline | $ | 210 | $ | 220 | $ | 230 | $ | 340 | $ | 355 | $ | 370 | ||||||||||||
Midstream | 80 | 90 | 100 | 320 | 410 | 500 | ||||||||||||||||||
Total | $ | 290 | $ | 310 | $ | 330 | $ | 660 | $ | 765 | $ | 870 | ||||||||||||
Expansion capital expenditures include expenditures for the following Gas Pipeline and Midstream projects:
Gas Pipeline
Mobile Bay South
In May 2009, we received approval from the FERC to construct a compression facility in Alabama allowing transportation service to various southbound delivery points. The cost of the project is estimated to be $37 million. The estimated project in-service date is May 2010 and will increase capacity by 253 Mdt/d.
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85 North
In September 2009, we received approval from the FERC to construct an expansion of our existing natural gas transmission system from Alabama to various delivery points as far north as North Carolina. The cost of the project is estimated to be $241 million. Phase I service is anticipated to begin in July 2010 and will increase capacity by 90 Mdt/d. Phase II service is anticipated to begin in May 2011 and will increase capacity by 218 Mdt/d.
Mobile Bay South II
In November 2009, we filed an application with the FERC to construct additional compression facilities and modifications to existing facilities in Alabama allowing transportation service to various southbound delivery points. The cost of the project is estimated to be $36 million. The estimated project in-service date is May 2011 and will increase capacity by 380 Mdt/d.
Sundance Trail
In November 2009, we received approval from the FERC to construct approximately 16 miles of 30-inch pipeline between our existing compressor stations in Wyoming. The project also includes an upgrade to our existing compressor station and is estimated to cost up to $65 million. The estimated in-service date is November 2010 and will increase capacity by 150 Mdt/d.
Midstream
Perdido Norte
The Perdido Norte project, in the western deepwater of the Gulf of Mexico, includes an expansion of our Markham gas processing facility and oil and gas lines that will expand the scale of our existing infrastructure. Significant milestones have been reached and, considering the progress of our customer’s drilling and tie-in construction, we expect this project to begin start-up operations in the first quarter of 2010.
Wamsutter
We expect additional processing and NGL production capacities at our Echo Springs facility and related gathering system expansions in the Wamsutter area of Wyoming to be in service at the end of 2010.
Marcellus Shale
In conjunction with a long-term agreement with a major producer, we will construct and operate a 28-mile natural gas gathering pipeline in the Marcellus Shale region that will deliver gas to the Transco interstate gas pipeline. Construction is expected to begin on the 20-inch pipeline in the latter part of 2010, and it is expected to be placed into service during 2011.
In addition to our initial investment, we intend to invest additional capital within our Laurel Mountain joint venture to grow the existing gathering infrastructure in 2010 and beyond.
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 expect to increase our quarterly distribution from $0.6350 to $0.6575 per unit effective with our distribution with respect to the first quarter of 2010. As part of the consideration for the Dropdown, we issued 203 million Class C limited partnership units to Williams, which are identical to our common limited partnership units except that for the first quarter of 2010 they will receive a prorated quarterly distribution since they were not outstanding during the full quarterly period. These Class C units will automatically convert into our common limited partnership units following the record date for the first-quarter 2010 cash distribution.
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Results of Operations — Cash Flows
The following table summarizes our cash flows and reflects the impacts of the Dropdown.
Years Ended December 31, | ||||||||||||
2009 | 2008 | 2007 | ||||||||||
(In millions) | ||||||||||||
Net cash provided (used) by: | ||||||||||||
Operating activities | $ | 1,447 | $ | 1,459 | $ | 1,854 | ||||||
Investing activities | (890 | ) | (858 | ) | (1,078 | ) | ||||||
Financing activities | (537 | ) | (514 | ) | (791 | ) | ||||||
Increase (decrease) in cash and cash equivalents | $ | 20 | $ | 87 | $ | (15 | ) | |||||
Operating Activities
Net cash provided by operating activities decreased $12 million in 2009 as compared to 2008 due primarily to lower operating income.
Net cash provided by operating activities decreased $395 million in 2008 as compared to 2007 due primarily to lower Midstream operating income and payment of $144 million of rate refunds in 2008 by Transco.
Investing Activities
Capital expenditures in 2009, 2008 and 2007 totaled $887 million, $873 million and $1,026 million. Also, 2009 included a $108 million cash payment for Midstream’s 51% ownership interest in the Laurel Mountain joint venture.
Financing Activities
Net cash used by financing activities in 2009 included:
• | distributions to Williams of $377 million. | ||
• | distributions to limited partner unitholders and our general partner of $144 million. |
Net cash used by financing activities in 2008 included:
• | distributions to Williams of $747 million. | ||
• | distributions to limited partner unitholders and our general partner of $155 million. | ||
• | $333 million proceeds from the completion of the WMZ initial public offering. | ||
• | $250 million issuance by Northwest Pipeline of 6.05% senior unsecured notes. These proceeds were used to repay Northwest Pipeline’s $250 million loan under Williams’ $1.5 billion credit facility. | ||
• | $175 million borrowing by Transco under Williams’ $1.5 billion credit facility to retire Transco’s $100 million 6.25% notes that matured in January 2008 and a $75 million adjustable rate note due in April 2008. | ||
• | $250 million issuance by Transco of 6.05% senior unsecured notes due 2018. These proceeds were used to repay Transco’s $175 million loan under Williams’ $1.5 billion credit facility. |
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Net cash used by financing activities in 2007 included:
• | distributions to Williams of $1,450 million. | ||
• | distributions to limited partner unitholders and our general partner of $87 million. | ||
• | proceeds of $492 million from the issuance of our limited partner units and proceeds from issuance of $250 million variable rate term loan related to the purchase of ownership interests in Wamsutter. | ||
• | $185 million issuance by Northwest Pipeline of 5.95% senior unsecured notes due 2017. These proceeds were used to retire $175 million of Northwest Pipeline’s 8.125% senior unsecured notes, plus an early retirement premium of approximately $7 million. | ||
• | $250 million borrowing by Northwest Pipeline under Williams’ $1.5 billion credit facility to retire Northwest Pipeline’s $250 million 6.25% notes that matured in December 2007. |
Contractual Obligations
A summary of our contractual obligations at December 31, 2009, as recast to reflect the Dropdown, is as follows:
2010 | 2011-2012 | 2013-2014 | 2015+ | Total | ||||||||||||||||
(in millions) | ||||||||||||||||||||
Long-term debt: | ||||||||||||||||||||
Principal (a) | $ | 15 | $ | 1,034 | $ | — | $ | 1,952 | $ | 3,001 | ||||||||||
Interest | 196 | (b) | 352 | 262 | 527 | 1,337 | ||||||||||||||
Capital leases | — | — | — | — | — | |||||||||||||||
Operating leases (c) | 27 | 40 | 33 | 125 | 225 | |||||||||||||||
Purchase obligations | 529 | 449 | 382 | 1,535 | 2,895 | |||||||||||||||
Other long term obligations | — | — | — | — | — | |||||||||||||||
Total | $ | 767 | $ | 1,875 | $ | 677 | $ | 4,139 | $ | 7,458 | ||||||||||
(a) | In February 2010, we issued $3.5 billion aggregate principal amount of senior unsecured notes. Additionally, we established a new $1.75 billion three-year unsecured revolving credit facility which replaced our previous $450 million credit facility. We utilized $250 million of the new facility to repay a term loan that was outstanding under the previous facility. The below table shows the impact by period of this transaction: |
2010 | 2011-2012 | 2013-2014 | Thereafter | Total | ||||||||||||||||
(Millions) | ||||||||||||||||||||
Long-term debt, including current portion: | ||||||||||||||||||||
Issuance of the $3.5 billion senior notes | $ | — | $ | — | $ | — | $ | 3,500 | $ | 3,500 | ||||||||||
Retirement of the $250 million term loan under our $450 million credit facility | — | (250 | ) | — | — | (250 | ) | |||||||||||||
Issuance of $250 million term loan under our new $1.75 billion credit facility | — | — | 250 | — | 250 | |||||||||||||||
Total | $ | — | $ | (250 | ) | $ | 250 | $ | 3,500 | $ | 3,500 | |||||||||
(b) | The assumed interest rate on our $250 million term loan is based on the forecasted forward LIBOR plus the applicable margin. | |
(c) | 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 2011 and thereafter does not include such variable amounts related to this agreement as the variable amount is not yet determinable. |
Off-Balance Sheet Arrangements
We have guarantees on behalf of certain entities in which we have an equity ownership interest which guarantee operating performance. These are disclosed in Note 9, Investments, of our Notes to Supplemental Consolidated Financial Statements. Other than these arrangements, we had no guarantees of off-balance sheet debt to third parties or any other off-balance sheet arrangements at December 31, 2009.
Effects of Inflation
Our operations have benefited from relatively low inflation rates. Following the Dropdown, approximately 66% of our gross property, plant and equipment is at Gas Pipeline. Gas Pipeline is 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 Midstream, operating costs are influenced to a greater extent by both competition for specialized services and specific price changes in oil and natural gas and related commodities than by changes in general inflation. Crude, natural gas, and natural gas liquids 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
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future, as well as general economic conditions. However, our exposure to 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. 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 $19.3 million, all of which are recorded as liabilities on our balance sheet at December 31, 2009. We will seek recovery of approximately $12.6 million of these costs through future natural gas transmission rates. The remainder of these costs will be funded from operations. During 2009, we paid approximately $3.6 million for cleanup and/or remediation and monitoring activities. We expect to pay approximately $3.2 million in 2010 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, 2009, certain assessment studies were still in process for which the ultimate outcome may yield significantly 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.
We are subject to the federal Clean Air Act and to the federal Clean Air Act Amendments of 1990, which require the EPA to issue new regulations. We are also subject to regulation at the state and local level. In September 1998, the EPA promulgated rules designed to mitigate the migration of ground-level ozone in certain states. Revisions to those rules were proposed in January 2010 and may result in additional controls. In March 2004 and June 2004, the EPA promulgated additional regulation regarding hazardous air pollutants, which may result in additional controls. Capital expenditures necessary to install emission control devices on the Transco gas pipeline system to comply with rules are estimated to be between $5 million and $10 million through 2013. The actual costs incurred will depend on the final implementation plans developed by each state to comply with these regulations. We consider these costs on the Transco system associated with compliance with these environmental laws and regulations to be prudent costs incurred in the ordinary course of business and, therefore, recoverable through its rates.
We have established systems and procedures to meet our reporting obligations under the Mandatory Reporting Rule related to greenhouse gas emissions issued by the EPA in late 2009. Also, certain states in which we have operations have established reporting obligations. We have not incurred significant capital investment to meet the obligations imposed by these new rules. The EPA is developing additional regulations that will expand the scope of the Mandatory Reporting Rule, with particular emphasis on natural gas operations. We are participating directly and through trade associations in developmental aspects of that prospective rulemaking. It is likely that additional rules will be issued in 2010 which may expand our reporting obligations as early as 2011. As those rules are still being developed, at this time we are unable to estimate any capital investment that may be required to comply.
Safety Matters
The United States Department of Transportation Pipeline and Hazardous Materials Safety Administration rules implementing the Pipeline Safety Improvement Act of 2002 require pipeline operators to implement integrity management programs, including more frequent inspections and other safeguards in areas where the potential consequences of pipeline accidents pose the greatest risk to people and property. In accordance with the final rule, Transco and Northwest Pipeline developed Integrity Management Plans, identified high consequence areas, completed baseline assessment plans, and are on schedule to complete the required assessments within specified timeframes. Currently, Transco and Northwest Pipeline estimate that the cost to perform required assessments and remediation will be primarily capital and range between $150 million and $220 million, and between $65 million and $85 million, respectively, over the remaining assessment period of 2010 through 2012. Management considers the costs associated with compliance with the rule to be prudent costs incurred in the ordinary course of business and, therefore, recoverable through their respective rates.
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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.
General Partner of Williams Partners L.P.
and the Limited Partners of Williams Partners L.P.
We have audited the accompanying supplemental consolidated balance sheets of Williams Partners L.P. as of December 31, 2009 and 2008, and the related supplemental consolidated statements of income, partners’ capital, and cash flows for each of the three years in the period ended December 31, 2009. These supplemental financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these supplemental 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. We were not engaged to perform an audit of the Company’s internal control over financial reporting for the supplemental financial statements. 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, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
The supplemental consolidated financial statements give retroactive effect to the acquisition of the Contributed Entities. The Contributed Entities were not previously held by Williams Partners L.P., and such acquisition has been accounted for in a manner similar to a pooling-of-interests as described in Note 1 to the supplemental consolidated financial statements. Generally accepted accounting principles proscribe giving effect to a consummated acquisition accounted for by the pooling-of-interests method in the financial statements that do not include the date of consummation. These supplemental financial statements do not extend through the date of consummation. However, they will become the historical consolidated financial statements of Williams Partners L.P. after financial statements covering the date of consummation of the merger are issued.
In our opinion, the supplemental financial statements referred to above present fairly, in all material respects, the consolidated financial position of Williams Partners L.P. at December 31, 2009 and 2008, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2009, in conformity with.U.S. generally accepted accounting principles applicable after financial statements are issued for a period which includes the date of the consummation of the transaction.
/s/ Ernst & Young LLP
Tulsa, Oklahoma
April 20, 2010
April 20, 2010
22
WILLIAMS PARTNERS L.P.
SUPPLEMENTAL CONSOLIDATED BALANCE SHEETS*
SUPPLEMENTAL CONSOLIDATED BALANCE SHEETS*
December 31, | ||||||||
2009 | 2008 | |||||||
(In millions) | ||||||||
ASSETS | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 153 | $ | 133 | ||||
Accounts receivable: | ||||||||
Trade | 381 | 273 | ||||||
Affiliate | 6 | 5 | ||||||
Notes receivable from parent | — | 252 | ||||||
Inventories | 129 | 147 | ||||||
Regulatory assets | 77 | 89 | ||||||
Other current assets | 75 | 87 | ||||||
Total current assets | 821 | 986 | ||||||
Investments | 593 | 524 | ||||||
Property, plant and equipment — net | 10,225 | 9,816 | ||||||
Regulatory assets, deferred charges and other | 345 | 350 | ||||||
Total assets | $ | 11,984 | $ | 11,676 | ||||
LIABILITIES AND EQUITY | ||||||||
Current liabilities: | ||||||||
Accounts payable: | ||||||||
Trade | $ | 356 | $ | 315 | ||||
Affiliate | 80 | 71 | ||||||
Accrued liabilities | 185 | 257 | ||||||
Long-term debt due within one year | 15 | — | ||||||
Total current liabilities | 636 | 643 | ||||||
Long-term debt | 2,981 | 2,971 | ||||||
Asset retirement obligations | 477 | 447 | ||||||
Regulatory liabilities, deferred income and other | 263 | 226 | ||||||
Contingent liabilities and commitments (Note 19) | ||||||||
Equity: | ||||||||
Common unitholders (52,777,452 units outstanding at December 31, 2009 and 2008) | 1,631 | 1,620 | ||||||
General partner | 5,647 | 5,423 | ||||||
Accumulated other comprehensive income | 2 | 4 | ||||||
Noncontrolling interests in consolidated subsidiaries | 347 | 342 | ||||||
Total equity | 7,627 | 7,389 | ||||||
Total liabilities and equity | $ | 11,984 | $ | 11,676 | ||||
* | Recast as discussed in Note 1. |
See accompanying notes to supplemental consolidated financial statements
23
WILLIAMS PARTNERS L.P.
SUPPLEMENTAL CONSOLIDATED STATEMENTS OF INCOME*
SUPPLEMENTAL CONSOLIDATED STATEMENTS OF INCOME*
Year Ended | ||||||||||||
December 31, | ||||||||||||
2009 | 2008 | 2007 | ||||||||||
(In millions, except per-unit amounts) | ||||||||||||
Revenues: | ||||||||||||
Gas Pipeline | $ | 1,591 | $ | 1,637 | $ | 1,623 | ||||||
Midstream Gas & Liquids | 2,928 | 4,135 | 3,997 | |||||||||
Intercompany eliminations | (7 | ) | (10 | ) | (4 | ) | ||||||
Total revenues | 4,512 | 5,762 | 5,616 | |||||||||
Segment costs and expenses: | ||||||||||||
Costs and operating expenses | 3,031 | 4,143 | 3,893 | |||||||||
Selling, general and administrative expense | 289 | 270 | 262 | |||||||||
Other (income) expense — net | (35 | ) | 9 | (20 | ) | |||||||
Segment costs and expenses | 3,285 | 4,422 | 4,135 | |||||||||
General corporate expenses | 105 | 92 | 98 | |||||||||
Operating income: | ||||||||||||
Gas Pipeline | 600 | 630 | 622 | |||||||||
Midstream Gas & Liquids | 627 | 710 | 859 | |||||||||
General corporate expenses | (105 | ) | (92 | ) | (98 | ) | ||||||
Total operating income | 1,122 | 1,248 | 1,383 | |||||||||
Equity earnings | 81 | 76 | 79 | |||||||||
Interest accrued — third-party | (205 | ) | (210 | ) | (204 | ) | ||||||
Interest accrued — affiliate | (52 | ) | (35 | ) | (20 | ) | ||||||
Interest capitalized | 56 | 36 | 23 | |||||||||
Interest income — third-party | 1 | 2 | 7 | |||||||||
Interest income — affiliate | 19 | 23 | 18 | |||||||||
Other income — net | 13 | 10 | 19 | |||||||||
Income before income taxes | 1,035 | 1,150 | 1,305 | |||||||||
Provision (benefit) for income taxes | 4 | (952 | ) | (144 | ) | |||||||
Net income | 1,031 | 2,102 | 1,449 | |||||||||
Less: Net income attributable to noncontrolling interests in subsidiaries | 27 | 25 | — | |||||||||
Net income attributable to controlling interests | $ | 1,004 | $ | 2,077 | $ | 1,449 | ||||||
Allocation of net income for calculation of earnings per unit: | ||||||||||||
Net income attributable to controlling interests | $ | 1,004 | $ | 2,077 | $ | 1,449 | ||||||
Allocation of net income to general partner | 852 | 1,915 | 1,364 | |||||||||
Allocation of net income to limited partners | $ | 152 | $ | 162 | $ | 85 | ||||||
Basic and diluted net income per limited partner unit | $ | 2.88 | $ | 3.08 | $ | 1.99 | ||||||
Weighted average number of common units outstanding | 52,777,452 | 52,775,710 | (a) | 40,131,195 | (a)(b) | |||||||
* Recast as discussed in Note 1. | ||||||||||||
(a) Includes subordinated units converted to common on February 19, 2008. | ||||||||||||
(b) Includes Class B units converted to common on May 21, 2007. |
See accompanying notes to supplemental consolidated financial statements
24
WILLIAMS PARTNERS L.P.
SUPPLEMENTAL CONSOLIDATED STATEMENT OF CHANGES IN EQUITY*
SUPPLEMENTAL CONSOLIDATED STATEMENT OF CHANGES IN EQUITY*
Williams Partners L.P. | ||||||||||||||||||||||||||||
Limited Partners | ||||||||||||||||||||||||||||
Accumulated Other | ||||||||||||||||||||||||||||
General | Comprehensive | Noncontrolling | Total | |||||||||||||||||||||||||
Common | Class B | Subordinated | Partner | Income (Loss) | Interests | Equity | ||||||||||||||||||||||
(In millions) | ||||||||||||||||||||||||||||
Balance — December 31, 2006 | $ | 734 | $ | 242 | $ | 109 | $ | 4,382 | $ | 5 | $ | — | $ | 5,472 | ||||||||||||||
Comprehensive income: | ||||||||||||||||||||||||||||
Net income - 2007 | 65 | 9 | 15 | 1,360 | — | — | 1,449 | |||||||||||||||||||||
Other comprehensive loss: | ||||||||||||||||||||||||||||
Net unrealized losses on cash flow hedges, net of reclassification adjustments | — | — | — | — | (11 | ) | — | (11 | ) | |||||||||||||||||||
Total other comprehensive loss | �� | — | (11 | ) | ||||||||||||||||||||||||
Total comprehensive income | 1,438 | |||||||||||||||||||||||||||
Cash distributions | (60 | ) | (6 | ) | (14 | ) | (7 | ) | — | — | (87 | ) | ||||||||||||||||
Conversion of Class B units into common (6,805,492 units) | 245 | (245 | ) | — | — | — | — | — | ||||||||||||||||||||
Issuance of units to public (9,250,000 common units) | 335 | — | — | — | — | — | 335 | |||||||||||||||||||||
Issuance of units to general partner (4,163,257 common units) | 157 | — | — | — | — | — | 157 | |||||||||||||||||||||
Distributions to The Williams Companies, Inc. — net | — | — | — | (1,450 | ) | — | — | (1,450 | ) | |||||||||||||||||||
Other | (2 | ) | — | (1 | ) | 5 | — | — | 2 | |||||||||||||||||||
Balance — December 31, 2007 | 1,474 | — | 109 | 4,290 | (6 | ) | — | 5,867 | ||||||||||||||||||||
Net income - 2008 | 163 | — | 2 | 1,912 | — | 25 | 2,102 | |||||||||||||||||||||
Other comprehensive income: | ||||||||||||||||||||||||||||
Net unrealized gains on cash flow hedges, net of reclassification adjustments | — | — | — | — | 10 | — | 10 | |||||||||||||||||||||
Total other comprehensive income | — | 10 | ||||||||||||||||||||||||||
Total comprehensive income | — | 2,112 | ||||||||||||||||||||||||||
Cash distributions | (124 | ) | — | (4 | ) | (27 | ) | — | — | (155 | ) | |||||||||||||||||
Sale of Williams Pipeline Partners L.P. limited partner units | — | — | — | — | — | 333 | 333 | |||||||||||||||||||||
Dividends paid to noncontrolling interests | — | — | — | — | — | (12 | ) | (12 | ) | |||||||||||||||||||
Conversion of subordinated units into common (7,000,000 units) | 107 | — | (107 | ) | — | — | — | — | ||||||||||||||||||||
Distributions to The Williams Companies, Inc. — net | — | — | — | (747 | ) | — | — | (747 | ) | |||||||||||||||||||
Other | — | — | — | (5 | ) | — | (4 | ) | (9 | ) | ||||||||||||||||||
Balance — December 31, 2008 | 1,620 | — | — | 5,423 | 4 | 342 | 7,389 | |||||||||||||||||||||
Net income - 2009 | 145 | — | — | 859 | — | 27 | 1,031 | |||||||||||||||||||||
Other comprehensive income: | ||||||||||||||||||||||||||||
Net unrealized losses on cash flow hedges, net of reclassification adjustments | — | — | — | — | (2 | ) | — | (2 | ) | |||||||||||||||||||
Total other comprehensive loss | — | (2 | ) | |||||||||||||||||||||||||
Total comprehensive income | — | 1,029 | ||||||||||||||||||||||||||
Cash distributions | (134 | ) | — | — | (10 | ) | — | — | (144 | ) | ||||||||||||||||||
Dividends paid to noncontrolling interests | — | — | — | — | — | (23 | ) | (23 | ) | |||||||||||||||||||
Distributions to The Williams Companies, Inc. — net | — | — | — | (377 | ) | — | — | (377 | ) | |||||||||||||||||||
Reclassification of notes receivable (see Note 3) | — | — | — | (253 | ) | — | — | (253 | ) | |||||||||||||||||||
Other | — | — | — | 5 | — | 1 | 6 | |||||||||||||||||||||
Balance — December 31, 2009 | $ | 1,631 | $ | — | $ | — | $ | 5,647 | $ | 2 | $ | 347 | $ | 7,627 | ||||||||||||||
* | Recast as discussed in Note 1. |
See accompanying notes to supplemental consolidated financial statements.
25
WILLIAMS PARTNERS L.P.
SUPPLEMENTAL CONSOLIDATED STATEMENTS OF CASH FLOWS*
SUPPLEMENTAL CONSOLIDATED STATEMENTS OF CASH FLOWS*
Year Ended December 31, | ||||||||||||
2009 | 2008 | 2007 | ||||||||||
(In millions) | ||||||||||||
OPERATING ACTIVITIES: | ||||||||||||
Net income | $ | 1,031 | $ | 2,102 | $ | 1,449 | ||||||
Adjustments to reconcile to net cash provided by operations: | ||||||||||||
Depreciation and amortization | 531 | 503 | 478 | |||||||||
Provision (benefit) for deferred income taxes | — | (997 | ) | (306 | ) | |||||||
Cash provided (used) by changes in current assets and liabilities: | ||||||||||||
Accounts and notes receivable | (93 | ) | 142 | (99 | ) | |||||||
Inventories | 17 | (42 | ) | 38 | ||||||||
Other current assets | 8 | (81 | ) | 17 | ||||||||
Accounts payable | 2 | (194 | ) | 71 | ||||||||
Accrued liabilities | (73 | ) | 36 | 156 | ||||||||
Affiliates — net | 16 | (9 | ) | (37 | ) | |||||||
Other, including changes in noncurrent assets and liabilities | 8 | (1 | ) | 87 | ||||||||
Net cash provided by operating activities | 1,447 | 1,459 | 1,854 | |||||||||
FINANCING ACTIVITIES: | ||||||||||||
Proceeds from long-term debt | — | 674 | 684 | |||||||||
Payments of long-term debt | (2 | ) | (600 | ) | (428 | ) | ||||||
Proceeds from sale of our limited partner units | — | 29 | 492 | |||||||||
Redemption of common units from general partner | — | (29 | ) | — | ||||||||
Proceeds from sale of Williams Pipeline Partners L.P. limited partner units | — | 333 | — | |||||||||
Dividends paid to noncontrolling interests in subsidiaries | (23 | ) | (12 | ) | — | |||||||
Distributions to The Williams Companies, Inc. — net | (377 | ) | (747 | ) | (1,450 | ) | ||||||
Distributions to limited partner unitholders and general partner | (144 | ) | (155 | ) | (87 | ) | ||||||
Other — net | 9 | (7 | ) | (2 | ) | |||||||
Net cash used by financing activities | (537 | ) | (514 | ) | (791 | ) | ||||||
INVESTING ACTIVITIES: | ||||||||||||
Property, plant and equipment: | ||||||||||||
Capital expenditures | (887 | ) | (873 | ) | (1,026 | ) | ||||||
Net proceeds from dispositions | 46 | 30 | (9 | ) | ||||||||
Changes in notes receivable from parent | (1 | ) | 1 | (24 | ) | |||||||
Cumulative distributions received in excess of equity earnings of Discovery | 9 | 36 | — | |||||||||
Distribution received from Gulfstream Natural Gas System, L.L.C. | 73 | — | — | |||||||||
Purchases of investments | (131 | ) | (50 | ) | (19 | ) | ||||||
Purchase of ARO trust investments | (46 | ) | (31 | ) | — | |||||||
Proceeds from sale of ARO trust investments | 41 | 14 | — | |||||||||
Other — net | 6 | 15 | — | |||||||||
Net cash used by investing activities | (890 | ) | (858 | ) | (1,078 | ) | ||||||
Increase (decrease) in cash and cash equivalents | 20 | 87 | (15 | ) | ||||||||
Cash and cash equivalents at beginning of year | 133 | 46 | 61 | |||||||||
Cash and cash equivalents at end of year | $ | 153 | $ | 133 | $ | 46 | ||||||
* | Recast as discussed in Note 1. |
See accompanying notes to supplemental consolidated financial statements
26
WILLIAMS PARTNERS L. P.
NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS
NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS
Note 1. Organization, Basis of Presentation and Description of Business
Organization
Unless the context clearly indicates otherwise, references in this report to “we,” “our,” “us” or similar language refer to Williams Partners L.P. and its subsidiaries.
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 February 17, 2010, Williams owns an approximate 82% limited partner interest, a 2% 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).
Basis of Presentation
On February 17, 2010, we closed a transaction (the Dropdown) with our general partner, our operating company and certain subsidiaries of and including Williams, pursuant to which Williams contributed to us the ownership interests in the entities that made up its Gas Pipeline and Midstream Gas & Liquids businesses to the extent not already owned by us, including Williams’ limited and general partner interests in Williams Pipeline Partners L.P. (WMZ), but excluding its Canadian, Venezuelan and olefins operations, and 25.5% of Gulfstream Natural Gas System, L.L.C.(Gulfstream ), collectively, the Contributed Entities.
This contribution was made in exchange for aggregate consideration of:
• | $3.5 billion in cash, less certain expenses incurred by us, which we financed by issuing $3.5 billion of senior unsecured notes (see Note 13), | ||
• | 203 million of our Class C limited partnership units, and | ||
• | an increase in the capital account of our general partner to allow it to maintain its 2% general partner interest. |
These transactions will be reflected in our March 31, 2010 consolidated financial statements. Because the acquired entities were affiliates of Williams at the time of the acquisition, this transaction will be accounted for as a combination of entities under common control, similar to a pooling of interests, whereby the assets and liabilities of the acquired entities are combined with ours at their historical amounts. These supplemental consolidated financial statements and notes are being provided prior to our filing of post-combination results and recast our historical consolidated financial statements and notes to reflect the combined historical results for all periods presented. The effect of recasting our financial statements to account for this common control transaction increased net income $878 million, $1,911 million and $1,284 million for 2009, 2008 and 2007, respectively. This acquisition does not impact historical earnings per unit as pre-acquisition earnings were allocated to our general partner. The cash distribution to Williams resulted in a decrease in the capital account of the general partner at the time of the distribution.
Description of Business
Our operations are located in the United States and are organized into the following reporting segments: Gas Pipeline and Midstream Gas & Liquids (Midstream).
Gas Pipeline is comprised primarily of the following interstate natural gas pipeline assets:
• | Transcontinental Gas Pipe Line Company, LLC (Transco), an interstate natural gas pipeline extending from the Gulf of Mexico region to the northeastern United States; | ||
• | Northwest Pipeline GP (Northwest Pipeline), an interstate natural gas pipeline extending from the San Juan basin in northwestern New Mexico and southwestern Colorado to Oregon and Washington; and | ||
• | A 24.5% equity interest in Gulfstream Natural Gas System L.L.C. (Gulfstream), an interstate natural gas pipeline extending from the Mobile Bay area in Alabama to markets in Florida. |
27
Midstream is comprised of the following natural gas gathering, processing and treating facilities, oil gathering and transportation facilities and natural gas liquids (NGL) transportation, fractionation and storage facilities and investments:
• | Two gathering systems and the Echo Springs and Opal processing plants serving the Wamsutter and southwest areas of Wyoming; | ||
• | A gathering system, the Ignacio, Kutz and Lybrook processing plants and the Milagro and Esperanza natural gas treating plants, all serving the San Juan basin in New Mexico and Colorado; | ||
• | A natural gas lateral, natural gas liquids (NGL) pipeline and Willow Creek processing plant in Colorado; | ||
• | An equity interest in a gathering system serving the Appalachian Basin in southwest Pennsylvania; | ||
• | Onshore and offshore natural gas gathering pipelines in the Gulf Coast region; | ||
• | The Mobile Bay and Markham processing plants in the Gulf Coast region; | ||
• | The Canyon Station and Devils Tower offshore production platforms in the Gulf of Mexico; | ||
• | Three Gulf of Mexico deepwater crude oil pipelines; | ||
• | NGL storage facilities in the Conway, Kansas area; | ||
• | Interests in two NGL fractionation facilities: one near Conway, Kansas and the other in Baton Rouge, Louisiana; | ||
• | An equity interest in Discovery Producer Services LLC (Discovery), whose assets include a processing plant and a fractionation plant in Louisiana, and an offshore natural gas gathering and transportation system in the Gulf of Mexico; and | ||
• | An equity interest in Aux Sable Liquid Products L.P., whose assets include a processing plant and a fractionator in Illinois. |
Note 2. Summary of Significant Accounting Policies
Principles of consolidation
The supplemental consolidated financial statements include the accounts of Williams Partners L.P., OLLC and our other wholly-owned subsidiaries. We eliminated all intercompany accounts and transactions. We apply the equity method of accounting for investments in unconsolidated companies in which we and our subsidiaries own 20% to 50% of the voting interest or otherwise exercise significant influence over operating and financial policies of the company. We also apply the equity method of accounting for investments where our majority ownership does not provide us with control due to the significant participatory rights of other owners.
In January 2008, WMZ completed an initial public offering of 16.25 million common units at a price of $20 per unit. In February 2008, the underwriters exercised their right to purchase an additional 1.65 million common units at the same price. The initial asset of the partnership is a 35% interest in Northwest Pipeline. We own approximately 47.7% of the interests in WMZ, including the interests of the general partner (Williams Pipeline GP LLC), which is wholly owned by us, and IDRs. We consolidate WMZ within our Gas Pipeline segment due to our control through the general partner.
We hold a 50% undivided interest in the Conway NGL fractionation facility, for which no separate legal entity exits. Accordingly, we proportionately consolidate our share of the fractionator revenues, costs and expenses, and property, plant and equipment.Liabilities in theSupplemental Consolidated Balance Sheets include those incurred on behalf of the co-owners with corresponding receivables from the co-owners.
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 supplemental consolidated financial statements and accompanying notes. Actual results could differ from those estimates.
Estimates and assumptions which, in the opinion of management, are significant to the underlying amounts included in the financial statements and for which it would be reasonably possible that future events or information could change those estimates include:
• | impairment assessments of long-lived assets; | ||
• | loss contingencies; |
28
• | environmental remediation obligations; and | ||
• | asset retirement obligations. |
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. These differences are discussed further throughout these notes.
Cash and Cash Equivalents
Cash and cash equivalentsinclude 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 maturities of three months or less when acquired.
Accounts Receivable
Accounts receivableare carried on a gross basis, with no discounting, less an allowance for doubtful accounts. We do not recognize an allowance for doubtful accounts at the time the revenue which generates the accounts receivable is recognized. 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. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted. The allowance for doubtful accounts at December 31, 2009 and 2008 was immaterial.
Inventory Valuation
Allinventoriesare stated at the lower of cost or market. We determine the cost of certain natural gas inventories held by Transco using the last-in, first-out (LIFO) cost method. We determine the cost of the remaining inventories primarily using the average-cost method. LIFO inventory at December 31, 2009 and 2008 was $7 million and $11 million, respectively.
29
Property, Plant and Equipment
Property, plant and equipmentis 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. Ordinary maintenance and repair costs are generally expensed as incurred. Costs of major renewals and replacements are capitalized.
As regulated entities, Transco and Northwest Pipeline 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.
Northwest Pipeline’s levelized rate design for a 2003 pipeline expansion project created a revenue stream that remains constant over the related 25-year and 15-year customer contract terms. The related levelized depreciation is lower than book depreciation in the early years and higher than book depreciation in the later years of the contract terms. The depreciation component of the levelized incremental rates will equal the accumulated book depreciation by the end of the primary contract terms. FERC has approved the accounting for the differences between book depreciation and the levelized depreciation as a regulatory asset with the offsetting credit to income. Credits totaling $2 million in 2009, $3 million in 2008 and $4 million in 2007 are recorded in the accompanyingSupplemental Consolidated Statements of Income. The accompanyingSupplemental Consolidated Balance Sheets reflect the related regulatory assets of $31 million and $29 million at December 31, 2009 and 2008, respectively. The regulatory asset will be amortized over the primary terms of the shipper agreements as such costs are collected through rates.
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 inother (income) expense — netincluded inoperating income in theSupplemental Consolidated Statements of Income.
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. The regulated pipelines 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 corresponding accretion expense included in costs and operating expenses, except for regulated entities, for which the liability is offset by a regulatory asset. The regulatory asset is amortized commensurate with the collection of those costs in rates.
Derivative Instruments and Hedging Activities
We may utilize derivatives to manage a portion of our commodity price risk. These instruments consist primarily of swap agreements, option contracts and forward contracts involving short- and long-term purchases and sales of physical energy commodities. The counterparty to certain of these instruments is a Williams affiliate. We report the fair value of derivatives, except those for which the normal purchases and normal sales exception has been elected, on theSupplemental Consolidated Balance Sheetsinother current assets,accrued liabilities,regulatory assets, deferred charges and other orregulatory liabilities, deferred income and other as either current or noncurrent. We determine the current and noncurrent classification based on the timing of expected future cash flows of individual contracts. We report these amounts on a gross basis.
The accounting for changes in the fair value of a commodity derivative depends on whether the derivative has been designated in a hedging relationship and whether we have elected the normal purchases and normal sales exception. The accounting for the change in fair value can be summarized as follows:
Derivative Treatment | Accounting Method | |
Normal purchases and normal sales exception | Accrual accounting | |
Designated in qualifying hedging relationship | Hedge accounting | |
All other derivatives | Mark-to-market accounting |
We have elected 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 have designated 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
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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 inrevenuesorcosts and operating expenses dependent upon the underlying hedged transaction.
For derivatives designated as a cash flow hedge, the effective portion of the change in fair value of the derivative is reported inaccumulated other comprehensive income (loss)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 inrevenuesorcosts and operating expenses. Gains or losses deferred inaccumulated other comprehensive income (loss)associated with terminated derivatives, derivatives that cease to be highly effective hedges, derivatives for which the forecasted transaction is reasonably possible but no longer probable of occurring, and cash flow hedges that have been otherwise discontinued remain inaccumulated other comprehensive income (loss)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 inaccumulated other comprehensive (income) lossis recognized inrevenuesorcosts and operating expensesat 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 inrevenues.
Certain gains and losses on derivative instruments included in theSupplemental Consolidated Statements of Income are netted together to a single net gain or loss, while other gains and losses are reported on a gross basis. Gains and losses recorded on a net basis include:
• | Unrealized gains and losses on all derivatives that are not designated as hedges and for which we have not elected the normal purchases and normal sales exception; | ||
• | The ineffective portion of unrealized gains and losses on derivatives that are designated as cash flow hedges; | ||
• | Realized gains and losses on all derivatives that settle financially other than natural gas derivatives for NGL processing activities; | ||
• | Realized gains and losses on derivatives entered into as a pre-contemplated buy/sell arrangement. |
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.
Gas Pipeline revenues
Gas Pipeline revenues are primarily from services pursuant to long-term firm transportation and storage agreements. These agreements provide for a demand 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 demand 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.
In the course of providing transportation services to customers, 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.
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.
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Midstream revenues
Natural gas gathering and processing services are performed under volumetric-based fee contracts, keep-whole agreements and percent-of-liquids arrangements. Revenues under volumetric-based fee contracts are recorded when services have been performed. Under 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 also market NGLs that we purchase from our producer customers. Revenues from marketing NGLs are recognized when the products have been sold and delivered.
Oil gathering and transportation revenues and offshore production handling fees are recognized when the services have been performed. Certain offshore production handling contracts contain fixed payment terms that result in the deferral of revenues until such services have been performed.
Storage revenues under prepaid contracted storage capacity contracts are recognized evenly over the life of the contract as services are provided.
Impairment of Long-Lived Assets and Investments
We evaluate our long-lived assets of identifiable business activities for impairment when events or changes in circumstances indicate 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 the carrying value of the assets is recoverable. We 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 the carrying value is not recoverable, 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.
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 estimated fair value is recognized in the financial statements as an impairment.
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. The use of alternate judgments and/or assumptions could result in the recognition of different levels of impairment charges in the financial statements.
Environmental
Environmental expenditures that relate to current or future revenues are expensed or capitalized based upon the nature of the expenditures. Expenditures that relate to an existing contamination caused by past operations that do not contribute to current or future revenue generation are expensed. Accruals related to environmental matters are generally determined based on site-specific plans for remediation, taking into account our prior remediation experience, and are not discounted. Environmental contingencies are recorded independently of any potential claim for recovery.
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Capitalized Interest
We generally 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. Our nonregulated operations capitalize interest based on our average interest rate on debt to the extent we incur interest expense. Our regulated operations capitalize interest on all projects. Interest is capitalized on borrowed funds and, where regulation by the FERC exists, on internally generated funds. Interest capitalized on internally generated funds reported as a component of other income – net was $10 million, $5 million and $12 million in 2009, 2008 and 2007, respectively. The rates used by regulated companies are calculated in accordance with FERC rules. Historically, Williams provided the financing for capital expenditures of the nonregulated companies acquired in the Dropdown; hence, the rates used by those companies were based on Williams’ average interest rate on debt.
Income Taxes
We are not a taxable entity for federal and state income tax purposes. The tax on our net income is borne by the individual partners through the allocation of taxable income. 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.
Although the Contributed Entities’ operations were included in the Williams’ consolidated federal income tax return prior to the Dropdown, following their acquisition by us, their operations are now treated as a partnership. Therefore, other than Transco and Northwest Pipeline, the historical operations exclude income taxes for all periods presented. Transco and Northwest Pipeline converted from corporations to limited liability companies on December 31, 2008 and October 1, 2007, respectively, and were not subject to income taxes after those respective dates. The effect of Transco and Northwest Pipeline’s change in tax status is included in theprovision (benefit) for income taxesin the respective period of the change.
During 2006, the state of Texas passed a law that imposed a partnership-level tax on us beginning in 2007 based on the net revenues of our assets apportioned to the state of Texas. This tax is included in theprovision (benefit) for income taxes.
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, Class B and subordinated units outstanding. Basic and diluted earnings per unit are equivalent as there are no dilutive securities outstanding.
Issuance of equity of consolidated subsidiary
Sales of residual equity interests in a consolidated subsidiary are accounted for as capital transactions. No adjustments to equity are made for sales of preferential interests in a subsidiary. No gain or loss is recognized on these transactions.
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Accounting standards issued but not yet effective
In January 2010, the Financial Accounting Standards Board issued Accounting Standards Update No. 2010-06, “Fair Value Measurements and Disclosures (Topic 820) — Improving Disclosures about Fair Value Measurements”. This Update requires new disclosures regarding the amount of transfers in or out of Level 1 and Level 2 fair value measurements along with the reason for such transfers and also requires a greater level of disaggregation when disclosing valuation techniques and inputs used in estimating Level 2 and Level 3 fair value measurements. The disclosures will be required for reporting beginning in the first quarter 2010. Also, beginning with the first quarter of 2011, the Update requires additional categorization of items included in the rollforward of activity for Level 3 fair value measurements on a gross basis. We are assessing the application of this Update to disclosures in our Consolidated Financial Statements.
Note 3. Related Party Transactions
The employees of our operated assets are employees of Williams. Williams directly charges us for the payroll and benefit costs associated with the operations employees and carries the obligations for many employee-related benefits in its financial statements, including the liabilities related to the employee retirement, medical plans and paid time off. Our share of those costs is charged to us through affiliate billings and reflected incosts and operating expensesin the accompanyingSupplemental Consolidated Statements of Income.
In addition, all of our general and administrative employees are employees of Williams, 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 administrative expenses is reflected inselling, general and administrative expense,and our share of allocated administrative expenses is reflected ingeneral corporate expensesin the accompanyingSupplemental Consolidated Statements of 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.
Under an omnibus agreement entered into in connection with the Dropdown, 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 Dropdown 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.
Under a separate omnibus agreement entered into in August 2005 with Williams, we are provided a quarterly credit for general and administrative expenses, which is reflected as a capital contribution from our general partner. During 2009, Williams agreed to provide up to an additional $10 million credit, in addition to the credit previously provided, to the extent that 2009 non-segment profit general and administrative expenses exceeded a certain level. We recorded total general and administrative expenses (including those expenses subject to the credit by Williams) as an expense, and we recorded any credits as capital contributions from Williams. The expense subject to this credit is allocated entirely to our general partner. As a result, the net income allocated to limited partners on a per-unit basis reflects the benefit of this credit. The total general and administrative credits received from Williams were $3 million, $2 million and $2 million in 2009, 2008 and 2007, respectively.
We have a contribution receivable from our general partner of less than $1 million at December 31, 2009 and 2008 for amounts reimbursable to us under the omnibus agreement. We net this receivable against equity on theSupplemental Consolidated Balance Sheets.
Gas Pipeline revenuesinclude revenues from transportation and exchange services and rental of communication facilities with subsidiaries of Williams. The rates charged to provide sales and services to affiliates are comparable to those that are charged to similarly-situated nonaffiliated customers.
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Midstream revenuesinclude revenues from the following types of transactions with affiliates:
• | Sales of feedstock commodities to Williams Olefins, LLC (Williams Olefins), a wholly owned subsidiary of Williams, for use in their facilities. These sales are generally made at market prices at the time of sale. | ||
• | Gathering, treating and processing services for Williams Production Company (WPC), a wholly owned subsidiary of Williams, 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. | ||
• | We buy and sell natural gas from and to Williams Gas Marketing, Inc. (WGM), a wholly owned subsidiary of Williams, related to our “crosshauling” activity on our Four Corners gathering system. Crosshauling typically involves the movement of some natural gas between gathering systems at established interconnect points to optimize flow, reduce expenses or increase profitability. As a result, we must purchase gas for delivery to customers at certain plant outlets, and we have excess volumes to sell at other plant outlets. WGM conducts these purchase and sale transactions at current market prices at each location. Because the transactions are entered into in contemplation of each other, we report them net in revenues. |
Costs and operating expensesalso include charges for the following types of transactions with affiliates:
• | Our Midstream segment purchases NGLs for resale from WPC and Williams Olefins at market prices at the time of purchase. | ||
• | Our Midstream segment purchases natural gas for shrink replacement and fuel for processing plants, the co-generation plant and a fractionator from WGM at market prices at the time of purchase or contract execution. | ||
• | Our Gas Pipeline segment purchases natural gas from WGM at contract or market prices. | ||
• | We transferred a transportation capacity agreement to WGM in a prior year. To the extent that WGM does not utilize this transportation capacity for its needs (primarily transporting third-party gas volumes), we reimburse WGM for these transportation costs. | ||
• | The amortization of a gas purchase contract transferred to us by Williams, for the purchase of a portion of our fuel requirements at a fractionator, at a market price not to exceed a specified level. This contract terminated on December 31, 2007. |
Below is a summary of the related party transactions discussed above.
Years Ended | ||||||||||||
December 31, | ||||||||||||
2009 | 2008 | 2007 | ||||||||||
(In millions) | ||||||||||||
Gas Pipeline revenues | $ | 29 | $ | 38 | $ | 45 | ||||||
Midstream revenues | ||||||||||||
Product sales | 75 | 164 | 127 | |||||||||
Gathering and processing | 73 | 44 | 43 | |||||||||
Costs and operating expenses | ||||||||||||
Product purchases | 497 | 972 | 680 | |||||||||
Employee costs | 196 | 207 | 189 | |||||||||
Other | 9 | 11 | 1 | |||||||||
Selling, general and administrative expense | ||||||||||||
Employee costs | 228 | 205 | 209 |
We periodically enter into financial swap contracts with WGM to hedge forecasted NGL sales and natural gas purchases. These contracts are priced based on market rates at the time of execution and are reflected inother current assets, regulatory assets, deferred charges and otherandaccrued liabilitieson theSupplemental Consolidated Balance Sheets(see Note 17).
The Contributed Entities historically participated in Williams’ cash management program under unsecured promissory note agreements with Williams for both advances to and from Williams. As of December 31, 2009 and 2008, the net advances to Williams are classified in theSupplemental Consolidated Balance Sheetsas follows:
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• | Transco’s and Northwest Pipeline’snotes receivable from parentare classified as current assets at December 31, 2008 because they are due on demand and have historically been repaid during the following year. The interest rate on Transco’s demand notes is based upon the weighted average cost of Williams’ debt outstanding at the end of each quarter. The interest rate on Northwest Pipeline’s demand notes was based upon the weighted average cost of Williams’ debt outstanding at the end of each quarter until its acquisition by WMZ in 2008. At that point the interest rate changed to the overnight investment rate paid on Williams’ excess cash. In contemplation of the Dropdown, Transco and Northwest Pipeline each approved and paid a cash distribution to Williams that included the balance of their outstanding notes receivable from parent and associated interest receivable which were paid in February 2010. Accordingly, those balances outstanding at December 31, 2009, totaling $253 million, are reflected as a reduction of equity. | ||
• | Wamsutter LLC’s net advances to Williams are included inaccounts receivable — affiliate. These balances are generally settled in cash quarterly. Interest is paid to Wamsutter on amounts receivable from Williams based on the rate received by Williams on the overnight investment of its excess cash. | ||
• | Net advances to Williams for the remaining Contributed Entities are classified as a component of equity because, although the advances are due on demand, Williams has not historically required repayment or repaid amounts owed to us. |
In connection with the Dropdown, the outstanding advances were distributed to Williams in February 2010. This distribution had no net impact on our assets or liabilities. Changes in the advances to Williams are presented as distributions to Williams in theSupplemental Consolidated Statement of Changes in Equity andSupplemental Consolidated Statements of Cash Flows.
Theaccounts receivable — affiliateandaccounts payable — affiliateon theSupplemental Consolidated Balance Sheetsrepresent the receivable and payable positions that result from the transactions with affiliates discussed above.
In June 2009, we issued a $26 million note payable to Laurel Mountain Midstream, LLC, an equity method investee, in connection with its formation. This note payable is included inlong-term debt due within one year andlong-term debt in theSupplemental Consolidated Balance Sheets.
Note 4. Allocation of Net Income and Distributions
The allocation of net income among our general partner, limited partners and noncontrolling interests, as reflected in theSupplemental Consolidated Statement of Changes in Equity, for the years ended December 31, 2009, 2008 and 2007 is as follows (in millions):
Year Ended December 31, | ||||||||||||
2009 | 2008 | 2007 | ||||||||||
Allocation of net income to general partner: | ||||||||||||
Net income | $ | 1,031 | $ | 2,102 | $ | 1,449 | ||||||
Net income applicable to pre-partnership operations allocated to general partner | (852 | ) | (1,886 | ) | (1,355 | ) | ||||||
Net income applicable to noncontrolling interests | (27 | ) | (25 | ) | — | |||||||
Beneficial conversion of Class B units* | — | — | (5 | ) | ||||||||
Reimbursable general and administrative and other costs charged directly to general partner | 3 | 2 | 2 | |||||||||
Income subject to 2% allocation of general partner interest | 155 | 193 | 91 | |||||||||
General partner’s share of net income | 2.0 | % | 2.0 | % | 2.0 | % | ||||||
General partner’s allocated share of net income before items directly allocable to general partner interest | 3 | 4 | 2 | |||||||||
Incentive distributions paid to general partner** | 7 | 24 | 5 | |||||||||
Charges allocated directly to general partner | (3 | ) | (2 | ) | (2 | ) | ||||||
Pre-partnership net income allocated to general partner interest | 852 | 1,886 | 1,355 | |||||||||
Net income allocated to general partner | $ | 859 | $ | 1,912 | $ | 1,360 | ||||||
Allocation of net income to limited partners: | ||||||||||||
Net income | $ | 1,031 | $ | 2,102 | $ | 1,449 | ||||||
Net income allocated to general partner | 859 | 1,912 | 1,360 | |||||||||
Net income allocated to noncontrolling interests | 27 | 25 | — | |||||||||
Net income allocated to limited partners | $ | 145 | $ | 165 | $ | 89 | ||||||
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* | The $5 million allocation of income to the Class B units reflects the Class B unit beneficial conversion feature resulting from the May 2007 conversion of these units into common units on a one-for-one basis. We computed the $5 million beneficial conversion feature as the product of the 6,805,492 Class B units and the difference between the fair value of a privately placed common unit on the date of issuance ($36.59) and the issue price of a privately placed Class B unit ($35.81). | |
** | 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 income allocated to the general partner’s capital account reflects IDRs paid during the current reporting period. In April 2009, Williams waived the IDRs related to 2009 distribution periods. The IDRs paid in 2009 relate to the fourth-quarter 2008 distribution. |
Common and subordinated unitholders shared equally, on a per-unit basis, in the net income allocated to limited partners before the conversion of the subordinated units into common units in 2008.
The reimbursable general and administrative and other costs represent the costs charged against our income that our general partner is required to reimburse us under the terms of the original omnibus agreement.
We paid the following partnership cash distributions during 2007, 2008, 2009 and 2010 (in millions, except for per unit amounts):
General Partner | ||||||||||||||||||||||||||||
Incentive | ||||||||||||||||||||||||||||
Per Unit | Common | Subordinated | Class B | Distribution | Total Cash | |||||||||||||||||||||||
Payment Date | Distribution | Units | Units | Units | 2% | Rights | Distribution | |||||||||||||||||||||
2/14/2007 | $ | 0.4700 | $ | 12 | $ | 3 | $ | 3 | $ | — | $ | 1 | $ | 19 | ||||||||||||||
5/15/2007 | $ | 0.5000 | $ | 13 | $ | 4 | $ | 3 | $ | — | $ | 1 | $ | 21 | ||||||||||||||
8/14/2007 | $ | 0.5250 | $ | 17 | $ | 4 | $ | — | $ | — | $ | 1 | $ | 22 | ||||||||||||||
11/14/2007 | $ | 0.5500 | $ | 18 | $ | 4 | $ | — | $ | — | $ | 2 | $ | 24 | ||||||||||||||
2/14/2008 | $ | 0.5750 | $ | 26 | $ | 4 | $ | — | $ | 1 | $ | 4 | $ | 35 | ||||||||||||||
5/15/2008 | $ | 0.6000 | $ | 32 | $ | — | $ | — | $ | 1 | $ | 5 | $ | 38 | ||||||||||||||
8/14/2008 | $ | 0.6250 | $ | 33 | $ | — | $ | — | $ | 1 | $ | 7 | $ | 41 | ||||||||||||||
11/14/2008 | $ | 0.6350 | $ | 33 | $ | — | $ | — | $ | 1 | $ | 8 | $ | 42 | ||||||||||||||
2/13/2009 | $ | 0.6350 | $ | 33 | $ | — | $ | — | $ | 1 | $ | 8 | $ | 42 | ||||||||||||||
5/15/2009 | $ | 0.6350 | $ | 33 | $ | — | $ | — | $ | 1 | $ | — | $ | 34 | ||||||||||||||
8/14/2009 | $ | 0.6350 | $ | 33 | $ | — | $ | — | $ | 1 | $ | — | $ | 34 | ||||||||||||||
11/13/2009 | $ | 0.6350 | $ | 33 | $ | — | $ | — | $ | 1 | $ | — | $ | 34 | ||||||||||||||
2/12/2010 | $ | 0.6350 | $ | 33 | $ | — | $ | — | $ | 1 | $ | — | $ | 34 |
Note 5. Asset Sales, Impairments and Other Accruals
The following table presents significant gains or losses from asset sales, impairments and other accruals or adjustments reflected inother (income) expense — netwithinsegment costs and expenses.
Years Ended | ||||||||||||
December 31, | ||||||||||||
2009 | 2008 | 2007 | ||||||||||
(In millions) | ||||||||||||
Gas Pipeline | ||||||||||||
Income from payments received for a terminated firm transportation agreement on Grays Harbor lateral | $ | — | $ | — | $ | (18 | ) | |||||
Income from change in estimate related to a regulatory liability | — | — | (17 | ) | ||||||||
Gain on sale of certain south Texas assets | — | (10 | ) | — | ||||||||
Midstream | ||||||||||||
Gain on sale of Cameron Meadows gas processing plant | (40 | ) | — | — | ||||||||
Income from favorable litigation outcome | — | — | (12 | ) | ||||||||
Impairments of offshore assets and other asset writedowns | — | 17 | 19 | |||||||||
Involuntary conversion gains | (4 | ) | (17 | ) | (1 | ) |
In November 2009, we sold our Cameron Meadows plant, which had a carrying value of $16 million, and recognized a $40 million gain. This plant sustained hurricane damage twice in recent years and is, therefore, considered incongruent with our strategy of providing the most reliable service in the industry.
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Note 6. Benefit Plans
Williams charges us for the benefits costs associated with providing benefits to employees that provide services to us.
Pension plans
Williams has noncontributory defined benefit pension plans that provide pension benefits for its eligible employees. Pension expense charged to us by Williams for 2009, 2008 and 2007 totaled $36 million, $12 million and $14 million, respectively. At the total Williams plan level, the pension plans had a projected benefit obligation of $1,118 million and $1,035 million at December 31, 2009 and 2008, respectively. The plans were underfunded by $258 million and $330 million at December 31, 2009 and 2008, respectively.
Postretirement benefits other than pensions
Williams provides certain retiree health care and life insurance benefits for eligible participants that generally 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. The accounting for the plan anticipates future cost-sharing changes to the plan that are consistent with Williams’ expressed intent to increase the retiree contribution level, generally in line with health care cost increases. Net periodic postretirement benefit expense charged to us by Williams for 2009, 2008 and 2007 totaled $4 million, $5 million and $6 million, respectively. At the total Williams plan level, the postretirement benefit plans had a projected benefit obligation of $259 million and $273 million at December 31, 2009 and 2008, respectively. The plans were underfunded by $111 million and $147 million at December 31, 2009 and 2008, 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
Employees that operate our assets participate in a Williams defined contribution plan. Williams charged us compensation expense of $14 million, $13 million and $12 million in 2009, 2008 and 2007, respectively, for Williams’ matching contributions to this plan.
Employee Stock-Based Compensation Plan Information
The Williams Companies, Inc. 2007 Incentive Plan (Plan) was approved by stockholders on May 17, 2007. The 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 granted directly to employees that operate our assets based on the fair value of the awards.
Total stock-based compensation expense, included in administrative and general expenses, for the years ended December 31, 2009, 2008 and 2007 was $10 million, $8 million and $10 million, respectively.
Note 7. Provision (Benefit) for Income Taxes
Transco and Northwest Pipeline converted to single member limited liability companies on December 31, 2008 and October 1, 2007, respectively. Each made an election to be treated as a disregarded entity; therefore, they were no longer subject to federal or state income tax as of their respective conversion date. Theprovision (benefit) for income taxesshown herein for 2007 includes Northwest Pipeline’s benefit through September 30, 2007, and the 2008provision (benefit) for income taxesincludes Transco’s benefit through December 31, 2008. Subsequent to the conversion, all deferred taxes were eliminated through income and Transco and Northwest Pipeline no longer provide for federal or state income taxes.
The provision for income taxes in 2009 reflects the Texas partnership-level tax that is based on net revenues of our assets apportioned to the State of Texas.
Theprovision (benefit) for income taxesincludes:
Years Ended December 31, | ||||||||||||
2009 | 2008 | 2007 | ||||||||||
(In millions) | ||||||||||||
Current: | ||||||||||||
Federal | $ | — | $ | 37 | $ | 138 | ||||||
State | 4 | 8 | 24 | |||||||||
4 | 45 | 162 | ||||||||||
Deferred: | ||||||||||||
Federal | — | (867 | ) | (273 | ) | |||||||
State | — | (130 | ) | (33 | ) | |||||||
— | (997 | ) | (306 | ) | ||||||||
Total provision (benefit) for income tax | $ | 4 | $ | (952 | ) | $ | (144 | ) | ||||
Reconciliations from the provision for income taxes at the federal statutory rate to the realizedprovision (benefit) for income taxesare as follows:
December 31, | ||||||||||||
2009 | 2008 | 2007 | ||||||||||
(In millions) | ||||||||||||
Provision at statutory rate | $ | 362 | $ | 403 | $ | 457 | ||||||
Increases (decreases) in taxes resulting from: | ||||||||||||
Income from operations not taxed as a LLC | (362 | ) | (296 | ) | (306 | ) | ||||||
State income taxes (net of federal benefit) | 4 | 14 | 17 | |||||||||
Conversion from corporation to LLC | — | (1,073 | ) | (312 | ) | |||||||
Provision (benefit) for income taxes | $ | 4 | $ | (952 | ) | $ | (144 | ) | ||||
We had no deferred tax liabilities or deferred tax assets at December 31, 2009 or 2008.
Total interest and penalties recognized as a component of income tax expense were immaterial in 2009, 2008 and 2007.
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As of December 31, 2008, the Internal Revenue Service (IRS) examinations of consolidated Williams U.S. income tax returns for 2006 and 2007 were in process. IRS examinations for 1997 through 2005 have been completed at the field level but the years remain open for certain unresolved issues. The statute of limitations for most states expires one year after expiration of the IRS statute. During the next twelve months, we do not expect ultimate resolution of any unrecognized tax benefit to have a material impact on our financial position.
Net cash payments made to Williams for income taxes were $21 million, $77 million and $93 million in 2009, 2008 and 2007, respectively.
Note 8. Inventories
Inventoriesat December 31, 2009 and 2008 are as follows:
December 31, | ||||||||
2009 | 2008 | |||||||
(In millions) | ||||||||
Natural gas liquids | $ | 44 | $ | 34 | ||||
Crude oil | 2 | 1 | ||||||
Natural gas in underground storage | 20 | 58 | ||||||
Materials, supplies and other | 63 | 54 | ||||||
$ | 129 | $ | 147 | |||||
Note 9. Investments
Investmentsbeing accounted for using the equity method at December 31, 2009 and 2008 are as follows:
December 31, | ||||||||
2009 | 2008 | |||||||
(In millions) | ||||||||
Gulfstream Natural Gas System, L.L.C. — 24.5% | $ | 188 | $ | 257 | ||||
Discovery Producer Services LLC — 60% | 189 | 184 | ||||||
Laurel Mountain Midstream, LLC — 51% | 133 | — | ||||||
Aux Sable Liquid Products L.P. — 14.6% | 16 | 14 | ||||||
Other | 67 | 69 | ||||||
$ | 593 | $ | 524 | |||||
Differences between the carrying value of our equity investments and the underlying equity in the net assets of the investees are primarily related to $42 million of impairments previously recognized. These differences are being amortized over the expected remaining life of the investees’ underlying assets.
Dividends and distributions, including those presented below, received from companies accounted for by the equity method were $168 million and $121 million in 2009 and 2008, respectively. These transactions reduced the carrying value of our investments. These dividends and distributions primarily included:
2009 | 2008 | |||||||
(In millions) | ||||||||
Gulfstream Natural Gas System, L.L.C. | $ | 109 | $ | 29 | ||||
Discovery Producer Services LLC | 32 | 56 | ||||||
Aux Sable Liquid Products L.P. | 15 | 28 |
We contributed $10 million and $44 million to Gulfstream Natural Gas System, L.L.C. in 2009 and 2008, respectively. We also contributed $13 million and $6 million to Discovery in 2009 and 2008, respectively. In June 2009, we acquired a 51% ownership interest in Laurel Mountain Midstream, LLC (LMM) for $133 million.
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Note 10. Property, Plant and Equipment
Property, plant and equipment — netat December 31, 2009 and 2008 is as follows:
Estimated Useful | Depreciation | |||||||||||||||
Life(a) | Rates(a) | December 31, | ||||||||||||||
(Years) | (%) | 2009 | 2008 | |||||||||||||
(In millions) | ||||||||||||||||
Nonregulated: | ||||||||||||||||
Natural gas gathering and processing facilities | 5-40 | $ | 4,095 | $ | 3,670 | |||||||||||
Construction in progress | 669 | 702 | ||||||||||||||
Other | 0-45 | 385 | 369 | |||||||||||||
Regulated: | ||||||||||||||||
Natural gas transmission facilities | .01 - 7.25 | 8,814 | 8,441 | |||||||||||||
Construction in progress | 152 | 121 | ||||||||||||||
Storage and other | 0-50 | 1,301 | 1,291 | |||||||||||||
Total property, plant and equipment, at cost | 15,416 | 14,594 | ||||||||||||||
Accumulated depreciation and amortization | (5,191 | ) | (4,778 | ) | ||||||||||||
Property, plant and equipment — net | $ | 10,225 | $ | 9,816 | ||||||||||||
(a) | Estimated useful life and depreciation rates are presented as of December 31, 2009. |
Depreciation expense forproperty, plant and equipment — netwas $525 million, $498 million and $471 million in 2009, 2008 and 2007, respectively.
Regulatedproperty, plant and equipment — netincludes approximately $946 million and $985 million at December 31, 2009 and 2008, respectively, related to amounts in excess of the original cost of the regulated facilities within Gas Pipeline 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
The following table presents the significant changes to our asset retirement obligations. The current portion included in accrued liabilities at December 31, 2009 and 2008, respectively, is $5 million and $9 million:
2009 | 2008 | |||||||
(In millions) | ||||||||
Beginning balance | $ | 456 | $ | 263 | ||||
Accretion | 33 | 52 | ||||||
New obligations | 15 | 13 | ||||||
Changes in estimates of existing obligations | (10 | ) | 138 | |||||
Property dispositions/obligations settled | (12 | ) | (10 | ) | ||||
Ending balance | $ | 482 | $ | 456 | ||||
The accrued obligations relate to gas transmission facilities, underground storage caverns, offshore platforms, gas processing, fractionation and compression facilities and gas gathering well connections and pipelines. At the end of the useful life of each respective asset, we are legally obligated to remove certain components of gas transmission facilities from the ground, plug storage caverns and remove any related surface equipment, remove surface equipment and restore land at gas processing, fractionation and compression facilities, dismantle offshore platforms, cap certain gathering pipelines at the wellhead connection and remove any related surface equipment.
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Beginning in 2009, measurements of asset retirement obligations 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.
Property Insurance Changes
As a result of damage caused by recent hurricanes, the availability of named windstorm insurance has been significantly reduced. Additionally, named windstorm insurance coverage that is available for offshore assets comes at significantly higher premium amounts, higher deductibles and lower coverage limits. Considering these changes, we have reduced the overall named windstorm property insurance coverage for our assets in the Gulf of Mexico area beginning in the second quarter of 2009. In addition, certain assets are no longer covered for named windstorm losses, primarily certain offshore lateral pipelines.
Note 11. Regulatory Assets and Liabilities
The regulatory assets and regulatory liabilities included inSupplemental Consolidated Balance Sheetsat December 31, 2009 and 2008 are as follows:
December 31, | ||||||||
2009 | 2008 | |||||||
(In millions) | ||||||||
Regulatory assets: | ||||||||
Gross-up deferred taxes on equity funds used during construction | $ | 108 | $ | 111 | ||||
Asset retirement obligations | 100 | 87 | ||||||
Fuel cost | 66 | 74 | ||||||
Levelized incremental depreciation | 31 | 29 | ||||||
Postretirement benefits other than pension | 8 | 12 | ||||||
Other | 21 | 30 | ||||||
$ | 334 | $ | 343 | |||||
Regulatory liabilities: | ||||||||
Negative salvage | $ | 67 | $ | 47 | ||||
Postretirement benefits other than pension | 20 | 17 | ||||||
Other | 4 | 10 | ||||||
$ | 91 | $ | 74 | |||||
Regulatory assets are included inregulatory assetsandregulatory assets, deferred charges and other. Regulatory liabilities are included inaccrued liabilities andregulatory liabilities, deferred income and other.
Note 12. Accounts Payable and Accrued Liabilities
Under our cash-management system with Williams, certain cash accounts reflected negative balances to the extent checks written have not been presented for payment. These negative balances represent obligations and have been reclassified toaccounts payable. Accounts payableincludes approximately $28 million and $24 million of these negative balances at December 31, 2009 and 2008, respectively.
Accrued liabilitiesat December 31, 2009 and 2008 are as follows:
December 31, | ||||||||
2009 | 2008 | |||||||
(In millions) | ||||||||
Deposits | $ | 38 | $ | 34 | ||||
Taxes other than income | 16 | 48 | ||||||
Interest | 49 | 49 | ||||||
Other, including other loss contingencies | 82 | 126 | ||||||
$ | 185 | $ | 257 | |||||
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Note 13. Debt, Banking Arrangements and Leases
Long-Term Debt
Long-term debtat December 31, 2009 and 2008 includes the following:
Weighted-Average | ||||||||||||
Interest | December 31, | |||||||||||
Rate(1) | 2009 | 2008 | ||||||||||
(In millions) | ||||||||||||
Transco: | ||||||||||||
6.05% to 8.875%, payable through 2026 | 7.24 | % | $ | 1,283 | $ | 1,283 | ||||||
Williams Partners L.P.: | ||||||||||||
Credit agreement term loan, due 2012 (2) | 1.22 | % | 250 | 250 | ||||||||
Senior unsecured notes, due 2011 and 2017 | 7.30 | % | 750 | 750 | ||||||||
Northwest: | ||||||||||||
5.95% to 7.125%, payable through 2025 | 6.39 | % | 695 | 695 | ||||||||
Williams Laurel Mountain, LLC: | ||||||||||||
8.00% to 10.00%, payable through 2012 | 8.00 | % | 23 | — | ||||||||
Unamortized debt discount | (5 | ) | (7 | ) | ||||||||
Total long-term debt, including current portion | 2,996 | 2,971 | ||||||||||
Long-term debt due within one year | 15 | — | ||||||||||
Long-term debt | $ | 2,981 | $ | 2,971 | ||||||||
(1) | At December 31, 2009. | |
(2) | Certain of our debt agreements contain covenants that restrict or limit, among other things, our ability to create liens supporting indebtedness, sell assets, make certain distributions, merge, consolidate or transfer all or substantially all of our properties or assets and incur additional debt. |
The terms of the 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 incur indebtedness or liens securing indebtedness and (2) mergers, consolidations and transfers of all or substantially all of our properties or 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.
We may redeem the senior unsecured notes at our option in whole or in part at any time or from time to time prior to the respective maturity dates, at a redemption price per note equal to the sum of (1) the then outstanding principal amount thereof, plus (2) accrued and unpaid interest, if any, to the redemption date (subject to the right of holders of record on the relevant record date to receive interest due on an interest payment date that is on or prior to the redemption date), plus (3) a specified “make-whole” premium (as defined in the indenture). Additionally, upon a change of control (as defined in the indenture), each holder of the senior unsecured notes will have the right to require us to repurchase all or any part of such holder’s senior unsecured notes at a price equal to 101% of the principal amount of the senior unsecured notes plus accrued and unpaid interest, if any, to the date of settlement. Except upon a change of control as described in the prior sentence, we are not required to make mandatory redemption or sinking fund payments with respect to the senior unsecured notes or to repurchase the senior unsecured notes at the option of the holders.
In connection with the Dropdown, we issued $3.5 billion face value of senior unsecured notes as set forth in the table below.
Interest | ||||||||
Rate | Millions | |||||||
Senior unsecured notes, fixed rate, due 2015 | 3.80 | % | $ | 750 | ||||
Senior unsecured notes, fixed rate, due 2020 | 5.25 | % | 1,500 | |||||
Senior unsecured notes, fixed rate, due 2040 | 6.30 | % | 1,250 | |||||
Total debt issuance at face value | $ | 3,500 | ||||||
In connection with the issuance of the $3.5 billion notes, we entered into registration rights agreements with the initial purchasers of the notes. We are obligated to file a registration statement for an offer to exchange the notes for a new issue of substantially identical notes registered under the Securities Act of 1933, as amended, within 180 days from closing, to use commercially reasonable efforts, to cause the registration statement to be declared effective within 270 days after closing and to consummate the exchange offers within 30 business days after such effective date. We may also be required to provide a shelf registration statement to cover resales of the notes under certain circumstances. If we fail to fulfill these obligations, additional interest will accrue on the affected securities. The rate of additional interest will be 0.25% per annum on the principal amount of the affected securities for the first 90-day period immediately following the occurrence of default, increasing by an additional 0.25% per annum with respect to each subsequent 90-day period thereafter, up to a maximum amount for all such defaults of 0.5% per annum. Following the cure of any registration defaults, the accrual of additional interest will cease.
On June 1, 2009, we issued a $26 million note payable to LMM in connection with LMM’s formation. The note is due through 2012 with interest rates of 8.00% to 10.00%.
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Credit facilities
At December 31, 2009, we had a $450 million senior unsecured credit agreement (Credit Agreement) with Citibank, N.A. as administrative agent, comprised of a $200 million revolving credit facility available for borrowings and letters of credit and a $250 million term loan. We expected that our ability to borrow under this facility was reduced by $12 million due to the bankruptcy of a participating bank. We were required to repay borrowings under the Credit Agreement by December 11, 2012. At December 31, 2009 and 2008, we had a $250 million term loan outstanding under the term loan provisions and no other amounts outstanding under the Credit Agreement. As a result of the second-quarter 2009 Fitch Ratings downgrade of our senior unsecured debt rating from BB+ to BB, our applicable margin on the $250 million term loan increased 0.25% to 1.0% and the commitment fee on the unused capacity of our revolver increased 0.05% to 0.175%.
At December 31, 2009, Williams had an unsecured, $1.5 billion credit facility (Williams Credit Facility) with a maturity date of May 1, 2012. Transco and Northwest Pipeline each had access to $400 million under the Williams Credit Facility to the extent not otherwise utilized by Williams. Williams expected that its ability to borrow under the Williams Credit Facility was reduced by $70 million due to the bankruptcy of a participating bank. Consequently, we expected both Transco’s and Northwest Pipeline’s ability to borrow under the Williams Credit Facility was reduced by approximately $18 million. As of December 31, 2009, no letters of credit had been issued by the participating institutions, and there were no revolving credit loans outstanding. Interest under the Williams Credit Facility is calculated based on a choice of two methods: a fluctuating rate equal to the lender’s base rate plus an applicable margin, or a periodic fixed rate equal to LIBOR plus an applicable margin. Williams is required to pay a commitment fee (currently 0.125%) based on the unused portion of the Williams Credit Facility. The margins and commitment fee are based on the specific borrower’s senior unsecured long-term debt ratings.
In connection with the Dropdown, we terminated our credit facility, and Transco and Northwest Pipline were removed as borrowers under the Williams Credit Facility. In addition, we entered a new $1.75 billion three-year senior unsecured revolving credit facility (New Credit Facility) with Transco and Northwest Pipeline as co-borrowers, Citibank, N.A., as the administrative agent, and certain other lenders named therein. The full amount of the New Credit Facility is available to us, to the extent not otherwise utilized by Transco and Northwest Pipeline, and may be increased by up to an additional $250 million. Transco and Northwest Pipeline are each able to borrow up to $400 million under the New Credit Facility to the extent not otherwise utilized by us. At closing, we borrowed $250 million under the New Credit Facility to repay the $250 million term loan outstanding under the Credit Agreement.
Interest on borrowings under the New Credit Facility is payable at rates per annum equal to, at the option of the borrower: (1) a fluctuating base rate equal to Citibank, N.A.’s adjusted base rate plus the applicable margin or (2) a periodic fixed rate equal to LIBOR plus the applicable margin. The adjusted base rate will be the highest of (i) the federal funds rate plus 0.5%, (ii) Citibank, N.A.’s publicly announced base rate and (iii) one-month LIBOR plus 1.0%. We pay a commitment fee (currently 0.5%) based on the unused portion of the New Credit Facility. The applicable margin and the commitment fee are determined by reference to a pricing schedule based on a borrower’s senior unsecured debt ratings.
The New Credit Facility contains various covenants that limit, among other things, a borrower’s and its respective subsidiaries’ ability to incur indebtedness, grant certain liens supporting indebtedness, merge or consolidate, sell all or substantially all of its assets, enter into certain affiliate transactions, make certain distributions during an event of default and allow any material change in the nature of its business.
In addition, we are required to maintain a ratio of debt to EBITDA (each as defined in the New Credit Facility) of no greater than 5.00 to 1.00 for us and our consolidated subsidiaries. For each of Transco and Northwest pipeline and their respective consolidated subsidiaries, the ratio of debt to capitalization (defined as net worth plus debt) is not permitted to be greater than 55%. Each of the above ratios will be tested, beginning June 30, 2010, at the end of each fiscal quarter, and the debt to EBITDA ratio will be measured on a rolling four-quarter basis.
The New Credit Facility also includes customary events of default, including events of default relating to nonpayment of principal, interest or fees, inaccuracy of representations and warranties in any material respect when made or when deemed made, violation of
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covenants, cross-payment defaults, cross acceleration, bankruptcy and insolvency events, certain unsatisfied judgments and a change of control. If an event of default with respect to a borrower occurs under the New Credit Facility, the lenders will be able to terminate the commitments for all borrowers and accelerate the maturity of the loans of the defaulting borrower under the New Credit Facility and exercise other rights and remedies.
We also had a $20 million revolving credit facility with Williams as the lender. The facility was available exclusively to fund working capital requirements. We paid a commitment fee to Williams on the unused portion of the credit facility of 0.125% annually. As of December 31, 2009, we had no outstanding borrowings under the working capital credit facility. This facility was terminated in connection with the Dropdown.
Other debt disclosures
As of December 31, 2009, aggregate minimum maturities oflong-term debt(excluding unamortized discount and premium) for each of the next five years are as follows:
(In millions) | ||||
2010 | $ | 15 | ||
2011 | 458 | |||
2012 | 575 | |||
2013 | — | |||
2014 | — |
Cash payments for interest (net of amounts capitalized) were $193 million, $208 million and $175 million in 2009, 2008 and 2007, respectively.
Leases-Lessee
On October 23, 2003, Transco entered into a lease agreement for space in the Williams Tower in Houston, Texas (Williams Tower). The lease term runs through March 31, 2014.
Effective October 1, 2009, Northwest Pipeline assigned its previous headquarters building lease to another party and, concurrently, entered into a new sublease agreement with that party. This agreement has an initial term of approximately 10 years with an option to renew for an additional 5 or 10 year term.
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Under our right-of-way agreement with the Jicarilla Apache Nation (JAN), we make annual payments of approximately $8 million and an additional annual payment which varies depending on the prior year’s per-unit NGL margins and the volume of gas gathered by our gathering facilities subject to the agreement. Depending primarily on the per-unit NGL margins for any given year, the additional annual payments could approximate the fixed amount. Additionally, on April 1, 2014, the JAN will have the option to acquire up to a 50% joint venture interest for 20 years in certain of our Four Corners area assets existing at the time the option is exercised. The joint venture option includes gathering assets subject to the agreement and portions of the gathering and processing assets located in an area adjacent to the JAN lands. If the JAN selects the joint venture option, the value of the assets contributed by each party to the joint venture will be based upon a market value determined by a neutral third party at the time the joint venture is formed.
We also lease other minor office, warehouse equipment and automobiles under non-cancelable leases. The future minimum annual rentals under non-cancelable operating leases as of December 31, 2009, are payable as follows:
(In millions) | ||||
2010 | $ | 26 | ||
2011 | 19 | |||
2012 | 19 | |||
2013 | 19 | |||
2014 | 12 | |||
Thereafter | 117 | |||
Total | $ | 212 | ||
Total rent expense, net of sublease revenues, was $31 million, $43 million and $36 million in 2009, 2008 and 2007, respectively.
Note 14. Noncontrolling Interests in Consolidated Subsidiaries
WMZ
The noncontrolling interests in WMZ represent its common units held by the public. At December 31, 2009 and 2008, we held 47.7% of the interests in WMZ, including common units, subordinated units, the general partner interest and IDRs. The common units are entitled to a minimum quarterly distribution of $0.2875 per unit.
Note 15. Equity
At December 31, 2009, the public held 76% of our total units outstanding, and affiliates of Williams held the remaining units. Following the Dropdown, the public held 16% of our total units outstanding, and affiliates of Williams held the remaining units.
In connection with the Dropdown, we issued 203 million Class C limited partnership units to Williams. The Class C units are identical to our common limited partnership units except that for the first quarter of 2010 they will receive a prorated quarterly distribution since they were not outstanding during the full quarterly period. The Class C units will automatically convert into our common limited partnership units following the record date for the first-quarter 2010 distribution.
Additionally, in connection with the Dropdown, we entered into a limited call right forbearance agreement with our general partner, under which our general partner agrees to forbear exercising a right in certain circumstances that is granted to it under our partnership agreement. Under our partnership agreement, if our general partner and its affiliates hold more than 80% of our common limited partner units, our general partner has the right to purchase all of the remaining common limited partner units. In this forbearance agreement, our general partner has agreed not to exercise this right unless it and its affiliates hold more than 85% of our common limited partner units. This forbearance agreement will terminate when the ownership by our general partner and its affiliates of our common limited partner units decreases below 75% (assuming the full conversion of Class C Units that are held by our general partner and its affiliates).
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 |
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and manage our activities. | |||
• | The general partner may be removed if such removal is approved by the unitholders holding at least 66 2/3% of the outstanding units voting as a single class, including units held by our general partner and its affiliates. |
Subordinated Units
Our subordination period ended on February 19, 2008 when we met the requirements for early termination pursuant to our partnership agreement. As a result of the termination, the 7,000,000 outstanding subordinated units owned by four subsidiaries of Williams converted one-for-one to common units and now participate pro rata with the other common units in distributions of available cash.
Class B Units
On May 21, 2007, the Class B units were converted into common units on a one-for-one basis and now participate pro rata with the other common units in distributions of available cash.
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 |
In April 2009, Williams waived the IDRs related to 2009 distribution periods.
In the event of liquidation, all property and cash in excess of that required to discharge all liabilities will be distributed to the unitholders and our general partner in proportion to their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.
Issuances of Additional Partnership Securities
Our partnership agreement allows us to issue additional partnership securities for any partnership purpose at any time and from time to time for consideration and on terms and conditions as our general partner determines, all without the approval of any limited partners.
Note 16. Fair Value Measurements
Fair value is the amount received to sell an asset or the amount paid to transfer a liability in an orderly transaction between market participants (an exit price) at the measurement date. Fair value is a market-based measurement considered from the perspective of a market participant. We use market data or assumptions that we believe market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation. These inputs can be readily observable, market corroborated, or unobservable. We apply both market and income approaches for recurring fair value measurements using the best available information while utilizing valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.
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Effective January 1, 2009, we applied new accounting guidance to our nonfinancial assets and nonfinancial liabilities that are not recognized or disclosed at fair value on a recurring basis. This guidance required us to consider our nonperformance risk when estimating the fair value of our liabilities. We applied a prospective transition as we did not have financial instrument transactions that required a cumulative-effect adjustment to beginning retained earnings. This initial adoption had no material impact on our Consolidated Financial Statements.
The fair value hierarchy prioritizes the inputs used to measure fair value, giving the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). We classify fair value balances based on the observability of those inputs. The three levels of the fair value hierarchy are as follows:
• | Level 1 — Quoted prices for identical assets or liabilities in active markets that we have the ability to access. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 primarily consists of financial instruments that are exchange traded. | ||
• | Level 2 — Inputs are other than quoted prices in active markets included in Level 1, that are either directly or indirectly observable. These inputs are either directly observable in the marketplace or indirectly observable through corroboration with market data for substantially the full contractual term of the asset or liability being measured. Our Level 2 has primarily consisted of natural gas purchase contracts. | ||
• | Level 3 — Inputs that are not observable for which there is little, if any, market activity for the asset or liability being measured. These inputs reflect management’s best estimate of the assumptions market participants would use in determining fair value. Our Level 3 consists of instruments valued using industry standard pricing models and other valuation methods that utilize unobservable pricing inputs that are significant to the overall fair value. |
In valuing certain contracts, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. For disclosure purposes, assets and liabilities are classified in their entirety in the fair value hierarchy level based on the lowest level of input that is significant to the overall fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels.
The following table presents, by level within the fair value hierarchy, our assets and liabilities that are measured at fair value on a recurring basis.
December 31, | December 31, | |||||||||||||||||||||||||||||||
2009 | 2008 | |||||||||||||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||||||
(In millions) | ||||||||||||||||||||||||||||||||
Assets: | ||||||||||||||||||||||||||||||||
Marketable securities | $ | 22 | $ | — | $ | — | $ | 22 | $ | 13 | $ | — | $ | — | $ | 13 | ||||||||||||||||
Energy derivatives | — | — | 2 | 2 | — | — | 1 | 1 | ||||||||||||||||||||||||
Total assets | $ | 22 | $ | — | $ | 2 | $ | 24 | $ | 13 | $ | — | $ | 1 | $ | 14 | ||||||||||||||||
Liabilities: | ||||||||||||||||||||||||||||||||
Energy derivatives | $ | — | $ | — | $ | 2 | $ | 2 | $ | — | $ | — | $ | — | $ | — | ||||||||||||||||
Total liabilities | $ | — | $ | — | $ | 2 | $ | 2 | $ | — | $ | — | $ | — | $ | — | ||||||||||||||||
Marketable securities consist primarily of money market funds, U.S. equity funds, international equity funds and municipal bonds. Energy derivatives consist primarily of commodity-based contracts with WGM, a wholly-owned subsidiary of Williams, that resemble similar exchange-traded contracts and over-the-counter (OTC) contracts. Exchange-traded contracts include futures, swaps, and options. OTC contracts include forwards, swaps and options.
Many contracts have bid and ask prices that can be observed in the market. Our policy is to use a mid-market pricing (the mid-point price between bid and ask prices) convention to value individual positions and then adjust on a portfolio level to a point within the bid and ask range that represents our best estimate of fair value. For offsetting positions by location, the mid-market price is used to measure both the long and short positions.
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The determination of fair value for our assets and liabilities also incorporates the time value of money and various credit risk factors which can include the credit standing of the counterparties involved, master netting arrangements, the impact of credit enhancements (such as cash collateral posted and letters of credit), and our nonperformance risk on our liabilities. The determination of the fair value of our liabilities does not consider noncash collateral credit enhancements.
Exchange-traded contracts include New York Mercantile Exchange and Intercontinental Exchange contracts and are valued based on quoted prices in these active markets and are classified within Level 1.
Contracts for which fair value can be estimated from executed transactions or broker quotes corroborated by other market data are generally classified within Level 2. These broker quotes are based on observable market prices at which transactions could currently be executed. In certain instances where these inputs are not observable for all periods, relationships of observable market data and historical observations are used as a means to estimate fair value. Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. The instruments included in Level 2 consist primarily of natural gas swaps, options and physical commitments.
Certain instruments trade in less active markets with lower availability of pricing information requiring valuation models using inputs that may not be readily observable or corroborated by other market data. These instruments are classified within Level 3 when these inputs have a significant impact on the measurement of fair value. The fair value of options is estimated using an industry standard Black-Scholes option pricing model. Certain inputs into the model are generally observable, such as commodity prices and interest rates, whereas other model inputs, such as implied volatility by location, is unobservable and requires judgment in estimating. The instruments included in Level 3 consist primarily of location based natural gas liquids swaps, options and physical commitments.
The following tables present a reconciliation of changes in the fair value of net derivatives classified as Level 3 in the fair value hierarchy.
Level 3 Fair Value Measurements Using Significant Unobservable Inputs
Net Derivatives | ||||||||
Year Ended December 31, | ||||||||
2009 | 2008 | |||||||
(In millions) | ||||||||
Beginning balance | $ | 1 | $ | (9 | ) | |||
Realized and unrealized gains (losses): | ||||||||
Included innet income | — | (9 | ) | |||||
Included inother comprehensive income (loss) | (2 | ) | 8 | |||||
Purchases, issuances, and settlements | 1 | 11 | ||||||
Transfers into Level 3 | — | — | ||||||
Transfers out of Level 3 | — | — | ||||||
Ending balance | $ | — | $ | 1 | ||||
Net unrealized gains included innet income relating to instruments still held at end of period | $ | 2 | $ | — | ||||
Realized and unrealized gains (losses) included innet incomefor the above periods are reported inrevenuesin ourSupplemental Consolidated Statements of Income.
During 2009, there were no assets or liabilities measured at fair value on a nonrecurring basis.
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Note 17. Financial Instruments, Derivatives, Guarantees and Concentration of Credit Risk
Financial Instruments
Fair-value methods
We use the following methods and assumptions in estimating our fair-value disclosures for financial instruments:
Cash and cash equivalents:The carrying amounts reported in theSupplemental Consolidated Balance Sheetsapproximate fair value due to the short-term maturity of these instruments.
ARO Trust Investments: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 asset retirement obligations. The ARO Trust invests in a portfolio of mutual funds that are classified as available-for-sale and are reported inregulatory assets, deferred charges and otherin theSupplemental Consolidated Balance Sheets. The fair value of these investments is based on indicative period-end traded market prices.
Notes receivable from parent:The carrying amounts reported in theSupplemental Consolidated Balance Sheetsapproximate fair value as these instruments are due on demand and have interest rates approximating market.
Notes and other noncurrent receivables:The carrying amounts reported in theSupplemental Consolidated Balance Sheetsapproximate fair value as these instruments have interest rates approximating market.
Long-term debt: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. We consider our non-performance risk in estimating fair value. At December 31, 2009 and 2008, approximately 91% and 92%, respectively, of our long-term debt was publicly traded.
Energy derivatives:Energy derivatives include futures, forwards, swaps, and options. See Note 16 for discussion of valuation of our energy derivatives.
Carrying amounts and fair values of our financial instruments
December 31, | December 31, | |||||||||||||||
2009 | 2008 | |||||||||||||||
Carrying | Carrying | |||||||||||||||
Amount | Fair Value | Amount | Fair Value | |||||||||||||
(In millions) | ||||||||||||||||
Asset (Liability): | ||||||||||||||||
Cash and cash equivalents | $ | 153 | $ | 153 | $ | 133 | $ | 133 | ||||||||
ARO Trust Investments | 22 | 22 | 13 | 13 | ||||||||||||
Notes receivable from parent | — | — | 252 | 252 | ||||||||||||
Notes and other noncurrent receivables | 3 | 3 | 1 | 1 | ||||||||||||
Long-term debt, including current portion | (2,996 | ) | (3,194 | ) | (2,971 | ) | (2,552 | ) | ||||||||
Net energy derivatives: | ||||||||||||||||
Energy commodity cash flow hedges — affiliate | (2 | ) | (2 | ) | — | — | ||||||||||
Other energy derivatives | 2 | 2 | 1 | 1 |
Energy Commodity Derivatives
Risk Management Activities
We are exposed to market risk from changes in energy commodity prices within our operations. We may utilize derivatives to manage our exposure to the variability in expected future cash flows from forecasted purchases of natural gas and forecasted sales of NGLs attributable to commodity price risk. Certain of these derivatives utilized for risk management purposes have been designated
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as cash flow hedges while others 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.
Midstream sells NGL volumes that it receives as compensation for certain processing services at different locations throughout the United States. Midstream also buys natural gas to satisfy the required fuel and shrink needed to generate NGLs. To reduce exposure to a decrease in revenues from fluctuations in NGL market prices or increases in costs and operating expenses from fluctuations in natural gas market prices, we may enter into NGL or natural gas swap agreements, financial or physical forward contracts, and financial option contracts to mitigate the price risk on forecasted sales of NGLs and purchases of natural gas. Midstream’s 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 three types:
• | Fixed price:Includes physical and financial derivative transactions that settle at a fixed location price; | ||
• | Basis:Includes financial derivative transactions priced off the difference in value between a commodity at two specific delivery points; and | ||
• | Index:Includes physical derivative transactions at an unknown future price. | ||
The following table depicts the notional amounts of the net long (short) positions in our commodity derivatives portfolio as of December 31, 2009. Natural gas is presented in millions of British Thermal Units (MMBtu) and NGLs are presented in gallons. |
Derivative Notional Volumes | Measurement | Fixed Price | Basis | Index | ||||||||||
Designated as Hedging Instruments | ||||||||||||||
Midstream Risk Management | MMBtu | 1,247,500 | 412,500 | |||||||||||
Midstream Risk Management | Gallons | (30,240,000 | ) | |||||||||||
Not Designated as Hedging Instruments | ||||||||||||||
Midstream Risk Management | Gallons | (2,998,800 | ) | |||||||||||
Midstream Other | MMBtu | 835,000 |
Fair values and gains (losses)
The following table presents the fair value of energy commodity derivatives. Our derivatives are included inother current assets, regulatory assets, deferred charges and other,andaccrued liabilitiesin ourSupplemental Consolidated Balance Sheets. Derivatives are classified as current or noncurrent based on the contractual timing of expected future net cash flows of individual contracts. The expected future net cash flows for derivatives classified as current are expected to occur within the next twelve months. 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.
December 31, | ||||||||
2009 | ||||||||
Assets | Liabilities | |||||||
(In millions) | ||||||||
Designated as hedging instruments | $ | — | $ | 2 | ||||
Not designated as hedging instruments | 2 | — | ||||||
Total derivatives | $ | 2 | $ | 2 | ||||
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The following table presents gains and losses for our energy commodity derivatives designated as cash flow hedges, as recognized in accumulated other comprehensive income (AOCI) or revenues.
Year Ended | ||||||||
December 31, | ||||||||
2009 | Classification | |||||||
(In millions) | ||||||||
Net gain (loss) recognized in other comprehensive income (effective portion) | $ | (6 | ) | AOCI | ||||
Net gain (loss) reclassified from accumulated other comprehensive income into income (effective portion) | $ | (4 | ) | Revenues | ||||
Gain (loss) recognized in income (ineffective portion) | $ | — | Revenues |
There were no gains or losses recognized in income as a result of excluding amounts from the assessment of hedge effectiveness or as a result of reclassifications to earnings following the discontinuance of any cash flow hedges. As of December 31, 2009, we have hedged portions of future cash flows associated with anticipated NGL sales and natural gas purchases for up to one year. Based on recorded values at December 31, 2009, net losses to be reclassified into earnings within the next twelve months are $2 million. These recorded values are based on market prices of the commodities as of December 31, 2009. Due to the volatile nature of commodity prices and changes in the creditworthiness of counterparties, actual gains or losses realized in the next twelve months will likely differ from these values. These gains or losses will offset net losses or gains that will be realized in earnings from previous unfavorable or favorable market movements associated with underlying hedged transactions.
Gains on our energy commodity derivatives not designated as hedging instruments of $4 million were recognized inMidstream revenuesduring 2009.
The cash flow impact of our derivative activities is presented in theSupplemental Consolidated Statements of Cash Flowsaschanges in other current assets, changes in accrued liabilitiesandchanges in noncurrent assets.
Credit-risk-related features
Our financial swap contracts are with WGM, and the derivative contracts not designated as hedging instruments are physical commodity sale contracts. These agreements do not contain any provisions that require us to post collateral related to net liability positions.
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.
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Accounts and notes receivable
The following table summarizes concentration of receivables, net of allowances, by product or service at December 31, 2009 and 2008:
December 31, | ||||||||
2009 | 2008 | |||||||
(In millions) | ||||||||
Receivables by product or service: | ||||||||
Sale of NGLs and related products and services | $ | 228 | $ | 143 | ||||
Transportation of natural gas and related products | 159 | 135 | ||||||
Total accounts receivable | 387 | 278 | ||||||
Notes receivable from parent | — | 252 | ||||||
Total | $ | 387 | $ | 530 | ||||
Natural gas and NGL customers include pipelines, distribution companies, producers, gas marketers and industrial users primarily located in the 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.
Derivative assets and liabilities
We have a risk of loss from counterparties not performing pursuant to the terms of their contractual obligations. Risk of loss is impacted by several factors, including credit considerations. We attempt to minimize credit-risk exposure to derivative counterparties through formal credit policies, consideration of credit ratings from public ratings agencies, monitoring procedures and collateral support under certain circumstances. Our NGL and natural gas financial contracts are with WGM and do not contain any provisions that require either party to post collateral related to net liability positions. Historically, WGM has not passed any counterparty risk back to us when they enter offsetting NGL and natural gas financial contracts with third parties. Our remaining derivatives are physical commodity sale contracts with non-investment grade companies.
Revenues
During 2009, we had one customer in our Midstream segment that accounted for 10% of our consolidated revenues. There were no customers for which our sales exceeded 10% of our consolidated revenues in 2008. During 2007, there were two customers in our Midstream segment for which our sales exceeded 10% of our consolidated revenues. The largest customer represented 15% of our 2007 consolidated revenues and the other represented 11%.
Note 18. Long-Term Incentive Plan
Our general partner maintains the Williams Partners GP LLC Long-Term Incentive Plan (the Plan) for employees, consultants and directors of our general partner and its affiliates who perform services for us. Initially, the Plan permitted granting of awards covering an aggregate of 700,000 common units, in the form of options, restricted units, phantom units or unit appreciation rights. During 2009 the Director’s Compensation Policy was amended to a 100% cash compensation program, thereby eliminating the issuance of any partnership units. The revisions to the policy do not affect restricted units previously granted.
During 2008 and 2007 our general partner granted 2,724 and 2,403 restricted units, respectively, pursuant to the Plan to members of our general partner’s board of directors who are not officers or employees of our general partner or its affiliates. These restricted units vested 180 days from the grant date. We recognized compensation expense of $20,000, $98,000 and $77,000 associated with the Plan in 2009, 2008 and 2007, respectively, based on the market price of our common units at the date of grant. No awards were granted under the plan in 2009.
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Note 19. Contingent Liabilities and Commitments
Environmental Matters
Since 1989, Transco has had studies underway to test certain of its facilities for the presence of toxic and hazardous substances to determine to what extent, if any, remediation may be necessary. Transco has responded to data requests from the U.S. Environmental Protection Agency (EPA) and state agencies regarding such potential contamination of certain of its sites. Transco has identified polychlorinated biphenyl (PCB) contamination in compressor systems, soils and related properties at certain compressor station sites. Transco has also been involved in negotiations with the EPA and state agencies to develop screening, sampling and cleanup programs. In addition, Transco commenced negotiations with certain environmental authorities and other parties concerning investigative and remedial actions relative to potential mercury contamination at certain gas metering sites. The costs of any such remediation will depend upon the scope of the remediation. At December 31, 2009, we had accrued liabilities of $5 million related to PCB contamination, potential mercury contamination, and other toxic and hazardous substances. Transco has been identified as a potentially responsible party at various Superfund and state waste disposal sites. Based on present volumetric estimates and other factors, we have estimated our aggregate exposure for remediation of these sites to be less than $1 million, which is included in the environmental accrual discussed above. We expect that these costs will be recoverable through Transco’s rates.
Beginning in the mid-1980s, Northwest Pipeline evaluated many of its facilities for the presence of toxic and hazardous substances to determine to what extent, if any, remediation might be necessary. Consistent with other natural gas transmission companies, Northwest Pipeline identified PCB contamination in air compressor systems, soils and related properties at certain compressor station sites. Similarly, Northwest Pipeline identified hydrocarbon impacts at these facilities due to the former use of earthen pits and mercury contamination at certain gas metering sites. The PCBs were remediated pursuant to a Consent Decree with the EPA in the late 1980s and Northwest Pipeline conducted a voluntary clean-up of the hydrocarbon and mercury impacts in the early 1990s. In 2005, the Washington Department of Ecology required Northwest Pipeline to reevaluate its previous mercury clean-ups in Washington. Consequently, Northwest Pipeline is conducting additional remediation activities at certain sites to comply with Washington’s current environmental standards. At December 31, 2009, we have accrued liabilities of $8 million for these costs. We expect that these costs will be recoverable through Northwest Pipeline’s rates.
In March 2008, the EPA issued a new air quality standard for ground level ozone. In September 2009, the EPA announced that it would reconsider those standards. In January 2010, the EPA proposed more stringent standards, which are expected to be final in August 2010. The EPA expects that new eight-hour ozone nonattainment areas will be designated in July 2011. The new standards and nonattainment areas will likely impact the operations of our interstate gas pipelines and cause us to incur additional capital expenditures to comply. At this time we are unable to estimate the cost of these additions that may be required to meet these regulations. We expect that costs associated with these compliance efforts will be recoverable through rates.
In September 2007, the EPA requested, and Transco later provided, information regarding natural gas compressor stations in the states of Mississippi and Alabama as part of the EPA’s investigation of our compliance with the Clean Air Act. On March 28, 2008, the EPA issued NOVs alleging violations of Clean Air Act requirements at these compressor stations. Transco met with the EPA in May 2008 and submitted its response denying the allegations in June 2008. In July 2009, the EPA requested additional information pertaining to these compressor stations and in August 2009, Transco submitted the requested information.
In April 2007, the New Mexico Environment Department’s Air Quality Bureau (NMED) issued a Notice of Violation (NOV) that alleges various emission and reporting violations in connection with our Lybrook gas processing plant’s flare and leak detection and repair program. In December 2007, the NMED proposed a penalty of approximately $3 million. In July 2008, the NMED issued an NOV that alleged air emissions permit exceedances for three glycol dehydrators at one of our compressor facilities and proposed a penalty of approximately $103,000. We are discussing the proposed penalties with the NMED. In March 2008, the Environmental Protection Agency (EPA) proposed a penalty of $370,000 for alleged violations relating to leak detection and repair program delays at our Ignacio gas plant in Colorado and for alleged permit violations at a compressor station. We met with the EPA and are exchanging information in order to resolve the issues. We have accrued liabilities totaling $1 million at December 31, 2009 for these environmental activities.
Current federal regulations require that certain unlined liquid containment pits located near named rivers and catchment areas be taken out of use, and current state regulations required all unlined, earthen pits to be either permitted or closed by December 31, 2005. Operating under a New Mexico Oil Conservation Division-approved work plan, we have physically closed all of our pits that were slated for closure under those regulations. We are presently awaiting agency approval of the closures for 40 to 50 of those pits. We are also a participant in certain hydrocarbon removal and groundwater monitoring activities associated with certain well sites in New Mexico. Of nine remaining active sites, product removal is ongoing at four and groundwater monitoring is ongoing at each site. As groundwater concentrations reach and sustain closure criteria levels and state regulator approval is received, the sites will be properly abandoned. We expect the remaining sites will be closed within four to seven years.
We are a participant in certain environmental remediation activities associated with soil and groundwater contamination at our Conway storage facilities. These activities relate to four projects that are in various remediation stages including assessment studies, cleanups and/or remedial operations and monitoring. We continue to coordinate with the Kansas Department of Health and Environment (KDHE) to develop screening, sampling, cleanup and monitoring programs. The costs of such activities will depend upon the program scope ultimately agreed to by the KDHE and are expected to be paid over the life of the assets. At December 31,
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2009, we had accrued liabilities totaling $5 million for these costs. Under an omnibus agreement with Williams entered into at the closing of our initial public offering, Williams agreed to indemnify us for certain Conway environmental remediation costs. At December 31, 2009, approximately $7 million remains available for future indemnification. Payments received under this indemnification are accounted for as a capital contribution to us by Williams as the costs are reimbursed.
Summary of environmental matters
Actual costs incurred for these matters could be substantially greater than amounts accrued depending on the actual number of contaminated sites identified, the actual amount and extent of contamination discovered, the final cleanup standards mandated by the EPA and other governmental authorities and other factors, but the amount cannot be reasonably estimated at this time.
Rate Matters
On March 1, 2001, Transco submitted to the FERC a general rate filing (Docket No. RP01-245) to recover increased costs. All cost of service, throughput and throughput mix, cost allocation and rate design issues in this rate proceeding have been resolved by settlement or litigation. The resulting rates were effective from September 1, 2001 to March 1, 2007. A tariff matter related to storage service in this proceeding has not yet been resolved.
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
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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 sought rehearing of the FERC’s order.
Safety Matters
The United States Department of Transportation Pipeline and Hazardous Materials Safety Administration rules implementing the Pipeline Safety Improvement Act of 2002 require pipeline operators to implement integrity management programs, including more frequent inspections and other safeguards in areas where the potential consequences of pipeline accidents pose the greatest risk to people and property. In accordance with the final rule, Transco and Northwest Pipeline developed Integrity Management Plans, identified high consequence areas, completed baseline assessment plans, and are on schedule to complete the required assessments within specified timeframes. Currently, Transco and Northwest Pipeline estimate that the cost to perform required assessments and remediation will be primarily capital and range between $150 million and $220 million, and between $65 million and $85 million, respectively, over the remaining assessment period of 2010 through 2012. Management considers the costs associated with compliance with the rule to be prudent costs incurred in the ordinary course of business and, therefore, recoverable through their respective rates.
Other Legal Matters
Will Price (formerly Quinque)
In 2001, we were named, along with other subsidiaries of Williams, as defendants in a nationwide class action lawsuit in Kansas state court that had been pending against other defendants, generally pipeline and gathering companies, since 2000. The plaintiffs alleged that the defendants have engaged in mismeasurement techniques that distort the heating content of natural gas, resulting in an alleged underpayment of royalties to the class of producer plaintiffs and sought an unspecified amount of damages. The fourth amended petition, which was filed in 2003, deleted all of our defendant entities except two Midstream subsidiaries. All remaining defendants have opposed class certification, and on September 18, 2009, the court denied plaintiffs’ most recent motion to certify the class. On October 2, 2009, the plaintiffs filed a motion for reconsideration of the denial. We are awaiting a decision from the court. The amount of any possible liability cannot be reasonably estimated at this time.
GEII Litigation
General Electric International, Inc. (GEII) worked on turbines at our Ignacio, New Mexico plant. We disagree with GEII on the quality of GEII’s work and the appropriate compensation. GEII asserts that it is entitled to additional extra work charges under the agreement, which we deny are due. In 2006, we filed suit in federal court in Tulsa, Oklahoma against GEII, GE Energy Services, Inc., and Qualified Contractors, Inc. We alleged, among other claims, breach of contract, breach of the duty of good faith and fair dealing, and negligent misrepresentation and sought unspecified damages. In 2007, the defendants and GEII filed counterclaims in the amount of $1.9 million against us that alleged breach of contract and breach of the duty of good faith and fair dealing. This matter was settled in 2009.
Other
In addition to the foregoing, various other proceedings are pending against us which are incidental to our operations.
Summary
Litigation, regulatory matters and environmental matters are subject to inherent uncertainties. Were an unfavorable ruling to occur, there exists the possibility of a material adverse impact on the results of operations in the period in which the ruling occurs. Management, including internal counsel, currently believes that the ultimate resolution of the foregoing matters, taken as a whole and after consideration of amounts accrued, insurance coverage, recovery from customers or other indemnification arrangements, will not have a material adverse effect upon our future liquidity or financial position.
Commitments
Commitments for construction and acquisition of property, plant and equipment are approximately $250 million at December 31, 2009.
Note 20. Segment Disclosures
Our reportable segments are strategic business units that offer different products and services. The segments are managed separately because each segment requires different technology, marketing strategies and industry knowledge. WMZ is consolidated within the Gas Pipeline segment. (See Note 1)
Performance Measurement
We currently evaluate performance based onsegment profitfrom operations, which includessegment revenuesfrom external and internal customers,segment costs and expenses, and equity earnings. The accounting policies of the segments are the same as those described in Note 2. Intersegment sales are generally accounted for at current market prices as if the sales were to unaffiliated third parties.
The primary types of costs and operating expenses by segment can be generally summarized as follows:
• | Gas Pipeline — depreciation and operation and maintenance expenses; and | ||
• | Midstream Gas & Liquids — commodity purchases (primarily for NGL and crude marketing, shrink, feedstock and fuel), depreciation, and operation and maintenance expenses. |
The following table reflects the reconciliation ofsegment revenuestorevenuesandsegment profittooperating incomeas reported in theSupplemental Consolidated Statements of Income. It also presents other financial information related to long-lived assets.
Midstream | ||||||||||||||||
Gas | Gas & | |||||||||||||||
Pipeline | Liquids | Eliminations | Total | |||||||||||||
(In millions) | ||||||||||||||||
Year Ended December 31, 2009 | ||||||||||||||||
Segment revenues: | ||||||||||||||||
External | $ | 1,590 | $ | 2,922 | $ | — | $ | 4,512 | ||||||||
Internal | 1 | 6 | (7 | ) | — | |||||||||||
Total revenues | $ | 1,591 | $ | 2,928 | $ | (7 | ) | $ | 4,512 | |||||||
Segment profit | $ | 635 | $ | 673 | $ | — | $ | 1,308 | ||||||||
Less: | ||||||||||||||||
Equity earnings | 35 | 46 | — | 81 | ||||||||||||
Segment operating income | $ | 600 | $ | 627 | $ | — | $ | 1,227 | ||||||||
General corporate expense | (105 | ) | ||||||||||||||
Total operating income | $ | 1,122 | ||||||||||||||
Other financial information: | ||||||||||||||||
Additions to long-lived assets | $ | 518 | $ | 485 | $ | — | $ | 1,003 | ||||||||
Depreciation and amortization | $ | 334 | $ | 197 | $ | — | $ | 531 |
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Midstream | ||||||||||||||||
Gas | Gas & | |||||||||||||||
Pipeline | Liquids | Eliminations | Total | |||||||||||||
(In millions) | ||||||||||||||||
Year Ended December 31, 2008 | ||||||||||||||||
Segment revenues: | ||||||||||||||||
External | $ | 1,637 | $ | 4,125 | $ | — | $ | 5,762 | ||||||||
Internal | — | 10 | (10 | ) | — | |||||||||||
Total revenues | $ | 1,637 | $ | 4,135 | $ | (10 | ) | $ | 5,762 | |||||||
Segment profit | $ | 661 | $ | 755 | $ | — | $ | 1,416 | ||||||||
Less: | ||||||||||||||||
Equity earnings | 31 | 45 | — | 76 | ||||||||||||
Segment operating income | $ | 630 | $ | 710 | $ | — | $ | 1,340 | ||||||||
General corporate expense | (92 | ) | ||||||||||||||
Total operating income | $ | 1,248 | ||||||||||||||
Other financial information: | ||||||||||||||||
Additions to long-lived assets | $ | 413 | $ | 654 | $ | — | $ | 1,067 | ||||||||
Depreciation and amortization | $ | 319 | $ | 184 | $ | — | $ | 503 |
Midstream | ||||||||||||||||
Gas | Gas & | |||||||||||||||
Pipeline | Liquids | Eliminations | Total | |||||||||||||
(In millions) | ||||||||||||||||
Year Ended December 31, 2007 | ||||||||||||||||
Segment revenues: | ||||||||||||||||
External | $ | 1,619 | $ | 3,997 | $ | — | $ | 5,616 | ||||||||
Internal | 4 | — | (4 | ) | — | |||||||||||
Total revenues | $ | 1,623 | $ | 3,997 | $ | (4 | ) | $ | 5,616 | |||||||
Segment profit | $ | 649 | $ | 911 | $ | — | $ | 1,560 | ||||||||
Less: | ||||||||||||||||
Equity earnings | 27 | 52 | — | 79 | ||||||||||||
Segment operating income | $ | 622 | $ | 859 | $ | — | $ | 1,481 | ||||||||
General corporate expense | (98 | ) | ||||||||||||||
Total operating income | $ | 1,383 | ||||||||||||||
Other financial information: | ||||||||||||||||
Additions to long-lived assets | $ | 546 | $ | 609 | $ | — | $ | 1,155 | ||||||||
Depreciation and amortization | $ | 313 | $ | 165 | $ | — | $ | 478 |
The following table reflectstotal assetsandinvestmentsby reporting segment.
Total Assets at December 31, | Investments at December 31, | |||||||||||||||||||||||
2009 | 2008 | 2007 | 2009 | 2008 | 2007 | |||||||||||||||||||
(In millions) | ||||||||||||||||||||||||
Gas Pipeline | $ | 7,711 | $ | 7,890 | $ | 7,673 | $ | 233 | $ | 302 | $ | 259 | ||||||||||||
Midstream Gas & Liquids | 4,276 | 3,788 | 3,397 | 360 | 222 | 258 | ||||||||||||||||||
Eliminations and reclassifications | (3 | ) | (2 | ) | (6 | ) | — | — | — | |||||||||||||||
Total | $ | 11,984 | $ | 11,676 | $ | 11,064 | $ | 593 | $ | 524 | $ | 517 | ||||||||||||
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