Exhibit 99.3
PART I
INDEX TO FINANCIAL STATEMENTS
Energy Transfer Partners GP, L.P. and Subsidiaries
Page | ||
Definitions | 2 | |
Report of Independent Registered Public Accounting Firm | 4 | |
Consolidated Balance Sheets – December 31, 2012 and 2011 | 5 | |
Consolidated Statements of Operations – Years Ended December 31, 2012, 2011 and 2010 | 7 | |
Consolidated Statements of Comprehensive Income – Years Ended December 31, 2012, 2011 and 2010 | 8 | |
Consolidated Statements of Equity – Years Ended December 31, 2012, 2011 and 2010 | 9 | |
Consolidated Statements of Cash Flows – Years Ended December 31, 2012, 2011 and 2010 | 10 | |
Notes to Consolidated Financial Statements | 11 |
1
Definitions
The following is a list of certain acronyms and terms generally used in the energy industry and throughout this document:
/d | per day | |
AmeriGas | AmeriGas Partners, L.P. | |
AOCI | accumulated other comprehensive income (loss) | |
AROs | asset retirement obligations | |
Bbls | barrels | |
Bcf | billion cubic feet | |
Btu | British thermal unit, an energy measurement used by gas companies to convert the volume of gas used to its heat equivalent, and thus calculate the actual energy used Capacity capacity of a pipeline, processing plant or storage facility refers to the maximum capacity under normal operating conditions and, with respect to pipeline transportation capacity, is subject to multiple factors (including natural gas injections and withdrawals at various delivery points along the pipeline and the utilization of compression) which may reduce the throughput capacity from specified capacity levels | |
Canyon | ETC Canyon Pipeline, LLC | |
Citrus | Citrus Corp. | |
CrossCountry | CrossCountry Energy, LLC | |
DOT | U.S. Department of Transportation | |
Enterprise | Enterprise Products Partners L.P., together with its subsidiaries | |
ETC Compression | ETC Compression, LLC | |
ETC FEP ETC | Fayetteville Express Pipeline, LLC | |
ETC OLP | La Grange Acquisition, L.P., which conducts business under the assumed name of Energy Transfer Company | |
ETC Tiger | ETC Tiger Pipeline, LLC | |
ETE | Energy Transfer Equity, L.P., a publicly traded partnership and the owner of ETP LLC | |
ET Interstate | Energy Transfer Interstate Holdings, LLC | |
ETP Credit Facility | ETP’s $2.5 billion revolving credit facility | |
ETP LLC | Energy Transfer Partners, L.L.C., the general partner of ETP GP | |
EPA | U.S. Environmental Protection Agency | |
Exchange Act | Securities Exchange Act of 1934 | |
FEP | Fayetteville Express Pipeline LLC | |
FERC | Federal Energy Regulatory Commission | |
FGT | Florida Gas Transmission Company, LLC | |
GAAP | accounting principles generally accepted in the United States of America | |
Holdco | ETP Holdco Corporation | |
HOLP | Heritage Operating, L.P. | |
IDRs | incentive distribution rights | |
Laclede Entities | The Laclede Group, Inc. subsidiaries | |
Laclede Massachusetts | purchaser of New England Gas Company | |
Laclede Missouri | purchaser of Missouri Gas Energy | |
LDH | LDH Energy Asset Holdings LLC, a wholly-owned subsidiary of Louis Dreyfus Highbridge Energy LLC (subsequently renamed Castleton Commodities International, LLC) | |
LIBOR | London Interbank Offered Rate | |
LNG | Liquefied natural gas | |
Lone Star | Lone Star NGL LLC | |
LPG | liquefied petroleum gas | |
MGE | Missouri Gas Energy | |
MMBtu | million British thermal units | |
MMcf | million cubic feet | |
NEG | New England Gas Company | |
NGL | natural gas liquid, such as propane, butane and natural gasoline | |
NYMEX | New York Mercantile Exchange | |
OTC | over-the-counter | |
OSHA | federal Occupational Safety and Health Act | |
Panhandle | Panhandle Eastern Pipe Line Company, LP | |
PCBs | polychlorinated biphenyls | |
PHMSA | Pipeline Hazardous Materials Safety Administration | |
Regency | Regency Energy Partners LP, a subsidiary of ETE |
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Reservoir | a porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs | |
Sea Robin | Sea Robin Pipeline Company, LLC | |
SEC | Securities and Exchange Commission | |
Southern Union | Southern Union Company | |
Southwest Gas | Pan Gas Storage, LLC (d.b.a. Southwest Gas) | |
SUGS | Southern Union Gas Services | |
Sunoco | Sunoco, Inc. | |
Sunoco Logistics | Sunoco Logistics Partners L.P. | |
Tcf | trillion cubic feet | |
Titan | Titan Energy Partners, L.P. | |
Transwestern | Transwestern Pipeline Company, LLC | |
Trunkline | Trunkline Gas Company, LLC |
Adjusted EBITDA is a term used throughout this document, which we define as earnings before interest, taxes, depreciation, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, noncash impairment charges, loss on extinguishment of debt, gain on deconsolidation and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities includes unrealized gains and losses on commodity derivatives and inventory fair value adjustments (excluding lower of cost or market adjustments). Adjusted EBITDA reflects amounts for less than wholly owned subsidiaries based on 100% of the subsidiaries’ results of operations and for unconsolidated affiliates based on the Partnership’s proportionate ownership.
3
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Partners
Energy Transfer Partners GP, L.P.
We have audited the accompanying consolidated balance sheets of Energy Transfer Partners GP, L.P. (a Delaware limited partnership) and subsidiaries (the “Partnership”) as of December 31, 2012 and 2011, and the related consolidated statements of operations, comprehensive income, equity, and cash flows for each of the three years in the period ended December 31, 2012. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We did not audit the consolidated financial statements of Sunoco Logistics Partners L.P., a consolidated subsidiary, as of December 31, 2012 and for the period from October 5, 2012 to December 31, 2012, which statements reflect total assets constituting 24 percent of consolidated total assets as of December 31, 2012, and total revenues of 20 percent of consolidated total revenues for the year then ended. Those statements were audited by other auditors, whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for Sunoco Logistics Partners L.P., is based solely on the report of the other auditors.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits and the report of the other auditors provide a reasonable basis for our opinion.
In our opinion, based on our audits and the report of the other auditors, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Energy Transfer Partners GP, L.P. and subsidiaries as of December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012 in conformity with accounting principles generally accepted in the United States of America.
/s/ GRANT THORNTON LLP
Dallas, Texas
November 13, 2013
4
ENERGY TRANSFER PARTNERS GP, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
December 31, | ||||||||
2012 | 2011 | |||||||
ASSETS | ||||||||
CURRENT ASSETS: | ||||||||
Cash and cash equivalents | $ | 311 | $ | 107 | ||||
Accounts receivable, net | 2,910 | 569 | ||||||
Accounts receivable from related companies | 94 | 82 | ||||||
Inventories | 1,495 | 307 | ||||||
Exchanges receivable | 55 | 19 | ||||||
Price risk management assets | 21 | 11 | ||||||
Current assets held for sale | 184 | — | ||||||
Other current assets | 334 | 180 | ||||||
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Total current assets | 5,404 | 1,275 | ||||||
PROPERTY, PLANT AND EQUIPMENT | 27,412 | 13,984 | ||||||
ACCUMULATED DEPRECIATION | (1,639 | ) | (1,678 | ) | ||||
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25,773 | 12,306 | |||||||
NON-CURRENT ASSETS HELD FOR SALE | 985 | — | ||||||
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES | 3,502 | 201 | ||||||
NON-CURRENT PRICE RISK MANAGEMENT ASSETS | 42 | 26 | ||||||
GOODWILL | 5,635 | 1,249 | ||||||
INTANGIBLE ASSETS, net | 1,561 | 331 | ||||||
OTHER NON-CURRENT ASSETS, net | 357 | 160 | ||||||
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Total assets | $ | 43,259 | $ | 15,548 | ||||
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The accompanying notes are an integral part of these consolidated financial statements.
5
ENERGY TRANSFER PARTNERS GP, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
December 31, | ||||||||
2012 | 2011 | |||||||
LIABILITIES AND EQUITY | ||||||||
CURRENT LIABILITIES: | ||||||||
Accounts payable | $ | 3,002 | $ | 401 | ||||
Accounts payable to related companies | 24 | 33 | ||||||
Exchanges payable | 156 | 18 | ||||||
Price risk management liabilities | 110 | 80 | ||||||
Accrued and other current liabilities | 1,562 | 630 | ||||||
Current maturities of long-term debt | 609 | 424 | ||||||
Current liabilities held for sale | 85 | — | ||||||
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Total current liabilities | 5,548 | 1,586 | ||||||
NON-CURRENT LIABILITIES HELD FOR SALE | 142 | — | ||||||
LONG-TERM DEBT, less current maturities | 15,442 | 7,388 | ||||||
LONG-TERM NOTES PAYABLE – RELATED PARTY | 166 | — | ||||||
NON-CURRENT PRICE RISK MANAGEMENT LIABILITIES | 129 | 42 | ||||||
DEFERRED INCOME TAXES | 3,476 | 126 | ||||||
OTHER NON-CURRENT LIABILITIES | 995 | 27 | ||||||
COMMITMENTS AND CONTINGENCIES (Note 9) | ||||||||
EQUITY: | ||||||||
General Partner | — | — | ||||||
Limited Partners: | ||||||||
Class A Limited Partner interest | 86 | 84 | ||||||
Class B Limited Partner interest | 131 | 127 | ||||||
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Total partners’ capital | 217 | 211 | ||||||
Noncontrolling interest | 17,144 | 6,168 | ||||||
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Total equity | 17,361 | 6,379 | ||||||
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Total liabilities and equity | $ | 43,259 | $ | 15,548 | ||||
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The accompanying notes are an integral part of these consolidated financial statements.
6
ENERGY TRANSFER PARTNERS GP, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions)
Years Ended December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
REVENUES: | ||||||||||||
Natural gas sales | $ | 2,387 | $ | 2,534 | $ | 2,440 | ||||||
NGL sales | 1,718 | 1,113 | 587 | |||||||||
Crude sales | 2,872 | — | — | |||||||||
Gathering, transportation and other fees | 2,007 | 1,488 | 1,192 | |||||||||
Refined product sales | 5,299 | — | — | |||||||||
Other | 1,419 | 1,664 | 1,624 | |||||||||
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Total revenues | 15,702 | 6,799 | 5,843 | |||||||||
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COSTS AND EXPENSES: | ||||||||||||
Cost of products sold | 12,266 | 4,175 | 3,591 | |||||||||
Operating expenses | 900 | 760 | 694 | |||||||||
Depreciation and amortization | 656 | 405 | 317 | |||||||||
Selling, general and administrative | 486 | 212 | 176 | |||||||||
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Total costs and expenses | 14,308 | 5,552 | 4,778 | |||||||||
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OPERATING INCOME | 1,394 | 1,247 | 1,065 | |||||||||
OTHER INCOME (EXPENSE): | ||||||||||||
Interest expense, net of interest capitalized | (665 | ) | (474 | ) | (413 | ) | ||||||
Equity in earnings of unconsolidated affiliates | 142 | 26 | 12 | |||||||||
Gain on deconsolidation of Propane Business | 1,057 | — | — | |||||||||
Loss on extinguishment of debt | (115 | ) | — | — | ||||||||
Gains (losses) on non-hedged interest rate derivatives | (4 | ) | (77 | ) | 5 | |||||||
Impairments of investments in affiliates | — | (5 | ) | (53 | ) | |||||||
Other, net | 11 | 2 | 23 | |||||||||
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INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE | 1,820 | 719 | 639 | |||||||||
Income tax expense from continuing operations | 63 | 19 | 16 | |||||||||
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INCOME FROM CONTINUING OPERATIONS | 1,757 | 700 | 623 | |||||||||
Loss from discontinued operations | (109 | ) | (3 | ) | (6 | ) | ||||||
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NET INCOME | 1,648 | 697 | 617 | |||||||||
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST | 1,187 | 264 | 229 | |||||||||
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NET INCOME ATTRIBUTABLE TO PARTNERS | 461 | 433 | 388 | |||||||||
GENERAL PARTNER’S INTEREST IN NET INCOME | — | — | — | |||||||||
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LIMITED PARTNERS’ INTEREST IN NET INCOME | $ | 461 | $ | 433 | $ | 388 | ||||||
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The accompanying notes are an integral part of these consolidated financial statements.
7
ENERGY TRANSFER PARTNERS GP, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in millions)
Years Ended December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
Net income | $ | 1,648 | $ | 697 | $ | 617 | ||||||
Other comprehensive income (loss), net of tax: | ||||||||||||
Reclassification to earnings of gains and losses on derivative instruments accounted for as cash flow hedges | (14 | ) | (38 | ) | (36 | ) | ||||||
Change in value of derivative instruments accounted for as cash flow hedges | 8 | 19 | 59 | |||||||||
Change in value of available-for-sale securities | — | (1 | ) | (4 | ) | |||||||
Actuarial loss relating to pension and other postretirement benefits | (10 | ) | — | — | ||||||||
Change in other comprehensive income (loss) from equity investments | (9 | ) | — | — | ||||||||
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(25 | ) | (20 | ) | 19 | ||||||||
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Comprehensive income | 1,623 | 677 | 636 | |||||||||
Less: Comprehensive income attributable to noncontrolling interest | 1,162 | 244 | 248 | |||||||||
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Comprehensive income attributable to partners | $ | 461 | $ | 433 | $ | 388 | ||||||
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The accompanying notes are an integral part of these consolidated financial statements.
8
ENERGY TRANSFER PARTNERS GP, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF EQUITY
(Dollars in millions)
General Partner | Limited Partners | Noncontrolling Interest | Total | |||||||||||||
Balance, December 31, 2009 | $ | — | $ | 204 | $ | 4,425 | $ | 4,629 | ||||||||
Redemption of units in connection with MEP Transaction | — | (4 | ) | (600 | ) | (604 | ) | |||||||||
Distributions to partners | — | (384 | ) | — | (384 | ) | ||||||||||
Distributions to noncontrolling interest | — | — | (677 | ) | (677 | ) | ||||||||||
Units issued for cash | — | — | 1,152 | 1,152 | ||||||||||||
Non-cash compensation expense, net of units tendered by employees for tax withholdings | — | — | 24 | 24 | ||||||||||||
Other comprehensive income, net of tax | — | — | 19 | 19 | ||||||||||||
Other, net | — | — | (4 | ) | (4 | ) | ||||||||||
Net income | — | 388 | 229 | 617 | ||||||||||||
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Balance, December 31, 2010 | — | 204 | 4,568 | 4,772 | ||||||||||||
Distributions to partners | — | (426 | ) | — | (426 | ) | ||||||||||
Distributions to noncontrolling interest | — | — | (785 | ) | (785 | ) | ||||||||||
Units issued for cash | — | — | 1,467 | 1,467 | ||||||||||||
Capital contributions from noncontrolling interest | — | — | 645 | 645 | ||||||||||||
Issuance of units in acquisitions | — | — | 3 | 3 | ||||||||||||
Non-cash compensation expense, net of units tendered by employees for tax withholdings | — | — | 30 | 30 | ||||||||||||
Other comprehensive loss, net of tax | — | — | (20 | ) | (20 | ) | ||||||||||
Other, net | — | — | (4 | ) | (4 | ) | ||||||||||
Net income | — | 433 | 264 | 697 | ||||||||||||
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Balance, December 31, 2011 | — | 211 | 6,168 | 6,379 | ||||||||||||
Distributions to partners | (454 | ) | — | (454 | ) | |||||||||||
Distributions to noncontrolling interest | — | — | (1,130 | ) | (1,130 | ) | ||||||||||
Units issued for cash | — | — | 791 | 791 | ||||||||||||
Capital contributions from noncontrolling interest | — | — | 343 | 343 | ||||||||||||
Sunoco Merger (See Note 3) | — | — | 5,868 | 5,868 | ||||||||||||
Holdco Transaction (See Note 3) | — | — | 3,913 | 3,913 | ||||||||||||
Issuance of units in other acquisitions (excluding Sunoco) | — | — | 7 | 7 | ||||||||||||
Non-cash compensation expense, net of units tendered by employees for tax withholdings | — | — | 27 | 27 | ||||||||||||
Other comprehensive loss, net of tax | — | — | (25 | ) | (25 | ) | ||||||||||
Other, net | — | (1 | ) | (15 | ) | (15 | ) | |||||||||
Net income | — | 461 | 1,187 | 1,648 | ||||||||||||
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Balance, December 31, 2012 | $ | — | $ | 217 | $ | 17,144 | $ | 17,361 | ||||||||
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The accompanying notes are an integral part of these consolidated financial statements.
9
ENERGY TRANSFER PARTNERS GP, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)
Years Ended December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
CASH FLOWS FROM OPERATING ACTIVITIES: | ||||||||||||
Net income | $ | 1,648 | $ | 697 | $ | 617 | ||||||
Reconciliation of net income to net cash provided by operating activities: | ||||||||||||
Impairments of investments in affiliates | — | 5 | 53 | |||||||||
Proceeds from termination of interest rate derivatives | — | — | 26 | |||||||||
Depreciation and amortization | 656 | 405 | 317 | |||||||||
Deferred income taxes | 62 | 4 | 6 | |||||||||
Amortization of finance costs charged to interest | (35 | ) | 10 | 10 | ||||||||
Loss on extinguishment of debt | 115 | — | — | |||||||||
LIFO valuation reserve | 75 | — | — | |||||||||
Non-cash compensation expense | 42 | 38 | 28 | |||||||||
Gain on deconsolidation of Propane Business | (1,057 | ) | — | — | ||||||||
Write-down of assets included in loss from discontinued operations (See Note 3) | 132 | — | — | |||||||||
Losses on disposal of assets | 1 | 3 | 5 | |||||||||
Equity in earnings of unconsolidated affiliates | (142 | ) | (26 | ) | (12 | ) | ||||||
Distributions from unconsolidated affiliates | 132 | 29 | 33 | |||||||||
Other non-cash | 52 | 21 | (2 | ) | ||||||||
Net change in operating assets and liabilities, net of effects of acquisitions, dispositions and deconsolidation (see Note 2) | (475 | ) | 166 | 125 | ||||||||
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Net cash provided by operating activities | 1,206 | 1,352 | 1,206 | |||||||||
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CASH FLOWS FROM INVESTING ACTIVITIES: | ||||||||||||
Cash paid for Citrus Acquisition | (1,895 | ) | — | — | ||||||||
Cash proceeds from the contribution and sale of propane operations | 1,443 | — | — | |||||||||
Cash received from (paid for) all other acquisitions | 531 | (1,972 | ) | (178 | ) | |||||||
Capital expenditures (excluding allowance for equity funds used during construction) | (2,840 | ) | (1,416 | ) | (1,351 | ) | ||||||
Contributions in aid of construction costs | 35 | 25 | 14 | |||||||||
Contributions to unconsolidated affiliates | (30 | ) | (222 | ) | (7 | ) | ||||||
Distributions from unconsolidated affiliates in excess of cumulative earnings | 130 | 22 | — | |||||||||
Sale of investment in MEP | — | 1 | — | |||||||||
Proceeds from sale of disposal group | 207 | — | — | |||||||||
Proceeds from the sale of assets | 18 | 9 | 28 | |||||||||
Other | 116 | — | — | |||||||||
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Net cash used in investing activities | (2,285 | ) | (3,553 | ) | (1,494 | ) | ||||||
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CASH FLOWS FROM FINANCING ACTIVITIES: | ||||||||||||
Proceeds from borrowings | 8,208 | 6,594 | 1,538 | |||||||||
Repayments of long-term debt | (6,598 | ) | (5,217 | ) | (1,345 | ) | ||||||
Proceeds from borrowings from affiliates | 221 | — | — | |||||||||
Repayments of borrowings from affiliates | (55 | ) | — | — | ||||||||
Net proceeds from issuance of ETP Limited Partner units | 791 | 1,467 | 1,152 | |||||||||
Capital contributions received from noncontrolling interest | 320 | 645 | — | |||||||||
Distributions to partners | (454 | ) | (426 | ) | (384 | ) | ||||||
Distributions to noncontrolling interest | (1,130 | ) | (785 | ) | (677 | ) | ||||||
Redemption of units | — | — | (15 | ) | ||||||||
Debt issuance costs | (20 | ) | (20 | ) | — | |||||||
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Net cash provided by financing activities | 1,283 | 2,258 | 269 | |||||||||
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INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS | 204 | 57 | (19 | ) | ||||||||
CASH AND CASH EQUIVALENTS, beginning of period | 107 | 50 | 69 | |||||||||
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CASH AND CASH EQUIVALENTS, end of period | $ | 311 | $ | 107 | $ | 50 | ||||||
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The accompanying notes are an integral part of these consolidated financial statements.
10
ENERGY TRANSFER PARTNERS GP, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Tabular dollar amounts are in millions)
1. | OPERATIONS AND ORGANIZATION: |
Energy Transfer Partners GP, L.P. (“ETP GP” or “the Partnership”) was formed in August 2000 as a Delaware limited partnership. ETP GP is the General Partner and the owner of the general partner interest of Energy Transfer Partners, L.P., a publicly traded master limited partnership (“ETP”). ETP GP is owned 99.99% by its limited partners, and 0.01% by its general partner, Energy Transfer Partners, L.L.C. (“ETP LLC”).
Energy Transfer Equity, L.P. (“ETE”) is the 100% owner of ETP LLC and also owns 100% of our Class A and Class B Limited Partner interests. For more information on our Class A and Class B Limited Partner interests, see Note 6.
Financial Statement Presentation
The consolidated financial statements and notes thereto of ETP GP and its subsidiaries presented herein for the years ended December 31, 2012, 2011 and 2010, have been prepared in accordance with GAAP. We consolidate all majority-owned subsidiaries and subsidiaries we control, even if we do not have a majority ownership. All significant intercompany transactions and accounts are eliminated in consolidation. Management has evaluated subsequent events through the date the financial statements were issued.
We also own varying undivided interests in certain pipelines. Ownership of these pipelines has been structured as an ownership of an undivided interest in assets, not as an ownership interest in a partnership, limited liability company, joint venture or other forms of entities. Each owner controls marketing and invoices separately, and each owner is responsible for any loss, damage or injury that may occur to their own customers. As a result, we apply proportionate consolidation for our interests in these assets.
In October 2012, we sold Canyon for approximately $207 million. The results of continuing operations of Canyon have been reclassified to loss from discontinued operations. In December 2012, Southern Union entered into a purchase and sale agreement with the Laclede Entities, pursuant to which Laclede Missouri has agreed to acquire the assets of Missouri Gas Energy division and Laclede Massachusetts has agreed to acquire the assets of the New England Gas Company division. For the period from March 26, 2012 to December 31, 2012 the results of operations of the distribution operations have been reclassified to income from discontinued operations. The assets and liabilities of the disposal group have been reclassified and reported as assets and liabilities held for sale as of December 31, 2012.
In accordance with GAAP, we have accounted for the Holdco Transaction (described in Note 3), whereby ETP obtained control of Southern Union, as a reorganization of entities under common control. Accordingly, ETP’s consolidated financial statements have been retrospectively adjusted to reflect consolidation of Southern Union into ETP beginning March 26, 2012 (the date ETE acquired Southern Union).
Business Operations
Our activities are primarily conducted through our operating subsidiaries (collectively, the “Operating Companies”) as follows:
• | ETC OLP, a Texas limited partnership engaged in midstream and intrastate transportation and storage natural gas operations. ETC OLP owns and operates, through its wholly and majority-owned subsidiaries, natural gas gathering systems, intrastate natural gas pipeline systems and gas processing plants and is engaged in the business of purchasing, gathering, transporting, processing, and marketing natural gas and NGLs in the states of Texas, Louisiana, New Mexico and West Virginia. Our intrastate transportation and storage operations primarily focus on transporting natural gas in Texas through our Oasis pipeline, ET Fuel System, East Texas pipeline and HPL System. Our midstream operations focus on the gathering, compression, treating, conditioning and processing of natural gas, primarily on or through our Southeast Texas System, Eagle Ford System, North Texas System and Northern Louisiana assets. ETC OLP also owns a 70% interest in Lone Star. |
• | ET Interstate, a Delaware limited liability company with revenues consisting primarily of fees earned from natural gas transportation services and operational gas sales. ET Interstate is the parent company of: |
• | Transwestern, a Delaware limited liability company engaged in interstate transportation of natural gas. Transwestern’s revenues consist primarily of fees earned from natural gas transportation services and operational gas sales. |
• | ETC FEP, a Delaware limited liability company that directly owns a 50% interest in FEP, which owns 100% of the Fayetteville Express interstate natural gas pipeline. |
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• | ETC Tiger, a Delaware limited liability company engaged in interstate transportation of natural gas. |
• | CrossCountry, a Delaware limited liability company that indirectly owns a 50% interest in Citrus Corp., which owns 100% of the FGT interstate natural gas pipeline. |
• | ETC Compression, a Delaware limited liability company engaged in natural gas compression services and related equipment sales. |
• | Sunoco Logistics is a publicly traded Delaware limited partnership that owns and operates a logistics business, consisting of refined products and crude oil pipelines, terminalling and storage assets, and refined products and crude oil acquisition and marketing assets. |
• | Holdco is a Delaware limited liability company that indirectly owns Southern Union and Sunoco. As discussed in Note 3, ETP acquired ETE’s 60% interest in Holdco on April 30, 2013. Sunoco and Southern Union operations are described as follows: |
• | Southern Union owns and operates assets in the regulated and unregulated natural gas industry and is primarily engaged in the transportation, storage and distribution of natural gas in the United States. |
• | Sunoco owns and operates retail marketing assets, that sell gasoline and middle distillates and operate convenience stores primarily on the east coast and in the midwest region of the United States. |
On January 12, 2012, we contributed HOLP and Titan, our subsidiaries that formerly operated our propane operations, to AmeriGas. See Note 4.
On October 5, 2012, we completed the Sunoco Merger and Holdco Transaction, as described below in Note 3.
The Partnership, ETP, the Operating Companies and their subsidiaries are collectively described in this report as “we,” “us,” “our,” “ETP,” “Energy Transfer” or the “Partnership.”
2. | ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL: |
Certain of our significant accounting policies have been impacted by current year transactions. See Note 3 for a discussion of these transactions.
Use of Estimates
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the accrual for and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.
The natural gas industry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results for the midstream, NGL and intrastate transportation and storage operations are estimated using volume estimates and market prices. Any differences between estimated results and actual results are recognized in the following month’s financial statements. Management believes that the estimated operating results represent the actual results in all material respects.
Some of the other significant estimates made by management include, but are not limited to, the timing of certain forecasted transactions that are hedged, the fair value of derivative instruments, useful lives for depreciation and amortization, purchase accounting allocations and subsequent realizability of intangible assets, fair value measurements used in the goodwill impairment test, market value of inventory, assets and liabilities resulting from the regulated ratemaking process, contingency reserves and environmental reserves. Actual results could differ from those estimates.
Revenue Recognition
Revenues for sales of natural gas and NGLs are recognized at the later of the time of delivery of the product to the customer or the time of sale or installation. Revenues from service labor, transportation, treating, compression and gas processing are recognized upon completion of the service. Transportation capacity payments are recognized when earned in the period the capacity is made available.
Our intrastate transportation and storage and interstate transportation and storage operations’ results are determined primarily by the amount of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines. Under transportation contracts, our customers are charged (i) a demand fee, which is a fixed fee for the reservation of an agreed amount of capacity on the transportation pipeline for a specified period of time and which obligates the customer to pay even if the customer does not transport natural gas on the respective pipeline, (ii) a transportation fee, which is based on the actual throughput of natural gas by the customer, (iii) fuel retention based on a percentage of gas transported on the pipeline, or (iv) a combination of the three, generally payable monthly. Fuel retained for a fee is typically valued at market prices.
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Our intrastate transportation and storage operations also generates revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and other marketing companies on the HPL System. Generally, we purchase natural gas from the market, including purchases from the midstream operations’ marketing operations, and from producers at the wellhead.
In addition, our intrastate transportation and storage operations generates revenues and margin from fees charged for storing customers’ working natural gas in our storage facilities. We also engage in natural gas storage transactions in which we seek to find and profit from pricing differences that occur over time utilizing the Bammel storage reservoir. We purchase physical natural gas and then sell financial contracts at a price sufficient to cover our carrying costs and provide for a gross profit margin. We expect margins from natural gas storage transactions to be higher during the periods from November to March of each year and lower during the period from April through October of each year due to the increased demand for natural gas during colder weather. However, we cannot assure that management’s expectations will be fully realized in the future and in what time period, due to various factors including weather, availability of natural gas in regions in which we operate, competitive factors in the energy industry, and other issues.
Results from the midstream operations are determined primarily by the volumes of natural gas gathered, compressed, treated, processed, purchased and sold through our pipeline and gathering systems and the level of natural gas and NGL prices. We generate midstream revenues and gross margins principally under fee-based or other arrangements in which we receive a fee for natural gas gathering, compressing, treating or processing services. The revenue earned from these arrangements is directly related to the volume of natural gas that flows through our systems and is not directly dependent on commodity prices.
We also utilize other types of arrangements in our midstream operations, including (i) discount-to-index price arrangements, which involve purchases of natural gas at either (1) a percentage discount to a specified index price, (2) a specified index price less a fixed amount or (3) a percentage discount to a specified index price less an additional fixed amount, (ii) percentage-of-proceeds arrangements under which we gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price, (iii) keep-whole arrangements where we gather natural gas from the producer, process the natural gas and sell the resulting NGLs to third parties at market prices, (iv) purchasing all or a specified percentage of natural gas and/or NGL delivered from producers and treating or processing our plant facilities, and (v) making other direct purchases of natural gas and/or NGL at specified delivery points to meet operational or marketing obligations. In many cases, we provide services under contracts that contain a combination of more than one of the arrangements described above. The terms of our contracts vary based on gas quality conditions, the competitive environment at the time the contracts are signed and customer requirements. Our contract mix may change as a result of changes in producer preferences, expansion in regions where some types of contracts are more common and other market factors.
NGL storage and pipeline transportation revenues are recognized when services are performed or products are delivered, respectively. Fractionation and processing revenues are recognized when product is either loaded into a truck or injected into a third party pipeline, which is when title and risk of loss pass to the customer.
We conduct marketing activities in which we market the natural gas that flows through our assets, referred to as on-system gas. We also attract other customers by marketing volumes of natural gas that do not move through our assets, referred to as off-system gas. For both on-system and off-system gas, we purchase natural gas from natural gas producers and other supply points and sell that natural gas to utilities, industrial consumers, other marketers and pipeline companies, thereby generating gross margins based upon the difference between the purchase and resale prices.
Terminalling and storage revenues are recognized at the time the services are provided. Pipeline revenues are recognized upon delivery of the barrels to the location designated by the shipper. Crude oil acquisition and marketing revenues, as well as refined product marketing revenues, are recognized when title to the product is transferred to the customer. Revenues are not recognized for crude oil exchange transactions, which are entered into primarily to acquire crude oil of a desired quality or to reduce transportation costs by taking delivery closer to end markets. Any net differential for exchange transactions is recorded as an adjustment of inventory costs in the purchases component of cost of products sold and operating expenses in the statements of operations.
Our retail marketing operations sells gasoline and diesel in addition to a broad mix of merchandise such as groceries, fast foods and beverages at its convenience stores. In addition some of Sunoco’s retail outlets provide a variety of car care services. Revenues related to the sale of products are recognized when title passes, while service revenues are recognized when services are provided. Title passage generally occurs when products are shipped or delivered in accordance with the terms of the respective sales agreements. In addition, revenues are not recognized until sales prices are fixed or determinable and collectability is reasonably assured.
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Regulatory Accounting—Regulatory Assets and Liabilities
Our interstate transportation and storage operations are subject to regulation by certain state and federal authorities and has accounting policies that conform to the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting policies allows certain of our regulated entities to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and revenues will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the consolidated statement of operations by an unregulated company. These deferred assets and liabilities will be reported in results of operations in the period in which the same amounts are included in rates and recovered from or refunded to customers. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities will require judgment and interpretation of laws and regulatory commission orders. If, for any reason, we cease to meet the criteria for application of regulatory accounting treatment for these entities, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the consolidated balance sheet for the period in which the discontinuance of regulatory accounting treatment occurs.
Southern Union records regulatory assets with respect to its distribution operations. We recorded regulatory assets with respect to Southern Union’s distribution operations, which have been classified as discontinued operations as of December 31, 2012. At December 31, 2012, we had $123 million of regulatory assets included in the consolidated balance sheet as non-current assets held for sale. Although Panhandle’s natural gas transmission systems and storage operations are subject to the jurisdiction of FERC in accordance with the Natural Gas Act of 1938 and Natural Gas Policy Act of 1978, it does not currently apply regulatory accounting policies in accounting for its operations. In 1999, prior to its acquisition by Southern Union, Panhandle discontinued the application of regulatory accounting policies primarily due to the level of discounting from tariff rates and its inability to recover specific costs.
Cash, Cash Equivalents and Supplemental Cash Flow Information
Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and that are subject to an insignificant risk of changes in value.
We place our cash deposits and temporary cash investments with high credit quality financial institutions. At times, our cash and cash equivalents may be uninsured or in deposit accounts that exceed the Federal Deposit Insurance Corporation insurance limit.
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The net change in operating assets and liabilities (net of acquisitions) included in cash flows from operating activities is comprised as follows:
Years Ended December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
Accounts receivable | $ | 300 | $ | 3 | $ | 63 | ||||||
Accounts receivable from related companies | (50 | ) | (28 | ) | 3 | |||||||
Inventories | (253 | ) | 68 | 15 | ||||||||
Exchanges receivable | 11 | 3 | 1 | |||||||||
Other current assets | 571 | (62 | ) | 33 | ||||||||
Other non-current assets, net | (53 | ) | 7 | 5 | ||||||||
Accounts payable | (979 | ) | 31 | (48 | ) | |||||||
Accounts payable to related companies | 100 | 6 | (11 | ) | ||||||||
Exchanges payable | — | 3 | (4 | ) | ||||||||
Accrued and other current liabilities | (151 | ) | 60 | 42 | ||||||||
Other non-current liabilities | 25 | — | — | |||||||||
Price risk management assets and liabilities, net | 4 | 75 | 26 | |||||||||
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Net change in operating assets and liabilities, net of effects of acquisitions, dispositions and deconsolidation | $ | (475 | ) | $ | 166 | $ | 125 | |||||
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Non-cash investing and financing activities and supplemental cash flow information are as follows:
Years Ended December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
NON-CASH INVESTING ACTIVITIES: | ||||||||||||
Accrued capital expenditures | $ | 359 | $ | 202 | $ | 88 | ||||||
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AmeriGas limited partner interest received in exchange for Propane Contribution | $ | 1,123 | $ | — | $ | — | ||||||
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Transfer of MEP joint venture interest in exchange for redemption of ETP common units | $ | — | $ | — | $ | 589 | ||||||
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NON-CASH FINANCING ACTIVITIES: | ||||||||||||
Long-term debt assumed and non-compete agreement notes payable issued in acquisitions | $ | 6,658 | $ | 4 | $ | 3 | ||||||
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Issuance of ETP common units in connection with certain acquisitions | $ | 2,295 | $ | 3 | $ | — | ||||||
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Contributions receivable related to noncontrolling interest | $ | 23 | $ | — | $ | — | ||||||
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SUPPLEMENTAL CASH FLOW INFORMATION: | ||||||||||||
Cash paid for interest, net of interest capitalized | $ | 678 | $ | 476 | $ | 431 | ||||||
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Cash paid for income taxes | $ | 22 | $ | 24 | $ | 9 | ||||||
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Accounts Receivable
Our midstream, NGL and intrastate transportation and storage operations deal with counterparties that are typically either investment grade or are otherwise secured with a letter of credit or other form of security (corporate guaranty prepayment or master setoff agreement). Management reviews midstream and intrastate transportation and storage accounts receivable balances bi-weekly. Credit limits are assigned and monitored for all counterparties of the midstream and intrastate transportation and storage operations. Bad debt expense related to these receivables is recognized at the time an account is deemed uncollectible.
Sunoco extends credit terms to certain customers after review of various credit indicators, including the customer’s credit rating. Outstanding customer receivable balances are regularly reviewed for possible non-payment indicators and reserves are recorded for doubtful accounts based upon management’s estimate of collectability at the time of review. Actual balances are charged against the reserve when all collection efforts have been exhausted.
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Our interstate transportation and storage operations have a concentration of customers in the electric and gas utility industries as well as natural gas producers. This concentration of customers may impact our overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic or other conditions. From time to time, specifically identified customers having perceived high credit risk are required to provide prepayments or other forms of collateral. Management believes that the portfolio of receivables, which includes regulated electric utilities, regulated local distribution companies and municipalities, is subject to minimal credit risk. Our interstate transportation and storage operations establish an allowance for doubtful accounts on trade receivables based on the expected ultimate recovery of these receivables and consider many factors including historical customer collection experience, general and specific economic trends and known specific issues related to individual customers, sectors and transactions that might impact collectability.
We enter into netting arrangements with counterparties of derivative contracts to mitigate credit risk. Transactions are confirmed with the counterparty and the net amount is settled when due. Amounts outstanding under these netting arrangements are presented on a net basis in the consolidated balance sheets.
Inventories
Inventories consist principally of natural gas held in storage, crude oil, petroleum and chemical products . Natural gas held in storage is valued at the lower of cost or market utilizing the weighted-average cost method. The cost of crude oil and petroleum and chemical products is determined using the last-in, first out method. The cost of appliances, parts and fittings is determined by the first-in, first-out method.
Inventories consisted of the following:
December 31, | ||||||||
2012 | 2011 | |||||||
Natural gas and NGLs, excluding propane | $ | 334 | $ | 144 | ||||
Propane | — | 87 | ||||||
Crude Oil | 418 | — | ||||||
Refined Products | 572 | — | ||||||
Appliances, parts and fittings and other | 171 | 76 | ||||||
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Total inventories | $ | 1,495 | $ | 307 | ||||
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We utilize commodity derivatives to manage price volatility associated with our natural gas inventory. Changes in fair value of designated hedged inventory is recorded in inventory on our consolidated balance sheets and cost of products sold in our consolidated statements of operations.
Exchanges
Exchanges consist of natural gas and NGL delivery imbalances (over and under deliveries) with others. These amounts, which are valued at market prices or weighted average market prices pursuant to contractual imbalance agreements, turn over monthly and are recorded as exchanges receivable or exchanges payable on our consolidated balance sheets. These imbalances are generally settled by deliveries of natural gas or NGLs, but may be settled in cash, depending on contractual terms.
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Other Current Assets
Other current assets consisted of the following:
December 31, | ||||||||
2012 | 2011 | |||||||
Deposits paid to vendors | $ | 41 | $ | 66 | ||||
Prepaid and other | 293 | 114 | ||||||
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Total other current assets | $ | 334 | $ | 180 | ||||
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Property, Plant and Equipment
Property, plant and equipment are stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful or Federal Energy Regulatory Commission (“FERC”) mandated lives of the assets, if applicable. Expenditures for maintenance and repairs that do not add capacity or extend the useful life are expensed as incurred. Expenditures to refurbish assets that either extend the useful lives of the asset or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset. Additionally, we capitalize certain costs directly related to the construction of assets including internal labor costs, interest and engineering costs. Upon disposition or retirement of pipeline components or natural gas plant components, any gain or loss is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in our consolidated statements of operations.
We review property, plant and equipment for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of long-lived assets is not recoverable, we reduce the carrying amount of such assets to fair value. A write down of the carrying amounts of the Canyon assets to their fair values was recorded for approximately $128 million during the year ended December 31, 2012.
Capitalized interest is included for pipeline construction projects, except for certain interstate projects for which an allowance for funds used during construction (“AFUDC”) is accrued. Interest is capitalized based on the current borrowing rate of our revolving credit facility when the related costs are incurred. AFUDC is calculated under guidelines prescribed by the FERC and capitalized as part of the cost of utility plant for interstate projects. It represents the cost of servicing the capital invested in construction work-in-process. AFUDC is segregated into two component parts – borrowed funds and equity funds.
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Components and useful lives of property, plant and equipment were as follows:
December 31, | ||||||||
2012 | 2011 | |||||||
Land and improvements | $ | 551 | $ | 136 | ||||
Buildings and improvements (5 to 40 years) | 568 | 268 | ||||||
Pipelines and equipment (5 to 83 years) | 17,031 | 9,174 | ||||||
Natural gas and NGL storage facilities (5 to 46 years) | 1,057 | 790 | ||||||
Bulk storage, equipment and facilities (3 to 83 years) | 1,745 | 977 | ||||||
Tanks and other equipment (10 to 40 years) | 1,187 | 643 | ||||||
Retail equipment (3 to 99 years) | 258 | — | ||||||
Vehicles (3 to 25 years) | 77 | 214 | ||||||
Right of way (20 to 83 years) | 2,042 | 734 | ||||||
Furniture and fixtures (3 to 12 years) | 48 | 47 | ||||||
Linepack | 116 | 57 | ||||||
Pad gas | 58 | 58 | ||||||
Other (2 to 19 years) | 986 | 154 | ||||||
Construction work-in-process | 1,688 | 732 | ||||||
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Less – Accumulated depreciation | (1,639 | ) | (1,678 | ) | ||||
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Property, plant and equipment, net | $ | 25,773 | $ | 12,306 | ||||
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We recognized the following amounts of depreciation expense for the periods presented:
Years Ended December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
Depreciation expense(1) | $ | 615 | $ | 380 | $ | 297 | ||||||
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Capitalized interest, excluding AFUDC | $ | 99 | $ | 11 | $ | 3 | ||||||
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(1) | Depreciation expense amounts have been restated by $26 million and $25 million for years ended December 31, 2011 and 2010, respectively, to present Canyon’s operations as discontinued operations. |
Advances to and Investments in Affiliates
We own interests in a number of related businesses that are accounted for by the equity method. In general, we use the equity method of accounting for an investment in which we have a 20% to 50% ownership and exercise significant influence over, but do not control, the investee’s operating and financial policies.
Goodwill
Goodwill is tested for impairment annually or more frequently if circumstances indicate that goodwill might be impaired. Our annual impairment test is performed as of August 31 for subsidiaries in our intrastate transportation and storage and midstream operations and as of December 31 for subsidiaries in our interstate transportation and storage and NGL transportation and services operations and all others. No goodwill impairments were recorded for the periods presented in these consolidated financial statements.
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Changes in the carrying amount of goodwill were as follows:
Intrastate Transportation and Storage | Interstate Transportation and Storage | Midstream | NGL Transportation and Services | Investment in Sunoco Logistics | Retail Marketing | All Other | Total | |||||||||||||||||||||||||
Balance, December 31, 2010 | $ | 10 | $ | 99 | $ | 50 | $ | — | $ | — | $ | — | $ | 652 | $ | 811 | ||||||||||||||||
Goodwill acquired | — | —�� | — | 432 | — | — | 6 | 438 | ||||||||||||||||||||||||
Other | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||
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Balance, December 31, 2011 | 10 | 99 | 50 | 432 | — | — | 658 | 1,249 | ||||||||||||||||||||||||
Goodwill acquired | — | 1,785 | 338 | — | 1,368 | 1,272 | 375 | 5,138 | ||||||||||||||||||||||||
Goodwill contributed in deconsolidation of Propane Business | — | — | — | — | — | — | (619 | ) | (619 | ) | ||||||||||||||||||||||
Goodwill allocated to the disposal group | — | — | — | — | — | — | (133 | ) | (133 | ) | ||||||||||||||||||||||
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Balance, December 31, 2012 | $ | 10 | $ | 1,884 | $ | 388 | $ | 432 | $ | 1,368 | $ | 1,272 | $ | 281 | $ | 5,635 | ||||||||||||||||
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Goodwill is recorded at the acquisition date based on a preliminary purchase price allocation and generally may be adjusted when the purchase price allocation is finalized. A net increase in goodwill of $4.39 billion was recorded during the year ended December 31, 2012, primarily due to $2.64 billion from the Sunoco Merger and $2.50 billion related to Southern Union, offset by $619 million in goodwill that was contributed as part of the deconsolidation of our Propane Business (see Note 3), and $133 million classified as assets held for sale (see Note 3). We acquired control of Southern Union through the Holdco Transaction. Because that transaction was a combination of entities under common control, we retrospectively consolidated Southern Union into the Partnership’s consolidated financial statements beginning on March 26, 2012 and also recorded Southern Union’s assets (including goodwill) and liabilities at ETE’s basis. The Sunoco Merger and Holdco Transaction are described in Note 3. This additional goodwill is not expected to be deductible for tax purposes.
Intangible Assets
Intangible assets are stated at cost, net of amortization computed on the straight-line method. We eliminate from our balance sheet the gross carrying amount and the related accumulated amortization for any fully amortized intangibles in the year they are fully amortized.
Components and useful lives of intangible assets were as follows:
December 31, 2012 | December 31, 2011 | |||||||||||||||
Gross Carrying Amount | Accumulated Amortization | Gross Carrying Amount | Accumulated Amortization | |||||||||||||
Amortizable intangible assets: | ||||||||||||||||
Customer relationships, contracts and agreements (3 to 46 years) | $ | 1,290 | $ | (80 | ) | $ | 338 | $ | (95 | ) | ||||||
Noncompete agreements (3 to 15 years) | — | — | 15 | (8 | ) | |||||||||||
Patents (9 years) | 48 | (1 | ) | 1 | — | |||||||||||
Other (10 to 15 years) | 4 | (1 | ) | 2 | (1 | ) | ||||||||||
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Total amortizable intangible assets | $ | 1,342 | $ | (82 | ) | $ | 356 | $ | (104 | ) | ||||||
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Trademarks | 301 | — | 79 | — | ||||||||||||
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Total intangible assets | $ | 1,643 | $ | (82 | ) | $ | 435 | $ | (104 | ) | ||||||
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Related to the Sunoco Merger and Holdco Transaction discussed in Note 3, we recorded customer contracts of $1.07 billion with useful lives ranging from 5 to 20 years, patents of $48 million with useful lives of 10 years and non-amortizable trademarks of $301 million during the year ended December 31, 2012.
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Aggregate amortization expense of intangible assets was as follows:
Years Ended December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
Reported in depreciation and amortization | $ | 36 | $ | 24 | $ | 20 | ||||||
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Estimated aggregate amortization expense for the next five years is as follows:
Years Ending December 31: | ||||
2013 | $ | 87 | ||
2014 | 86 | |||
2015 | 86 | |||
2016 | 86 | |||
2017 | 86 |
We review amortizable intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of amortizable intangible assets is not recoverable, we reduce the carrying amount of such assets to fair value. We review non-amortizable intangible assets for impairment annually, or more frequently if circumstances dictate.
Other Non-Current Assets, net
Other non-current assets, net are stated at cost less accumulated amortization. Other non-current assets, net consisted of the following:
December 31, | ||||||||
2012 | 2011 | |||||||
Unamortized financing costs (3 to 30 years) | $ | 54 | $ | 47 | ||||
Regulatory assets | 87 | 89 | ||||||
Deferred charges | 140 | — | ||||||
Other | 76 | 24 | ||||||
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Total other non-current assets, net | $ | 357 | $ | 160 | ||||
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Asset Retirement Obligation
We have determined that we are obligated by contractual or regulatory requirements to remove facilities or perform other remediation upon retirement of certain assets. The fair value of any ARO is determined based on estimates and assumptions related to retirement costs, which the Partnership bases on historical retirement costs, future inflation rates and credit-adjusted risk-free interest rates. These fair value assessments are considered to be level 3 measurements, as they are based on both observable and unobservable inputs. Changes in the liability are recorded for the passage of time (accretion) or for revisions to cash flows originally estimated to settle the ARO.
An ARO is required to be recorded when a legal obligation to retire an asset exists and such obligation can be reasonably estimated. We will record an asset retirement obligation in the periods in which management can reasonably determine the settlement dates.
Except for the AROs of Southern Union, Sunoco Logistics and Sunoco discussed below, management was not able to reasonably measure the fair value of asset retirement obligations as of December 31, 2012 and 2011 because the settlement dates were indeterminable. Although a number of other onshore assets in Southern Union’s system are subject to agreements or regulations that give rise to an ARO upon Southern Union’s discontinued use of these assets, AROs were not recorded because these assets have an indeterminate removal or abandonment date given the expected continued use of the assets with proper maintenance or replacement. Sunoco has legal asset retirement obligations for several other assets at its refineries, pipelines and terminals, for which it is not possible to estimate when the obligations will be settled. Consequently, the retirement obligations for these assets cannot be measured at this time. At the end of the useful life of these underlying assets, Sunoco is legally or contractually required to abandon in place or remove the asset. Sunoco Logistics believes it may have additional asset retirement obligations related to its pipeline assets and storage tanks, for which it is not possible to estimate whether or when the retirement obligations will be settled. Consequently, these retirement obligations cannot be measured at this time.
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Below is a schedule of AROs by entity recorded as other non-current liabilities in the consolidated balance sheet:
December 31, 2012 | ||||
Southern Union | $ | 46 | ||
Sunoco | 53 | |||
Sunoco Logistics | 41 | |||
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Individual component assets have been and will continue to be replaced, but the pipeline and the natural gas gathering and processing systems will continue in operation as long as supply and demand for natural gas exists. Based on the widespread use of natural gas in industrial and power generation activities, management expects supply and demand to exist for the foreseeable future. We have in place a rigorous repair and maintenance program that keeps the pipelines and the natural gas gathering and processing systems in good working order. Therefore, although some of the individual assets may be replaced, the pipelines and the natural gas gathering and processing systems themselves will remain intact indefinitely.
As of December 31, 2012, there were no legally restricted funds for the purpose of settling AROs.
Accrued and Other Current Liabilities
Accrued and other current liabilities consisted of the following:
December 31, | ||||||||
2012 | 2011 | |||||||
Interest payable | $ | 256 | $ | 143 | ||||
Customer advances and deposits | 44 | 84 | ||||||
Accrued capital expenditures | 356 | 197 | ||||||
Accrued wages and benefits | 236 | 67 | ||||||
Taxes payable other than income taxes | 203 | 77 | ||||||
Income taxes payable | 40 | 14 | ||||||
Deferred income taxes | 130 | — | ||||||
Other | 297 | 48 | ||||||
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Total accrued and other current liabilities | $ | 1,562 | $ | 630 | ||||
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Deposits or advances are received from our customers as prepayments for natural gas deliveries in the following month. Prepayments and security deposits may also be required when customers exceed their credit limits or do not qualify for open credit.
Environmental Remediation
We accrue environmental remediation costs for work at identified sites where an assessment has indicated that cleanup costs are probable and reasonably estimable. Such accruals are undiscounted and are based on currently available information, estimated timing of remedial actions and related inflation assumptions, existing technology and presently enacted laws and regulations. If a range of probable environmental cleanup costs exists for an identified site, the minimum of the range is accrued unless some other point in the range is more likely in which case the most likely amount in the range is accrued.
Fair Value of Financial Instruments
The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate their fair value. Price risk management assets and liabilities are recorded at fair value.
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Based on the estimated borrowing rates currently available to us and our subsidiaries for loans with similar terms and average maturities, the aggregate fair value and carrying amount of our debt obligations as of December 31, 2012 was $17.84 billion and $16.22 billion, respectively. As of December 31, 2011, the aggregate fair value and carrying amount of our debt obligations was $8.39 billion and $7.81 billion, respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities.
We have commodity derivatives and interest rate derivatives that are accounted for as assets and liabilities at fair value in our consolidated balance sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of marketable securities and commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider over-the-counter (“OTC”) commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions. Additionally, we consider our options transacted through our clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. We consider the valuation of our interest rate derivatives as Level 2 as the primary input, the LIBOR curve, is based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements. Level 3 inputs are unobservable. We currently do not have any recurring fair value financial instrument measurements that are considered Level 3 valuations. During the period ended December 31, 2012, no transfers were made between any levels within the fair value hierarchy.
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The following tables summarize the fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of December 31, 2012 and 2011 based on inputs used to derive their fair values:
Fair Value | Fair Value Measurements at December 31, 2012 | |||||||||||
Total | Level 1 | Level 2 | ||||||||||
Assets: | ||||||||||||
Interest rate derivatives | $ | 55 | $ | — | $ | 55 | ||||||
Commodity derivatives: | ||||||||||||
Natural Gas: | ||||||||||||
Basis Swaps IFERC/NYMEX | 11 | 11 | — | |||||||||
Swing Swaps IFERC | 3 | — | 3 | |||||||||
Fixed Swaps/Futures | 96 | 94 | 2 | |||||||||
Options – Puts | 1 | — | 1 | |||||||||
Options – Calls | 3 | — | 3 | |||||||||
Forward Physical Swaps | 1 | — | 1 | |||||||||
Power: | ||||||||||||
Forwards | 27 | — | 27 | |||||||||
Futures | 1 | 1 | — | |||||||||
Options – Calls | 2 | — | 2 | |||||||||
Natural Gas Liquids – Swaps | 1 | 1 | — | |||||||||
Refined Products | 5 | 1 | 4 | |||||||||
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Total commodity derivatives | 151 | 108 | 43 | |||||||||
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Total Assets | $ | 206 | $ | 108 | $ | 98 | ||||||
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Liabilities: | ||||||||||||
Interest rate derivatives | $ | (223 | ) | $ | — | $ | (223 | ) | ||||
Commodity derivatives: | ||||||||||||
Natural Gas: | ||||||||||||
Basis Swaps IFERC/NYMEX | (18 | ) | (18 | ) | — | |||||||
Swing Swaps IFERC | (2 | ) | — | (2 | ) | |||||||
Fixed Swaps/Futures | (103 | ) | (94 | ) | (9 | ) | ||||||
Options – Puts | (1 | ) | — | (1 | ) | |||||||
Options – Calls | (3 | ) | — | (3 | ) | |||||||
Forward Physical Swaps | — | — | — | |||||||||
Power: | ||||||||||||
Forwards | (27 | ) | — | (27 | ) | |||||||
Futures | (2 | ) | (2 | ) | — | |||||||
Natural Gas Liquids – Swaps | (3 | ) | (3 | ) | — | |||||||
Refined Products | (8 | ) | (1 | ) | (7 | ) | ||||||
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Total commodity derivatives | (167 | ) | (118 | ) | (49 | ) | ||||||
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Total Liabilities | $ | (390 | ) | $ | (118 | ) | $ | (272 | ) | |||
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Fair Value | Fair Value Measurements at December 31, 2011 | |||||||||||
Total | Level 1 | Level 2 | ||||||||||
Assets: | ||||||||||||
Marketable securities | $ | 1 | $ | 1 | $ | — | ||||||
Interest rate derivatives | 36 | — | 36 | |||||||||
Commodity derivatives: | ||||||||||||
Natural Gas: | ||||||||||||
Basis Swaps IFERC/NYMEX | 63 | 63 | — | |||||||||
Swing Swaps IFERC | 15 | 2 | 13 | |||||||||
Fixed Swaps/Futures | 215 | 215 | — | |||||||||
Options – Puts | 6 | — | 6 | |||||||||
Forward Physical Swaps | 1 | — | 1 | |||||||||
Total commodity derivatives | 300 | 280 | 20 | |||||||||
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Total Assets | $ | 337 | $ | 281 | $ | 56 | ||||||
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Liabilities: | ||||||||||||
Interest rate derivatives | $ | (117 | ) | $ | — | $ | (117 | ) | ||||
Commodity derivatives: | ||||||||||||
Natural Gas: | ||||||||||||
Basis Swaps IFERC/NYMEX | (82 | ) | (82 | ) | — | |||||||
Swing Swaps IFERC | (16 | ) | (3 | ) | (13 | ) | ||||||
Fixed Swaps/Futures | (148 | ) | (148 | ) | — | |||||||
Forward Physical Swaps | (1 | ) | — | (1 | ) | |||||||
Propane – Forwards/Swaps | (4 | ) | — | (4 | ) | |||||||
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Total commodity derivatives | (251 | ) | (233 | ) | (18 | ) | ||||||
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Total Liabilities | $ | (368 | ) | $ | (233 | ) | $ | (135 | ) | |||
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Contributions in Aid of Construction Costs
On certain of our capital projects, third parties are obligated to reimburse us for all or a portion of project expenditures. The majority of such arrangements are associated with pipeline construction and production well tie-ins. Contributions in aid of construction costs (“CIAC”) are netted against our project costs as they are received, and any CIAC which exceeds our total project costs, is recognized as other income in the period in which it is realized.
Shipping and Handling Costs
Shipping and handling costs related to fuel sold are included in cost of products sold. Shipping and handling costs related to fuel consumed for compression and treating are included in operating expenses and are as follows:
Years Ended December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
Shipping and handling costs – recorded in operating expenses | $ | 25 | $ | 40 | $ | 43 | ||||||
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Costs and Expenses
Costs of products sold include actual cost of fuel sold, adjusted for the effects of our hedging and other commodity derivative activities, and the cost of appliances, parts and fittings. Operating expenses include all costs incurred to provide products to customers, including compensation for operations personnel, insurance costs, vehicle maintenance, advertising costs, purchasing costs and plant operations. Selling, general and administrative expenses include all partnership related expenses and compensation for executive, partnership, and administrative personnel.
We record the collection of taxes to be remitted to government authorities on a net basis except for our retail marketing operation in which consumer excise taxes on sales of refined products and merchandise are included in both revenues and costs and expenses in the consolidated statements of operations, with no effect on net income (loss).
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Income Taxes
ETP GP is a limited partnership and is not taxable for federal and most state income tax purposes. As a result, our earnings or losses, to the extent not included in a taxable subsidiary, for federal and most state purposes are included in the tax returns of the individual partners. Net earnings for financial statement purposes may differ significantly from taxable income reportable to Unitholders as a result of differences between the tax basis and financial basis of assets and liabilities, differences between the tax accounting and financial accounting treatment of certain items, and due to allocation requirements related to taxable income under the Partnership Agreement.
As a limited partnership, ETP is subject to a statutory requirement that its “qualifying income” (as defined by the Internal Revenue Code, related Treasury Regulations, and Internal Revenue Service pronouncements) exceed 90% of its total gross income, determined on a calendar year basis. If ETP’s qualifying income does not meet this statutory requirement, ETP would be taxed as a corporation for federal and state income tax purposes. For the years ended December 31, 2012, 2011 and 2010, ETP’s qualifying income met the statutory requirement.
The Partnership conducts certain activities through corporate subsidiaries which are subject to federal, state and local income taxes. Holdco, formed via the Holdco Transaction (see Note 3), which includes Sunoco and Southern Union, is included amongst these corporate subsidiaries. The Partnership and its corporate subsidiaries account for income taxes under the asset and liability method.
Under this method, deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in earnings in the period that includes the enactment date. Valuation allowances are established when necessary to reduce deferred tax assets to the amounts more likely than not to be realized.
The determination of the provision for income taxes requires significant judgment, use of estimates, and the interpretation and application of complex tax laws. Significant judgment is required in assessing the timing and amounts of deductible and taxable items and the probability of sustaining uncertain tax positions. The benefits of uncertain tax positions are recorded in our financial statements only after determining a more-likely-than-not probability that the uncertain tax positions will withstand challenge, if any, from taxing authorities. When facts and circumstances change, we reassess these probabilities and record any changes through the provision for income taxes.
See Note 8 for income tax disclosures.
Accounting for Derivative Instruments and Hedging Activities
For qualifying hedges, we formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment and the gains and losses offset related results on the hedged item in the statement of operations. The market prices used to value our financial derivatives and related transactions have been determined using independent third party prices, readily available market information, broker quotes and appropriate valuation techniques.
At inception of a hedge, we formally document the relationship between the hedging instrument and the hedged item, the risk management objectives, and the methods used for assessing and testing effectiveness and how any ineffectiveness will be measured and recorded. We also assess, both at the inception of the hedge and on a quarterly basis, whether the derivatives that are used in our hedging transactions are highly effective in offsetting changes in cash flows. If we determine that a derivative is no longer highly effective as a hedge, we discontinue hedge accounting prospectively by including changes in the fair value of the derivative in net income for the period.
If we designate a commodity hedging relationship as a fair value hedge, we record the changes in fair value of the hedged asset or liability in cost of products sold in our consolidated statement of operations. This amount is offset by the changes in fair value of the related hedging instrument. Any ineffective portion or amount excluded from the assessment of hedge ineffectiveness is also included in the cost of products sold in the consolidated statement of operations.
Cash flows from derivatives accounted for as cash flow hedges are reported as cash flows from operating activities, in the same category as the cash flows from the items being hedged.
If we designate a derivative financial instrument as a cash flow hedge and it qualifies for hedge accounting, the change in the fair value is deferred in accumulated other comprehensive income (“AOCI”) until the underlying hedged transaction occurs. Any ineffective portion of a cash flow hedge’s change in fair value is recognized each period in earnings. Gains and losses deferred in AOCI related to cash flow hedges remain in AOCI until the underlying physical transaction occurs, unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two-month period of time thereafter. For financial derivative instruments that do not qualify for hedge accounting, the change in fair value is recorded in cost of products sold in the consolidated statements of operations.
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We manage a portion of our interest rate exposures by utilizing interest rate swaps and similar instruments. Certain of our interest rate derivatives are accounted for as either cash flow hedges or fair value hedges. For interest rate derivatives accounted for as either cash flow or fair value hedges, we report realized gains and losses and ineffectiveness portions of those hedges in interest expense. For interest rate derivatives not designated as hedges for accounting purposes, we report realized and unrealized gains and losses on those derivatives in “Gains (losses) on non-hedged interest rate derivatives” in the consolidated statements of operations. See Note 10 for additional information related to interest rate derivatives.
Pensions and Other Postretirement Benefit Plans
Employers are required to recognize in their balance sheets the overfunded or underfunded status of defined benefit pension and other postretirement plans, measured as the difference between the fair value of the plan assets and the benefit obligation (the projected benefit obligation for pension plans and the accumulated postretirement benefit obligation for other postretirement plans). Each overfunded plan is recognized as an asset and each underfunded plan is recognized as a liability. Employers must recognize the change in the funded status of the plan in the year in which the change occurs through AOCI in equity.
See Note 11 for additional related information.
Allocation of Income
For purposes of maintaining partner capital accounts, the Partnership Agreement specifies that items of income and loss shall generally be allocated among the partners in accordance with their percentage interests (see Note 6). Our net income for partners’ capital and statement of operations presentation purposes is allocated to the General Partner and Limited Partners in accordance with their respective partnership percentages, after giving effect to priority income allocations for incentive distributions, if any, to our General Partner, the holder of the incentive distribution rights (“IDRs”) pursuant to our Partnership Agreement, which are declared and paid following the close of each quarter. Earnings in excess of distributions are allocated to the General Partner and Limited Partners based on their respective ownership interests.
3. | ACQUISITIONS AND RELATED TRANSACTIONS: |
2013 Transactions
SUGS Contribution
On April 30, 2013, Southern Union completed its contribution to Regency of all of the issued and outstanding membership interest in Southern Union Gathering Company, LLC, and its subsidiaries, including SUGS (the “SUGS Contribution”). The general partner and IDRs of Regency are owned by ETE. The consideration paid by Regency in connection with this transaction consisted of (i) the issuance of approximately 31.4 million Regency common units to Southern Union, (ii) the issuance of approximately 6.3 million Regency Class F units to Southern Union, (iii) the distribution of $463 million in cash to Southern Union, net of closing adjustments, and (iv) the payment of $30 million in cash to a subsidiary of ETP. This transaction was between commonly controlled entities; therefore, the amounts recorded in the consolidated balance sheet for the investment in Regency and the related deferred tax liabilities were based on the historical book value of SUGS. In addition, PEPL Holdings, LLC, a wholly-owned subsidiary of Southern Union, provided a guarantee of collection with respect to the payment of the principal amounts of Regency’s debt related to the SUGS Contribution. The Regency Class F units have the same rights, terms and conditions as the Regency common units, except that Southern Union will not receive distributions on the Regency Class F units for the first eight consecutive quarters following the closing, and the Regency Class F units will thereafter automatically convert into Regency common units on a one-for-one basis. The Partnership has not presented SUGS as discontinued operations due to the expected continuing involvement with SUGS through affiliate relationships, as well as the direct investment in Regency common and Class F units received, which has been accounted for using the equity method.
Acquisition of ETE’s Holdco Interest
On April 30, 2013, ETP acquired ETE’s 60% interest in Holdco for approximately 49.5 million of newly issued ETP Common Units and $1.40 billion in cash, less $68 million of closing adjustments (the “Holdco Acquisition”). As a result, ETP now owns 100% of Holdco. ETE, which owns the general partner and IDRs of ETP, agreed to forego incentive distributions on the newly issued ETP units for each of the first eight consecutive quarters beginning with the quarter in which the closing of the transaction occurred and 50% of incentive distributions on the newly issued ETP units for the following eight consecutive quarters. ETP controlled Holdco prior to this acquisition; therefore, the transaction did not constitute a change of control.
Sale of Distribution Operations
Effective September 1, 2013, Southern Union completed its sale of the assets of MGE division to Laclede Gas Company for an aggregate purchase price of $975 million, subject to customary post-closing adjustments. The sale of Southern Union’s NEG division is expected to close in the fourth quarter of 2013 for cash proceeds of $40 million, subject to customary post-closing adjustments and the assumption of $20 million of debt.
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2012 Transactions
Southern Union Merger
On March 26, 2012, ETE completed its acquisition of Southern Union. Southern Union is the surviving entity in the merger and operates as a wholly-owned subsidiary of ETE. See below for discussion of Holdco Transaction and ETE’s contribution of Southern Union to Holdco.
Under the terms of the merger agreement, Southern Union stockholders received a total of 56,982,160 ETE Common Units and a total of approximately $3.01 billion in cash. Effective with the closing of the transaction, Southern Union’s common stock was no longer publicly traded.
Citrus Acquisition
In connection with the Southern Union Merger on March 26, 2012, we completed our acquisition of CrossCountry, a subsidiary of Southern Union which owned an indirect 50% interest in Citrus, the owner of FGT. The total merger consideration was approximately $2.0 billion, consisting of approximately $1.9 billion in cash and approximately 2.25 million ETP Common Units. See Note 4 for more information regarding our equity method investment in Citrus.
Sunoco Merger
On October 5, 2012, ETP completed its merger with Sunoco. Under the terms of the merger agreement, Sunoco shareholders received 55 million ETP Common Units and a total of approximately $2.6 billion in cash.
Sunoco generates cash flow from a portfolio of retail outlets for the sale of gasoline and middle distillates in the east coast, midwest and southeast areas of the United States. Prior to October 5, 2012, Sunoco also owned a 2% general partner interest, 100% of the IDRs, and 32% of the outstanding common units of Sunoco Logistics. As discussed below, on October 5, 2012, Sunoco’s interests in Sunoco Logistics were transferred to the Partnership.
Sunoco Logistics is a publicly traded limited partnership that owns and operates a logistics business consisting of a geographically diverse portfolio of complementary pipeline, terminalling and crude oil acquisition and marketing assets. The refined products pipelines business consists of refined products pipelines located in the northeast, midwest and southwest United States, and equity interests in refined products pipelines. The crude oil pipeline business consists of crude oil pipelines located principally in Oklahoma and Texas. The terminal facilities business consists of refined products and crude oil terminal capacity at the Nederland Terminal on the Gulf Coast of Texas and capacity at the Eagle Point terminal on the banks of the Delaware River in New Jersey. The crude oil acquisition and marketing business, principally conducted in Oklahoma and Texas, involves the acquisition and marketing of crude oil and consists of crude oil transport trucks and crude oil truck unloading facilities.
Prior to the Sunoco Merger, on September 8, 2012, Sunoco completed the exit from its Northeast refining operations by contributing the refining assets at its Philadelphia refinery and various commercial contracts to PES, a joint venture with The Carlyle Group. Sunoco also permanently idled the main refining processing units at its Marcus Hook refinery in June 2012. The Marcus Hook facility continued to support operations at the Philadelphia refinery prior to commencement of the PES joint venture. Under the terms of the joint venture agreement, The Carlyle Group contributed cash in exchange for a 67% controlling interest in PES. In exchange for contributing its Philadelphia refinery assets and various commercial contracts to the joint venture, Sunoco retained an approximate 30% non-operating noncontrolling interest. The fair value of Sunoco’s retained interest in PES, which was $75 million on the date on which the joint venture was formed, was determined based on the equity contributions of The Carlyle Group. Sunoco has indemnified PES for environmental liabilities related to the Philadelphia refinery that arose from the operation of such assets prior the formation of the joint venture. The Carlyle Group will oversee day-to-day operations of PES and the refinery. JPMorgan Chase will provide working capital financing to PES in the form of an asset-backed loan, supply crude oil and other feedstocks to the refinery at the time of processing and purchase certain blendstocks and all finished refined products as they are processed. Sunoco entered into a ten-year supply contract for gasoline and diesel produced at the refinery for its retail marketing business.
ETP incurred merger related costs related to the Sunoco Merger of $28 million during the year ended December 31, 2012. Sunoco’s revenue included in our consolidated statement of operations was approximately $5.93 billion during October through December 2012. Sunoco’s net loss included in our consolidated statement of operations was approximately $14 million during October through December 2012. Sunoco Logistics’ revenue included in our consolidated statement of operations was approximately $3.11 billion during October through December 2012. Sunoco Logistics’ net income included in our consolidated statement of operations was approximately $145 million during October through December 2012.
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Holdco Transaction
Immediately following the closing of the Sunoco Merger, ETE contributed its interest in Southern Union into Holdco, an ETP-controlled entity, in exchange for a 60% equity interest in Holdco. In conjunction with ETE’s contribution, ETP contributed its interest in Sunoco to Holdco and retained a 40% equity interest in Holdco. Prior to the contribution of Sunoco to Holdco, Sunoco contributed $2.0 billion of cash and its interests in Sunoco Logistics to ETP in exchange for 90,706,000 Class F Units representing limited partner interests in ETP (“Class F Units”). The Class F Units are entitled to 35% of the quarterly cash distribution generated by ETP and its subsidiaries other than Holdco, subject to a maximum cash distribution of $3.75 per Class F Unit per year, which is the current distribution level. Pursuant to a stockholders agreement between ETE and ETP, ETP controls Holdco. Consequently, ETP consolidated Holdco (including Sunoco and Southern Union) in its financial statements subsequent to consummation of the Holdco Transaction.
Under the terms of the Holdco transaction agreement, ETE agreed to relinquish its right to $210 million of incentive distributions from ETP that ETE would otherwise be entitled to receive over 12 consecutive quarters beginning with the distribution paid on November 14, 2012.
In accordance with GAAP, we have accounted for the Holdco Transaction, whereby ETP obtained control of Southern Union, as a reorganization of entities under common control. Accordingly, the consolidated financial statements have been retrospectively adjusted to reflect consolidation of Southern Union into ETP beginning March 26, 2012 (the date ETE acquired Southern Union).
Summary of Assets Acquired and Liabilities Assumed
We accounted for the Sunoco Merger using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date. Upon consummation of the Holdco Transaction, we applied the accounting guidance for transactions between entities under common control. Accordingly, we retrospectively consolidated Southern Union beginning on March 26, 2012, the date of the Southern Union Merger. In doing so, we recorded the values of assets and liabilities that had been recorded by ETE as reflected below.
The following table summarizes the assets acquired and liabilities assumed as of the respective acquisition dates:
Sunoco(1) | Southern Union(2) | |||||||
Total current assets | $ | 7,312 | $ | 556 | ||||
Property, plant and equipment | 6,686 | 6,242 | ||||||
Goodwill | 2,641 | 2,497 | ||||||
Intangible assets | 1,361 | 55 | ||||||
Investments in unconsolidated affiliates | 240 | 2,023 | ||||||
Note receivable | 821 | — | ||||||
Other assets | 128 | 163 | ||||||
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19,189 | 11,536 | |||||||
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Current liabilities | 4,424 | 1,348 | ||||||
Long-term debt obligations, less current maturities | 2,879 | 3,120 | ||||||
Deferred income taxes | 1,762 | 1,419 | ||||||
Other non-current liabilities | 769 | 284 | ||||||
Noncontrolling interest | 3,580 | — | ||||||
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13,414 | 6,171 | |||||||
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Total consideration | 5,775 | 5,365 | ||||||
Cash received | 2,714 | 37 | ||||||
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Total consideration, net of cash received | $ | 3,061 | $ | 5,328 | ||||
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(1) | Includes amounts recorded with respect to Sunoco Logistics. |
(2) | Includes ETP’s acquisition of Citrus. |
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As a result of the Holdco Transaction, we recognized $38 million of merger-related costs during the year ended December 31, 2012 related to Southern Union. Southern Union’s revenue included in our consolidated statement of operations was approximately $1.26 billion since the acquisition date to December 31, 2012. Southern Union’s net income included in our consolidated statement of operations was approximately $39 million since the acquisition date to December 31, 2012.
Propane Operations
On January 12, 2012, we contributed our propane operations, consisting of HOLP and Titan (collectively, the “Propane Business”) to AmeriGas. We received approximately $1.46 billion in cash and approximately 30 million AmeriGas common units. AmeriGas assumed approximately $71 million of existing HOLP debt. In connection with the closing of this transaction, we entered into a support agreement with AmeriGas pursuant to which we are obligated to provide contingent, residual support of $1.5 billion of intercompany indebtedness owed by AmeriGas to a finance subsidiary that in turn supports the repayment of $1.5 billion of senior notes issued by this AmeriGas finance subsidiary to finance the cash portion of the purchase price.
We have not reflected our Propane operations as discontinued operations as we will have a continuing involvement in this business as a result of the investment in AmeriGas that was transferred as consideration for the transaction.
Discontinued Operations
In October 2012, we sold Canyon for approximately $207 million. The results of continuing operations of Canyon have been reclassified to loss from discontinued operations. A write down of the carrying amounts of the Canyon assets to their fair values was recorded for approximately $132 million during the year ended December 31, 2012.
In December 2012, Southern Union entered into a purchase and sale agreement with the Laclede Entities, pursuant to which Laclede Missouri has agreed to acquire the assets of MGE division and Laclede Massachusetts has agreed to acquire the assets of the NEG division. Total consideration is expected to be $1.04 billion, subject to customary closing adjustments, less the assumption of approximately $19 million of debt. For the period from March 26, 2012 to December 31, 2012 the results of continuing operations of distribution operations have been reclassified to income from discontinued operations. The assets and liabilities of the disposal group have been reclassified and reported as assets and liabilities held for sale as of December 31, 2012.
In February 2013, The Laclede Group, Inc. entered into an agreement with Algonquin Power & Utilities Corp (“APUC”) that will allow a subsidiary of APUC to assume the rights of The Laclede Group, Inc. to purchase the assets of Southern Union’s NEG division, subject to certain approvals.
Below is selected financial information related to Southern Union’s distribution operations for the period from March 26, 2012 to December 31, 2012:
Revenue from discontinued operations | $ | 324 | ||
Net income of discontinued operations, excluding effect of taxes and overhead allocations | 43 |
The goodwill allocated to the disposal group was $133 million at December 31, 2012.
2011 Transactions
LDH Acquisition
On May 2, 2011, ETP-Regency Midstream Holdings, LLC (“ETP-Regency LLC”), a joint venture owned 70% by the Partnership and 30% by Regency Energy Partners LP (“Regency”), acquired all of the membership interest in LDH Energy Asset Holdings LLC (“LDH”), from Louis Dreyfus Highbridge Energy LLC (“Louis Dreyfus”) for approximately $1.98 billion in cash (the “LDH Acquisition”), including working capital adjustments. The Partnership contributed approximately $1.38 billion to ETP-Regency LLC to fund its 70% share of the purchase price. Subsequent to closing, ETP-Regency LLC was renamed Lone Star.
Lone Star owns and operates a natural gas liquids storage, fractionation and transportation business. Lone Star’s storage assets are primarily located in Mont Belvieu, Texas, and its West Texas Pipeline transports NGLs through an intrastate pipeline system that originates in the Permian Basin in west Texas, passes through the Barnett Shale production area in north Texas and terminates at the Mont Belvieu storage and fractionation complex. Lone Star also owns and operates fractionation and processing assets located in Louisiana. The acquisition of LDH by Lone Star expands the Partnership’s asset portfolio by adding an NGL platform with storage, transportation and fractionation capabilities.
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We accounted for the LDH Acquisition using the acquisition method of accounting. Lone Star’s results of operations are included in our NGL transportation and services operations. Regency’s 30% interest in Lone Star is reflected as noncontrolling interest.
2010 Transactions
In March 2010, we purchased a natural gas gathering company, which provides dehydration, treating, redelivery and compression services on a 120-mile pipeline system in the Haynesville Shale for approximately $150 million in cash, excluding certain adjustments as defined in the purchase agreement. In connection with this transaction, we recorded customer contracts of $68 million and goodwill of $27 million.
4. | ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES: |
Citrus Corp.
On March 26, 2012, ETE consummated the acquisition of Southern Union and, concurrently with the closing of the Southern Union acquisition, CrossCountry Energy, LLC (“CrossCountry”), a subsidiary of Southern Union that indirectly owned a 50% interest in Citrus Corp. (“Citrus”), merged with a subsidiary of ETP and, in connection therewith, ETP paid approximately $1.9 billion in cash and issued $105 million of ETP Common Units (the “Citrus Acquisition”) to a subsidiary of ETE. As a result of the consummation of the Citrus Acquisition, ETP owns CrossCountry, which in turn owns a 50% interest in Citrus. The other 50% interest in Citrus is owned by a subsidiary of Kinder Morgan, Inc.
Citrus owns 100% of FGT, a natural gas pipeline system that originates in Texas and delivers natural gas to the Florida peninsula.
We recorded our investment in Citrus at $2.0 billion, which exceeded our proportionate share of Citrus’ equity by $1.03 billion, all of which is treated as equity method goodwill due to the application of regulatory accounting. Our investment in Citrus was $1.98 billion as of December 31, 2012.
AmeriGas Partners, L.P.
On January 12, 2012, we contributed our propane operations, consisting of HOLP and Titan (collectively, the “Propane Business”) to AmeriGas. We received approximately $1.46 billion in cash and approximately 30 million AmeriGas Common Units valued at $1.12 billion at the time of the contribution. In addition, AmeriGas assumed approximately $71 million of existing HOLP debt. We recognized a gain on deconsolidation of $1.06 billion as a result of this transaction. The cash proceeds were used to complete our tender offer of existing debt (see Note 6) in January 2012 and to repay borrowings on our revolving credit facility.
Our investment in AmeriGas reflected $630 million in excess of our proportionate share of AmeriGas’ limited partners’ capital. Of this excess fair value, $289 million is being amortized over a weighted average period of 14 years, and $341 million is being treated as equity method goodwill and non-amortizable intangible assets.
In connection with the closing of this transaction, we entered into a support agreement with AmeriGas (See Note 10).
We have not reflected our Propane Business as discontinued operations as a result of our investment in AmeriGas.
In June 2012, we sold the remainder of our retail propane operations, consisting of our cylinder exchange business, to a third party. In connection with the contribution agreement with AmeriGas, certain excess sales proceeds from the sale of the cylinder exchange business were remitted to AmeriGas, and we received net proceeds of approximately $43 million.
Our investment in AmeriGas was $1.02 billion as of December 31, 2012.
FEP
We have a 50% interest in FEP, a 50/50 joint venture with Kinder Morgan Energy Partners, L.P. (“KMP”). FEP owns the Fayetteville Express pipeline, an approximately 185-mile natural gas pipeline that originate in Conway County, Arkansas, continues eastward through White County, Arkansas and terminates at an interconnect with Trunkline Gas Company in Panola County, Mississippi.
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Summarized Financial Information
The following tables present aggregated selected balance sheet and income statement data for our unconsolidated affiliates, FEP, AmeriGas and Citrus (on a 100% basis) for all periods presented:
December 31, | ||||||||
2012 | 2011 | |||||||
Current assets | $ | 878 | $ | 833 | ||||
Property, plant and equipment, net | 8,063 | 7,350 | ||||||
Other assets | 2,529 | 810 | ||||||
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Total assets | $ | 11,470 | $ | 8,993 | ||||
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Current liabilities | $ | 1,605 | $ | 1,491 | ||||
Non-current liabilities | 6,143 | 4,900 | ||||||
Equity | 3,722 | 2,602 | ||||||
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Total liabilities and equity | $ | 11,470 | $ | 8,993 | ||||
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Years Ended December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
Revenue | $ | 4,057 | $ | 3,337 | $ | 2,889 | ||||||
Operating income | 635 | 681 | 502 | |||||||||
Net income | 338 | 341 | 339 |
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5. | DEBT OBLIGATIONS: |
Our debt obligations consist of the following:
December 31, | ||||||||
2012 | 2011 | |||||||
ETP Debt | ||||||||
5.65% Senior Notes due August 1, 2012 | $ | — | $ | 400 | ||||
6.0% Senior Notes due July 1, 2013 | 350 | 350 | ||||||
8.5% Senior Notes due April 15, 2014 | 292 | 350 | ||||||
5.95% Senior Notes due February 1, 2015 | 750 | 750 | ||||||
6.125% Senior Notes due February 15, 2017 | 400 | 400 | ||||||
6.7% Senior Notes due July 1, 2018 | 600 | 600 | ||||||
9.7% Senior Notes due March 15, 2019 | 400 | 600 | ||||||
9.0% Senior Notes due April 15, 2019 | 450 | 650 | ||||||
4.65% Senior Notes due June 1, 2021 | 800 | 800 | ||||||
5.20% Senior Notes due February 1, 2022 | 1,000 | — | ||||||
6.625% Senior Notes due October 15, 2036 | 400 | 400 | ||||||
7.5% Senior Notes due July 1, 2038 | 550 | 550 | ||||||
6.05% Senior Notes due June 1, 2041 | 700 | 700 | ||||||
6.50% Senior Notes due February 1, 2042 | 1,000 | — | ||||||
ETP $2.5 billion Revolving Credit Facility due October 27, 2016 | 1,395 | 314 | ||||||
Other | — | 81 | ||||||
Unamortized premiums, discounts and fair value adjustments, net | (14 | ) | (2 | ) | ||||
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9,073 | 6,943 | |||||||
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Transwestern Debt | ||||||||
5.39% Senior Notes due November 17, 2014 | 88 | 88 | ||||||
5.54% Senior Notes due November 17, 2016 | 125 | 125 | ||||||
5.64% Senior Notes due May 24, 2017 | 82 | 82 | ||||||
5.36% Senior Notes due December 9, 2020 | 175 | 175 | ||||||
5.89% Senior Notes due May 24, 2022 | 150 | 150 | ||||||
5.66% Senior Notes due December 9, 2024 | 175 | 175 | ||||||
6.16% Senior Notes due May 24, 2037 | 75 | 75 | ||||||
Unamortized premiums, discounts and fair value adjustments, net | (1 | ) | (1 | ) | ||||
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869 | 869 | |||||||
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Southern Union Debt | ||||||||
7.60% Senior Notes due February 1, 2024 | 360 | — | ||||||
8.25% Senior Notes due November 14, 2029 | 300 | — | ||||||
7.20% Junior Subordinated Notes due November 1, 2066 | 600 | — | ||||||
Southern Union $700 million Revolving Credit Facility due May 20, 2016 | 210 | — | ||||||
Other | 7 | — | ||||||
Unamortized premiums, discounts and fair value adjustments, net | 49 | — | ||||||
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1,526 | — | |||||||
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Panhandle Debt | ||||||||
6.05% Senior Notes due August 15, 2013 | 250 | — | ||||||
6.20% Senior Notes due November 1, 2017 | 300 | — | ||||||
7.00% Senior Notes due June 15, 2018 | 400 | — | ||||||
8.125% Senior Notes due June 1, 2019 | 150 | — | ||||||
7.00% Senior Notes due July 15, 2029 | 66 | — | ||||||
Term Loan due February 23, 2015 (1.84% interest rate at December 31, 2012) | 455 | — | ||||||
Unamortized premiums, discounts and fair value adjustments, net | 136 | — | ||||||
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1,757 | — | |||||||
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Sunoco Debt | ||||||||
4.875% Senior Notes due October 15, 2014 | 250 | — | ||||||
9.625% Senior Notes due April 15, 2015 | 250 | — | ||||||
5.75% Senior Notes due January 15, 2017 | 400 | — | ||||||
9.00% Debentures due November 1, 2024 | 65 | — | ||||||
Other | 25 | — | ||||||
Unamortized premiums, discounts and fair value adjustments, net | 104 | — | ||||||
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1,094 | — | |||||||
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Sunoco Logistics Debt | ||||||||
8.75% Senior Notes due February 15, 2014 | 175 | — | ||||||
6.125% Senior Notes due May 15, 2016 | 175 | — | ||||||
5.50% Senior Notes due February 15, 2020 | 250 | — | ||||||
4.65% Senior Notes due February 15, 2022 | 300 | — | ||||||
6.85% Senior Notes due February 15, 2040 | 250 | — | ||||||
6.10% Senior Notes due February 15, 2042 | 300 | — | ||||||
Sunoco Logistics $200 million Revolving Credit Facility due August 21, 2013 | 26 | — | ||||||
Sunoco Logistics $35 million Revolving Credit Facility due April 30, 2015 | 20 | — | ||||||
Sunoco Logistics $350 million Revolving Credit Facility due August 22, 2016 | 93 | — | ||||||
Unamortized premiums, net of discounts and fair value adjustments | 143 | — | ||||||
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1,732 | — | |||||||
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Note Payable to ETE | 166 | — | ||||||
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16,217 | 7,812 | |||||||
Current maturities | (609 | ) | (424 | ) | ||||
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$ | 15,608 | $ | 7,388 | |||||
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The following table reflects future maturities of long-term debt for each of the next five years and thereafter. These amounts exclude $418 million in unamortized net premiums and fair value adjustments:
2013 | $ | 609 | ||
2014 | 973 | |||
2015 | 1,475 | |||
2016 | 1,999 | |||
2017 | 1,183 | |||
Thereafter | 9,561 | |||
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Total | $ | 15,800 | ||
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ETP as Co-Obligor of Sunoco Debt
In connection with the Sunoco Merger and Holdco Transaction, ETP became a co-obligor on approximately $965 million of aggregate principal amount of Sunoco’s existing senior notes and debentures.
ETP Senior Notes
The ETP Senior Notes were registered under the Securities Act of 1933 (as amended). The Partnership may redeem some or all of the ETP Senior Notes at any time, or from time to time, pursuant to the terms of the indenture and related indenture supplements related to the ETP Senior Notes. The balance is payable upon maturity. Interest on the ETP Senior Notes is paid semi-annually.
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The ETP Senior Notes are unsecured obligations of the Partnership and the obligation of the Partnership to repay the ETP Senior Notes is not guaranteed by any of the Partnership’s subsidiaries. As a result, the ETP Senior Notes effectively rank junior to any future indebtedness of ours or our subsidiaries that is both secured and unsubordinated to the extent of the value of the assets securing such indebtedness, and the ETP Senior Notes effectively rank junior to all indebtedness and other liabilities of our existing and future subsidiaries.
Transwestern Senior Notes
The Transwestern notes are payable at any time in whole or pro rata in part, subject to a premium or upon a change of control event or an event of default, as defined. The balance is payable upon maturity. Interest is paid semi-annually.
Southern Union Junior Subordinated Notes
Southern Union has interest rate swap agreements that effectively fix the interest rate applicable to the floating rate on $525 million of the $600 million Junior Subordinated Notes due 2066. The interest rate on the remaining notes is a variable rate based upon the three-month LIBOR rate plus 3.0175%. The balance of the variable rate portion of the Junior Subordinated Notes was $75 million at an effective interest rate of 3.32% at December 31, 2012.
Panhandle Term Loans
In February 2012, Southern Union refinanced LNG Holdings’ $455 million term loan due March 2012 with an unsecured three-year term loan facility due February 23, 2015, with LNG Holdings as borrower and PEPL and Trunkline LNG as guarantors and a floating interest rate tied to LIBOR plus a margin based on the rating of PEPL’s senior unsecured debt. The effective interest rate of PEPL’s term loan was 1.84% at December 31, 2012.
Senior Notes Offering
In January 2013, ETP completed a public offering of $800 million aggregate principal amount of our 3.6% Senior Notes due February 1, 2023 and $450 million aggregate principal amount of our 5.15% Senior Notes due February 1, 2043. We used the net proceeds of approximately $1.24 billion from this offering to repay borrowings outstanding under our revolving credit facility and for general partnership purposes.
In addition, in January 2013, Sunoco Logistics issued $350 million of 3.45% Senior Notes and $350 million of 4.95% Senior Notes (the “2023 and 2043 Senior Notes”), due January 2023 and January 2043, respectively. The terms and conditions of the 2023 and 2043 Senior Notes are comparable to those under Sunoco Logistics’ existing Senior Notes. The net proceeds of $691 million from the 2023 and 2043 Senior Notes were used to pay outstanding borrowings under the $350 million and $200 million Credit Facilities and for general partnership purposes.
In September 2013, ETP issued $700 million aggregate principal of 4.15% Senior Notes due October 2020, $350 million aggregate principal of 4.90% Senior Notes due February 2024 and $450 million aggregate principal of 5.95% Senior Notes due October 2043. ETP used the net proceeds of $1.47 billion from the offering to repay $455 million in borrowings outstanding under the term loan of Panhandle’s wholly owned subsidiary, Trunkline LNG Holdings, LLC, to repay borrowings outstanding under the ETP Credit Facility and for general partnership purposes.
Note Exchange
On June 24, 2013, ETP completed the exchange of approximately $1.09 billion total principal amount of Southern Union’s outstanding senior notes, comprising 77% of the principal amount of the 7.6% Senior Notes due 2024, 89% of the principal amount of the 8.25% Senior Notes due 2029 and 91% of the principal amount of the Junior Subordinated Notes due 2066. These notes were exchanged for new notes issued by ETP with the same coupon rates and maturity dates. In conjunction with this transaction, Southern Union entered into intercompany notes payable to ETP, which provide for the reimbursement by Southern Union of ETP’s payments under the newly issued notes.
Credit Facilities
ETP Credit Facility
The indebtedness under ETP’s revolving credit facility is unsecured and not guaranteed by any of the ETP’s subsidiaries and has equal rights to holders of our current and future unsecured debt. The indebtedness under the ETP Credit Facility has the same priority of payment as our other current and future unsecured debt.
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As of December 31, 2012, ETP had $1.40 billion outstanding under the ETP Credit Facility, and the amount available for future borrowings was $1.03 billion taking into account letters of credit of $72 million. The weighted average interest rate on the total amount outstanding as of December 31, 2012 was 1.71%.
ETP used approximately $2.0 billion of Sunoco’s cash on hand to partially fund the cash portion of the Sunoco Merger consideration. The remainder of the cash portion of the merger consideration, approximately $620 million, was funded with borrowings under the ETP Credit Facility.
On October 27, 2011, ETP amended and restated the ETP Credit Facility to, among other things, (i) allow for borrowings of up to $2.5 billion; (ii) extend the maturity date from July 20, 2012 to October 27, 2016 (which may be extended by one year with lender approval); (iii) allow for an increase in the size of the credit facility to $3.75 billion (subject to obtaining lender commitments for the additional borrowing capacity); and (iv) to adjust the interest rates and commitment fees to current market terms. Following this amendment and based on our current ratings, the interest margin for LIBOR rate loans is 1.50% and the commitment fee for unused borrowing capacity is 0.25%.
Southern Union Credit Facility
The Southern Union Credit Facility provides for a $700 million revolving credit facility which matures on May 20, 2016. Borrowings under the Southern Union Credit Facility are available for working capital, other general company purposes and letter of credit requirements. The interest rate and commitment fee under the Southern Union Credit Facility are calculated using a pricing grid, which is based on the credit ratings for Southern Union’s senior unsecured notes. The weighted average interest rate on the total amount outstanding as of December 31, 2012 was 1.84%.
On August 10, 2012, Southern Union entered into a First Amendment of the Southern Union Credit Facility. The amendment provides for, among other things, (i) a revision to the change of control definition to permit equity ownership of Southern Union by ETP or any direct subsidiaries of ETP in addition to ETE or any direct or indirect subsidiary of ETE; and (ii) a waiver of any potential default that may result from the Holdco Transaction.
Proceeds from the SUGS Contribution (see Note 3) were used to repay $240 million of borrowings under the Southern Union Credit Facility and the facility was terminated.
Sunoco Logistics Credit Facilities
Sunoco Logistics maintains two credit facilities to fund the Partnership’s working capital requirements, finance acquisitions and capital projects and for general partnership purposes. The credit facilities consist of a $350 million unsecured credit facility which expires in August 2016 (the “$350 million Credit Facility”) and a $200 million unsecured credit facility which expires in August 2013 (the “$200 million Credit Facility”). Outstanding borrowings under $350 million Credit Facility and $200 million Credit Facility were $93 million and $26 million, respectively, at December 31, 2012.
In May 2012, Sunoco Logistics’ West Texas Gulf entered into a $35 million revolving credit facility (the “$35 million Credit Facility”) which expires in April 2015. The facility is available to fund West Texas Gulf’s general corporate purposes including working capital and capital expenditures. Outstanding borrowings under this credit facility were $20 million at December 31, 2012.
Covenants Related to Our Credit Agreements
Covenants Related to ETP
The agreements relating to the ETP Senior Notes contain restrictive covenants customary for an issuer with an investment-grade rating from the rating agencies, which covenants include limitations on liens and a restriction on sale-leaseback transactions.
The credit agreement relating to the ETP Credit Facility contains covenants that limit (subject to certain exceptions) the Partnership’s and certain of the Partnership’s subsidiaries’ ability to, among other things:
• | incur indebtedness; |
• | grant liens; |
• | enter into mergers; |
• | dispose of assets; |
• | make certain investments; |
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• | make Distributions (as defined in such credit agreement) during certain Defaults (as defined in such credit agreement) and during any Event of Default (as defined in such credit agreement); |
• | engage in business substantially different in nature than the business currently conducted by the Partnership and its subsidiaries; |
• | engage in transactions with affiliates; and |
• | enter into restrictive agreements. |
The credit agreement relating to the ETP Credit Facility also contains a financial covenant that provides that the Leverage Ratio, as defined in the ETP Credit Facility, shall not exceed 5.0 to 1 as of the end of each quarter, with a permitted increase to 5.5 to 1 during a Specified Acquisition Period, as defined in the ETP Credit Facility.
The agreements relating to the Transwestern senior notes contain certain restrictions that, among other things, limit the incurrence of additional debt, the sale of assets and the payment of dividends and specify a maximum debt to capitalization ratio.
Failure to comply with the various restrictive and affirmative covenants of our revolving credit facilities could require us to pay debt balances prior to scheduled maturity and could negatively impact the Operating Companies’ ability to incur additional debt and/or our ability to pay distributions.
We were in compliance with all requirements, tests, limitations, and covenants related to our debt agreements as of December 31, 2012.
Covenants Related to Southern Union
Southern Union is not party to any lending agreement that would accelerate the maturity date of any obligation due to a failure to maintain any specific credit rating, nor would a reduction in any credit rating, by itself, cause an event of default under any of Southern Union’s lending agreements. Financial covenants exist in certain of Southern Union’s debt agreements that require Southern Union to maintain a certain level of net worth, to meet certain debt to total capitalization ratios and to meet certain ratios of earnings before depreciation, interest and taxes to cash interest expense. A failure by Southern Union to satisfy any such covenant would give rise to an event of default under the associated debt, which could become immediately due and payable if Southern Union did not cure such default within any permitted cure period or if Southern Union did not obtain amendments, consents or waivers from its lenders with respect to such covenants.
Southern Union’s restrictive covenants include restrictions on debt levels, restrictions on liens securing debt and guarantees, restrictions on mergers and on the sales of assets, capitalization requirements, dividend restrictions, cross default and cross-acceleration and prepayment of debt provisions. A breach of any of these covenants could result in acceleration of Southern Union’s debt and other financial obligations and that of its subsidiaries. Under the current credit agreements, the significant debt covenants and cross defaults are as follows:
• | Under the Southern Union Credit Facility, the ratio of consolidated funded debt to consolidated earnings before interest, taxes, depreciation and amortization, as defined therein, cannot exceed 5.25 times through December 31, 2012 and 5.00 times thereafter; |
• | Under the Southern Union Credit Facility, in the event Southern Union’s credit rating falls below investment grade, the ratio of consolidated earnings before interest, taxes, depreciation and amortization to consolidated interest expense, as defined therein, cannot be less than 2.00 times; and |
• | Under LNG Holding’s $455 million term loan, the ratio of consolidated funded debt to consolidated earnings before interest, taxes, depreciation and amortization, as defined therein, for Panhandle cannot exceed 5.00 times. |
In addition to the above financial covenants, Southern Union and/or its subsidiaries are subject to certain additional restrictions and covenants. These restrictions and covenants include limitations on additional debt at some of its subsidiaries; limitations on the use of proceeds from borrowing at some of its subsidiaries; limitations, in some cases, on transactions with its affiliates; limitations on the incurrence of liens; potential limitations on the abilities of some of its subsidiaries to declare and pay dividends and potential limitations on some of its subsidiaries to participate in Southern Union’s cash management program; and limitations on Southern Union’s ability to prepay debt.
Covenants Related to Sunoco Logistics
The $350 and $200 million Credit Facilities contain various covenants limiting the Partnership’s ability to incur indebtedness; grant certain liens; make certain loans, acquisitions and investments; make any material change to the nature of its business; or enter into a merger or sale of assets, including the sale or transfer of interests in the Operating Partnership’s subsidiaries. The credit facilities also limit the Partnership, on a rolling four-quarter basis, to a maximum total consolidated debt to consolidated EBITDA ratio, as defined in the underlying credit agreements, of 5.0 to 1, which can generally be increased to 5.5 to 1 during an acquisition period. The Partnership’s ratio of total debt to EBITDA was 2.0 to 1 at December 31, 2012, as calculated in accordance with the credit agreements.
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The $35 million Credit Facility limits West Texas Gulf, on a rolling four-quarter basis, to a minimum fixed charge coverage ratio, as defined in the underlying credit agreement. The ratio for the fiscal quarter ending December 31, 2012 shall not be less than 1.00 to 1. The minimum ratio fluctuates between 0.80 to 1 and 1.00 to 1 throughout the term of the revolver as specified in the credit agreement. In addition, the credit facility limits West Texas Gulf to a maximum leverage ratio of 2.00 to 1. West Texas Gulf’s fixed charge coverage ratio and leverage ratio were 1.29 to 1 and 0.62 to 1, respectively, at December 31, 2012.
6. | EQUITY: |
Limited Partner interests are represented by Class A Units and Class B Units that entitle the holders thereof to the rights and privileges specified in the Partnership Agreement. The Class B Units constitute a profits interest in ETP GP and will only receive allocations of income, gain, loss deduction and credit and their pro rata share of cash distributions from ETP GP attributable to the ownership of ETP’s IDRs. Under our Partnership Agreement, after giving effect to the special allocation of net income to our Class B Units for their profits interest, net income is allocated among the Partners as follows:
• | First, 100% to our General Partner, until the aggregate net income allocated to our General Partner for the current year and all previous years is equal to the aggregate net losses allocated to our General Partner for all previous years; |
• | Second, 99.99% to our Class A Limited Partners, in proportion to their relative allocation of net losses, and 0.01% to our General Partner until the aggregate net income allocated to our Class A Limited Partners and our General Partner for the current and all previous years is equal to the aggregate net losses allocated to our Class A Limited Partners and our General Partner for all previous years; and |
• | Third, 99.99% to our Class A Limited Partners, pro rata, and 0.01% to our General Partner. |
Common Unit Activity by ETP
The change in ETP Common Units was as follows:
Years Ended December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
Number of Common Units, beginning of period | 225.5 | 193.2 | 179.3 | |||||||||
Common Units issued in connection with public offerings | 15.5 | 29.4 | 20.7 | |||||||||
Common Units issued in connection with certain acquisitions | 57.4 | 0.1 | — | |||||||||
Common Units issued in connection with the Distribution Reinvestment Plan | 1.0 | 0.4 | — | |||||||||
Common Units issued in connection with the equity distribution program | 1.6 | 2.0 | 5.2 | |||||||||
Issuance of Common Units under equity incentive plans | 0.5 | 0.4 | 0.3 | |||||||||
Redemption of Common Units in connection with MEP Transaction | — | — | (12.3 | ) | ||||||||
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Number of Common Units, end of period | 301.5 | 225.5 | 193.2 | |||||||||
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ETP’s Common Units are registered under the Securities Exchange Act of 1934 (as amended) and are listed for trading on the NYSE. Each holder of an ETP Common Unit is entitled to one vote per unit on all matters presented to the ETP Limited Partners for a vote. In addition, if at any time any person or group (other than ETP’s General Partner and its affiliates) owns beneficially 20% or more of all ETP Common Units, any ETP Common Units owned by that person or group may not be voted on any matter and are not considered to be outstanding when sending notices of a meeting of ETP Unitholders (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under the Partnership Agreement. The ETP Common Units are entitled to distributions of Available Cash as described below under “Quarterly Distributions of Available Cash.”
ETP Class G Units
In April 2013, all of the outstanding ETP Class F Units, which were issued in connection with the Sunoco Merger, were exchanged for ETP Class G Units on a one-for-one basis. The Class G Units have terms that are substantially the same as the Class F Units, with the principal difference between the Class G Units and the Class F Units being that allocations of depreciation and amortization to the Class G Units for tax purposes are based on a predetermined percentage and are not contingent on whether ETP has net income or loss.
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ETP Class H Units
Pursuant to an Exchange and Redemption Agreement previously entered into between ETP, ETE and ETE Common Holdings, LLC, a wholly owned subsidiary of ETE (“ETE Holdings”), ETP redeemed and cancelled 50.2 million of its common units representing limited partner interests (the “Redeemed Units”) owned by ETE Holdings on October 31, 2013 in exchange for the issuance by ETP to ETE Holdings of a new class of limited partner interest in ETP (the “Class H Units”), which are generally entitled to (i) allocations of profits, losses and other items from ETP corresponding to 50.05% of the profits, losses, and other items allocated to ETP by Sunoco Partners LLC (“Sunoco Partners”), the general partner of Sunoco Logistics, with respect to the IDRs and general partner interest in Sunoco Logistics held by Sunoco Partners, (ii) distributions from available cash at ETP for each quarter equal to 50.05% of the cash distributed to ETP by Sunoco Partners with respect to the IDRs and general partner interest in Sunoco Logistics held by Sunoco Partners for such quarter and, to the extent not previously distributed to holders of the Class H Units, for any previous quarters and (iii) incremental additional cash distributions in the aggregate amount of $329 million, to be payable by ETP to ETE Holdings over 15 quarters, commencing with the quarter ended September 30, 2013 and ending with the quarter ending March 31, 2017. The incremental cash distributions referred to in clause (iii) of the previous sentence are intended to offset a portion of the IDR subsidies previously granted by ETE to ETP in connection with the Citrus Merger, the Holdco Transaction and the Holdco Acquisition. In connection with the issuance of the Class H Units, ETE and ETP also agreed to certain adjustments to the prior IDR subsidies in order to ensure that the IDR subsidies are fixed amounts for each quarter to which the IDR subsidies are in effect. For a summary of the net IDR subsidy amounts resulting from this transaction, see “ETP’s Quarterly Distributions of Available Cash” below.
Sale of Common Units by ETP
The following table summarizes ETP’s public offerings of Common Units, all of which have been registered under the Securities Act of 1933 (as amended):
Date | Number of Common Units(1) | Price per Unit | Net Proceeds | Use of Proceeds | ||||||||||
January 2010 | 9.8 | $ | 44.72 | $ | 424 | (2)(3) | ||||||||
August 2010 | 10.9 | 46.22 | 489 | (2)(3) | ||||||||||
April 2011 | 14.2 | 50.52 | 695 | (3) | ||||||||||
November 2011 | 15.2 | 44.67 | 660 | (2)(3) | ||||||||||
July 2012 | 15.5 | 44.57 | 671 | (2)(3) | ||||||||||
April 2013 | 13.8 | 48.08 | 657 | (2)(3) |
(1) | Number of ETP Common Units includes the exercise of the overallotment options by the underwriters. |
(2) | Proceeds were used to repay amounts outstanding under the ETP Credit Facility. |
(3) | Proceeds were used to fund capital expenditures and capital contributions to joint ventures, and for general partnership purposes. |
ETP’s Equity Distribution Program
From time to time, ETP has sold ETP Common Units through an equity distribution agreement. Such sales of ETP Common Units are made by means of ordinary brokers’ transactions on the NYSE at market prices, in block transactions or as otherwise agreed between ETP and the sales agent which is the counterparty to the equity distribution agreement. In January 2013 and May 2013, ETP entered into equity distribution agreements pursuant to which we may sell from time to time Common Units having aggregate offering prices of up to $200 million and $800 million, respectively. Under the terms of the agreements, ETP may also sell ETP Common Units to Merrill Lynch, Pierce, Fenner & Smith Incorporated (“BofA Merrill Lynch”). BofA Merrill Lynch as principal for its own account at a price agreed upon at the time of sale. Any sale of ETP Common Units to BofA Merrill Lynch as principal would be pursuant to the terms of a separate agreement between ETP and BofA Merrill Lynch.
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Quarterly Distribution of Available Cash
Our distributions policy is consistent with the terms of the Partnership Agreement, which require that we distribute all of our available cash quarterly. Our only cash-generating assets consist of partnership interests, including IDRs, from which we receive quarterly distributions from ETP. We have no independent operations outside of our interests in ETP. Under the Partnership Agreement, our distributions are characterized as the GP Distribution Amount and the IDR Distribution Amount. The GP Distribution Amount is all distributions we receive from ETP with respect to our General Partner Interest and the IDR Distribution Amount is all distributions received from ETP with respect to the IDR. Within 45 days following the end of each quarter, we will distribute all of our GP Available Cash and IDR Available Cash, as defined in the Partnership Agreement. GP Available Cash shall be distributed 99.99% to the Class A Limited Partners, pro rata and 0.01% to the General partner. IDR Available Cash shall be distributed 99.99% to the Class B Limited Partners, pro rata and 0.01% to the General Partner.
ETP GP has the right, in connection with the issuance of any equity security by ETP, to purchase equity securities on the same terms as these equity securities are issued to third parties sufficient to enable ETP GP and its affiliates to maintain the aggregate percentage equity interest in ETP as ETP GP and its affiliates owned immediately prior to such issuance.
Contributions to Subsidiary
In order to maintain our general partner interest in ETP, ETP GP has previously been required to make contributions to ETP each time ETP issues limited partner interests for cash or in connection with acquisitions. These contributions are generally paid by offsetting the required contributions against the funds ETP GP receives from ETP distributions on the general partner and limited partner interests owned by ETP GP.
In July 2009, ETP amended and restated its partnership agreement, and as a result, ETP GP is no longer required to make corresponding contributions to maintain its general partner interest in ETP.
ETP’s Quarterly Distributions of Available Cash
ETP’s Partnership Agreement requires that ETP distribute all of its Available Cash to its Unitholders and its General Partner within forty-five days following the end of each fiscal quarter, subject to the payment of incentive distributions to the holders of IDRs to the extent that certain target levels of cash distributions are achieved. The term Available Cash generally means, with respect to any of ETP’s fiscal quarters, all cash on hand at the end of such quarter, plus working capital borrowings after the end of the quarter, less reserves established by the ETP General Partner (ETP GP) in its sole discretion to provide for the proper conduct of ETP’s business, to comply with applicable laws or any debt instrument or other agreement, or to provide funds for future distributions to partners with respect to any one or more of the next four quarters. Available Cash is more fully defined in the ETP Partnership Agreement.
ETP’s distributions of Available Cash from operating surplus, excluding incentive distributions, to our General Partner and Limited Partner interests are based on their respective interests as of the distribution record date. Incentive distributions allocated to the General Partner are determined based on the amount by which quarterly distribution to ETP common Unitholders exceed certain specified target levels, as set forth in the ETP Partnership Agreement.
ETP distributions declared during the periods presented below are summarized as follows:
Quarter Ended | Record Date | Payment Date | Rate | |||||
September 30, 2012 | November 6, 2012 | November 14, 2012 | $ | 0.89375 | ||||
June 30, 2012 | August 6, 2012 | August 14, 2012 | 0.89375 | |||||
March 31, 2012 | May 4, 2012 | May 15, 2012 | 0.89375 | |||||
December 31, 2011 | February 7, 2012 | February 14, 2012 | 0.89375 | |||||
September 30, 2011 | November 4, 2011 | November 14, 2011 | $ | 0.89375 | ||||
June 30, 2011 | August 5, 2011 | August 15, 2011 | 0.89375 | |||||
March 31, 2011 | May 6, 2011 | May 16, 2011 | 0.89375 | |||||
December 31, 2010 | February 7, 2011 | February 14, 2011 | 0.89375 | |||||
September 30, 2010 | November 8, 2010 | November 15, 2010 | $ | 0.89375 | ||||
June 30, 2010 | August 9, 2010 | August 16, 2010 | 0.89375 | |||||
March 31, 2010 | May 7, 2010 | May 17, 2010 | 0.89375 | |||||
December 31, 2009 | February 8, 2010 | February 15, 2010 | 0.89375 |
On January 28, 2013, ETP declared a cash distribution for the three months ended December 31, 2012 of $0.89375 per ETP Common Unit. ETP paid this distribution on February 14, 2013 to Unitholders of record at the close of business on February 7, 2013.
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On April 24, 2013, ETP declared a cash distribution for the three months ended March 31, 2013 of $0.89375 per ETP Common Unit. ETP paid this distribution on May 15, 2013 to Unitholders of record at the close of business on May 6, 2013.
On July 25, 2013, ETP declared a cash distribution for the three months ended June 30, 2013 of $0.89375 per ETP Common Unit. ETP paid this distribution on August 14, 2013 to Unitholders of record at the close of business on August 5, 2013.
On October 23, 2013, ETP declared a cash distribution for the three months ended September 30, 2013 of $0.90500 per ETP Common Unit, payable on November 14, 2013 to Unitholders of record at the close of business on November 4, 2013.
Following are incentive distributions ETE has agreed to relinquish:
• | In conjunction with the Partnership’s Citrus Merger, ETE agreed to relinquish its rights to $220 million of incentive distributions from ETP that ETE would otherwise be entitled to receive over 16 consecutive quarters beginning with the distribution paid on May 15, 2012. |
• | In conjunction with the Holdco Transaction in October 2012, ETE agreed to relinquish its right to $210 million of incentive distributions from ETP that ETE would otherwise be entitled to receive over 12 consecutive quarters beginning with the distribution paid on November 14, 2012. |
• | As discussed in Note 3, in connection with the Holdco Acquisition on April 30, 2013, ETE also agreed to relinquish incentive distributions on the newly issued Common Units for the first eight consecutive quarters beginning with the distribution paid on August 14, 2013, and 50% of the incentive distributions for the following eight consecutive quarters. |
• | As discussed under “Class H Units” above, ETP has agreed to make incremental cash distributions in the aggregate amount of $329 million to ETE Holdings over 15 quarters, commencing with the quarter ended September 30, 2013 and ending with the quarter ending March 31, 2017, in respect of the Class H units as a means to offset prior IDR subsidies that ETE agreed to in connection with the Citrus Merger, the Holdco Transaction and the Holdco Acquisition. |
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As a result, the net IDR subsidies from ETE, taking into account the incremental cash distributions related to the Class H units as an offset thereto, will be the amounts set forth in the table below:
Quarters Ending | ||||||||||||||||||||
March 31 | June 30 | September 30 | December 31 | Total Year | ||||||||||||||||
2013 | N/A | N/A | $ | 21.00 | $ | 21.00 | $ | 42.00 | ||||||||||||
2014 | $ | 27.25 | $ | 27.25 | 27.25 | 27.25 | 109.00 | |||||||||||||
2015 | 13.25 | 13.25 | 13.25 | 13.25 | 53.00 | |||||||||||||||
2016 | 5.50 | 5.50 | 5.50 | 5.50 | 22.00 |
Sunoco Logistics Quarterly Distributions of Available Cash
Following are distributions declared and/or paid by Sunoco Logistics subsequent to December 31, 2012:
Quarter Ended | Record Date | Payment Date | Rate | |||||
December 31, 2012 | February 8, 2013 | February 14, 2013 | $ | 0.54500 | ||||
March 31, 2013 | May 9, 2013 | May 15, 2013 | 0.57250 | |||||
June 30, 2013 | August 8, 2013 | August 14, 2013 | 0.60000 | |||||
September 30, 2013 | November 8, 2013 | November 14, 2013 | 0.63000 |
Accumulated Other Comprehensive Income (Loss)
The following table presents the components of AOCI, net of tax:
December 31, | ||||||||
2012 | 2011 | |||||||
Net gains on commodity related hedges | $ | — | $ | 6 | ||||
Actuarial loss related to pensions and other postretirement benefits | (10 | ) | — | |||||
Equity investments, net | (9 | ) | — | |||||
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Subtotal | (19 | ) | 6 | |||||
Amounts attributable to noncontrolling interest | 19 | (6 | ) | |||||
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Total AOCI, net of tax | $ | — | $ | — | ||||
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7. | UNIT-BASED COMPENSATION PLANS: |
ETP Unit-Based Compensation Plan
ETP has issued equity incentive plans for employees, officers and directors, which provide for various types of awards, including options to purchase ETP Common Units, restricted units, phantom units, distribution equivalent rights (“DERs”), Common Unit appreciation rights, and other unit-based awards. As of December 31, 2012, an aggregate total of 2,815,982 ETP Common Units remain available to be awarded under its equity incentive plans.
ETP Unit Grants
ETP has granted restricted unit awards to employees that vest over a specified time period, typically a 5-year period at 20% per year, with vesting contingent on continued employment as of each applicable vesting date. Upon vesting, ETP Common Units are issued. These unit awards entitle the recipients of the unit awards to receive, with respect to each Common Unit subject to such award that has not either vested or been forfeited, a cash payment equal to each cash distribution per Common Unit made by ETP on the Common Units promptly following each such distribution to the Unitholders. These rights are called “distribution equivalent rights.”
Under the equity incentive plans, ETP non-employee directors each receive grants that vest ratably over three years and do not entitle the holders to receive distributions during the vesting period.
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Award Activity
The following table shows the activity of the awards granted to employees and non-employee directors:
Number of Units | Weighted Average Grant-Date Fair Value Per Unit | |||||||
Unvested awards as of December 31, 2011 | 2.5 | $ | 46.37 | |||||
Awards granted | 0.3 | 43.93 | ||||||
Awards vested | (0.6 | ) | 44.58 | |||||
Awards forfeited | (0.3 | ) | 44.58 | |||||
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Unvested awards as of December 31, 2012 | 1.9 | 46.95 | ||||||
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During the years ended December 31, 2012, 2011 and 2010, the weighted average grant-date fair value per unit award granted was $43.93, $48.35 and $49.82, respectively. The total fair value of awards vested was $29 million, $27 million and $17 million, respectively based on the market price of ETP Common Units as of the vesting date. As of December 31, 2012, a total of 1,859,159 unit awards remain unvested, for which ETP expects to recognize a total of $51 million in compensation expense over a weighted average period of 1.76 years.
Sunoco Logistics’ Unit-Based Compensation Plan
Sunoco Logistics’ general partner has a long-term incentive plan for employees and directors, which permits the grant of restricted units and unit options of Sunoco Logistics covering an additional 0.9 million Sunoco common units. As of December 31, 2012, a total of 427,610 Sunoco Logistics restricted units were outstanding for which Sunoco Logistics expects to recognize $10 million of expense over a weighted-average period of 2.5 years.
Related Party Awards
McReynolds Energy Partners, L.P., the general partner of which is owned and controlled by the President of the entity that indirectly owns our general partner, awarded to certain officers of ETP certain rights related to units of ETE previously issued by ETE to such ETE officer. These rights include the economic benefits of ownership of these ETE units based on a 5 year vesting schedule whereby the officer will vest in the ETE units at a rate of 20% per year. As these ETE units are conveyed to the recipients of these awards upon vesting from a partnership that is not owned or managed by ETE or ETP, none of the costs related to such awards are paid by ETP or ETE unless this partnership defaults under its obligations pursuant to these unit awards. As these units were outstanding prior to these awards, these awards do not represent an increase in the number of outstanding units of either ETP or ETE and are not dilutive to cash distributions per unit with respect to either ETP or ETE.
We recognize non-cash compensation expense over the vesting period based on the grant-date fair value of the ETE units awarded the ETP employees assuming no forfeitures. For the years ended December 31, 2012, 2011 and 2010, we recognized non-cash compensation expense, net of forfeitures, of $1 million, $2 million and $4 million, respectively, as a result of these awards. As of December 31, 2012, rights related to 90,000 ETE common units remain outstanding, for which we expect to recognize a total of less than $1 million in compensation expense over a weighted average period of 0.61 years.
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8. | INCOME TAXES: |
As a partnership, we are not subject to U.S. federal income tax and most state income taxes. However, the partnership conducts certain activities through corporate subsidiaries which are subject to federal and state income taxes. The components of the federal and state income tax expense (benefit) are summarized as follows:
Years Ended December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
Current expense (benefit): | ||||||||||||
Federal | $ | (3 | ) | $ | (1 | ) | $ | 1 | ||||
State | 4 | 16 | 9 | |||||||||
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Total | 1 | 15 | 10 | |||||||||
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Deferred expense: | ||||||||||||
Federal | 45 | 4 | 6 | |||||||||
State | 17 | — | — | |||||||||
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Total | 62 | 4 | 6 | |||||||||
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Total income tax expense from continuing operations | $ | 63 | $ | 19 | $ | 16 | ||||||
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Historically, our effective rate differed from the statutory rate primarily due to Partnership earnings that are not subject to U.S. federal and most state income taxes at the Partnership level. The completion of the Southern Union, Sunoco and Holdco transactions (see Note 3) significantly increased the activities conducted through corporate subsidiaries. A reconciliation of income tax expense (benefit) at the U.S. statutory rate to the income tax expense (benefit) attributable to continuing operations for the year ended December 31, 2012 is as follows:
Holdco(1) | Other Corporate Subsidiaries(2) | Partnership(3) | Consolidated | |||||||||||||
Income tax expense (benefit) at U.S. statutory rate of 35 percent | $ | (1 | ) | $ | 2 | $ | — | $ | 1 | |||||||
Increase (reduction) in income taxes resulting from: | ||||||||||||||||
Nondeductible executive compensation | 28 | — | — | 28 | ||||||||||||
State income taxes (net of federal income tax effects) | 9 | — | 7 | 16 | ||||||||||||
Other | 17 | 1 | — | 18 | ||||||||||||
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Income tax income from continuing operations | $ | 53 | $ | 3 | $ | 7 | $ | 63 | ||||||||
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(1) | Holdco, which was formed via the Sunoco Merger and the Holdco transactions (see Note 3), includes Sunoco and Southern Union and their subsidiaries. |
(2) | Includes Oasis Pipeline Company, Inland Corporation, Mid-Valley Pipeline Company and West Texas Gulf Pipeline Company. The latter three entities were acquired in the Sunoco transaction. |
(3) | Includes ETP and its subsidiaries that are classified as pass-through entities for federal income tax purposes. |
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Deferred taxes result from the temporary differences between financial reporting carrying amounts and the tax basis of existing assets and liabilities. The table below summarizes the principal components of the deferred tax assets (liabilities) as follows:
December 31, | ||||||||
2012 | 2011 | |||||||
Deferred income tax assets: | ||||||||
Net operating losses and alternative minimum tax credit | $ | 268 | $ | 3 | ||||
Pension and other postretirement benefits | 127 | — | ||||||
Long term debt | 117 | — | ||||||
Other | 288 | 2 | ||||||
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Total deferred income tax assets | 800 | 5 | ||||||
Valuation allowance | (90 | ) | — | |||||
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Net deferred income tax assets | 710 | 5 | ||||||
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Deferred income tax liabilities: | ||||||||
Properties, plants and equipment | (1,938 | ) | (55 | ) | ||||
Inventory | (516 | ) | — | |||||
Investment in unconsolidated affiliates | (1,542 | ) | (72 | ) | ||||
Trademarks | (192 | ) | — | |||||
Other | (128 | ) | (1 | ) | ||||
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Total deferred income tax liabilities | (4,316 | ) | (128 | ) | ||||
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Net deferred income tax liability | (3,606 | ) | (123 | ) | ||||
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Less: current portion of deferred income tax assets (liabilities) | (130 | ) | 3 | |||||
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Accumulated deferred income taxes | $ | (3,476 | ) | $ | (126 | ) | ||
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The completion of the Southern Union, Sunoco and Holdco transactions (see Note 3) significantly increased the deferred tax assets (liabilities). The table below provides a rollforward of the net deferred income tax liability as follows:
December 31, | ||||
2012 | ||||
Net deferred income tax liability, beginning of year | $ | (123 | ) | |
Southern Union acquisition | (1,420 | ) | ||
Sunoco acquisition | (1,989 | ) | ||
Tax provision (including discontinued operations) | (73 | ) | ||
Other | (1 | ) | ||
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Net deferred income tax liability | $ | (3,606 | ) | |
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Holdco and other corporate subsidiaries have gross federal net operating loss carryforwards of $362 million, of which $18 million, $40 million and $304 million will expire in 2030, 2031 and 2032, respectively. Holdco has $37 million of federal alternative minimum tax credits which do not expire. Holdco and other corporate subsidiaries have state net operating loss carryforward benefits of $104 million, net of federal tax, which expire between 2013 and 2032. The valuation allowance of $90 million is applicable to the state net operating loss carryforward benefits applicable to Sunoco pre-acquisition periods.
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The following table sets forth the changes in unrecognized tax benefits:
Years Ended December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
Balance at beginning of year | $ | 2 | $ | 2 | $ | 1 | ||||||
Additions attributable to acquisitions | 28 | — | — | |||||||||
Additions attributable to tax positions taken in the current year | — | 1 | — | |||||||||
Additions attributable to tax positions taken in prior years | — | — | 1 | |||||||||
Settlements | — | (1 | ) | — | ||||||||
Lapse of statute | (3 | ) | — | — | ||||||||
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Balance at end of year | $ | 27 | $ | 2 | $ | 2 | ||||||
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As of December 31, 2012, we have $24 million ($16 million after federal income tax benefits) related to tax positions which, if recognized, would impact our effective tax rate. We believe it is reasonably possible that its unrecognized tax benefits may be reduced by $5 million ($3 million, net of federal tax) within the next twelve months due to settlement of certain positions.
Our policy is to accrue interest expense and penalties on income tax underpayments (overpayments) as a component of income tax expense. During 2012, we recognized interest and penalties of less than $1 million. At December 31, 2012, we have interest and penalties accrued of $5 million, net of tax.
In general, ETP and its subsidiaries are no longer subject to examination by the Internal Revenue Service for tax years prior to 2009, except Sunoco and Southern Union which are no longer subject to examination by the IRS for tax years prior to 2007 and 2004, respectively.
Sunoco has been examined by the IRS for the 2007 and 2008 tax years, however, the statutes remain open for both of these tax years due to carryback of net operating losses. Southern Union is under examination for the tax years 2004 through 2009. As of December 31, 2012, the IRS has proposed only one adjustment for the years under examination. For the 2006 tax year, the IRS is challenging $545 million of the $690 million of deferred gain associated with a like kind exchange involving certain assets of its distribution operations and its gathering and processing operations. We will vigorously defend and believe Southern Union’s tax position will prevail against this challenge by the IRS. Accordingly, no unrecognized tax benefit has been recorded with respect to this tax position.
ETP and its subsidiaries also have various state and local income tax returns in the process of examination or administrative appeal in various jurisdictions. We believe the appropriate accruals or unrecognized tax benefits have been recorded for any potential assessment with respect to these examinations.
Sunoco has historically included certain government incentive payments as taxable income on its federal and state income tax returns. In connection with Sunoco’s 2004 through 2011 open statute years, Sunoco has proposed to the Internal Revenue Service (“IRS”) that these government incentive payments be excluded from federal taxable income. A successful claim could result in significant tax refunds for multiple years. However, a thorough evaluation of the ultimate financial impact to Sunoco is complex and requires significant analysis, including the ramifications of tax indemnification agreements with certain former Sunoco affiliates which were members of Sunoco’s consolidated federal return group during these years. At this time, a benefit for the claim is not estimable and has not been recorded in the financial statements.
9. | REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES: |
Southern Union and its Subsidiaries
The FERC is currently conducting an audit of PEPL, a subsidiary of Southern Union, to evaluate its compliance with the Uniform System of Accounts as prescribed by the FERC, annual and quarterly financial reporting to the FERC, reservation charge crediting policy and record retention. The audit is related to the period from January 1, 2010 through December 31, 2011 and is pending the issuance of a draft audit report.
Contingent Matters Potentially Impacting the Partnership from Our Investment in Citrus
Florida Gas Pipeline Relocation Costs. The Florida Department of Transportation, Florida’s Turnpike Enterprise (“FDOT/FTE”) has various turnpike/State Road 91 widening projects that have impacted or may, over time, impact one or more of FGTs’ mainline pipelines located in FDOT/FTE rights-of-way. Several FDOT/FTE projects are the subject of
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litigation in Broward County, Florida. On January 27, 2011, a jury awarded FGT $83 million and rejected all damage claims by the FDOT/FTE. On May 2, 2011, the judge issued an order entitling FGT to an easement of 15 feet on either side of its pipelines and 75 feet of temporary work space. The judge further ruled that FGT is entitled to approximately $8 million in interest. In addition to ruling on other aspects of the easement, he ruled that pavement could not be placed directly over FGTs’ pipeline without the consent of FGT, although FGT would be required to relocate the pipeline if it did not provide such consent. While FGT would seek reimbursement of any costs associated with relocation of its pipeline in connection with an FDOT project, FGT may not be successful in obtaining such reimbursement and, as such, could be required to bear the cost of such relocation. In any such instance, FGT would seek recovery of the reimbursement costs in rates. The judge also denied all other pending post-trial motions. The FDOT/FTE filed a notice of appeal on July 12, 2011. On June 6, 2012, Florida’s Fourth District Court of Appeal (“4th DCA”) issued an opinion affirming the jury award of damages and also affirming or remanding for further consideration by the trial court certain other determinations with respect to FGT’s easement rights and FDOT/FTE’s obligations regarding future FDOT/FTE projects. In particular, the 4th DCA affirmed that FDOT/FTE could not pave directly over our pipeline without FGTs’ consent and remanded and directed the trial court to make reference in the final judgment to FDOT/FTE’s obligation to seek reasonable alternatives to relocation. In addition, the 4th DCA overturned the portion of the trial court judgment defining the width of Florida Gas’s easements as 15 feet on either side of its pipelines and defining the temporary work space available to Florida Gas under its easements as 75 feet in width, stating that the width of such easements and temporary work space should be determined on a case by case basis dependent on the needs of each particular relocation and whether a road improvement is a material interference with the easement. Reimbursement for any future relocation expenses will also be determined on a case by case basis. As a result of the decision by the 4th DCA affirming the monetary award of the judgment and the trial court’s November 7, 2012 issuance of a peremptory writ of mandamus, FDOT paid to FGT on November 16, 2012 the sum of $100 million, representing the amount of judgment plus interest through that date. The amounts received reduced FGTs’ property, plant and equipment costs. FGT previously filed a petition requesting the Supreme Court of Florida to exercise its discretionary jurisdiction and to reverse the portion of the 4th DCA decision overturning the trial court judgment specifically defining the width of FGTs’ easements and temporary work space. By order dated December 28, 2012, the Supreme Court of Florida denied that petition.
Contingent Residual Support Agreement — AmeriGas
In order to finance the cash portion of the purchase price of the Propane Transaction described in Note 3, AmeriGas Finance LLC (“Finance Company”), a wholly owned subsidiary of AmeriGas, issued $550 million in aggregate principal amount of 6.75% senior notes due 2020 and $1.0 billion in aggregate principal amount of 7.00% senior notes due 2022. AmeriGas borrowed $1.5 billion of the proceeds of the Senior Notes issuance from Finance Company through an intercompany borrowing having maturity dates and repayment terms that mirror those of the Senior Notes (the “Supported Debt”).
In connection with the closing of the Propane Transaction, ETP entered into and delivered a Contingent Residual Support Agreement (“CRSA”) with AmeriGas, Finance Company, AmeriGas Finance Corp. and UGI Corp., pursuant to which ETP will provide contingent, residual support of the Supported Debt as defined in the CRSA.
NGL Pipeline Regulation
We have interests in NGL pipelines located in Texas. We believe that these pipelines do not provide interstate service and that they are thus not subject to the jurisdiction of the FERC under the Interstate Commerce Act (“ICA”) and the Energy Policy Act of 1992. Under the ICA, tariffs must be just and reasonable and not unduly discriminatory or confer any undue preference. We cannot guarantee that the jurisdictional status of our NGL facilities will remain unchanged; however, should they be found jurisdictional, the FERC’s rate-making methodologies may limit our ability to set rates based on our actual costs, may delay or limit the use of rates that reflect increased costs and may subject us to potentially burdensome and expensive operational, reporting and other requirements. Any of the foregoing could adversely affect our business, revenues and cash flow.
Commitments
In the normal course of our business, we purchase, process and sell natural gas pursuant to long-term contracts and we enter into long-term transportation and storage agreements. Such contracts contain terms that are customary in the industry. We believe that the terms of these agreements are commercially reasonable and will not have a material adverse effect on our financial position or results of operations.
We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments and expire at various dates through 2056. Rental expense under these operating leases has been included in operating expenses in the accompanying statements of operations and totaled approximately $57 million, $26 million and $21 million for the years ended December 31, 2012, 2011 and 2010, respectively, which include contingent rentals totaling $6 million in 2012. During the three months ended December 31, 2012, approximately $4 million of rental expense was recovered through related sublease rental income.
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Future minimum lease commitments for such leases are:
Years Ending December 31: | ||||
2013 | $ | 90 | ||
2014 | 80 | |||
2015 | 77 | |||
2016 | 63 | |||
2017 | 52 | |||
Thereafter | 460 | |||
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Future minimum lease commitments | 822 | |||
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Less: Sublease rental income | (64 | ) | ||
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Net future minimum lease commitments | $ | 758 | ||
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Amounts reflected above do not include future minimum lease commitments for the Southern Union distribution operations, which were reclassified and reported as assets and liabilities held for sale at December 31, 2012 as described in Note 3.
Our joint venture agreements require that we fund our proportionate share of capital contributions to our unconsolidated affiliates. Such contributions will depend upon our unconsolidated affiliates’ capital requirements, such as for funding capital projects or repayment of long-term obligations.
Litigation and Contingencies
We may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business. Natural gas and crude are flammable and combustible. Serious personal injury and significant property damage can arise in connection with their transportation, storage or use. In the ordinary course of business, we are sometimes threatened with or named as a defendant in various lawsuits seeking actual and punitive damages for product liability, personal injury and property damage. We maintain liability insurance with insurers in amounts and with coverage and deductibles management believes are reasonable and prudent, and which are generally accepted in the industry. However, there can be no assurance that the levels of insurance protection currently in effect will continue to be available at reasonable prices or that such levels will remain adequate to protect us from material expenses related to product liability, personal injury or property damage in the future.
Sunoco Litigation
Following the announcement of the Sunoco Merger on April 30, 2012, eight putative class action and derivative complaints were filed in connection with the Sunoco Merger in the Court of Common Pleas of Philadelphia County, Pennsylvania. Each complaint names as defendants the members of Sunoco’s board of directors and alleges that they breached their fiduciary duties by negotiating and executing, through an unfair and conflicted process, a merger agreement that provides inadequate consideration and that contains impermissible terms designed to deter alternative bids. Each complaint also names as defendants Sunoco, ETP, ETP GP, ETP LLC, and Sam Acquisition Corporation, alleging that they aided and abetted the breach of fiduciary duties by Sunoco’s directors; some of the complaints also name ETE as a defendant on those aiding and abetting claims. In September 2012, all of these lawsuits were settled with no payment obligation on the part of any of the defendants following the filing of Current Reports on Form 8-K that included additional disclosures that were incorporated by reference into the proxy statement related to the Sunoco Merger. Subsequent to the settlement of these cases, the plaintiffs’ attorneys sought compensation from Sunoco for attorneys’ fees related to their efforts in obtaining these additional disclosures. In January 2013, Sunoco entered into agreements to compensate the plaintiffs’ attorneys in the state court actions in the aggregate amount of not more than $950,000 and to compensate the plaintiffs’ attorneys in the federal court action in the amount of not more than $250,000. The payment of $950,000 was made in July 2013.
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Litigation Relating to the Southern Union Merger
In June 2011, several putative class action lawsuits were filed in the Judicial District Court of Harris County, Texas naming as defendants the members of the Southern Union Board, as well as Southern Union and ETE. The lawsuits were styledJaroslawicz v. Southern Union Company, et al., Cause No. 2011-37091, in the 333rd Judicial District Court of Harris County, Texas andMagda v. Southern Union Company, et al., Cause No. 2011-37134, in the 11th Judicial District Court of Harris County, Texas. The lawsuits were consolidated into an action styledIn re: Southern Union Company; Cause No. 2011-37091, in the 333rd Judicial District Court of Harris County, Texas. Plaintiffs allege that the Southern Union directors breached their fiduciary duties to Southern Union’s stockholders in connection with the Merger and that Southern Union and ETE aided and abetted the alleged breaches of fiduciary duty. The amended petitions allege that the Merger involves an unfair price and an inadequate sales process, that Southern Union’s directors entered into the Merger to benefit themselves personally, including through consulting and noncompete agreements, and that defendants have failed to disclose all material information related to the Merger to Southern Union stockholders. The amended petitions seek injunctive relief, including an injunction of the Merger, and an award of attorneys’ and other fees and costs, in addition to other relief. On October 21, 2011, the court denied ETE’s October 13, 2011, motion to stay the Texas proceeding in favor of cases pending in the Delaware Court of Chancery.
Also in June 2011, several putative class action lawsuits were filed in the Delaware Court of Chancery naming as defendants the members of the Southern Union Board, as well as Southern Union and ETE. Three of the lawsuits also named Merger Sub as a defendant. These lawsuits are styled:Southeastern Pennsylvania Transportation Authority, et al. v. Southern Union Company, et al., C.A. No. 6615-CS;KBC Asset Management NV v. Southern Union Company, et al., C.A. No. 6622-CS;LBBW Asset Management Investment GmbH v. Southern Union Company, et al., C.A. No. 6627-CS; andMemo v. Southern Union Company, et al., C.A. No. 6639-CS. These cases were consolidated with the following style:In re Southern Union Co. Shareholder Litigation, C.A. No. 6615-CS, in the Delaware Court of Chancery. The consolidated complaint asserts similar claims and allegations as the Texas state-court consolidated action. On July 25, 2012, the Delaware plaintiffs filed a notice of voluntary dismissal of all claims without prejudice. In the notice, plaintiffs stated their claims were being dismissed to avoid duplicative litigation and indicated their intent to join the Texas case.
On September 18, 2013, the plaintiff dismissed without prejudice its lawsuit against all defendants.
MTBE Litigation
Sunoco, along with other refiners, manufacturers and sellers of gasoline, is a defendant in lawsuits alleging MTBE contamination of groundwater. The plaintiffs typically include water purveyors and municipalities responsible for supplying drinking water and governmental authorities. The plaintiffs are asserting primarily product liability claims and additional claims including nuisance, trespass, negligence, violation of environmental laws and deceptive business practices. The plaintiffs in all of the cases are seeking to recover compensatory damages, and in some cases, injunctive relief, punitive damages and attorneys’ fees.
As of September 30, 2013, Sunoco is a defendant in six cases, including one initiated by the State of New Jersey and another by the Commonwealth of Puerto Rico. These cases are venued in a multidistrict proceeding in a New York federal court. The two state cases assert natural resource damage claims. In addition, Sunoco has received notice from another state that it intends to file an MTBE lawsuit in the near future asserting natural resource damage claims.
Discovery is proceeding in these cases. There has been insufficient information developed about the plaintiffs’ legal theories or the facts in the natural resource damage claims that would be relevant to an analysis of the ultimate liability of Sunoco in these matters; however, it is reasonably possible that a loss may be realized. Management believes that an adverse determination with respect to one or more of the MTBE cases could have a significant impact on results of operations the period in which any said adverse determination occurs, but does not believe that any such adverse determination would have a material adverse effect on the Partnership’s consolidated financial position.
Other Litigation and Contingencies
In November 2011, a derivative lawsuit was filed in the Judicial District Court of Harris County, Texas naming as defendants ETP, ETP GP, ETP LLC, the boards of directors of ETP LLC (collectively with ETP GP and ETP LLC, the “ETP Defendants”), certain members of management for ETP and ETE, ETE, and Southern Union. The lawsuit is styled W. J. Garrett Trust v. Bill W. Byrne, et al., Cause No. 2011-71702, in the 157th Judicial District Court of Harris County, Texas. Plaintiffs assert claims for breaches of fiduciary duty, breaches of contractual duties, and acts of bad faith against each of the ETP Defendants and the individual defendants. Plaintiffs also assert claims for aiding and abetting and tortious interference with contract against Southern Union. On October 5, 2012, certain defendants filed a motion for summary judgment with respect to the primary allegations in this action. On December 13, 2012, Plaintiffs filed their opposition to the motion for summary judgment. Defendants filed a reply on December 19, 2012. On December 20, 2012, the court conducted an oral hearing on the motion. Plaintiffs filed a post-hearing sur-reply on January 7, 2013. On January 16, 2013, the Court granted defendants’ motion for summary judgment. The deadline for the remaining defendants to file an answer or otherwise respond is March 1, 2013. Trial in this action is not currently set.
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We or our subsidiaries are a party to various legal proceedings and/or regulatory proceedings incidental to our businesses. For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies, the likelihood of an unfavorable outcome and the availability of insurance coverage. If we determine that an unfavorable outcome of a particular matter is probable and can be estimated, we accrue the contingent obligation, as well as any expected insurance recoverable amounts related to the contingency. As of December 31, 2012 and 2011, accruals of approximately $15 million and $18 million, respectively, were reflected on our balance sheets related to these contingent obligations. As new information becomes available, our estimates may change. The impact of these changes may have a significant effect on our results of operations in a single period.
The outcome of these matters cannot be predicted with certainty and there can be no assurance that the outcome of a particular matter will not result in the payment of amounts that have not been accrued for the matter. Furthermore, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome.
No amounts have been recorded in our December 31, 2012 or 2011 consolidated balance sheets for contingencies and current litigation, other than amounts disclosed herein.
Litigation Related to Incident at JJ’s Restaurant. On February 19, 2013, there was a natural gas explosion at JJ’s Restaurant located at 910 W. 48th Street in Kansas City, Missouri. Effective September 1, 2013, Laclede Gas Company, a subsidiary of The Laclede Group, Inc. (“Laclede”), assumed any and all liability arising from this incident in ETP’s sale of the assets of MGE to Laclede.
Attorney General of the Commonwealth of Massachusetts v New England Gas Company. On July 7, 2011, the Massachusetts Attorney General (AG) filed a regulatory complaint with the MDPU against New England Gas Company with respect to certain environmental cost recoveries. The AG is seeking a refund to New England Gas Company customers for alleged “excessive and imprudently incurred costs” related to legal fees associated with Southern Union’s environmental response activities. In the complaint, the AG requests that the MDPU initiate an investigation into the New England Gas Company’s collection and reconciliation of recoverable environmental costs including: (i) the prudence of any and all legal fees, totaling $19 million, that were charged by the Kasowitz, Benson, Torres & Friedman firm and passed through the recovery mechanism since 2005, the year when a partner in the firm, the Company’s former Vice Chairman, President and Chief Operating Officer, joined Southern Union’s management team; (ii) the prudence of any and all legal fees that were charged by the Bishop, London & Dodds firm and passed through the recovery mechanism since 2005, the period during which a member of the firm served as the Company’s Chief Ethics Officer; and (iii) the propriety and allocation of certain legal fees charged that were passed through the recovery mechanism that the AG contends only qualify for a lesser, 50%, level of recovery. Southern Union has filed its answer denying the allegations and moved to dismiss the complaint, in part on a theory of collateral estoppel. The hearing officer has deferred consideration of Southern Union’s motion to dismiss. The AG’s motion to be reimbursed expert and consultant costs by the Company of up to $150,000 was granted. The hearing officer has stayed discovery until resolution of a separate matter concerning the applicability of attorney-client privilege to legal billing invoices. Southern Union believes it has complied with all applicable requirements regarding its filings for cost recovery and has not recorded any accrued liability; however, Southern Union will continue to assess its potential exposure for such cost recoveries as the matter progresses. Additionally, New England Gas Company’s assets and liabilities have been included in discontinued operations at December 31, 2012.
Air Quality Control. SUGS is currently negotiating settlements to certain enforcement actions by the NMED and the TCEQ.
Compliance Orders from the New Mexico Environmental Department
SUGS has been in discussions with the NMED concerning allegations of violations of New Mexico air regulations related to the Jal #3 and Jal #4 facilities. The NMED has issued amended compliance orders and proposed penalties for alleged violations at Jal #4 in the amount of $1 million and at Jal #3 in the amount of $7 million. Hearings on the compliance orders were delayed until May 2013 to allow the parties to pursue substantive settlement discussions. SUGS has meritorious defenses to the NMED claims and can offer significant mitigating factors to the claimed violations. Southern Union has recorded an accrued liability and will continue to assess its potential exposure to the allegations as the matter progresses.
Environmental Matters
Our operations are subject to extensive federal, state and local environmental and safety laws and regulations that require expenditures to ensure compliance, including related to air emissions and wastewater discharges, at operating facilities and for remediation at current and former facilities as well as waste disposal sites. Although we believe our operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in the business of transporting, storing, gathering, treating, compressing, blending and processing natural gas, natural gas liquids and other products. As a result, there can be no assurance that significant costs and liabilities will not be
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incurred. Costs of planning, designing, constructing and operating pipelines, plants and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, the issuance of injunctions and the filing of federally authorized citizen suits. Moreover, there can be no assurance that other developments, such as increasingly stringent environmental laws, regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from the operations, will not result in substantial costs and liabilities. We are unable to estimate any losses or range of losses that could result from such developments. Furthermore, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome.
Environmental exposures and liabilities are difficult to assess and estimate due to unknown factors such as the magnitude of possible contamination, the timing and extent of remediation, the determination of our liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future. Although environmental costs may have a significant impact on the results of operations for any single period, we believe that such costs will not have a material adverse effect on our financial position.
Based on information available at this time and reviews undertaken to identify potential exposure, we believe the amount reserved for environmental matters is adequate to cover the potential exposure for cleanup costs.
Environmental Remediation
Our subsidiaries are responsible for environmental remediation at certain sites, including the following:
• | Certain of our interstate pipelines conduct soil and groundwater remediation related to contamination from past uses of PCBs. PCB assessments are ongoing and, in some cases, our subsidiaries could potentially be held responsible for contamination caused by other parties. |
• | Certain gathering and processing systems are responsible for soil and groundwater remediation related to releases of hydrocarbons. |
• | Southern Union’s distribution operations are responsible for soil and groundwater remediation at certain sites related to MGPs and may also be responsible for the removal of old MGP structures. |
• | Currently operating Sunoco retail sites. |
• | Legacy sites related to Sunoco, that are subject to environmental assessments include formerly owned terminals and other logistics assets, retail sites that Sunoco no longer operates, closed and/or sold refineries and other formerly owned sites. |
• | Sunoco is potentially subject to joint and several liability for the costs of remediation at sites at which it has been identified as a “potentially responsible party” (“PRP”). As of December 31, 2012, Sunoco had been named as a PRP at 35 identified or potentially identifiable as “Superfund” sites under federal and/or comparable state law. The Company is usually one of a number of companies identified as a PRP at a site. Sunoco has reviewed the nature and extent of its involvement at each site and other relevant circumstances and, based upon Sunoco’s purported nexus to the sites, believes that its potential liability associated with such sites will not be significant. |
To the extent estimable, expected remediation costs are included in the amounts recorded for environmental matters in our consolidated balance sheets. In some circumstances, future costs cannot be reasonably estimated because remediation activities are undertaken as claims are made by customers and former customers. To the extent that an environmental remediation obligation is recorded by a subsidiary that applies regulatory accounting policies, amounts that are expected to be recoverable through tariffs or rates are recorded as regulatory assets on our consolidated balance sheets.
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The table below reflects the amounts of accrued liabilities recorded in our consolidated balance sheets related to environmental matters that are considered to be probable and reasonably estimable. Except for matters discussed above, we do not have any material environmental matters assessed as reasonably possible that would require disclosure in our consolidated financial statements.
December 31, | ||||||||
2012 | 2011 | |||||||
Current | $ | 46 | $ | 1 | ||||
Non-current | 165 | 13 | ||||||
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Total environmental liabilities | $ | 211 | $ | 14 | ||||
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During the three months ended December 31, 2012, Sunoco had $12 million of expenditures related to environmental cleanup programs.
The U.S. Environmental Protection Agency’s (the “EPA”) Spill Prevention, Control and Countermeasures program regulations were recently modified and impose additional requirements on many of our facilities. We expect to expend resources on tank integrity testing and any associated corrective actions as well as potential upgrades to containment structures to comply with the new rules. Costs associated with tank integrity testing and resulting corrective actions cannot be reasonably estimated at this time, but we believe such costs will not have a material adverse effect on our financial position, results of operations or cash flows.
On August 20, 2010, the EPA published new regulations under the federal Clean Air Act (“CAA”) to control emissions of hazardous air pollutants from existing stationary reciprocal internal combustion engines. The rule will require us to undertake certain expenditures and activities, likely including purchasing and installing emissions control equipment. In response to an industry group legal challenge to portions of the rule in the U.S. Court of Appeals for the D.C. Circuit and a Petition for Administrative Reconsideration to the EPA, on March 9, 2011, the EPA issued a new proposed rule and direct final rule effective on May 9, 2011 to clarify compliance requirements related to operation and maintenance procedures for continuous parametric monitoring systems. If no further changes to the standard are made as a result of comments to the proposed rule, we would not expect that the cost to comply with the rule’s requirements will have a material adverse effect on our financial condition or results of operations. Compliance with the final rule was required by October 2013, and the Partnership believes it is in compliance.
On June 29, 2011, the EPA finalized a rule under the CAA that revised the new source performance standards for manufacturers, owners and operators of new, modified and reconstructed stationary internal combustion engines. The rule became effective on August 29, 2011. The rule modifications may require us to undertake significant expenditures, including expenditures for purchasing, installing, monitoring and maintaining emissions control equipment, if we replace equipment or expand existing facilities in the future. At this point, we are not able to predict the cost to comply with the rule’s requirements, because the rule applies only to changes we might make in the future.
Our pipeline operations are subject to regulation by the DOT under the PHMSA, pursuant to which the PHMSA has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Moreover, the PHMSA, through the Office of Pipeline Safety, has promulgated a rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule refers to as “high consequence areas.” Activities under these integrity management programs involve the performance of internal pipeline inspections, pressure testing or other effective means to assess the integrity of these regulated pipeline segments, and the regulations require prompt action to address integrity issues raised by the assessment and analysis. For the years ended December 31, 2012, 2011 and 2010, $7 million, $18 million and $13 million, respectively, of capital costs and $17 million, $15 million and $15 million, respectively, of operating and maintenance costs have been incurred for pipeline integrity testing. Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could cause ETP to incur even greater capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of its pipelines; however, no estimate can be made at this time of the likely range of such expenditures.
Our operations are also subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”), and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA’s hazardous communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in substantial compliance with the OSHA requirements, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances.
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10. | PRICE RISK MANAGEMENT ASSETS AND LIABILITIES: |
Commodity Price Risk
We are exposed to market risks related to the volatility of commodity prices. To manage the impact of volatility from these prices, we utilize various exchange-traded and OTC commodity financial instrument contracts. These contracts consist primarily of futures, swaps and options and are recorded at fair value in the consolidated balance sheets.
We inject and hold natural gas in our Bammel storage facility to take advantage of contango markets (i.e., when the price of natural gas is higher in the future than the current spot price). We use financial derivatives to hedge the natural gas held in connection with these arbitrage opportunities. At the inception of the hedge, we lock in a margin by purchasing gas in the spot market or off peak season and entering into a financial contract to lock in the sale price. If we designate the related financial contract as a fair value hedge for accounting purposes, we value the hedged natural gas inventory at current spot market prices along with the financial derivative we use to hedge it. Changes in the spread between the forward natural gas prices designated as fair value hedges and the physical inventory spot price result in unrealized gains or losses until the underlying physical gas is withdrawn and the related designated derivatives are settled. Once the gas is withdrawn and the designated derivatives are settled, the previously unrealized gains or losses associated with these positions are realized. Unrealized margins represent the unrealized gains or losses from our derivative instruments using mark-to-market accounting, with changes in the fair value of our derivatives being recorded directly in earnings. These margins fluctuate based upon changes in the spreads between the physical spot price and forward natural gas prices. If the spread narrows between the physical and financial prices, we will record unrealized gains or lower unrealized losses. If the spread widens, we will record unrealized losses or lower unrealized gains. Typically, as we enter the winter months, the spread converges so that we recognize in earnings the original locked-in spread through either mark-to-market adjustments or the physical withdraw of natural gas.
We are also exposed to market risk on natural gas we retain for fees in our intrastate transportation and storage operations and operational gas sales on our interstate transportation and storage operations. We use financial derivatives to hedge the sales price of this gas, including futures, swaps and options. Certain contracts that qualify for hedge accounting are designated as cash flow hedges of the forecasted sale of natural gas. The change in value, to the extent the contracts are effective, remains in AOCI until the forecasted transaction occurs. When the forecasted transaction occurs, any gain or loss associated with the derivative is recorded in cost of products sold in the consolidated statement of operations.
We are also exposed to commodity price risk on NGLs and residue gas we retain for fees in our midstream operations whereby the Company generally gathers and processes natural gas on behalf of producers, sells the resulting residue gas and NGL volumes at market prices and remits to producers an agreed upon percentage of the proceeds based on an index price for the residue gas and NGLs. We use derivative swap contracts to hedge forecasted sales of NGL equity volumes. Certain contracts that qualify for hedge accounting are accounted for as cash flow hedges. The change in value, to the extent the contracts are effective, remains in AOCI until the forecasted transaction occurs. When the forecasted transaction occurs, any gain or loss associated with the derivative is recorded in cost of products sold in the consolidated statement of operations.
Our trading activities include the use of financial commodity derivatives to take advantage of market opportunities. These trading activities are a complement to our transportation and storage operations and are netted in cost of products sold in our consolidated statements of operations. Additionally, we also have trading activities related to power in our “All Other” operations which are also netted in cost of products sold. As a result of our trading activities and the use of derivative financial instruments in our transportation and storage operations, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to period. We attempt to manage this volatility through the use of daily position and profit and loss reports provided to our risk oversight committee, which includes members of senior management, and the limits and authorizations set forth in our commodity risk management policy.
Derivatives are utilized in our midstream operations in order to mitigate price volatility and manage fixed price exposure incurred from contractual obligations. We attempt to maintain balanced positions in our marketing activities to protect against volatility in the energy commodities markets; however, net unbalanced positions can exist. Long-term physical contracts are tied to index prices.
Prior to the deconsolidation of the Propane Business, we also used propane futures contracts to fix the purchase price related to certain fixed price sales contracts. Prior to the sale of our cylinder exchange business, we used propane futures contracts to secure the purchase price of our propane inventory for a percentage of the anticipated sales.
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The following table details our outstanding commodity-related derivatives:
December 31, 2012 | December 31, 2011 | |||||||||||||||
Notional Volume | Maturity | Notional Volume | Maturity | |||||||||||||
Mark-to-Market Derivatives | ||||||||||||||||
(Trading) | ||||||||||||||||
Natural Gas (MMBtu): | ||||||||||||||||
Basis Swaps IFERC/NYMEX (1) | (30,980,000 | ) | 2013-2014 | (151,260,000 | ) | 2012-2013 | ||||||||||
Power (Megawatt): | ||||||||||||||||
Forwards | 19,650 | 2013 | — | — | ||||||||||||
Futures | (1,509,300 | ) | 2013 | — | — | |||||||||||
Options – Calls | 1,656,400 | 2013 | — | — | ||||||||||||
(Non-Trading) | ||||||||||||||||
Natural Gas (MMBtu): | ||||||||||||||||
Basis Swaps IFERC/NYMEX | 150,000 | 2013 | (61,420,000 | ) | 2012-2013 | |||||||||||
Swing Swaps IFERC | (83,292,500 | ) | 2013 | 92,370,000 | 2012-2013 | |||||||||||
Fixed Swaps/Futures | 27,077,500 | 2013 | 797,500 | 2012 | ||||||||||||
Forward Physical Contracts | 11,689,855 | 2013-2014 | (10,672,028 | ) | 2012 | |||||||||||
Options – Puts | — | 2013 | — | — | ||||||||||||
Natural Gas Liquid (Bbls): | ||||||||||||||||
Forwards/Swaps | (30,000 | ) | 2013 | — | — | |||||||||||
Refined Products (Bbls) | (666,000 | ) | 2013 | — | — | |||||||||||
Propane (Gallons): | ||||||||||||||||
Forwards/Swaps | — | — | 38,766,000 | 2012-2013 | ||||||||||||
Fair Value Hedging Derivatives | ||||||||||||||||
(Non-Trading) | ||||||||||||||||
Natural Gas (MMBtu): | ||||||||||||||||
Basis Swaps IFERC/NYMEX | (18,655,000 | ) | 2013 | (28,752,500 | ) | 2012 | ||||||||||
Fixed Swaps/Futures | (44,272,500 | ) | 2013 | (45,822,500 | ) | 2012 | ||||||||||
Hedged Item – Inventory | 44,272,500 | 2013 | 45,822,500 | 2012 | ||||||||||||
Cash Flow Hedging Derivatives | ||||||||||||||||
(Non-Trading) | ||||||||||||||||
Natural Gas (MMBtu): | ||||||||||||||||
Fixed Swaps/Futures | (8,212,500 | ) | 2013 | — | — | |||||||||||
Options – Puts | — | — | 3,600,000 | 2012 | ||||||||||||
Options – Calls | — | — | (3,600,000 | ) | 2012 | |||||||||||
Natural Gas Liquid (Bbls): | ||||||||||||||||
Forwards/Swaps | (930,000 | ) | 2013 | — | — | |||||||||||
Refined Products (BBls) | (98,000 | ) | 2013 | — | — |
(1) | Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations. |
We expect losses of $6 million related to commodity derivatives to be reclassified into earnings over the next 12 months related to amounts currently reported in AOCI. The amount ultimately realized, however, will differ as commodity prices change and the underlying physical transaction occurs.
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Interest Rate Risk
We are exposed to market risk for changes in interest rates. In order to maintain a cost effective capital structure, we borrow funds using a mix of fixed rate debt and variable rate debt. We manage our current interest rate exposures by utilizing interest rate swaps to achieve a desired mix of fixed and variable rate debt. We also utilize forward starting interest rate swaps to lock in the rate on a portion of our anticipated debt issuances.
We had the following interest rate swaps outstanding as of December 31, 2012 and 2011, none of which are designated as hedges for accounting purposes:
Notional Amount Outstanding | ||||||||||||
Entity | Term | Type(1) | December 31, 2012 | December 31, 2011 | ||||||||
ETP | May 2012(2) | Forward starting to pay a fixed rate of 2.59% and receive a floating rate | $ | — | $ | 350 | ||||||
ETP | August 2012(2) | Forward starting to pay a fixed rate of 3.51% and receive a floating rate | — | 500 | ||||||||
ETP | July 2013(2) | Forward starting to pay a fixed rate of 4.02% and receive a floating rate | 400 | 300 | ||||||||
ETP | July 2014(2) | Forward starting to pay a fixed rate of 4.25% and receive a floating rate | 400 | — | ||||||||
ETP | July 2018 | Pay a floating rate plus a spread of 4.17% and receive a fixed rate of 6.70% | 600 | 500 | ||||||||
Southern Union | November 2016 | Pay a fixed rate of 2.91% and receive a floating rate | 75 | — | ||||||||
Southern Union | November 2021 | Pay a fixed rate of 3.75% and receive a floating rate | 450 | — |
(1) | As of December 31, 2012, floating rates are based on 3-month LIBOR. |
(2) | Represents the effective date. These forward starting swaps have a term of 10 years with a mandatory termination date the same as the effective date. |
As of December 31, 2012, Southern Union had no outstanding treasury rate locks; however, certain of its treasury rate locks that settled in prior periods are associated with interest payments on outstanding long-term debt. These treasury rate locks are accounted for as cash flow hedges, with the effective portion of their settled value recorded in AOCI and reclassified into interest expense in the same periods during which the related interest payments on long-term debt impact earnings.
Credit Risk
We maintain credit policies with regard to our counterparties that we believe minimize our overall credit risk. These policies include an evaluation of potential counterparties’ financial condition (including credit ratings), collateral requirements under certain circumstances and the use of standardized agreements, which allow for netting of positive and negative exposure associated with a single or multiple counterparties.
Our counterparties consist primarily of petrochemical companies and other industrials, small to major oil and gas producers, midstream and power generation companies. This concentration of counterparties may impact our overall exposure to credit risk, either positively or negatively in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions. Currently, management does not anticipate a material adverse effect on our financial position or results of operations as a result of counterparty nonperformance.
We utilize master-netting agreements and have maintenance margin deposits with certain counterparties in the OTC market and with clearing brokers. Payments on margin deposits are required when the value of a derivative exceeds our pre-established credit limit with the counterparty. Margin deposits are returned to us on the settlement date for non-exchange traded derivatives, and we exchange margin calls on a daily basis for exchange traded transactions. Since the margin calls are made daily with the exchange brokers, the fair value of the financial derivative instruments are deemed current and netted in deposits paid to vendors within other current assets in the consolidated balance sheets. The Partnership had net deposits with counterparties of $41 million and $66 million as of December 31, 2012 and 2011, respectively.
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Certain of Southern Union’s derivative instruments contain provisions that require Southern Union’s debt to be maintained at an investment grade credit rating from each of the major credit rating agencies. If Southern Union’s debt were to fall below investment grade, Southern Union would be in violation of these provisions, and the counterparties to the derivative instruments could potentially require Southern Union to post collateral for certain of the derivative instruments. The aggregate fair value of Southern Union’s derivative instruments with credit-risk-related contingent features that are in a net liability position at December 31, 2012 was $4 million, all of which were included in the disposal group held for sale liabilities at December 31, 2012.
For financial instruments, failure of a counterparty to perform on a contract could result in our inability to realize amounts that have been recorded on our consolidated balance sheet and recognized in net income or other comprehensive income.
Derivative Summary
The following table provides a balance sheet overview of the Partnership’s derivative assets and liabilities as of December 31, 2012 and 2011:
Fair Value of Derivative Instruments | ||||||||||||||||
Asset Derivatives | Liability Derivatives | |||||||||||||||
2012 | 2011 | 2012 | 2011 | |||||||||||||
Derivatives designated as hedging instruments: | ||||||||||||||||
Commodity derivatives (margin deposits) | $ | 8 | $ | 77 | $ | (10 | ) | $ | (1 | ) | ||||||
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8 | 77 | (10 | ) | (1 | ) | |||||||||||
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Derivatives not designated as hedging instruments: | ||||||||||||||||
Commodity derivatives (margin deposits) | 110 | 227 | (116 | ) | (251 | ) | ||||||||||
Commodity derivatives | 35 | 1 | (43 | ) | (5 | ) | ||||||||||
Interest rate derivatives | 55 | 36 | (223 | ) | (117 | ) | ||||||||||
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200 | 264 | (382 | ) | (373 | ) | |||||||||||
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Total derivatives | $ | 208 | $ | 341 | $ | (392 | ) | $ | (374 | ) | ||||||
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The commodity derivatives (margin deposits) are recorded in “Other current assets” on our consolidated balance sheets. The remainder of the derivatives are recorded in “Price risk management assets/liabilities”. As of December 31, 2012 commodity derivative assets of $1 million and commodity derivatives liabilities of $8 million were recorded in “Non-current assets held for sale” and “Current liabilities held for sale” on our consolidated balances sheet. In addition to the above derivatives, $7 million in option premiums included in “Price risk management liabilities” as of December 31, 2012 will amortize in 2013.
We disclose the non-exchange traded financial derivative instruments as price risk management assets and liabilities on our consolidated balance sheets at fair value with amounts classified as either current or long-term depending on the anticipated settlement date.
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The following tables summarize the amounts recognized with respect to our derivative financial instruments for the periods presented:
Change in Value Recognized in OCI on Derivatives (Effective Portion) | ||||||||||||
Years Ended December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
Derivatives in cash flow hedging relationships: | ||||||||||||
Commodity derivatives | $ | 8 | $ | 19 | $ | 61 | ||||||
Interest rate derivatives | — | — | (1 | ) | ||||||||
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Total | $ | 8 | $ | 19 | $ | 60 | ||||||
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Location of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion) | Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion) | |||||||||||||
Years Ended December 31, | ||||||||||||||
2012 | 2011 | 2010 | ||||||||||||
Derivatives in cash flow hedging relationships: | ||||||||||||||
Commodity derivatives | Cost of products sold | $ | 14 | $ | 38 | $ | 37 | |||||||
Interest rate derivatives | Interest expense | — | — | (1 | ) | |||||||||
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Total | $ | 14 | $ | 38 | $ | 36 | ||||||||
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Location of Gain/(Loss) Recognized in Income on Derivatives | Amount of Gain (Loss) Recognized in Income representing hedge ineffectiveness and amount excluded from the assessment of effectiveness | |||||||||||||
Years Ended December 31, | ||||||||||||||
2012 | 2011 | 2010 | ||||||||||||
Derivatives in fair value hedging relationships (including hedged item): | ||||||||||||||
Commodity derivatives | Cost of products sold | $ | 54 | $ | 34 | $ | 16 | |||||||
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Total | $ | 54 | $ | 34 | $ | 16 | ||||||||
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Location of Gain/(Loss) Recognized in Income on Derivatives | Amount of Gain (Loss) Recognized in Income on Derivatives | |||||||||||||
Years Ended December 31, | ||||||||||||||
2012 | 2011 | 2010 | ||||||||||||
Derivatives not designated as hedging instruments: | ||||||||||||||
Commodity derivatives – Trading | Cost of products sold | $ | (7 | ) | $ | (30 | ) | $ | — | |||||
Commodity derivatives – Non-trading | Cost of products sold | (15 | ) | 9 | 12 | |||||||||
Commodity contracts – Non-trading | Deferred gas purchases | (26 | ) | — | — | |||||||||
Interest rate derivatives | Losses on non-hedged interest rate derivatives | (4 | ) | (77 | ) | 5 | ||||||||
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Total | $ | (52 | ) | $ | (98 | ) | $ | 17 | ||||||
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11. | RETIREMENT BENEFITS: |
Savings and Profit Sharing Plans
We and our subsidiaries sponsor defined contribution savings plans, which collectively cover virtually all employees. Employer matching contributions are calculated using a formula based on employee contributions. We made matching contributions of $8 million, $11 million and $10 million to the 401(k) savings plan for the years ended December 31, 2012, 2011 and 2010, respectively.
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Southern Union sponsors a defined contribution savings plan (Savings Plan) that is available to all employees. Southern Union contributions to the Savings Plan during the period from Acquisition (March 26, 2012) to December 31, 2012 were $6 million.
In addition, the Southern Union makes employer contributions to separate accounts, referred to as Retirement Power Accounts, within the defined contribution plan. The contribution amounts are determined as a percentage of compensation and range from 3.5% to 12%. Southern Union contributions are generally 100% vested after five years of continuous service. Southern Union contributions to Retirement Power Accounts during the period from Acquisition (March 26, 2012) to December 31, 2012 were $2 million.
Pension and Other Postretirement Benefit Plans
Southern Union
Southern Union has funded non-contributory defined benefit pension plans that cover substantially all employees of Southern Union’s distribution operations. Normal retirement age is 65, but certain plan provisions allow for earlier retirement. Pension benefits are calculated under formulas principally based on average earnings and length of service for salaried and non-union employees and average earnings and length of service or negotiated non-wage based formulas for union employees.
The 2012 postretirement benefits expense for Southern Union reflects the impact of curtailment accounting as postretirement benefits for all active participants who did not meet certain criteria were eliminated. Southern Union previously had postretirement health care and life insurance plans that covered substantially all of Southern Union’s distribution and transportation and storage operations employees as well as all corporate employees. The health care plans generally provide for cost sharing between Southern Union and its retirees in the form of retiree contributions, deductibles, coinsurance, and a fixed cost cap on the amount Southern Union pays annually to provide future retiree health care coverage under certain of these plans.
Sunoco
Sunoco has both funded and unfunded noncontributory defined benefit pension plans (see “defined benefit plans”). Sunoco also has plans which provide health care benefits for substantially all of its current retirees (“postretirement benefit plans”). The postretirement benefit plans are unfunded and the costs are shared by Sunoco and its retirees. Prior to the Sunoco Merger on October 5, 2012, pension benefits under Sunoco’s defined benefit plans were frozen for most of the participants in these plans at which time Sunoco instituted a discretionary profit-sharing contribution on behalf of these employees in its defined contribution plan. Postretirement medical benefits were also phased down or eliminated for all employees retiring after July 1, 2010. Sunoco has established a trust for its postretirement benefit liabilities by making a tax-deductible contribution of approximately $200 million and restructuring the retiree medical plan to eliminate Sunoco’s liability beyond this funded amount. The retiree medical plan change eliminated substantially all of Sunoco’s future exposure to variances between actual results and assumptions used to estimate retiree medical plan obligations.
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Obligations and Funded Status
Pension and other postretirement benefit liabilities are accrued on an actuarial basis during the years an employee provides services. The following table contains information at the dates indicated about the obligations and funded status of pension and other postretirement plans on a combined basis:
December 31, 2012 | ||||||||
Pension Benefits | Other Postretirement Benefits | |||||||
Change in benefit obligation: | ||||||||
Benefit obligation at acquisition date | $ | 1,257 | $ | 359 | ||||
Service cost | 3 | 1 | ||||||
Interest cost | 15 | 3 | ||||||
Amendments | — | 17 | ||||||
Benefits paid, net | (71 | ) | (8 | ) | ||||
Curtailments | — | (80 | ) | |||||
Actuarial (gain)/loss and other | (9 | ) | 4 | |||||
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Benefit obligation at end of period | $ | 1,195 | $ | 296 | ||||
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Change in plan assets: | ||||||||
Fair value of plan assets at acquisition date | $ | 941 | $ | 306 | ||||
Return on plan assets and other | 22 | 5 | ||||||
Employer contributions | 14 | 9 | ||||||
Benefits paid, net | (71 | ) | (8 | ) | ||||
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Fair value of plan assets at end of period | $ | 906 | $ | 312 | ||||
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Amount underfunded (overfunded) at end of period | $ | 289 | $ | (16 | ) | |||
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Amounts recognized in the consolidated balance sheets consist of: | ||||||||
Noncurrent assets | $ | — | $ | 59 | ||||
Current liabilities | (15 | ) | (2 | ) | ||||
Noncurrent liabilities | (274 | ) | (41 | ) | ||||
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$ | (289 | ) | $ | 16 | ||||
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Amounts recognized in accumulated other comprehensive loss (pre-tax basis) consist of: | ||||||||
Net actuarial (gain) loss | $ | (1 | ) | $ | (1 | ) | ||
Prior service cost | — | 16 | ||||||
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$ | (1 | ) | $ | 15 | ||||
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The following table summarizes information at the dates indicated for plans with an accumulated benefit obligation in excess of plan assets:
December 31, 2012 | ||||||||
Pension Benefits | Other Postretirement Benefits | |||||||
Projected benefit obligation | $ | 1,195 | N/A | |||||
Accumulated benefit obligation | 1,179 | $ | 225 | |||||
Fair value of plan assets | 906 | 185 |
Components of Net Periodic Benefit Cost
December 31, 2012 | ||||||||
Pension Benefits | Other Postretirement Benefits | |||||||
Net Periodic Benefit Cost: | ||||||||
Service cost | $ | 3 | $ | 1 | ||||
Interest cost | 15 | 3 | ||||||
Expected return on plan assets | (21 | ) | (5 | ) | ||||
Special termination benefits charge | 2 | — | ||||||
Curtailment recognition(1) | — | (15 | ) | |||||
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(1 | ) | (16 | ) | |||||
Regulatory adjustment(2) | 9 | 2 | ||||||
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Net periodic benefit cost | $ | 8 | $ | (14 | ) | |||
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(1) | Subsequent to the Southern Union Merger, Southern Union amended certain of its other postretirement employee benefit plans, which prospectively restrict participation in the plans for the impacted active employees. The plan amendments resulted in the plans becoming currently over-funded and, accordingly, Southern Union recorded a pre-tax curtailment gain of $75 million. Such gain was offset by establishment of a non-current refund liability in the amount of $60 million. As such, the net curtailment gain recognition was $15 million. |
(2) | In its distribution operations, Southern Union recovers certain qualified pension benefit plan and other postretirement benefit plan costs through rates charged to utility customers. Certain utility commissions require that the recovery of these costs be based on the Employee Retirement Income Security Act of 1974, as amended, or other utility commission specific guidelines. The difference between these regulatory-based amounts and the periodic benefit cost calculated pursuant to GAAP is deferred as a regulatory asset or liability and amortized to expense over periods in which this difference will be recovered in rates, as promulgated by the applicable utility commission. |
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Assumptions
The weighted-average assumptions used in determining benefit obligations at the dates indicated are shown in the table below:
December 31, 2012 | ||||||||
Pension Benefits | Other Postretirement Benefits | |||||||
Discount rate | 3.41 | % | 2.39 | % | ||||
Rate of compensation increase | 3.17 | % | N/A |
The weighted-average assumptions used in determining net periodic benefit cost for the periods presented are shown in the table below:
December 31, 2012 | ||||||||
Pension Benefits | Other Postretirement Benefits | |||||||
Discount rate | 2.37 | % | 2.43 | % | ||||
Expected return on assets: | ||||||||
Tax exempt accounts | 7.63 | % | 7.00 | % | ||||
Taxable accounts | N/A | 4.50 | % | |||||
Rate of compensation increase | 3.02 | % | N/A |
The long-term expected rate of return on plan assets was estimated based on a variety of factors including the historical investment return achieved over a long-term period, the targeted allocation of plan assets and expectations concerning future returns in the marketplace for both equity and fixed income securities. Current market factors such as inflation and interest rates are evaluated before long-term market assumptions are determined. Peer data and historical returns are reviewed to ensure reasonableness and appropriateness.
The assumed health care cost trend rates used to measure the expected cost of benefits covered by Southern Union and Sunoco’s other postretirement benefit plans are shown in the table below:
December 31, 2012 | ||||
Health care cost trend rate assumed for next year | 7.78 | % | ||
Rate to which the cost trend is assumed to decline (the ultimate trend rate) | 5.32 | % | ||
Year that the rate reaches the ultimate trend rate | 2018 |
Changes in the health care cost trend rate assumptions are not expected to have a significant impact on postretirement benefits.
Plan Assets
For the Southern Union plans, the overall investment strategy is to maintain an appropriate balance of actively managed investments with the objective of optimizing longer-term returns while maintaining a high standard of portfolio quality and achieving proper diversification. To achieve diversity within its pension plan asset portfolio, Southern Union has targeted the following asset allocations: equity of 25% to 70%, fixed income of 15% to 35%, alternative assets of 10% to 35% and cash of 0% to 10%. To achieve diversity within its other postretirement plan asset portfolio, Southern Union has targeted the following asset allocations: equity of 25% to 35%, fixed income of 65% to 75% and cash and cash equivalents of 0% to 10%.
The investment strategy of Sunoco funded defined benefit plans is to achieve consistent positive returns, after adjusting for inflation, and to maximize long-term total return within prudent levels of risk through a combination of income and capital appreciation. The objective of this strategy is to reduce the volatility of investment returns, maintain a sufficient funded status of the plans and limit required contributions. Sunoco has targeted the following asset allocations: equity of 35%, fixed income of 55%, and private equity investments of 10%. Sunoco anticipates future shifts in targeted asset allocation from equity securities to fixed income securities if funding levels improve due to asset performance or Sunoco contributions.
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The fair value of the pension plan assets by asset category at the dates indicated is as follows:
Fair Value as of December 31, 2012 | Fair Value Measurements at December 31, 2012 Using Fair Value Hierarchy | |||||||||||||||
Level 1 | Level 2 | Level 3 | ||||||||||||||
Asset Category: | ||||||||||||||||
Cash and cash equivalents | $ | 25 | $ | 25 | $ | — | $ | — | ||||||||
Mutual funds(1) | 516 | — | 433 | 83 | ||||||||||||
Fixed income securities | 354 | — | 354 | — | ||||||||||||
Multi-strategy hedge funds(2) | 11 | — | 11 | — | ||||||||||||
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Total | $ | 906 | $ | 25 | $ | 798 | $ | 83 | ||||||||
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(1) | Primarily comprised of approximately 36% equities, 54% fixed income securities, and 10% in other investments as of December 31, 2012. |
(2) | Primarily includes hedge funds that invest in multiple strategies, including relative value, opportunistic/macro, long/short equities, merger arbitrage/event driven, credit, and short selling strategies, to generate long-term capital appreciation through a portfolio having a diversified risk profile with relatively low volatility and a low correlation with traditional equity and fixed-income markets. These investments can generally be redeemed effective as of the last day of a calendar quarter at the net asset value per share of the investment with approximately 65 days prior written notice. |
The fair value of other postretirement plan assets by asset category at the dates indicated is as follows:
Fair Value as of | Fair Value Measurements at December 31, 2012 Using Fair Value Hierarchy | |||||||||||||||
December 31, 2012 | Level 1 | Level 2 | Level 3 | |||||||||||||
Asset Category: | ||||||||||||||||
Cash and Cash Equivalents | $ | 7 | $ | 7 | $ | — | $ | — | ||||||||
Mutual funds(1) | 147 | 126 | 21 | — | ||||||||||||
Fixed income securities | 158 | — | 158 | — | ||||||||||||
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Total | $ | 312 | $ | 133 | $ | 179 | $ | — | ||||||||
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(1) | Primarily comprised of approximately 19% equities, 74% fixed income securities, 4% cash, and 3% in other investments as of December 31, 2012. |
The Level 1 plan assets are valued based on active market quotes. The Level 2 plan assets are valued based on the net asset value per share (or its equivalent) of the investments, which was not determinable through publicly published sources but was calculated consistent with authoritative accounting guidelines. See Note 2 for information related to the framework used to measure the fair value of its pension and other postretirement plan assets.
Contributions
We expect to contribute approximately $18 million to pension plans and approximately $8 million to other postretirement plans in 2013. The costs of the plans are funded in accordance with federal regulations, not to exceed the amounts deductible for income tax purposes.
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Benefit Payments
Southern Union and Sunoco’s estimate of expected benefit payments, which reflect expected future service, as appropriate, in each of the next five years and in the aggregate for the five years thereafter are shown in the table below:
Years | Benefits | Other Postretirement Benefits (Gross, Before Medicare Part D) | Other Postretirement Benefits (Medicare Part D Subsidy Receipts) | |||||||||
2013 | $ | 254 | $ | 38 | $ | 1 | ||||||
2014 | 105 | 34 | 1 | |||||||||
2015 | 98 | 33 | 1 | |||||||||
2016 | 87 | 32 | 1 | |||||||||
2017 | 82 | 30 | 1 | |||||||||
2018 - 2021 | 328 | 107 | 4 |
The Medicare Prescription Drug Act provides for a prescription drug benefit under Medicare (Medicare Part D) as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare Part D.
12. | RELATED PARTY TRANSACTIONS: |
ETE has agreements with subsidiaries to provide or receive various general and administrative services. ETE pays us to provide services on its behalf and the behalf of other subsidiaries of ETE, which includes the reimbursement of various general and administrative services for expenses incurred by us on behalf of Regency.
In the ordinary course of business, we provide Regency with certain natural gas and NGLs sales and transportation services and compression equipment, and Regency provides us with certain contract compression services. These related party transactions are generally based on transactions made at market-related rates.
Sunoco Logistics has an agreement with PES relating to the Fort Mifflin Terminal Complex. Under this agreement, PES will deliver an average of 300,000 Bbls/d of crude oil and refined products per contract year at the Fort Mifflin facility. PES does not have exclusive use of the Fort Mifflin Terminal Complex; however, Sunoco Logistics is obligated to provide the necessary tanks, marine docks and pipelines for PES to meet its minimum requirements under the agreement. Sunoco Logistics executed a 10-year agreement with PES in September 2012.
In September 2012, Sunoco assigned its lease for the use of Sunoco Logistics’ inter-refinery pipelines between the Philadelphia and Marcus Hook refineries to PES. Under the 20-year lease agreement which expires in February 2022, PES leases the inter-refinery pipelines for an annual fee which escalates at 1.67% each January 1 for the term of the agreement. The lease agreement also requires PES to reimburse Sunoco Logistics for any non-routine maintenance expenditures, as defined, incurred during the term of the agreement. There were no material reimbursements under this agreement during 2010 through 2012.
The following table summarizes the affiliate revenue on our consolidated statements of operations:
Years Ended December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
Affiliated revenue | $ | 173 | $ | 690 | $ | 571 |
In January 2012, Enterprise sold a significant portion of its ownership in ETE’s common units. Subsequent to that transaction Enterprise owns less than 5% of ETE’s outstanding common units and is no longer considered a related party. Previously, transactions between us and Enterprise were considered to be related party transactions due to Enterprise’s ownership of a portion of ETE’s common units. During the years ended December 31, 2011 and 2010, ETP recorded sales to Enterprise of $665 million and $554 million, respectively, and purchases from Enterprise of $498 million and $439 million, respectively, all of which were related party transactions based on Enterprise’s interests in ETE at the time of the transactions.
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The following table summarizes the related company balances on our consolidated balance sheets:
December 31, | ||||||||
2012 | 2011 | |||||||
Accounts receivable from related companies: | ||||||||
ETE | $ | 16 | $ | 14 | ||||
Regency | 10 | 10 | ||||||
PES(1) | 60 | — | ||||||
Enterprise(2) | — | 55 | ||||||
Other | 8 | 3 | ||||||
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Total accounts receivable from related companies: | $ | 94 | $ | 82 | ||||
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Accounts payable to related companies: | ||||||||
ETE | $ | 7 | $ | 2 | ||||
Regency | 2 | — | ||||||
PES(1) | 13 | — | ||||||
Enterprise(2) | — | 30 | ||||||
Other | 2 | 1 | ||||||
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Total accounts payable to related companies: | $ | 24 | $ | 33 | ||||
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(1) | PES became a related party in October 2012 as a result of the Sunoco Merger. See Note 3. |
(2) | In January 2012, Enterprise sold a significant portion of its ownership in ETE’s common units. Subsequent to that transaction, Enterprise owns less than 5% of ETE’s outstanding common units and is no longer considered a related party. |
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ENERGY TRANSFER PARTNERS GP, L.P.
BALANCE SHEETS
December 31, | ||||||||
2012 | 2011 | |||||||
ASSETS | ||||||||
INVESTMENT IN ENERGY TRANSFER PARTNERS | $ | 188 | $ | 182 | ||||
GOODWILL | 29 | 29 | ||||||
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Total assets | $ | 217 | $ | 211 | ||||
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LIABILITIES AND EQUITY | ||||||||
EQUITY: | ||||||||
General Partner | $ | — | $ | — | ||||
Limited Partners: | ||||||||
Class A Limited Partner interest | 86 | 84 | ||||||
Class B Limited Partner interest | 131 | 127 | ||||||
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Total partners’ capital | 217 | 211 | ||||||
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Total liabilities and equity | $ | 217 | $ | 211 | ||||
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STATEMENTS OF OPERATIONS
Years Ended December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
OTHER INCOME (EXPENSE): | ||||||||||||
Equity in earnings of unconsolidated affiliates | $ | 461 | $ | 433 | $ | 388 | ||||||
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NET INCOME BEFORE INCOME TAX EXPENSE | 461 | 433 | 388 | |||||||||
Income tax expense | — | — | — | |||||||||
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NET INCOME | $ | 461 | $ | 433 | $ | 388 | ||||||
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STATEMENTS OF CASH FLOWS
Years Ended December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
NET CASH PROVIDED BY OPERATING ACTIVITIES | $ | 454 | $ | 426 | $ | 384 | ||||||
CASH FLOWS FROM FINANCING ACTIVITIES: | ||||||||||||
Distributions to partners | (454 | ) | (426 | ) | (384 | ) | ||||||
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Net cash used in financing activities | (454 | ) | (426 | ) | (384 | ) | ||||||
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INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS | — | — | — | |||||||||
CASH AND CASH EQUIVALENTS, beginning of period | — | — | — | |||||||||
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CASH AND CASH EQUIVALENTS, end of period | $ | — | $ | — | $ | — | ||||||
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