Exhibit 99.1
Report of Independent Auditors
The Board of Directors of
The Williams Companies, Inc.
The Williams Companies, Inc.
We have audited the accompanying combined balance sheets of the Contributed Entities, as defined in Note 1, as of December 31, 2009 and 2008, and the related combined statements of income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2009. These financial statements are the responsibility of The Williams Companies, Inc.’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the 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 Contributed Entities’ internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Contributed Entities’ 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.
In our opinion, the financial statements referred to above present fairly, in all material respects, the combined financial position of the Contributed Entities at December 31, 2009 and 2008, and the combined results of their operations and their cash flows for each of the three years in the period ended December 31, 2009, in conformity with U.S. generally accepted accounting principles.
/s/ Ernst & Young LLP
Tulsa, Oklahoma
April 20, 2010
April 20, 2010
CONTRIBUTED ENTITIES
December 31, | ||||||||
2008 | 2009 | |||||||
(In millions) | ||||||||
ASSETS | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 16 | $ | 9 | ||||
Accounts receivable: | ||||||||
Trade | 249 | 356 | ||||||
Affiliate | 9 | 9 | ||||||
Notes receivable from parent | 252 | — | ||||||
Inventories | 146 | 129 | ||||||
Regulatory assets | 89 | 77 | ||||||
Other current assets | 80 | 64 | ||||||
Total current assets | 841 | 644 | ||||||
Investments | 339 | 405 | ||||||
Property, plant and equipment — net | 9,176 | 9,591 | ||||||
Regulatory assets, deferred charges and other | 322 | 320 | ||||||
Total assets | $ | 10,678 | $ | 10,960 | ||||
LIABILITIES AND EQUITY | ||||||||
Current liabilities: | ||||||||
Accounts payable: | ||||||||
Trade | $ | 285 | $ | 322 | ||||
Affiliate | 70 | 86 | ||||||
Accrued liabilities | 225 | 151 | ||||||
Long-term debt due within one year | — | 15 | ||||||
Total current liabilities | 580 | 574 | ||||||
Long-term debt | 1,971 | 1,981 | ||||||
Asset retirement obligations | 434 | 462 | ||||||
Regulatory liabilities, deferred income and other | 223 | 258 | ||||||
Contingent liabilities and commitments (Note 16) | ||||||||
Equity: | ||||||||
Owner’s equity | 6,846 | 7,065 | ||||||
Accumulated other comprehensive income | 4 | 2 | ||||||
Noncontrolling interests in consolidated subsidiaries | 620 | 618 | ||||||
Total equity | 7,470 | 7,685 | ||||||
Total liabilities and equity | $ | 10,678 | $ | 10,960 | ||||
See accompanying notes to combined financial statements
1
CONTRIBUTED ENTITIES
Year Ended | ||||||||||||
December 31, | ||||||||||||
2007 | 2008 | 2009 | ||||||||||
(In millions) | ||||||||||||
Revenues: | ||||||||||||
Gas Pipeline | $ | 1,623 | $ | 1,637 | $ | 1,593 | ||||||
Midstream Gas & Liquids | 3,707 | 3,828 | 2,640 | |||||||||
Intercompany eliminations | (4 | ) | (10 | ) | (7 | ) | ||||||
Total revenues | 5,326 | 5,455 | 4,226 | |||||||||
Segment costs and expenses: | ||||||||||||
Costs and operating expenses | 3,776 | 4,027 | 2,893 | |||||||||
Selling, general and administrative expense | 227 | 234 | 251 | |||||||||
Other (income) expense — net | (32 | ) | 15 | (27 | ) | |||||||
Segment costs and expenses | 3,971 | 4,276 | 3,117 | |||||||||
General corporate expenses | 88 | 80 | 95 | |||||||||
Operating income: | ||||||||||||
Gas Pipeline | 622 | 630 | 600 | |||||||||
Midstream Gas & Liquids | 733 | 549 | 509 | |||||||||
General corporate expenses | (88 | ) | (80 | ) | (95 | ) | ||||||
Total operating income | 1,267 | 1,099 | 1,014 | |||||||||
Equity earnings | 51 | 55 | 58 | |||||||||
Interest accrued — third-party | (147 | ) | (144 | ) | (145 | ) | ||||||
Interest accrued — affiliate | (19 | ) | (35 | ) | (51 | ) | ||||||
Interest capitalized | 23 | 36 | 55 | |||||||||
Interest income — third-party | 4 | 1 | 1 | |||||||||
Interest income — affiliate | 18 | 23 | 19 | |||||||||
Other income — net | 19 | 10 | 13 | |||||||||
Income before income taxes | 1,216 | 1,045 | 964 | |||||||||
Provision (benefit) for income taxes | (144 | ) | (952 | ) | 4 | |||||||
Net income | 1,360 | 1,997 | 960 | |||||||||
Less: Net income attributable to noncontrolling interests in subsidiaries | 7 | 113 | 110 | |||||||||
Net income attributable to controlling interests | $ | 1,353 | $ | 1,884 | $ | 850 | ||||||
See accompanying notes to combined financial statements
2
CONTRIBUTED ENTITIES
Contributed Entities | ||||||||||||||||
Accumulated | ||||||||||||||||
Other | ||||||||||||||||
Owner’s | Comprehensive | Noncontrolling | ||||||||||||||
Equity | Income | Interests | Total | |||||||||||||
(In millions) | ||||||||||||||||
Balance, December 31, 2006 | $ | 5,257 | $ | 5 | $ | — | $ | 5,262 | ||||||||
Comprehensive income (loss): | ||||||||||||||||
Net income — 2007 | 1,353 | — | 7 | 1,360 | ||||||||||||
Net unrealized losses on cash flow hedges, net of reclassification adjustments | — | (8 | ) | — | (8 | ) | ||||||||||
Total comprehensive income (loss) | 1,353 | (8 | ) | 7 | 1,352 | |||||||||||
Distribution of noncontrolling interest in Wamsutter | (278 | ) | — | 278 | — | |||||||||||
Distributions to The Williams Companies, Inc. — net | (623 | ) | — | — | (623 | ) | ||||||||||
Balance, December 31, 2007 | 5,709 | (3 | ) | 285 | 5,991 | |||||||||||
Comprehensive income(loss): | ||||||||||||||||
Net income — 2008 | 1,884 | — | 113 | 1,997 | ||||||||||||
Net unrealized gains on cash flow hedges, net of reclassification adjustments | — | 7 | — | 7 | ||||||||||||
Total comprehensive income | 1,884 | 7 | 113 | 2,004 | ||||||||||||
Sale of Williams Pipeline Partners L.P. limited partner units | — | — | 333 | 333 | ||||||||||||
Dividends paid to noncontrolling interests | — | — | (111 | ) | (111 | ) | ||||||||||
Distributions to The Williams Companies, Inc. — net | (747 | ) | — | — | (747 | ) | ||||||||||
Balance, December 31, 2008 | 6,846 | 4 | 620 | 7,470 | ||||||||||||
Comprehensive income (loss): | ||||||||||||||||
Net income — 2009 | 850 | — | 110 | 960 | ||||||||||||
Net unrealized losses on cash flow hedges, net of reclassification adjustments | — | (2 | ) | — | (2 | ) | ||||||||||
Total comprehensive income (loss) | 850 | (2 | ) | 110 | 958 | |||||||||||
Dividends paid to noncontrolling interests | — | — | (113 | ) | (113 | ) | ||||||||||
Distributions to The Williams Companies, Inc. — net | (377 | ) | — | — | (377 | ) | ||||||||||
Reclassification of notes receivable (see Note 3) | (253 | ) | — | — | (253 | ) | ||||||||||
Other | (1 | ) | — | 1 | — | |||||||||||
Balance, December 31, 2009 | $ | 7,065 | $ | 2 | $ | 618 | $ | 7,685 | ||||||||
See accompanying notes to combined financial statements
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CONTRIBUTED ENTITIES
Year Ended December 31, | ||||||||||||
2007 | 2008 | 2009 | ||||||||||
(In millions) | ||||||||||||
OPERATING ACTIVITIES: | ||||||||||||
Net income | $ | 1,360 | $ | 1,997 | $ | 960 | ||||||
Adjustments to reconcile to net cash provided by operations: | ||||||||||||
Depreciation and amortization | 432 | 458 | 486 | |||||||||
Benefit for deferred income taxes | (306 | ) | (997 | ) | — | |||||||
Gain on sale of Cameron Meadows plant | — | — | (40 | ) | ||||||||
Cash provided (used) by changes in current assets and liabilities: | ||||||||||||
Accounts and notes receivable | (115 | ) | 136 | ( 91 | ) | |||||||
Inventories | 38 | (42 | ) | 17 | ||||||||
Other current assets | 9 | (77 | ) | 14 | ||||||||
Accounts payable | 56 | (172 | ) | 5 | ||||||||
Accrued liabilities | 156 | 25 | (80 | ) | ||||||||
Affiliates — net | (37 | ) | (9 | ) | 16 | |||||||
Other, including changes in noncurrent assets and liabilities | 75 | (2 | ) | 46 | ||||||||
Net cash provided by operating activities | 1,668 | 1,317 | 1,333 | |||||||||
FINANCING ACTIVITIES: | ||||||||||||
Proceeds from long-term debt | 434 | 674 | — | |||||||||
Payments of long-term debt | (428 | ) | (600 | ) | (2 | ) | ||||||
Proceeds from sale of Williams Pipeline Partners L.P. limited partner units | — | 333 | — | |||||||||
Dividends paid to noncontrolling interests in subsidiaries | — | (111 | ) | (113 | ) | |||||||
Distributions to The Williams Companies, Inc. — net | (623 | ) | (747 | ) | (377 | ) | ||||||
Other — net | (13 | ) | (10 | ) | 5 | |||||||
Net cash used by financing activities | (630 | ) | (461 | ) | (487 | ) | ||||||
INVESTING ACTIVITIES: | ||||||||||||
Property, plant and equipment: | ||||||||||||
Capital expenditures | (979 | ) | (821 | ) | (850 | ) | ||||||
Net proceeds from dispositions | (9 | ) | 30 | 46 | ||||||||
Changes in notes receivable from parent | (24 | ) | 1 | (1 | ) | |||||||
Distribution received from Gulfstream Natural Gas System, L.L.C. | — | — | 73 | |||||||||
Purchases of investments | (19 | ) | (44 | ) | (118 | ) | ||||||
Purchase of ARO trust investments | — | (31 | ) | (46 | ) | |||||||
Proceeds from sale of ARO trust investments | — | 14 | 41 | |||||||||
Other — net | — | 2 | 2 | |||||||||
Net cash used by investing activities | (1,031 | ) | (849 | ) | (853 | ) | ||||||
Increase (decrease) in cash and cash equivalents | 7 | 7 | (7 | ) | ||||||||
Cash and cash equivalents at beginning of year | 2 | 9 | 16 | |||||||||
Cash and cash equivalents at end of year | $ | 9 | $ | 16 | $ | 9 | ||||||
See accompanying notes to combined financial statements
4
CONTRIBUTED ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS
NOTES TO COMBINED FINANCIAL STATEMENTS
Note 1. | Organization and Description of Business |
Organization
The accompanying combined financial statements and related notes present the combined financial position, results of operations, cash flows and changes in equity of the following entities acquired by Williams Partners L.P. (Williams Partners) on February 17, 2010. These entities made up the Gas Pipeline and Midstream Gas & Liquids businesses of The Williams Companies, Inc. (Williams) to the extent not previously owned by Williams Partners, including Williams’ limited and general partner interests in Williams Pipeline Partners L.P. (Pipeline Partners), but excluding its Canadian, Venezuelan and olefins operations, and 25.5% of Gulfstream Natural Gas System, L.L.C. See Note 3 for a discussion of transactions with related parties.
Wholly-owned subsidiaries:
Marsh Resources, LLC
Transcontinental Gas Pipe Line Company, LLC and its consolidated subsidiaries (Transco)
WGP Development, LLC
WGPC Holdings LLC and its consolidated subsidiary
Williams Energy Solutions, Inc.
Williams Field Services Group, LLC and its consolidated subsidiaries (WFSG)
Williams Mobile Bay Producers Services, LLC
Williams NGL Marketing, LLC
Williams Pacific Connector Gas Operator, LLC
Williams Pipeline GP LLC and its consolidated subsidiaries
Williams Pipeline Services Company
Transcontinental Gas Pipe Line Company, LLC and its consolidated subsidiaries (Transco)
WGP Development, LLC
WGPC Holdings LLC and its consolidated subsidiary
Williams Energy Solutions, Inc.
Williams Field Services Group, LLC and its consolidated subsidiaries (WFSG)
Williams Mobile Bay Producers Services, LLC
Williams NGL Marketing, LLC
Williams Pacific Connector Gas Operator, LLC
Williams Pipeline GP LLC and its consolidated subsidiaries
Williams Pipeline Services Company
Equity investees:
24.5% membership interest in Gulfstream Natural Gas System, L.L.C.
31.45% membership interest in Baton Rouge Fractionators, LLC
29.98% membership interest in Pacific Connector Gas Pipeline, LP
29.98% membership interest in Pacific Connector Gas Pipeline, LLC
31.45% membership interest in Baton Rouge Fractionators, LLC
29.98% membership interest in Pacific Connector Gas Pipeline, LP
29.98% membership interest in Pacific Connector Gas Pipeline, LLC
These combined financial statements are prepared in connection with the acquisition (the Acquisition) of these entities and investments (Contributed Entities) by Williams Partners pursuant to the Contribution Agreement by and among Williams Gas Pipeline Company, LLC, Williams Energy Services, LLC, WGP Gulfstream Pipeline Company, L.L.C., Williams Partners GP LLC (the Contributing Parties), Williams Partners and Williams Partners Operating LLC dated January 15, 2010 (the Contribution Agreement).
We have evaluated our disclosure of subsequent events through April 20, 2010, the date that the combined financial statements were filed.
Unless the context clearly indicates otherwise, references in this report to “we,” “our,” “us” or similar language refer to the Contributed Entities.
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 includes the following interstate natural gas pipeline assets:
• | Transco, an interstate natural gas pipeline extending from the Gulf of Mexico region to the northeastern United States; |
5
CONTRIBUTED ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS (continued)
NOTES TO COMBINED FINANCIAL STATEMENTS (continued)
• | 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. |
Midstream is comprised of the following natural gas gathering, processing and treating facilities and investments located primarily in the Rocky Mountain and Gulf Coast regions of the United States and oil gathering and transportation facilities in the Gulf Coast region of the United States:
• | Two gathering systems and the Echo Springs and Opal processing plants serving the Wamsutter and southwest areas of Wyoming; | |
• | 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 deepwater crude oil pipelines; and | |
• | An equity interest in Aux Sable Liquid Products L.P., whose assets include a processing plant and fractionator in Illinois. |
Note 2. | Summary of Significant Accounting Policies |
Principles of consolidation
The combined financial statements include both the accounts of the entities and the equity investments noted above. 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. The 51% investment in Laurel Mountain Midstream, LLC held by WFSG is accounted for under the equity method due to the significant participatory rights of our partner such that we do not control the investment.
On December 11, 2007, we distributed ownership interests in Wamsutter LLC (Wamsutter) valued at $750 million (with an historical net book value of $278 million) to Williams, who, in turn, sold those ownership interests to Williams Partners. Certain of Williams Partners’ interests in Wamsutter have preference in the first $70 million of annual distributions. We consolidate our ownership interest in Wamsutter because we are the operator and the voting provisions of Wamsutter’s limited liability company agreement provide our interests with control. See Note 13 for further discussion of the Wamsutter ownership interests.
In January 2008, Pipeline Partners 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 Pipeline Partners, including the interests of the general partner (Williams Pipeline GP LLC), which is wholly owned by us, and incentive distribution rights. We consolidate Pipeline Partners within our Gas Pipeline segment due to our control through the general partner.
6
CONTRIBUTED ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS (continued)
NOTES TO COMBINED FINANCIAL STATEMENTS (continued)
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 combined 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 combined 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; | |
• | 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 for Transco and Northwest Pipeline to account for and report regulatory assets and liabilities 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
Ourcash and cash equivalentsbalance includes amounts primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government. These have maturity dates of three months or less when acquired.
Accounts receivable
Accounts receivableare carried on a gross basis, with no discounting, less the 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 conditions of the customers and the amount and age of past due accounts. Receivables are considered 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, 2008 and 2009 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 thelast-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, 2008 and 2009 was $11 million and $7 million, respectively.
7
CONTRIBUTED ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS (continued)
NOTES TO COMBINED FINANCIAL STATEMENTS (continued)
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 related25-year and15-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 recorded to a regulatory credit. Regulatory credits totaling $4 million in 2007, $3 million in 2008 and $2 million in 2009 are recorded in the accompanyingCombined Statements of Income. The accompanyingCombined Balance Sheetsreflect the related regulatory assets of $29 million and $31 million at December 31, 2008 and 2009, respectively. Such amounts 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 — net included inoperating income.
We record an asset and a liability upon incurrence equal to the present value of each expected future asset retirement obligation (ARO). 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 a corresponding accretion expense included incosts and operating expenses, except for regulated entities, for which the liability is offset by a regulatory asset. The regulatory asset is amortized commensurate with our collection of those costs in rates.
Derivative instruments and hedging activities
We 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 for those for which the normal purchases and normal sales exception has been elected, on theCombined Balance Sheets inother current assets, other assets and deferred charges, accrued liabilitiesandother liabilities and deferred incomeas 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.
8
CONTRIBUTED ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS (continued)
NOTES TO COMBINED FINANCIAL STATEMENTS (continued)
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 a 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 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 inrevenues or costs and operating expenses dependent upon the underlying hedged transaction.
For commodity 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 inrevenues or costs 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 (loss)is recognized inrevenues or costs and operating expensesat that time. The change in likelihood 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 theCombined Statements of Incomeare 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; and | |
• | Realized gains and losses on all derivatives that settle financially. |
Gains and losses realized through the settlement of derivatives that require physical delivery are recorded on a gross basis. In reaching our conclusions on this presentation, we evaluated whether we act as principal in
9
CONTRIBUTED ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS (continued)
NOTES TO COMBINED FINANCIAL STATEMENTS (continued)
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 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.
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-liquids processing contracts, we retain the rights to all or a portion of the NGLs extracted from the producers’ natural gas stream and recognize revenues when the extracted NGLs are sold and delivered.
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.
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.
Impairment of long-lived assets and investments
We evaluate the long-lived assets of identifiable business activities for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable. When an indicator of impairment has occurred, we compare our management’s estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether 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 fair value is recognized in the combined financial statements as an impairment.
10
CONTRIBUTED ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS (continued)
NOTES TO COMBINED FINANCIAL STATEMENTS (continued)
Judgments and assumptions are inherent in our management’s estimate of undiscounted future cash flows and an asset’s fair value. Additionally, judgment is used to determine the probability of sale with respect to assets considered for disposal. The use of alternate judgmentsand/or assumptions could result in the recognition of different levels of impairment charges in the combined 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 related 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.
Capitalization of 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 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 ofother income — netwas $12 million, $5 million and $10 million in 2007, 2008 and 2009, 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; hence, the rates used by nonregulated companies were based on Williams’ average interest rate on debt during the applicable period of time.
Income taxes
Our operations were previously included in the Williams’ consolidated federal income tax return. Following the acquisition by Williams Partners, our operations are now treated as a partnership. Therefore, other than Transco and Northwest Pipeline, our 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 are 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 apartnership-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 share
During the periods presented, the controlling interest in the Contributed Entities was held by Williams. Accordingly, we have not calculated earnings per share.
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.
11
CONTRIBUTED ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS (continued)
NOTES TO COMBINED FINANCIAL STATEMENTS (continued)
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 Levels 1 and 2 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 of 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 inputs on a gross basis. We are assessing the application of this Update to disclosures in our Combined 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 and medical plans. Our share of those costs is charged to us through affiliate billings and reflected incosts and operating expensesin the accompanyingCombined 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 operations. 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 accompanyingCombined 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.
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.
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. |
12
CONTRIBUTED ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS (continued)
NOTES TO COMBINED FINANCIAL STATEMENTS (continued)
• | Sale of NGLs to Mid-Continent Fractionation and Storage, LLC, a wholly owned subsidiary of Williams Partners, for their inventory balancing needs. These sales are generally made at market prices at the time of sale. | |
• | The sale of waste heat from our co-generation plant to Williams Four Corners, LLC, a wholly owned subsidiary of Williams Partners, for the natural gas treating process at their Milagro treating plant. The rate we charge for the waste heat is based on the natural gas needed to generate the waste heat. |
Costs and operating expensesalso include charges for the following types of transactions with affiliates:
• | Our Midstream segment purchases NGLs for resale from Williams Partners and WPC at market prices at the time of purchase. | |
• | Our Midstream segment purchases natural gas for shrink replacement and fuel for processing plants and the co-generation plant from Williams Gas Marketing, Inc. (WGM) at market prices at the time of purchase. | |
• | Our Midstream segment purchases NGLs for resale from Williams Olefins at market prices at the time of purchase. | |
• | 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. |
Below is a summary of the related party transactions discussed above.
Years Ended | ||||||||||||
December 31, | ||||||||||||
2007 | 2008 | 2009 | ||||||||||
(In millions) | ||||||||||||
Gas Pipeline revenues | $ | 45 | $ | 38 | $ | 29 | ||||||
Midstream revenues | ||||||||||||
Product sales | 145 | 176 | 84 | |||||||||
Gathering and processing | 7 | 6 | 29 | |||||||||
Costs and operating expenses | ||||||||||||
Product purchases | 838 | 1,124 | 606 | |||||||||
Employee costs | 127 | 130 | 147 | |||||||||
Other | 1 | 11 | 9 | |||||||||
Selling, general and administrative expense | ||||||||||||
Employee costs | 167 | 161 | 181 |
Theaccounts receivable — affiliateandaccounts payable — affiliateon theCombined Balance Sheets represent the receivable and payable positions that result from the transactions with affiliates other than Williams discussed above.
We periodically enter into financial swap contracts with WGM to hedge forecasted NGL sales. These contracts are priced based on market rates at the time of execution and are reflected inother current assets, other assets and deferred chargesandaccrued liabilitieson theCombined Balance Sheets(see Note 15).
We 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, 2008 and 2009, the net advances to Williams are classified in theCombined Balance Sheets as follows:
• | Midstream’s net advances to Williams are classified as a component ofowner’s equity because, although the advances are due on demand, Williams has not historically required repayment or repaid amounts owed to us. |
13
CONTRIBUTED ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS (continued)
NOTES TO COMBINED FINANCIAL STATEMENTS (continued)
• | Transco’s and Northwest Pipeline’snotes receivable from parent are 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 Pipeline Partners in 2008. At that point the interest rate changed to the overnight investment rate paid on Williams’ excess cash. In contemplation of the Acquisition, 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 ofowner’s 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. |
Under the Contribution Agreement, 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 theCombined Statement of Changes in EquityandCombined Statements of Cash Flows.
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 theCombined Balance Sheets.
Note 4. | 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, | ||||||||||||
2007 | 2008 | 2009 | ||||||||||
(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 | 8 | 11 | — | |||||||||
Involuntary conversion gain | (1 | ) | (5 | ) | — |
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.
Note 5. | 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 2007, 2008 and 2009 totaled $12 million, $10 million and $33 million, respectively. At the total Williams plan level, the pension plans had a projected benefit obligation of $1,035 million and $1,118 million at December 31, 2008 and 2009, respectively. The plans were underfunded by $330 million and $258 million at December 31, 2008 and 2009, respectively.
14
CONTRIBUTED ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS (continued)
NOTES TO COMBINED FINANCIAL STATEMENTS (continued)
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 2007, 2008 and 2009 totaled $5 million, $5 million and $4 million, respectively. At the total Williams plan level, the postretirement benefit plans had a projected benefit obligation of $273 million and $259 million at December 31, 2008 and 2009, respectively. The plans were underfunded by $147 million and $111 million at December 31, 2008 and 2009, 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 $10 million, $11 million and $12 million in 2007, 2008 and 2009, 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, 2007, 2008 and 2009 was $9 million, $7 million and $9 million, respectively.
Note 6. | 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 taxes shown herein for 2007 includes Northwest Pipeline’s benefit through September 30, 2007, and the 2008provision (benefit) for income taxes includes 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.
15
CONTRIBUTED ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS (continued)
NOTES TO COMBINED FINANCIAL STATEMENTS (continued)
Theprovision (benefit) for income taxesincludes:
Years Ended December 31, | ||||||||||||
2007 | 2008 | 2009 | ||||||||||
(In millions) | ||||||||||||
Current: | ||||||||||||
Federal | $ | 138 | $ | 37 | $ | — | ||||||
State | 24 | 8 | 4 | |||||||||
162 | 45 | 4 | ||||||||||
Deferred: | ||||||||||||
Federal | (273 | ) | (867 | ) | — | |||||||
State | (33 | ) | (130 | ) | — | |||||||
(306 | ) | (997 | ) | — | ||||||||
Total provision (benefit) for income tax | $ | (144 | ) | $ | (952 | ) | $ | 4 | ||||
Reconciliations from the provision for income taxes at the federal statutory rate to the realizedprovision (benefit) for income taxesare as follows:
December 31, | ||||||||||||
2007 | 2008 | 2009 | ||||||||||
(In millions) | ||||||||||||
Provision at statutory rate | $ | 426 | $ | 366 | $ | 338 | ||||||
Increases (decreases) in taxes resulting from: | ||||||||||||
Income from operations not taxed as a LLC | (275 | ) | (259 | ) | (338 | ) | ||||||
State income taxes (net of federal benefit) | 17 | 14 | 4 | |||||||||
Conversion from corporation to LLC | (312 | ) | (1,073 | ) | — | |||||||
Provision (benefit) for income taxes | $ | (144 | ) | $ | (952 | ) | $ | 4 | ||||
16
CONTRIBUTED ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS (continued)
NOTES TO COMBINED FINANCIAL STATEMENTS (continued)
We had no deferred tax liabilities or deferred tax assets at December 31, 2008 or 2009.
Total interest and penalties recognized as a component of income tax expense were immaterial in 2007, 2008 and 2009.
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 $93 million, $77 million and $21 million in 2007, 2008 and 2009, respectively.
Note 7. | Inventories |
Inventoriesat December 31, 2008 and 2009 are as follows:
December 31, | ||||||||||
2008 | 2009 | |||||||||
(In millions) | ||||||||||
Natural gas liquids | $ | 34 | $ | 44 | ||||||
Crude oil | 1 | 2 | ||||||||
Natural gas in underground storage | 58 | 20 | ||||||||
Materials, supplies and other | 53 | 63 | ||||||||
$ | 146 | $ | 129 | |||||||
17
CONTRIBUTED ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS (continued)
NOTES TO COMBINED FINANCIAL STATEMENTS (continued)
Note 8. | Investments |
Investmentsbeing accounted for using the equity method at December 31, 2008 and 2009 are as follows:
December 31, | ||||||
2008 | 2009 | |||||
(In millions) | ||||||
Gulfstream Natural Gas System, L.L.C. — 24.5% | $ | 257 | $ | 188 | ||
Laurel Mountain Midstream, LLC — 51% | — | 133 | ||||
Aux Sable Liquid Products L.P. — 14.6% | 14 | 16 | ||||
Other | 68 | 68 | ||||
$ | 339 | $ | 405 | |||
Differences between the carrying value of our equity investments and the underlying equity in the net assets of the investees are primarily related to $30 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 $64 million in 2008 and $136 million in 2009. These transactions reduced the carrying value of our investments. These dividends and distributions primarily included:
2008 | 2009 | |||||||
(In millions) | ||||||||
Gulfstream Natural Gas System, L.L.C. | $ | 29 | $ | 109 | ||||
Aux Sable Liquid Products L.P. | 28 | 15 |
In addition, we contributed $44 million and $10 million to Gulfstream Natural Gas System, L.L.C. in 2008 and 2009, respectively. In June 2009, we acquired a 51% ownership interest in Laurel Mountain Midstream, LLC (LMM) for $133 million.
18
CONTRIBUTED ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS (continued)
NOTES TO COMBINED FINANCIAL STATEMENTS (continued)
Note 9. | Property, Plant and Equipment |
Property, plant and equipment — netat December 31, 2008 and 2009 is as follows:
Estimated Useful | Depreciation | |||||||||||||||
Life(a) | Rates(a) | December 31, | ||||||||||||||
(Years) | (%) | 2008 | 2009 | |||||||||||||
(In millions) | ||||||||||||||||
Nonregulated: | ||||||||||||||||
Natural gas gathering and processing facilities | 5 - 40 | $ | 2,621 | $ | 3,019 | |||||||||||
Construction in progress | 683 | 652 | ||||||||||||||
Other | 0 - 45 | 172 | 181 | |||||||||||||
Regulated: | ||||||||||||||||
Natural gas transmission facilities | .01 - 7.25 | 8,441 | 8,814 | |||||||||||||
Construction in progress | 121 | 152 | ||||||||||||||
Storage and other | 0 - 50 | 1,292 | 1,301 | |||||||||||||
Total property, plant and equipment, at cost | 13,330 | 14,119 | ||||||||||||||
Accumulated depreciation and amortization | (4,154 | ) | (4,528 | ) | ||||||||||||
Property, plant and equipment — net | $ | 9,176 | $ | 9,591 | ||||||||||||
(a) | Estimated useful life and depreciation rates are presented as of December 31, 2009. |
Depreciation expense forproperty, plant and equipment — netwas $429 million, $455 million and $483 million in 2007, 2008 and 2009, respectively.
Regulatedproperty, plant and equipment — netincludes approximately $985 million and $946 million at December 31, 2008 and 2009, 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 inaccrued liabilities is $9 million and $5 million at December 31, 2008 and 2009, respectively.
2008 | 2009 | |||||||
(In millions) | ||||||||
Beginning balance | $ | 254 | $ | 443 | ||||
Accretion | 51 | 32 | ||||||
New obligations | 13 | 15 | ||||||
Changes in estimates of existing obligations | 135 | (11 | ) | |||||
Property dispositions/obligations settled | (10 | ) | (12 | ) | ||||
Ending balance | $ | 443 | $ | 467 | ||||
The accrued obligations relate to gas transmission facilities, underground storage caverns, offshore platforms, fractionation 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
19
CONTRIBUTED ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS (continued)
NOTES TO COMBINED FINANCIAL STATEMENTS (continued)
equipment and restore land at fractionation facilities, dismantle offshore platforms, cap certain gathering pipelines at the wellhead connection and remove any related surface equipment.
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.
Note 10. | Regulatory Assets and Liabilities |
The regulatory assets and regulatory liabilities included inCombined Balance Sheets at December 31, 2008 and 2009 are as follows:
December 31, | ||||||||
2008 | 2009 | |||||||
(In millions) | ||||||||
Regulatory assets: | ||||||||
Gross-up deferred taxes on equity funds used during construction | $ | 111 | $ | 108 | ||||
Asset retirement obligations | 87 | 100 | ||||||
Fuel cost | 74 | 66 | ||||||
Levelized incremental depreciation | 29 | 31 | ||||||
Postretirement benefits other than pension | 12 | 8 | ||||||
Other | 30 | 21 | ||||||
$ | 343 | $ | 334 | |||||
Regulatory liabilities: | ||||||||
Negative salvage | $ | 47 | $ | 67 | ||||
Postretirement benefits other than pension | 17 | 20 | ||||||
Other | 10 | 4 | ||||||
$ | 74 | $ | 91 | |||||
Regulatory assets are included inregulatory assetsandregulatory assets, deferred charges and other. Regulatory liabilities are included inaccrued liabilities and regulatory liabilities, deferred income and other.
Note 11. | 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 $22 million and $27 million of these negative balances at December 31, 2008 and 2009, respectively.
Accrued liabilitiesat December 31, 2008 and 2009 are as follows:
December 31, | ||||||||
2008 | 2009 | |||||||
(In millions) | ||||||||
Deposits | $ | 34 | $ | 38 | ||||
Taxes other than income | 46 | 14 | ||||||
Interest | 30 | 30 | ||||||
Other, including other loss contingencies | 115 | 69 | ||||||
$ | 225 | $ | 151 | |||||
20
CONTRIBUTED ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS (continued)
NOTES TO COMBINED FINANCIAL STATEMENTS (continued)
Note 12. | Debt, Leases and Banking Arrangements |
Long-Term Debt
Long-term debtat December 31, 2008 and 2009 includes the following:
Weighted-Average | ||||||||||||
Interest | December 31, | |||||||||||
Rate(1) | 2008 | 2009 | ||||||||||
(In millions) | ||||||||||||
Transco: | ||||||||||||
6.05% to 8.875%, payable through 2026 | 7.24% | $ | 1,283 | $ | 1,283 | |||||||
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 | (7 | ) | (5 | ) | ||||||||
Total long-term debt, including current portion | 1,971 | 1,996 | ||||||||||
Long-term debt due within one year | — | 15 | ||||||||||
Long-term debt | $ | 1,971 | $ | 1,981 | ||||||||
(1) | At December 31, 2009. |
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%.
Credit facilities
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 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 generally based on the specific borrower’s senior unsecured long-term debt ratings.
21
CONTRIBUTED ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS (continued)
NOTES TO COMBINED FINANCIAL STATEMENTS (continued)
In connection with the Acquisition, borrowing capacity under the Williams Credit Facility was reduced, and Transco and Northwest Pipeline were removed as borrowers. In addition, Williams Partners 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. 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.
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 percent, (ii) Citibank, N.A.’s publicly announced base rate and (iii) LIBOR for a one month interest period plus 1.0 percent. The applicable margin spread and the per annum percentage used to calculate the unused commitment fee under the New Credit Facility will be determined 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, including us, to incur indebtedness, grant certain liens supporting indebtedness, merge, 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, Williams Partners is 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 it and its consolidated subsidiaries. For each of Transco and Northwest Pipeline and their respective consolidated subsidiaries, the ratio of debt to capitalization (as 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 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.
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 | 308 | |||
2012 | 325 | |||
2013 | — | |||
2014 | — |
Cash payments for interest (net of amounts capitalized) were $136 million, $142 million and $135 million in 2007, 2008 and 2009, 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.
22
CONTRIBUTED ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS (continued)
NOTES TO COMBINED FINANCIAL STATEMENTS (continued)
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.
Future minimum annual rentals under noncancelable operating leases as of December 31, 2009, are payable as follows:
(In millions) | ||||
2010 | $ | 12 | ||
2011 | 11 | |||
2012 | 11 | |||
2013 | 11 | |||
2014 | 5 | |||
Thereafter | 12 | |||
Total | $ | 62 | ||
Total rent expense, net of sublease revenues, was $15 million, $19 million and $18 million in 2007, 2008 and 2009, respectively.
Note 13. | Noncontrolling interests in consolidated subsidiares |
Wamsutter
The noncontrolling interests in Wamsutter represent its Class A membership interests and a portion of its Class C membership interests, both of which are held by Williams Partners. We hold Wamsutter’s Class B membership interests and the remainder of its Class C membership interests, operate the assets and fund the significant expansion capital expenditures. Class C units are issued to Class A and Class B members based on their funding of expansion capital expenditures placed in service. At December 31, 2008 and 2009, we held 50% and 31%, respectively, of the Class C membership interests and Williams Partners held 50% and 69%, respectively.
The Class A membership interests are entitled to $70 million of distributions and net income allocation annually before the Class C membership interests. Of the remaining cash available for distribution, 5% is distributed to the holder of the Class A membership interest and 95% is distributed to holders of the Class C units on apro ratabasis. Net income is allocated between the Class A and Class C membership interests in a similar manner as the cash distributions. Our Class B membership interests does not receive distributions or net income allocations. Distributions to the noncontrolling interests in Wamsutter totaled $99 million in 2008 and $90 million in 2009.
Pipeline Partners
The noncontrolling interests in Pipeline Partners represent its common units held by the public. At December 31, 2008 and 2009, we held 47.7% of the interests in Pipeline Partners, including common units, subordinated units, the general partner interest and incentive distribution rights. The common units are entitled to a minimum quarterly distribution of $0.2875 per unit. Distributions to the noncontrolling interests in Pipeline Partners totaled $15 million in 2008 and $23 million in 2009.
Note 14. | 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
23
CONTRIBUTED ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS (continued)
NOTES TO COMBINED FINANCIAL STATEMENTS (continued)
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.
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 Combined 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.
24
CONTRIBUTED ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS (continued)
NOTES TO COMBINED FINANCIAL STATEMENTS (continued)
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, | |||||||||||||||||||||||||||||||
2008 | 2009 | |||||||||||||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||||||
(In millions) | ||||||||||||||||||||||||||||||||
Assets: | ||||||||||||||||||||||||||||||||
Marketable securities | $ | 13 | $ | — | $ | — | $ | 13 | $ | 22 | $ | — | $ | — | $ | 22 | ||||||||||||||||
Energy derivatives | — | — | 1 | 1 | — | — | 2 | 2 | ||||||||||||||||||||||||
Total assets | $ | 13 | $ | — | $ | 1 | $ | 14 | $ | 22 | $ | — | $ | 2 | 24 | |||||||||||||||||
Liabilities: | ||||||||||||||||||||||||||||||||
Energy derivatives | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 1 | $ | 1 | ||||||||||||||||
Total liabilities | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 1 | $ | 1 | ||||||||||||||||
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.
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.
25
CONTRIBUTED ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS (continued)
NOTES TO COMBINED FINANCIAL STATEMENTS (continued)
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, | ||||||||
2008 | 2009 | |||||||
(In millions) | ||||||||
Beginning balance | $ | (7 | ) | $ | 1 | |||
Realized and unrealized gains (losses): | ||||||||
Included innet income | (9 | ) | 2 | |||||
Included inother comprehensive income (loss) | 8 | (1 | ) | |||||
Purchases, issuances, and settlements | 9 | (1 | ) | |||||
Transfers into Level 3 | — | — | ||||||
Transfers out of Level 3 | — | — | ||||||
Ending balance | $ | 1 | $ | 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 ourCombined Statements of Income.
During 2009, there were no assets or liabilities measured at fair value on a nonrecurring basis.
Note 15. | 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 theCombined Balance Sheets approximate 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 inother assets and deferred chargesin theCombined 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 theCombined Balance Sheets approximate 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 theCombined Balance Sheets approximate 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
26
CONTRIBUTED ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS (continued)
NOTES TO COMBINED FINANCIAL STATEMENTS (continued)
with similar terms and credit ratings. At December 31, 2008 and 2009, approximately 100% and 99%, respectively, of our long-term debt was publicly traded.
Energy derivatives: Energy derivatives include futures, forwards, swaps, and options. See Note 14 for discussion of valuation of our energy derivatives.
Carrying amounts and fair values of our financial instruments
December 31, | December 31, | |||||||||||||||
2008 | 2009 | |||||||||||||||
Carrying | Carrying | |||||||||||||||
Amount | Fair Value | Amount | Fair Value | |||||||||||||
(In millions) | ||||||||||||||||
Asset (Liability): | ||||||||||||||||
Cash and cash equivalents | $ | 16 | $ | 16 | $ | 9 | $ | 9 | ||||||||
ARO Trust Investments | 13 | 13 | 22 | 22 | ||||||||||||
Notes receivable from parent | 252 | 252 | — | — | ||||||||||||
Notes and other noncurrent receivables | 1 | 1 | 3 | 3 | ||||||||||||
Long-term debt, including current portion | (1,971 | ) | (1,727 | ) | (1,996 | ) | (2,194 | ) | ||||||||
Net energy derivatives: | ||||||||||||||||
Energy commodity cash flow hedges — affiliate | — | — | (1 | ) | (1 | ) | ||||||||||
Other energy derivatives | 1 | 1 | 2 | 2 |
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 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; |
27
CONTRIBUTED ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS (continued)
NOTES TO COMBINED FINANCIAL STATEMENTS (continued)
• | 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 | (25,956,000 | ) | |||||||||||||||
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, other assets and deferred charges,and accrued liabilitiesin ourCombined 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 | $ | — | $ | 1 | ||||
Not designated as hedging instruments | 2 | — | ||||||
Total derivatives | $ | 2 | $ | 1 | ||||
The following table presents pre-tax 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) | $ | (3 | ) | AOCI | ||
Net gain (loss) reclassified from accumulated other comprehensive income into income (effective portion) | $ | (2 | ) | 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 $1 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
28
CONTRIBUTED ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS (continued)
NOTES TO COMBINED FINANCIAL STATEMENTS (continued)
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 theCombined 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.
29
CONTRIBUTED ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS (continued)
NOTES TO COMBINED FINANCIAL STATEMENTS (continued)
Accounts and notes receivable
The following table summarizes concentration of receivables, net of allowances, by product or service at December 31, 2008 and 2009:
December 31, | ||||||||
2008 | 2009 | |||||||
(In millions) | ||||||||
Receivables by product or service: | ||||||||
Sale of NGLs and related products and services | $ | 123 | $ | 206 | ||||
Transportation of natural gas and related products | 135 | 159 | ||||||
Total accounts receivable | 258 | 365 | ||||||
Notes receivable from parent | 252 | — | ||||||
Total | $ | 510 | $ | 365 | ||||
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 2007, there were two customers in our Midstream segment for which our sales exceeded 10% of our combined revenues. The largest customer represented 16% of our 2007 combined revenues and the other represented 12%. There were no customers for which our sales exceeded 10% of our combined revenues in 2008. During 2009, we had one customer in our Midstream segment that accounted for 11% of our combined revenues.
Note 16. | 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.
30
CONTRIBUTED ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS (continued)
NOTES TO COMBINED FINANCIAL STATEMENTS (continued)
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 voluntaryclean-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 mercuryclean-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.
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.
31
CONTRIBUTED ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS (continued)
NOTES TO COMBINED FINANCIAL STATEMENTS (continued)
Rate Matters
On March 1, 2001, Transco submitted to the FERC a general rate filing (DocketNo. 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 (DocketNo. RP06-569) designed to recover increased costs. The rates became effective March 1, 2007, subject to refund and the outcome of a hearing. All issues in this proceeding except one have been resolved by settlement.
The one issue reserved for litigation or further settlement relates to Transco’s proposal to change the design of the rates for service under one of its storage rate schedules, which was implemented subject to refund on March 1, 2007. A hearing on that issue was held before a FERC Administrative Law Judge (ALJ) in July 2008. In November 2008, the ALJ issued an initial decision in which he determined that Transco’s proposed incremental rate design is unjust and unreasonable. On January 21, 2010, the FERC reversed the ALJ’s initial decision and approved our proposed incremental rate design. Certain parties 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 consequence 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 assessment 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.
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 $245 million at December 31, 2009.
Note 17. | 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. Pipeline Partners is consolidated within the Gas Pipeline segment. (See Note 1.)
32
CONTRIBUTED ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS (continued)
NOTES TO COMBINED FINANCIAL STATEMENTS (continued)
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 1. 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 theCombined 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, 2007 | ||||||||||||||||
Segment revenues: | ||||||||||||||||
External | $ | 1,619 | $ | 3,707 | $ | — | $ | 5,326 | ||||||||
Internal | 4 | — | (4 | ) | — | |||||||||||
Total revenues | $ | 1,623 | $ | 3,707 | $ | (4 | ) | $ | 5,326 | |||||||
Segment profit | $ | 649 | $ | 757 | $ | — | $ | 1,406 | ||||||||
Less: | ||||||||||||||||
Equity earnings | 27 | 24 | — | 51 | ||||||||||||
Segment operating income | $ | 622 | $ | 733 | $ | — | $ | 1,355 | ||||||||
General corporate expense | (88 | ) | ||||||||||||||
Total operating income | $ | 1,267 | ||||||||||||||
Other financial information: | ||||||||||||||||
Additions to long-lived assets | $ | 546 | $ | 561 | $ | — | $ | 1,107 | ||||||||
Depreciation and amortization | $ | 313 | $ | 119 | $ | — | $ | 432 |
33
CONTRIBUTED ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS (continued)
NOTES TO COMBINED FINANCIAL STATEMENTS (continued)
Midstream | ||||||||||||||||
Gas | Gas & | |||||||||||||||
Pipeline | Liquids | Eliminations | Total | |||||||||||||
(In millions) | ||||||||||||||||
Year Ended December 31, 2008 | ||||||||||||||||
Segment revenues: | ||||||||||||||||
External | $ | 1,637 | $ | 3,818 | $ | — | $ | 5,455 | ||||||||
Internal | — | 10 | (10 | ) | — | |||||||||||
Total revenues | $ | 1,637 | $ | 3,828 | $ | (10 | ) | $ | 5,455 | |||||||
Segment profit | $ | 661 | $ | 573 | $ | — | $ | 1,234 | ||||||||
Less: | ||||||||||||||||
Equity earnings | 31 | 24 | — | 55 | ||||||||||||
Segment operating income | $ | 630 | $ | 549 | $ | — | $ | 1,179 | ||||||||
General corporate expense | (80 | ) | ||||||||||||||
Total operating income | $ | 1,099 | ||||||||||||||
Other financial information: | ||||||||||||||||
Additions to long-lived assets | $ | 413 | $ | 608 | $ | — | $ | 1,021 | ||||||||
Depreciation and amortization | $ | 319 | $ | 139 | $ | — | $ | 458 |
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CONTRIBUTED ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS (continued)
NOTES TO COMBINED FINANCIAL STATEMENTS (continued)
Midstream | ||||||||||||||||
Gas | Gas & | |||||||||||||||
Pipeline | Liquids | Eliminations | Total | |||||||||||||
(In millions) | ||||||||||||||||
Year Ended December 31, 2009 | ||||||||||||||||
Segment revenues: | ||||||||||||||||
External | $ | 1,592 | $ | 2,634 | $ | — | $ | 4,226 | ||||||||
Internal | 1 | 6 | (7 | ) | — | |||||||||||
Total revenues | $ | 1,593 | $ | 2,640 | $ | (7 | ) | $ | 4,226 | |||||||
Segment profit | $ | 635 | $ | 532 | $ | — | $ | 1,167 | ||||||||
Less: | ||||||||||||||||
Equity earnings | 35 | 23 | — | 58 | ||||||||||||
Segment operating income | $ | 600 | $ | 509 | $ | — | $ | 1,109 | ||||||||
General corporate expense | (95 | ) | ||||||||||||||
Total operating income | $ | 1,014 | ||||||||||||||
Other financial information: | ||||||||||||||||
Additions to long-lived assets | $ | 518 | $ | 448 | $ | — | $ | 966 | ||||||||
Depreciation and amortization | $ | 333 | $ | 153 | $ | — | $ | 486 |
The following table reflectstotal assetsandinvestmentsby reporting segment.
Total Assets at December 31, | Investments at December 31, | |||||||||||||||||||||||
2007 | 2008 | 2009 | 2007 | 2008 | 2009 | |||||||||||||||||||
(In millions) | ||||||||||||||||||||||||
Gas Pipeline | $ | 7,676 | $ | 7,891 | $ | 7,711 | $ | 259 | $ | 302 | $ | 234 | ||||||||||||
Midstream Gas & Liquids | 2,422 | 2,789 | 3,250 | 44 | 37 | 171 | ||||||||||||||||||
Eliminations | (6 | ) | (2 | ) | (1 | ) | — | — | — | |||||||||||||||
Total | $ | 10,092 | $ | 10,678 | $ | 10,960 | $ | 303 | $ | 339 | $ | 405 | ||||||||||||
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