Exhibit 99.2
TEPPCO PARTNERS, L.P.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
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F-1
To the Board of Directors of Texas Eastern Products Pipeline Company, LLC and
Unitholders of TEPPCO Partners, L.P.
Houston, Texas
We have audited the accompanying consolidated balance sheets of TEPPCO Partners, L.P. and subsidiaries (the “Partnership”) as of December 31, 2008 and 2007, and the related statements of consolidated income, comprehensive income, cash flows and partners’ capital for each of the three years in the period ended December 31, 2008. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. 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 provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of TEPPCO Partners, L.P. and subsidiaries as of December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008, in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Partnership’s internal control over financial reporting as of December 31, 2008, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 2, 2009 expressed an unqualified opinion on the Partnership's internal control over financial reporting and did not include the internal control over financial reporting related to the acquired operations of Cenac Towing Co., Inc., Cenac Offshore, L.L.C. and Mr. Arlen B. Cenac, Jr. and Horizon Maritime, L.L.C.
/s/ Deloitte & Touche LLP
Houston, Texas
March 2, 2009
F-2
TEPPCO PARTNERS, L.P. (Dollars in thousands) | ||||||||
| December 31, | ||||||||
| 2008 | 2007 | |||||||
| ASSETS | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 28 | $ | 23 | ||||
Accounts receivable, trade (net of allowance for doubtful accounts of $2,559 and $125) | 790,374 | 1,381,871 | ||||||
Accounts receivable, related parties | 15,758 | 6,525 | ||||||
Inventories | 52,906 | 80,299 | ||||||
Other | 48,496 | 47,271 | ||||||
Total current assets | 907,562 | 1,515,989 | ||||||
Property, plant and equipment, at cost (net of accumulated depreciation of $678,784 and $582,225) | 2,439,910 | 1,793,634 | ||||||
| Equity investments | 1,255,923 | 1,146,995 | ||||||
Intangible assets (net of accumulated amortization of $158,391 and $130,094) | 207,653 | 164,681 | ||||||
| Goodwill | 106,611 | 15,506 | ||||||
| Other assets | 132,161 | 113,252 | ||||||
Total assets | $ | 5,049,820 | $ | 4,750,057 | ||||
| LIABILITIES AND PARTNERS’ CAPITAL | ||||||||
Current liabilities: | ||||||||
Senior notes | $ | -- | $ | 353,976 | ||||
Accounts payable and accrued liabilities | 792,469 | 1,413,447 | ||||||
Accounts payable, related parties | 17,219 | 38,980 | ||||||
Accrued interest | 36,401 | 35,491 | ||||||
Other accrued taxes | 23,038 | 20,483 | ||||||
Other | 30,869 | 84,848 | ||||||
Total current liabilities | 899,996 | 1,947,225 | ||||||
| Long-term debt: | ||||||||
| Senior notes | 1,713,291 | 721,545 | ||||||
| Junior subordinated notes | 299,574 | 299,538 | ||||||
| Other long-term debt | 516,654 | 490,000 | ||||||
Total long-term debt | 2,529,519 | 1,511,083 | ||||||
| Other liabilities and deferred credits | 28,826 | 27,122 | ||||||
| Commitments and contingencies | ||||||||
Partners’ capital: | ||||||||
Limited partners’ interests: | ||||||||
Limited partner units (104,547,561 and 89,849,132 units outstanding) | 1,746,210 | 1,394,812 | ||||||
Restricted limited partner units (157,300 and 62,400 units outstanding) | 1,373 | 338 | ||||||
General partner’s interest | (110,309 | ) | (87,966 | ) | ||||
Accumulated other comprehensive loss | (45,795 | ) | (42,557 | ) | ||||
Total partners’ capital | 1,591,479 | 1,264,627 | ||||||
Total liabilities and partners’ capital | $ | 5,049,820 | $ | 4,750,057 | ||||
See Notes to Consolidated Financial Statements.
F-3
TEPPCO PARTNERS, L.P.
(Dollars in thousands)
For Year Ended December 31, | ||||||||||||
| 2008 | 2007 | 2006 | ||||||||||
Operating revenues: | ||||||||||||
Sales of petroleum products | $ | 12,840,649 | $ | 9,147,104 | $ | 9,080,516 | ||||||
Transportation – Refined products | 164,120 | 170,231 | 152,552 | |||||||||
Transportation – LPGs | 105,419 | 101,076 | 89,315 | |||||||||
Transportation – Crude oil | 57,305 | 45,952 | 38,822 | |||||||||
Transportation – NGLs | 52,192 | 46,542 | 43,838 | |||||||||
Transportation – Marine | 164,265 | -- | -- | |||||||||
Gathering – Natural gas | 57,097 | 61,634 | 123,933 | |||||||||
Other | 91,842 | 85,521 | 78,509 | |||||||||
Total operating revenues | 13,532,889 | 9,658,060 | 9,607,485 | |||||||||
Costs and expenses: | ||||||||||||
Purchases of petroleum products | 12,703,534 | 9,017,109 | 8,967,062 | |||||||||
Operating expense | 285,760 | 191,697 | 203,015 | |||||||||
Operating fuel and power | 99,079 | 61,458 | 57,450 | |||||||||
General and administrative | 41,364 | 33,657 | 31,348 | |||||||||
Depreciation and amortization | 126,329 | 105,225 | 108,252 | |||||||||
Taxes – other than income taxes | 23,401 | 18,012 | 17,983 | |||||||||
(Gains) losses on sales of assets | 2 | (18,653 | ) | (7,404 | ) | |||||||
Total costs and expenses | 13,279,469 | 9,408,505 | 9,377,706 | |||||||||
Operating income | 253,420 | 249,555 | 229,779 | |||||||||
Other income (expense): | ||||||||||||
| Interest expense – net | (139,988 | ) | (101,223 | ) | (86,171 | ) | ||||||
| Gain on sale of ownership interest in Mont Belvieu Storage | ||||||||||||
Partners, L.P. | -- | 59,628 | -- | |||||||||
| Equity earnings | 82,693 | 68,755 | 36,761 | |||||||||
| Interest income | 1,091 | 1,676 | 2,077 | |||||||||
| Other income | 953 | 1,346 | 888 | |||||||||
Income before provision for income taxes | 198,169 | 279,737 | 183,334 | |||||||||
| Provision for income taxes | 4,617 | 557 | 652 | |||||||||
Income from continuing operations | 193,552 | 279,180 | 182,682 | |||||||||
| Income from discontinued operations | -- | -- | 1,497 | |||||||||
| Gain on sale of discontinued operations | -- | -- | 17,872 | |||||||||
| Discontinued operations | -- | -- | 19,369 | |||||||||
| Net income | $ | 193,552 | $ | 279,180 | $ | 202,051 | ||||||
F-4
TEPPCO PARTNERS, L.P.
STATEMENTS OF CONSOLIDATED INCOME – (Continued)
(Dollars in thousands, except per Unit amounts)
For Year Ended December 31, | ||||||||||||
| 2008 | 2007 | 2006 | ||||||||||
| Net Income Allocation: | ||||||||||||
| Limited Partners: | ||||||||||||
| Income from continuing operations | $ | 160,969 | $ | 233,193 | $ | 130,483 | ||||||
| Income from discontinued operations | -- | -- | 13,835 | |||||||||
Total Limited Partner’s interest in net income | 160,969 | 233,193 | 144,318 | |||||||||
| General Partner: | ||||||||||||
| Income from continuing operations | 32,583 | 45,987 | 52,199 | |||||||||
| Income from discontinued operations | -- | -- | 5,534 | |||||||||
Total General Partner’s interest in net income | 32,583 | 45,987 | 57,733 | |||||||||
Total net income allocated | $ | 193,552 | $ | 279,180 | $ | 202,051 | ||||||
Basic and diluted net income per Limited Partner Unit: | ||||||||||||
Continuing operations | $ | 1.65 | $ | 2.60 | $ | 1.77 | ||||||
Discontinued operations | -- | -- | 0.19 | |||||||||
Basic and diluted net income per Limited Partner Unit | $ | 1.65 | $ | 2.60 | $ | 1.96 | ||||||
| Weighted average Limited Partner Units outstanding | 97,530 | 89,850 | 73,657 | |||||||||
See Notes to Consolidated Financial Statements.
F-5
TEPPCO PARTNERS, L.P.
(Dollars in thousands)
For Year Ended December 31, | ||||||||||||
| 2008 | 2007 | 2006 | ||||||||||
| Net income | $ | 193,552 | $ | 279,180 | $ | 202,051 | ||||||
| Other comprehensive income (loss): | ||||||||||||
| Cash flow hedges: | ||||||||||||
Change in fair values of interest rate and treasury lock | ||||||||||||
financial instruments | (26,802 | ) | (23,604 | ) | (248 | ) | ||||||
Reclassification adjustment for (gain) loss included in net income | ||||||||||||
related to interest rate and treasury lock financial instruments | 4,923 | (64 | ) | -- | ||||||||
Changes in fair values of crude oil financial instruments | (19,257 | ) | (21,036 | ) | 991 | |||||||
Reclassification adjustment for (gain) loss included in net income | ||||||||||||
related to crude oil financial instruments | 37,898 | 1,654 | (261 | ) | ||||||||
| Changes in plan assets and projected benefit obligation | -- | (67 | ) | -- | ||||||||
Total cash flow hedges | (3,238 | ) | (43,117 | ) | 482 | |||||||
Total other comprehensive income (loss) | (3,238 | ) | (43,117 | ) | 482 | |||||||
| Comprehensive income | $ | 190,314 | $ | 236,063 | $ | 202,533 | ||||||
See Notes to Consolidated Financial Statements.
F-6
TEPPCO PARTNERS, L.P.
(Dollars in thousands)
| For Year Ended December 31, | ||||||||||||
| 2008 | 2007 | 2006 | ||||||||||
Operating activities: | ||||||||||||
Net income | $ | 193,552 | $ | 279,180 | $ | 202,051 | ||||||
Adjustments to reconcile net income to cash provided by continuing operating activities: | ||||||||||||
Income from discontinued operations | -- | -- | (19,369 | ) | ||||||||
Deferred income tax provision | 36 | (679 | ) | 652 | ||||||||
Depreciation and amortization | 126,329 | 105,225 | 108,252 | |||||||||
Amortization of deferred compensation | 993 | 830 | -- | |||||||||
Amortization in interest expense | 2,224 | (2,762 | ) | (2,798 | ) | |||||||
Changes in fair market value of financial instruments | (258 | ) | 198 | 143 | ||||||||
Earnings in equity investments | (82,693 | ) | (68,755 | ) | (36,761 | ) | ||||||
Distributions from equity investments | 146,095 | 122,900 | 63,483 | |||||||||
(Gains) losses on sales of assets | 2 | (18,653 | ) | (7,404 | ) | |||||||
Gain on sale of ownership interest in Mont Belvieu Storage | ||||||||||||
Partners, L.P. | -- | (59,628 | ) | -- | ||||||||
Loss on early extinguishment of debt | 8,689 | 1,356 | -- | |||||||||
Net effect of changes in operating accounts | (48,108 | ) | (8,640 | ) | (36,697 | ) | ||||||
Net cash provided by continuing operating activities | 346,861 | 350,572 | 271,552 | |||||||||
Net cash provided by discontinued operations | -- | -- | 1,521 | |||||||||
Net cash provided by operating activities | 346,861 | 350,572 | 273,073 | |||||||||
Investing activities: | ||||||||||||
Proceeds from sales of assets | -- | 27,784 | 51,558 | |||||||||
Proceeds from sale of ownership interest | -- | 137,326 | -- | |||||||||
Purchase of assets | -- | (12,909 | ) | (4,771 | ) | |||||||
Cash used for business combinations | (351,327 | ) | -- | (15,702 | ) | |||||||
Investment in Mont Belvieu Storage Partners, L.P. | -- | -- | (4,767 | ) | ||||||||
Investment in Centennial Pipeline LLC | -- | (11,081 | ) | (2,500 | ) | |||||||
Investment in Jonah Gas Gathering Company | (129,759 | ) | (187,547 | ) | (121,035 | ) | ||||||
Investment in Texas Offshore Port System | (35,953 | ) | -- | -- | ||||||||
Acquisition of intangible assets | (694 | ) | (3,283 | ) | -- | |||||||
Cash paid for linefill on assets owned | (12,784 | ) | (39,418 | ) | (6,453 | ) | ||||||
Capital expenditures | (300,503 | ) | (228,272 | ) | (170,046 | ) | ||||||
Net cash used in investing activities | (831,020 | ) | (317,400 | ) | (273,716 | ) | ||||||
Financing activities: | ||||||||||||
Proceeds from term credit facility | 1,000,000 | -- | -- | |||||||||
Repayments on term credit facility | (1,000,000 | ) | -- | -- | ||||||||
Proceeds from revolving credit facility | 2,508,089 | 1,305,750 | 924,125 | |||||||||
Repayments on revolving credit facility | (2,481,436 | ) | (1,305,750 | ) | (840,025 | ) | ||||||
Repayment of debt assumed in Cenac acquisition | (63,157 | ) | -- | -- | ||||||||
Redemption of 7.51% TE Products Senior Notes | (181,571 | ) | (36,138 | ) | -- | |||||||
Repayment of 6.45% TE Products Senior Notes | (180,000 | ) | -- | -- | ||||||||
Issuance of Limited Partner Units, net | 275,856 | 1,696 | 195,060 | |||||||||
Issuance of senior notes | 996,349 | -- | -- | |||||||||
Issuance of junior subordinated notes | -- | 299,517 | -- | |||||||||
Debt issuance costs | (9,862 | ) | (4,052 | ) | -- | |||||||
Settlement of treasury lock agreements | (52,098 | ) | 1,443 | -- | ||||||||
Payment for termination of interest rate swap | -- | (1,235 | ) | -- | ||||||||
Acquisition of treasury units | (9 | ) | -- | -- | ||||||||
Distributions paid | (327,997 | ) | (294,450 | ) | (278,566 | ) | ||||||
Net cash provided by (used in) financing activities | 484,164 | (33,219 | ) | 594 | ||||||||
| Net change in cash and cash equivalents | 5 | (47 | ) | (49 | ) | |||||||
| Cash and cash equivalents, January 1 | 23 | 70 | 119 | |||||||||
| Cash and cash equivalents, December 31 | $ | 28 | $ | 23 | $ | 70 | ||||||
See Notes to Consolidated Financial Statements.
F-7
TEPPCO PARTNERS, L.P.
(Dollars in thousands)
| Accumulated | ||||||||||||||||
| General | Limited | Other | ||||||||||||||
| Partner’s | Partners’ | Comprehensive | ||||||||||||||
| Interest | Interests | (Loss) Income | Total | |||||||||||||
| Balance, December 31, 2005 | $ | (61,487 | ) | $ | 1,262,846 | $ | 11 | $ | 1,201,370 | |||||||
Net proceeds from issuance of Limited Partner Units | -- | 195,060 | -- | 195,060 | ||||||||||||
Net income allocation | 57,733 | 144,318 | -- | 202,051 | ||||||||||||
Cash distributions | (81,901 | ) | (196,665 | ) | -- | (278,566 | ) | |||||||||
Changes in fair values of crude oil financial instruments | -- | -- | 991 | 991 | ||||||||||||
Reclassification adjustment for gain included in net income | ||||||||||||||||
related to crude oil financial instruments | -- | -- | (261 | ) | (261 | ) | ||||||||||
Changes in fair values of interest rate and treasury lock financial instruments | -- | -- | (248 | ) | (248 | ) | ||||||||||
Adjustment to initially apply SFAS 158 | -- | -- | (67 | ) | (67 | ) | ||||||||||
| Balance, December 31, 2006 | (85,655 | ) | 1,405,559 | 426 | 1,320,330 | |||||||||||
Net proceeds from issuance of Limited Partner Units in connection with Employee Unit Purchase Plan | -- | 180 | -- | 180 | ||||||||||||
Net proceeds from issuance of Limited Partner Units in connection with Distribution Reinvestment Plan | -- | 1,516 | -- | 1,516 | ||||||||||||
Net income allocation | 45,987 | 233,193 | -- | 279,180 | ||||||||||||
Cash distributions | (48,298 | ) | (246,152 | ) | -- | (294,450 | ) | |||||||||
Non-cash contribution | -- | 426 | -- | 426 | ||||||||||||
Amortization of equity awards | -- | 428 | -- | 428 | ||||||||||||
Changes in fair values of crude oil financial instruments | -- | -- | (21,036 | ) | (21,036 | ) | ||||||||||
Reclassification adjustment for loss included in net income | ||||||||||||||||
related to crude oil financial instruments | -- | -- | 1,654 | 1,654 | ||||||||||||
Changes in fair values of interest rate and treasury lock financial instruments | -- | -- | (23,604 | ) | (23,604 | ) | ||||||||||
Reclassification adjustment for gain included in net income | ||||||||||||||||
related to interest rate and treasury lock financial instruments | -- | -- | (64 | ) | (64 | ) | ||||||||||
SFAS 158 pension benefit adjustment | -- | -- | 67 | 67 | ||||||||||||
| Balance, December 31, 2007 | (87,966 | ) | 1,395,150 | (42,557 | ) | 1,264,627 | ||||||||||
Issuance of units in connection with Cenac acquisition on February 1, 2008 | -- | 186,558 | -- | 186,558 | ||||||||||||
Net proceeds from issuance of Limited Partner Units in connection with Distribution Reinvestment Plan | -- | 11,455 | -- | 11,455 | ||||||||||||
Net proceeds from issuance of Limited Partner Units in connection with Employee Unit Purchase Plan | -- | 758 | -- | 758 | ||||||||||||
Net proceeds from issuance of Limited Partner Units | -- | 263,643 | -- | 263,643 | ||||||||||||
Acquisition of treasury units | -- | (9 | ) | -- | (9 | ) | ||||||||||
Net income allocation | 32,583 | 160,969 | -- | 193,552 | ||||||||||||
Cash distributions | (54,926 | ) | (273,071 | ) | -- | (327,997 | ) | |||||||||
Non-cash contribution | -- | 797 | -- | 797 | ||||||||||||
Amortization of equity awards | -- | 1,333 | -- | 1,333 | ||||||||||||
Changes in fair values of crude oil financial instruments | -- | -- | (19,257 | ) | (19,257 | ) | ||||||||||
Reclassification adjustment for loss included in net income | ||||||||||||||||
related to crude oil financial instruments | -- | -- | 37,898 | 37,898 | ||||||||||||
Changes in fair values of treasury lock financial instruments | -- | -- | (26,802 | ) | (26,802 | ) | ||||||||||
Reclassification adjustment for loss included in net income | ||||||||||||||||
related to treasury lock financial instruments | -- | -- | 4,923 | 4,923 | ||||||||||||
| Balance, December 31, 2008 | $ | (110,309 | ) | $ | 1,747,583 | $ | (45,795 | ) | $ | 1,591,479 | ||||||
See Notes to Consolidated Financial Statements.
Except per unit amounts, or as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are stated in thousands.
NOTE 1. PARTNERSHIP ORGANIZATION
Partnership Organization
TEPPCO Partners, L.P. (the “Partnership”) is a publicly traded, diversified energy logistics company with operations that span much of the continental United States. Our limited partner units (“Units”) are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “TPP”. We were formed in March 1990 as a Delaware limited partnership. As used in this Report, “we,” “us,” “our,” the “Partnership” and “TEPPCO” mean TEPPCO Partners, L.P. and, where the context requires, include our subsidiaries.
We operate through TE Products Pipeline Company, LLC (“TE Products”), TCTM, L.P. (“TCTM”) TEPPCO Midstream Companies, LLC (“TEPPCO Midstream”), and beginning February 1, 2008, through TEPPCO Marine Services, LLC (“TEPPCO Marine Services”). Texas Eastern Products Pipeline Company, LLC (the “General Partner”), a Delaware limited liability company, serves as our general partner and owns a 2% general partner interest in us. We hold a 99.999% limited partner interest in TCTM, 99.999% membership interests in each of TE Products and TEPPCO Midstream and a 100% membership interest in TEPPCO Marine Services. TEPPCO GP, Inc. (“TEPPCO GP”), our subsidiary, holds a 0.001% general partner interest in TCTM and a 0.001% managing member interest in each of TE Products and TEPPCO Midstream.
Dan L. Duncan and certain of his affiliates, including Enterprise GP Holdings L.P. (“Enterprise GP Holdings”) and Dan Duncan LLC, a privately held company controlled by him, control us, our General Partner and Enterprise Products Partners L.P. (“Enterprise Products Partners”) and its affiliates, including Duncan Energy Partners L.P. (“Duncan Energy Partners”). Enterprise GP Holdings owns and controls the 2% general partner interest in us and has the right (through its 100% ownership of our General Partner) to receive the incentive distribution rights associated with the general partner interest. Enterprise GP Holdings, DFI GP Holdings L.P. (“DFIGP”) and other entities controlled by Mr. Duncan own 17,073,315 of our Units, which include 2,500,000 of our Units owned by DFIGP. Under an amended and restated administrative services agreement (“ASA”), EPCO, Inc. (“EPCO”), a privately held company also controlled by Mr. Duncan, performs management, administrative and operating functions required for us, and we reimburse EPCO for all direct and indirect expenses that have been incurred in managing us.
Partnership Agreement
On December 8, 2006, at a special meeting of our unitholders, the Fourth Amended and Restated Agreement of Limited Partnership (the “New Partnership Agreement”), which amended and restated the Third Amended and Restated Agreement of Limited Partnership in effect prior to the special meeting (the “Previous Partnership Agreement”) was approved and became effective. The New Partnership Agreement contained the following amendments to the Previous Partnership Agreement, among others:
| § | changes to certain provisions that relate to distributions and capital contributions, including the reduction in the General Partner’s incentive distribution rights from 50% to 25% (“IDR Reduction Amendment”), elimination of the General Partner’s requirement to make capital contributions to us to maintain a 2% capital account, and adjustment of our minimum quarterly distribution and target distribution levels for entity-level taxes; |
| § | changes to various voting percentage requirements, in most cases from 66 2/3% of outstanding Units to a majority of outstanding Units; |
| § | the percentage of holders of outstanding Units necessary to constitute a quorum was reduced from 66 2/3% to a majority of the outstanding Units; |
F-9
TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
| § | removal of provisions requiring unitholder approval for specified actions with respect to our operating companies, TCTM, TE Products and TEPPCO Midstream; |
| § | changes to supplement and revise certain provisions that relate to conflicts of interest and fiduciary duties; and |
| § | changes to provide for certain registration rights of the General Partner and its affiliates (including with respect to the Units issued in respect of the IDR Reduction Amendment, as described below), for the maintenance of the separateness of us from any other person or entity and other miscellaneous matters. |
References in this Report to our “Partnership Agreement” are to our partnership agreement (including, as applicable, the Previous Partnership Agreement or the New Partnership Agreement), as in effect from time to time. By approval of the various proposals at the special meeting, and upon effectiveness of the New Partnership Agreement, an agreement was effectuated whereby we issued 14,091,275 Units on December 8, 2006 to our General Partner as consideration for the IDR Reduction Amendment. The number of Units issued to our General Partner was based upon a predetermined formula that, based on the distribution rate and the number of Units outstanding at the time of the issuance, resulted in our General Partner receiving cash distributions from the newly-issued Units and from its reduced maximum percentage interest in our quarterly distributions approximately equal to the cash distributions our General Partner would have received from its maximum percentage interest in our quarterly distributions without the IDR Reduction Amendment. Effective as of December 8, 2006, the General Partner distributed the newly issued Units to its member, which in turn caused them to be distributed to other affiliates of EPCO.
On December 27, 2007, our Partnership Agreement was amended in order to comply with the NYSE’s eligibility rules regarding the Depository Trust Company’s Direct Registration System. On November 6, 2008, our Partnership Agreement was amended to clarify that amendments of certain provisions thereof would not impair indemnitees’ rights to receive expense advancements (in addition to indemnification) under the Partnership Agreement.
At December 31, 2008, 2007 and 2006, we had outstanding 104,704,861, 89,911,532 and 89,804,829 Units, respectively.
NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
We adhere to the following significant accounting policies in the preparation of our consolidated financial statements.
Business Segments
We operate and report in four business segments:
| § | pipeline transportation, marketing and storage of refined products, liquefied petroleum gases (“LPGs”) and petrochemicals (“Downstream Segment”); |
| § | gathering, pipeline transportation, marketing and storage of crude oil, distribution of lubrication oils and specialty chemicals and fuel transportation services (“Upstream Segment”); |
| § | gathering of natural gas, fractionation of natural gas liquids (“NGLs”) and pipeline transportation of NGLs (“Midstream Segment”); and |
| § | marine transportation of refined products, crude oil, condensate, asphalt, heavy fuel oil and other heated oil products via tow boats and tank barges (“Marine Services Segment”). |
F-10
TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Our reportable segments offer different products and services and are managed separately because each requires different business strategies (see Note 14).
Our interstate transportation operations, including rates charged to customers, are subject to regulations prescribed by the Federal Energy Regulatory Commission (“FERC”). We refer to refined products, LPGs, petrochemicals, crude oil, lubrication oils and specialty chemicals, NGLs, natural gas, asphalt, heavy fuel oil and other heated oil products in this Report, collectively, as “petroleum products” or “products.”
Allowance for Doubtful Accounts
Our allowance for doubtful accounts balance is generally determined based on specific identification and estimates of future uncollectible accounts, as appropriate. Our procedure for recording an allowance for doubtful accounts is based on (i) our historical experience, (ii) the financial stability of our customers and (iii) the levels of credit granted to customers. In addition, we may also increase the allowance account in response to specific identification of customers involved in bankruptcy proceedings and those experiencing other financial difficulties. We routinely review estimates associated with the allowance for doubtful accounts to assess the sufficiency of the reserves to cover potential losses. The following table presents the activity of our allowance for doubtful accounts for the years ended December 31, 2008, 2007 and 2006:
| For Year Ended December 31, | ||||||||||||
| 2008 | 2007 | 2006 | ||||||||||
Balance at January 1 | $ | 125 | $ | 100 | $ | 250 | ||||||
Charges to expense (1) | 2,434 | 25 | 64 | |||||||||
Deductions and other | -- | -- | (214 | ) | ||||||||
Balance at December 31 | $ | 2,559 | $ | 125 | $ | 100 | ||||||
_________________
| (1) | Charges to expense for the year ended December 31, 2008 include the write-off of receivables primarily attributable to two customer bankruptcies. |
Asset Retirement Obligations
Asset retirement obligations (“AROs”) are legal obligations associated with the retirement of tangible long-lived assets that result from their acquisition, construction, development and/or normal operation. We record a liability for AROs when incurred and capitalize an increase in the carrying value of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over its useful life. We will either settle our ARO obligations at the recorded amount or incur a gain or loss upon settlement. See Note 8 for further information regarding our AROs.
The Downstream Segment assets consist primarily of an interstate trunk pipeline system and a series of storage facilities that originate along the upper Texas Gulf Coast and extend through the Midwest and northeastern United States. We transport refined products, LPGs and petrochemicals through the pipeline system. These products are primarily received in the south end of the system and stored and/or transported to various points along the system per customer nominations. The Upstream Segment’s operations include purchasing crude oil from producers at the wellhead and providing delivery, storage and other services to its customers. The principal properties in the Upstream Segment consist of interstate trunk pipelines, pump stations, trucking facilities, storage tanks and various gathering systems primarily in Texas and Oklahoma. The Midstream Segment gathers natural gas from wells owned by producers and delivers natural gas and NGLs on its pipeline systems, primarily in Texas, Wyoming, New Mexico and Colorado. The Midstream Segment also owns and operates two NGL fractionation facilities in Colorado. The Marine Services Segment’s principal assets consist of tow boats and tank barges used in the marine transportation of refined products, crude oil, condensate, asphalt, heavy fuel oil and other heated oil products.
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TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
We have determined that we are obligated by contractual or regulatory requirements to remove certain facilities or perform other remediation upon retirement of our assets. However, we are not able to reasonably determine the fair value of the AROs for our trunk, interstate and gathering pipelines and our surface facilities, since future dismantlement and removal dates are indeterminate. During 2006, we recorded conditional AROs related to the retirement of the Val Verde Gas Gathering Company, L.P. (“Val Verde”) natural gas gathering system and to structural restoration work to be completed on leased office space that is required upon our anticipated office lease termination.
In order to determine a removal date for our crude oil gathering lines and related surface assets, reserve information regarding the production life of the specific field is required. As a transporter and gatherer of crude oil, we are not a producer of the field reserves, and we therefore do not have access to adequate forecasts that predict the timing of expected production for existing reserves on those fields in which we gather crude oil. In the absence of such information, we are not able to make a reasonable estimate of when future dismantlement and removal dates of our crude oil gathering assets will occur. With regard to our trunk and interstate pipelines and their related surface assets, it is impossible to predict when demand for transportation of the related products will cease. Our right-of-way agreements allow us to maintain the right-of-way rather than remove the pipe. In addition, we can evaluate our trunk pipelines for alternative uses, which can be and have been found. We will record AROs in the period in which sufficient information becomes available for us to reasonably estimate the settlement dates of the retirement obligations.
Basis of Presentation and Principles of Consolidation
The financial statements include our accounts on a consolidated basis. We have eliminated all significant intercompany items in consolidation. Our results for the year ended December 31, 2006 reflects the operations and activities of Jonah Gas Gathering Company’s (“Jonah”) Pioneer plant as discontinued operations.
Cash and Cash Equivalents
Cash and cash equivalents represent unrestricted cash on hand and liquid investments with maturities of three months or less when purchased. The carrying value of cash equivalents approximate fair value because of the short term nature of these investments.
Our Statements of Consolidated Cash Flows are prepared using the indirect method. The indirect method derives net cash flows from operating activities by adjusting net income to remove (i) the effects of all deferrals of past operating cash receipts and payments, such as changes during the period in inventory, deferred income and similar transactions, (ii) the effects of all accruals of expected future operating cash receipts and cash payments, such as changes during the period in receivables and payables, (iii) the effects of all items classified as investing or financing cash flows, such as gains or losses on sale of property, plant and equipment or extinguishment of debt, and (iv) other non-cash amounts such as depreciation, amortization and changes in the fair market value of financial instruments.
Capitalization of Interest
We capitalize interest on borrowed funds related to capital projects only for periods that activities are in progress to bring these projects to their intended use. The weighted average rates used to capitalize interest on borrowed funds were 6.43%, 6.45% and 6.27% for the years ended December 31, 2008, 2007 and 2006, respectively.
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TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Consolidation Policy
Our consolidated financial statements include our accounts and those of our majority-owned subsidiaries in which we have a controlling financial or equity interest, after the elimination of all significant intercompany accounts and transactions. We evaluate our financial interests in companies to determine if they represent variable interest entities where we are the primary beneficiary. If such criteria are met, we consolidate the financial statements of such businesses with those of our own.
If an investee is organized as a limited partnership or limited liability company and maintains separate ownership accounts, we account for our investment using the equity method if our ownership interest is between 3% and 50% and we exercise significant influence over the entity’s operating and financial policies. For all other types of investments, we apply the equity method of accounting if our ownership interest is between 20% and 50% and we exercise significant influence over the entity’s operating and financial policies. In consolidation, we eliminate our proportionate share of profits and losses from transactions with equity method unconsolidated affiliates to the extent such amounts are material and remain on our balance sheet (or those of our equity method investments) in inventory or similar accounts.
Our investments in Seaway Crude Pipeline Company (“Seaway”) and Centennial Pipeline LLC (“Centennial”) are accounted for under the equity method of accounting, as we own 50% ownership interests in these entities and have 50% equal management with the other joint venture participants. Our investment in Texas Offshore Port System (a development stage enterprise) is accounted for under the equity method of accounting, as we own a 33% ownership interest in this entity and have equal voting rights with the other joint venture participants. Our investment in Jonah is accounted for under the equity method of accounting, as we have 50% equal management with the other participant, even though we own an approximate 80% economic interest in the partnership.
If our ownership interest in an entity does not provide us with either control or significant influence over the investee, we account for the investment using the cost method.
Contingencies
Certain conditions may exist as of the date our financial statements are issued, which may result in a loss to us but which will only be resolved when one or more future events occur or fail to occur. Our management with input from legal counsel assesses such contingent liabilities, and such assessment inherently involves an exercise in judgment. In assessing loss contingencies related to legal proceedings that are pending against us or unasserted claims that may result in proceedings, our management with input from legal counsel evaluates the perceived merits of any legal proceedings or unasserted claims as well as the perceived merits of the amount of relief sought or expected to be sought therein.
If the assessment of a contingency indicates that it is probable that a material loss has been incurred and the amount of liability can be estimated, then the estimated liability would be accrued in our financial statements. If the assessment indicates that a potentially material loss contingency is not probable but is reasonably possible, or is probable but cannot be estimated, then the nature of the contingent liability, together with an estimate of the range of possible loss if determinable and material, is disclosed.
Loss contingencies considered remote are generally not disclosed unless they involve guarantees, in which case the guarantees would be disclosed.
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TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Current Assets and Current Liabilities
We present, as individual captions in our consolidated balance sheets, all components of current assets and current liabilities that exceed five percent of total current assets and liabilities, respectively.
Environmental Expenditures
We accrue for environmental costs that relate to existing conditions caused by past operations, including conditions with assets we have acquired. Environmental costs include initial site surveys and environmental studies of potentially contaminated sites, costs for remediation and restoration of sites determined to be contaminated and ongoing monitoring costs, as well as damages and other costs, when estimable. We monitor the balance of accrued undiscounted environmental liabilities on a regular basis. We record liabilities for environmental costs at a specific site when our liability for such costs is probable and a reasonable estimate of the associated costs can be made. Adjustments to initial estimates are recorded, from time to time, to reflect changing circumstances and estimates based upon additional information developed in subsequent periods. Estimates of our ultimate liabilities associated with environmental costs are particularly difficult to make with certainty due to the number of variables involved, including the early stage of investigation at certain sites, the lengthy time frames required to complete remediation alternatives available and the evolving nature of environmental laws and regulations. None of our estimated environmental remediation liabilities are discounted to present value since the ultimate amount and timing of cash payments for such liabilities are not readily determinable. Expenditures to mitigate or prevent future environmental contamination are capitalized.
At December 31, 2008 and 2007, our accrued liabilities for environmental remediation projects totaled $6.9 million and $4.0 million, respectively. These amounts were derived from a range of reasonable estimates based upon studies and site surveys. Unanticipated changes in circumstances and/or legal requirements could result in expenses being incurred in future periods in addition to an increase in actual cash required to remediate contamination for which we are responsible.
The following table presents the activity of our environmental reserve for the years ended December 31, 2008, 2007 and 2006:
| For Year Ended December 31, | ||||||||||||
| 2008 | 2007 | 2006 | ||||||||||
Balance at January 1 | $ | 4,002 | $ | 1,802 | $ | 2,447 | ||||||
Charges to expense | 4,981 | 3,402 | 1,887 | |||||||||
Deductions and other | (2,047 | ) | (1,202 | ) | (2,532 | ) | ||||||
Balance at December 31 | $ | 6,936 | $ | 4,002 | $ | 1,802 | ||||||
Estimates
The preparation of financial statements in conformity with U.S. generally accepted accounting principles (“GAAP”) requires our management to make estimates and assumptions that affect the reported amounts of assets and liabilities 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 periods. Although we believe these estimates are reasonable, actual results could differ from those estimates.
Fair Value of Current Assets and Current Liabilities
The carrying amount of cash and cash equivalents, accounts receivable, inventories, other current assets, accounts payable and accrued liabilities, other current liabilities and financial instruments approximates their fair
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TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
value due to their short-term nature. The fair values of these financial instruments are represented in our consolidated balance sheets.
Financial Instruments
We account for financial instruments in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 133, Accounting for Derivative Instruments and Hedging Activities, and SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities, an amendment of FASB Statement No. 133. These statements establish accounting and reporting standards requiring that financial instruments (including certain financial instruments embedded in other contracts) be recorded on the balance sheet at fair value as either assets or liabilities. The accounting for changes in the fair value of a financial instrument depends on the intended use of the financial instrument and the resulting designation, which is established at the inception of a financial instrument.
Our financial instruments consist primarily of contracts for the purchase and sale of petroleum products in connection with our crude oil marketing activities. Substantially all financial instruments related to our crude oil marketing activities meet the normal purchases and sales criteria of SFAS 133, as amended, and as such, changes in the fair value of petroleum product purchase and sales agreements are reported on the accrual basis of accounting. SFAS 133 describes normal purchases and sales as contracts that provide for the purchase or sale of something other than a financial instrument that will be delivered in quantities expected to be used or sold by the reporting entity over a reasonable period in the normal course of business.
For all hedging relationships, we formally document at inception the hedging relationship and its risk-management objective and strategy for undertaking the hedge, the hedging instrument, the item, the nature of the risk being hedged, how the hedging instrument’s effectiveness in offsetting the hedged risk will be assessed and a description of the method of measuring ineffectiveness. This process includes linking all financial instruments that are designated as fair value or cash flow to specific assets and liabilities on the balance sheet or to specific firm commitments or forecasted transactions. We also formally assess, both at the hedge’s inception and on an ongoing basis, whether the financial instruments that are used in hedging transactions are highly effective in offsetting changes in fair values or cash flows of hedged items. If it is determined that a financial instrument is not highly effective as a hedge or that it has ceased to be a highly effective hedge, we discontinue hedge accounting prospectively.
For financial instruments designated as fair value hedges, changes in the fair value of a financial instrument that is highly effective and that is designated and qualifies as a fair value hedge, along with the loss or gain on the hedged asset or liability or unrecognized firm commitment of the hedged item that is attributable to the hedged risk, are recorded in earnings with the change in fair value of the financial instrument and hedged asset or liability reflected on the balance sheet. Changes in the fair value of a financial instrument that is highly effective and that is designated and qualifies as a cash flow hedge are recorded in other comprehensive income to the extent that the financial instrument is effective as a hedge, until earnings are affected by the variability in cash flows of the designated hedged item. Hedge effectiveness is measured at least quarterly based on the relative cumulative changes in fair value between the financial instrument contract and the hedged item over time. The ineffective portion of the change in fair value of a financial instrument that qualifies as either a fair value hedge or a cash flow hedge is reported immediately in earnings.
According to SFAS 133, as amended, we are required to discontinue hedge accounting prospectively when it is determined that the financial instrument is no longer effective in offsetting changes in the fair value or cash flows of the hedged item, or the financial instrument expires or is sold, terminated, or exercised, or the financial instrument is de-designated as a hedging instrument, because it is unlikely that a forecasted transaction will occur, a hedged firm commitment no longer meets the definition of a firm commitment, or management determines that designation of the financial instrument as a hedging instrument is no longer appropriate.
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TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
When hedge accounting is discontinued because it is determined that the financial instrument no longer qualifies as an effective fair value hedge, we continue to carry the financial instrument on the balance sheet at its fair value and no longer adjust the hedged asset or liability for changes in fair value. The adjustment of the carrying amount of the hedged asset or liability is accounted for in the same manner as other components of the carrying amount of that asset or liability. When hedge accounting is discontinued because the hedged item no longer meets the definition of a firm commitment, we continue to carry the financial instrument on the balance sheet at its fair value, remove any asset or liability that was recorded pursuant to recognition of the firm commitment from the balance sheet, and recognize any gain or loss in earnings. When hedge accounting is discontinued because it is probable that a forecasted transaction will not occur, we continue to carry the financial instrument on the balance sheet at its fair value with subsequent changes in fair value included in earnings, and gains and losses that were accumulated in other comprehensive income are recognized immediately in earnings. In all other situations in which hedge accounting is discontinued, we continue to carry the financial instrument at its fair value on the balance sheet and recognize any subsequent changes in its fair value in earnings.
Goodwill
Goodwill represents the excess of purchase price over fair value of net assets acquired. Our goodwill amounts are assessed for impairment (i) on an annual basis during the fourth quarter of each year or (ii) on an interim basis when impairment indicators are present. If such indicators are present (e.g., loss of a significant customer, economic obsolescence of plant assets, etc.), the fair value of the reporting unit to which the goodwill is assigned will be calculated and compared to its book value.
If the fair value of the reporting unit exceeds its book value, the goodwill amount is not considered to be impaired and no impairment charge is required. If the fair value of the reporting unit is less than its book value, a charge to earnings is recorded to adjust the carrying value of the goodwill to its implied fair value. We have not recognized any impairment losses related to our goodwill for any of the periods presented (see Note 11 for a further discussion of our goodwill).
Income Taxes
We are a limited partnership, organized as a pass-through entity for federal income tax purposes. As a result, our partners are responsible for federal income taxes on their share of our taxable income. Except as noted below, we are not a taxable entity for federal and state income tax purposes and do not directly pay federal and state income tax. Our taxable income or loss, which may vary substantially from the net income or net loss we report in our statements of consolidated income, is includable in the federal and state income tax returns of each unitholder. Accordingly, except as noted below, no recognition has been given to federal and state income taxes for our operations.
Revised Texas Franchise Tax
In general, legal entities that conduct business in Texas are subject to the Revised Texas Franchise Tax. In May 2006, the State of Texas expanded its pre-existing franchise tax to include limited partnerships, limited liability companies, corporations and limited liability partnerships. As a result of the change in tax law, our tax status in the State of Texas has changed from non-taxable to taxable. TE Products (formerly TE Products Pipeline Company, Limited Partnership) and TEPPCO Midstream (formerly TEPPCO Midstream Companies, L.P.) each converted into a Texas limited partnership and immediately thereafter each merged into a separate newly-formed Texas limited liability company on June 30, 2007. The pre-June 30, 2007 revenue of each of these former partnerships was not subject to the Revised Texas Franchise Tax because the former partnerships did not conduct business in Texas after June 30, 2007.
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TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
For the years ended December 31, 2008, 2007 and 2006, our provision for income taxes is applicable to our state tax obligations under the Revised Texas Franchise Tax. At December 31, 2008 and 2007, we had current tax liabilities of $3.9 million and $1.2 million, respectively. At December 31, 2008, we had a deferred tax liability of less than $0.1 million, while at December 31, 2007, we had a deferred tax asset of less than $0.1 million. During the years ended December 31, 2008 and 2007, we recorded increases in current income tax liabilities of $4.5 million and $1.2 million, respectively. During the years ended December 31, 2008 and 2007, we recorded a less than $0.1 million increase to deferred tax liability and a $0.7 million reduction to deferred tax liability, respectively. The offsetting net charges to deferred tax expense and income tax expense are shown on our statements of consolidated income as provision for income taxes.
Accounting for Uncertainty in Income Taxes
In accordance with Financial Accounting Standards Board (“FASB”) Interpretation No. 48, Accounting for Uncertainty in Income Taxes, we must recognize the tax effects of any uncertain tax positions we may adopt, if the position taken by us is more likely than not sustainable. If a tax position meets such criteria, the tax effect to be recognized by us would be the largest amount of benefit with more than a 50% chance of being realized upon ultimate settlement with a taxing authority with full knowledge of all relevant information. This guidance was effective January 1, 2007, and our adoption of this guidance had no material impact on our financial position, results of operations or cash flows.
Intangible Assets and Excess Investments
Intangible assets on the consolidated balance sheets consist primarily of gathering contracts assumed in the acquisition of Val Verde on June 30, 2002, a fractionation agreement, customer contracts related to the acquisition of crude oil supply and transportation assets, customer relationships and non-compete agreements related to the acquisition of the marine assets and other intangible assets (see Note 11). Included in equity investments on the consolidated balance sheets are excess investments in Centennial, Seaway and Jonah.
In connection with the acquisition of Val Verde, we assumed fixed-term contracts with customers that gather coal bed methane from the San Juan Basin in New Mexico and Colorado. The value assigned to these intangible assets relates to contracts with customers that are for a fixed term. These intangible assets are amortized on a unit-of-production basis, based upon the actual throughput of the system over the expected total throughput for the lives of the contracts. Revisions to the unit-of-production estimates may occur as additional production information is made available to us (see Note 11).
In connection with the formation of Centennial, we recorded excess investment, the majority of which is amortized on a unit-of-production basis over a period of 10 years. In connection with the acquisition of our interest in Seaway, we recorded excess investment, which is amortized on a straight-line basis over a period of 39 years. In connection with the formation of our Jonah joint venture and the construction of its expansion, we recorded excess investment, which is amortized on a straight-line basis over the life of the assets constructed (see Note 11).
Inventories
Inventories consist primarily of petroleum products, which are valued at the lower of cost (weighted average cost method) or market. Our Downstream Segment acquires and disposes of various products under purchase, sale and exchange agreements. Receivables and payables arising from exchange transactions are usually satisfied with products rather than cash. The net balances of exchange receivables and payables are valued at weighted average cost and included in inventories. Our Upstream Segment also acquires and disposes of crude oil under purchase, sale, buy/sell and exchange agreements. Additionally, our Upstream Segment acquires crude oil inventory through a pipeline loss allowance (“PLA”) in certain of our pipeline tariffs, whereby the shipper conveys physical crude oil to us, in addition to a cash tariff payment for transportation services, in exchange for our bearing
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TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
the risk of pipeline volumetric losses. These PLA barrels are recorded to inventory based on the current market value at the time the barrels are transported and later sold. Inventories of materials and supplies, used for ongoing replacements and expansions, are carried at cost.
Natural Gas Imbalances
Gas imbalances occur when gas producers (customers) deliver more or less actual natural gas gathering volumes to our gathering systems than they originally nominated. Actual deliveries are different from nominated volumes due to fluctuations in gas production at the wellhead. To the extent that these shipper imbalances are not cashed out, Val Verde records a payable to shippers who supply more natural gas gathering volumes than nominated, and a receivable from the shippers who nominate more natural gas gathering volumes than supplied. To the extent pipeline imbalances are not cashed out, Val Verde records a receivable from connecting pipeline transporters when total volumes delivered exceed the total of shipper’s nominations and records a payable to connecting pipeline transporters when the total shippers’ nominations exceed volumes delivered. We record natural gas imbalances using average market prices, which is representative of the estimated value of the imbalances upon final settlement.
Net Income Per Unit
Basic net income per Unit is computed by dividing net income or loss, after deduction of the General Partner’s interest, by the weighted average number of distribution-bearing Units outstanding during a period. The General Partner’s percentage interest in our net income is based on its percentage of cash distributions from Available Cash for each period (see Note 13). Diluted net income per Unit is computed by dividing net income or loss, after deduction of the General Partner’s interest, by the sum of (i) the weighted average number of distribution-bearing Units outstanding during a period (as used in determining basic earnings per Unit); and (ii) the number of incremental Units resulting from the assumed exercise of dilutive unit options outstanding during a period (the “incremental option units”) (see Note 16).
In a period of net operating losses, restricted units and incremental option units are excluded from the calculation of diluted earnings per Unit due to their anti-dilutive effect. The dilutive incremental option units are calculated using the treasury stock method, which assumes that proceeds from the exercise of all in-the-money options at the end of each period are used to repurchase Units at an average market value during the period. The amount of Units remaining after the proceeds are exhausted represents the potentially dilutive effect of the securities.
The General Partner’s percentage interest in our net income increases as cash distributions paid per Unit increase above specified levels, in accordance with our Partnership Agreement. On December 8, 2006, our Partnership Agreement was amended and restated, and our General Partner’s maximum percentage interest in our quarterly distributions was reduced from 50% to 25% in exchange for 14.1 million Units (see Note 1).
Property, Plant and Equipment
Property, plant and equipment is recorded at its acquisition cost. Additions to property, plant and equipment, including major replacements or betterments, are recorded at cost. We charge replacements and renewals of minor items of property that do not materially increase values or extend useful lives to maintenance expense. Depreciation expense is computed on the straight-line method using rates based upon expected useful lives of various classes of assets (ranging from 2% to 20% per annum).
We evaluate impairment of long-lived assets in accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of
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TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
the carrying amount of assets to be held and used is measured by a comparison of the carrying amount of the asset to estimated future net cash flows expected to be generated by the asset. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the estimated fair value of the assets. Assets to be disposed of are reported at the lower of the carrying amount or estimated fair value less costs to sell.
Revenue Recognition
Our Downstream Segment revenues are earned from pipeline transportation, marketing and storage of refined products and LPGs, intrastate pipeline transportation of petrochemicals, sale of product inventory and other ancillary services. Transportation revenues are recognized as products are delivered to customers. Storage revenues are recognized upon receipt of products into storage and upon performance of storage services. Refined products terminaling revenues are recognized as products are out-loaded. From time to time, we buy and sell products to balance our inventory for operational needs, and the gains or losses from the sale of product inventory are recognized when the products are sold. Our refined products marketing activities generate revenues by purchasing refined products from our throughput partner and establishing a margin by selling refined products for physical delivery through spot and contract sales. These marketing activities are conducted at our Aberdeen and Boligee truck racks to independent wholesalers and retailers of refined products. Spot purchases and sales are generally contracted to occur on the same day.
Our Upstream Segment revenues are earned from gathering, pipeline transporting, marketing and storing crude oil, distributing lubrication oils and specialty chemicals, and fuel transportation services principally in Oklahoma, Texas, New Mexico and the Rocky Mountain region. Revenues are also generated from trade documentation and terminaling services, primarily at Cushing, Oklahoma, and Midland, Texas. Revenues are accrued at the time title to the product sold transfers to the purchaser, which typically occurs upon receipt of the product by the purchaser, and purchases are accrued at the time title to the product purchased transfers to our crude oil marketing company, TEPPCO Crude Oil, LLC (“TCO”), which typically occurs upon our receipt of the product. Revenues related to trade documentation and terminaling services are recognized as services are completed.
Except for crude oil purchased from time to time as inventory required for operations, our policy is to purchase only crude oil for which we have a market to sell and to structure sales contracts so that crude oil price fluctuations do not materially affect the margin received. As we purchase crude oil, we establish a margin by selling crude oil for physical delivery to third party users or by entering into a future delivery obligation. Through these transactions, we seek to maintain a position that is balanced between crude oil purchases and sales and future delivery obligations. However, commodity price risks cannot be completely hedged. In addition, when PLA barrels in crude oil inventory are sold, we recognize gains or losses in revenues depending on the current market price at the date of sale.
Our Midstream Segment revenues are earned from the gathering of natural gas, pipeline transportation of NGLs and fractionation of NGLs. Gathering revenues are recognized as natural gas is received from the customer. Transportation revenues are recognized as NGLs are delivered. Based upon contract terms, fractionation revenues are recognized based upon the volume of NGLs fractionated at a fixed rate per gallon. We generally do not take title to the natural gas gathered, NGLs transported or NGLs fractionated, with the exception of natural gas imbalances that are settled in-kind. Since we record natural gas imbalances using average market prices, the results of our Midstream Segment are affected by changes in the prices of natural gas.
Our Marine Services Segment revenues are earned from inland and offshore transportation of refined products, crude oil, condensate, asphalt, heavy fuel oil and other heated oil products via tow boats and tank barges. We also provide offshore flow-back operations relating to well-testing and pipeline remediation and utilize our offshore tugs in general towing operations. Our transportation services are generally provided under term contracts (also referred to as affreightment contracts), which are agreements with specific customers to transport cargo from
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TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
within designated operating areas at set day rates or a set fee per cargo movement. Most of the inland term contracts have one-year terms with the remainder having terms of up to two years. Substantially all of the inland contracts have renewal options, which are exercisable subject to agreement on rates applicable to the option terms. Most of the offshore service and transportation contracts have up to one-year terms with renewal options, which are exercisable subject to agreement on rates applicable to the option terms, or are spot contracts. A spot contract is an agreement with a customer to move cargo within designated operating areas for a rate negotiated at the time the cargo movement takes place. Revenue is recognized over the transit time of individual tows as determined on an individual contract basis, which are generally less than ten days in duration. We estimate unbilled revenue at the end of each financial reporting period. Unbilled revenue represents revenue attributable to that portion of transportation services that has taken place prior to period end which is part of a voyage still in progress and has not yet been invoiced. We do not assume ownership of the products we transport in this segment. As is typical for inland and offshore affreightment contracts, the term contracts establish set day rates but do not include revenue or volume guarantees. Most of the contracts include escalation provisions to recover specific increased operating costs such as incremental increases in labor. The costs of fuel, substantially all of which is a pass through expense, and other specified operational fees and costs are directly reimbursed by the customer under most of the contracts.
Equity Awards
We account for equity awards in accordance with SFAS No. 123(R), Share-Based Payment. SFAS 123(R) requires us to recognize compensation expense related to equity awards based on the fair value of the award at grant date. The fair value of restricted unit awards is based on the market price of the underlying Units on the date of grant. The fair value of other equity awards is estimated using the Black-Scholes option pricing model. Under SFAS 123(R), the fair value of an equity award is amortized to earnings on a straight-line basis over the requisite service or vesting period of the equity awards. As used in the context of the compensation plans, the term “restricted unit” represents a time-vested unit under SFAS 123(R). Such awards are non-vested until the required service period expires. Compensation for liability awards is recognized over the requisite service or vesting period of an award based on the fair value of the award remeasured at each reporting period. Liability awards will be settled in cash upon vesting. We accrue compensation expense based upon the terms of each plan (see Note 4).
NOTE 3. RECENT ACCOUNTING DEVELOPMENTS
The accounting standard setting bodies have recently issued the following accounting guidance that may affect our future financial statements: SFAS No. 141(R), Business Combinations; FASB Staff Position (“FSP”) SFAS 142-3, Determination of the Useful Life of Intangible Assets; SFAS No. 157, Fair Value Measurements; SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities – An Amendment of FASB Statement No. 133; Emerging Issues Task Force (“EITF”) 08-6, Equity Method Investment Accounting Considerations; and EITF 07-4, Application of the Two Class Method Under FASB Statement No. 128, Earnings Per Share, to Master Limited Partnerships (“MLPs”).
SFAS No. 141(R), Business Combinations. SFAS 141(R) replaces SFAS No. 141, Business Combinations and was effective January 1, 2009. SFAS 141(R) retains the fundamental requirements of SFAS 141 in that the acquisition method of accounting (previously termed the “purchase method”) is used for all business combinations and for the “acquirer” to be identified for each business combination. SFAS 141(R) defines the acquirer as the entity that obtains control of one or more businesses in a business combination and establishes the acquisition date as the date that the acquirer achieves control. This new guidance also retains guidance in SFAS 141 for identifying and recognizing intangible assets separately from goodwill. SFAS 141(R) will have an impact on the way in which we evaluate acquisitions.
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TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The objective of SFAS 141(R) is to improve the relevance, representational faithfulness, and comparability of the information a reporting entity provides in its financial reports about business combinations and their effects. To accomplish this, SFAS 141(R) establishes principles and requirements for how the acquirer:
| § | recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interests in the acquiree. |
| § | recognizes and measures the goodwill acquired in the business combination or a gain resulting from a bargain purchase. SFAS 141(R) defines a bargain purchase as a business combination in which the total acquisition-date fair value of the identifiable net assets acquired exceeds the fair value of the consideration transferred plus any noncontrolling interest in the acquiree, and requires the acquirer to recognize that excess in net income as a gain attributable to the acquirer. |
| § | determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. |
SFAS 141(R) also requires that direct costs of an acquisition (e.g. finder’s fees, outside consultants, etc.) be expensed as incurred and not capitalized as part of the purchase price.
FSP No. FAS 142-3, Determination of the Useful Life of Intangible Assets. In April 2008, the FASB issued FSP No. 142-3, which revised the factors that should be considered in developing renewal or extension assumptions used in determining the useful lives of recognized intangible assets under SFAS No. 142, Goodwill and Other Intangible Assets. These revisions are intended to improve consistency between the useful life of a recognized intangible asset under SFAS 142 and the period of expected cash flows used to measure the fair value of such assets under SFAS 141(R) and other accounting guidance. The measurement and disclosure requirements of this new guidance will be applied to intangible assets acquired after January 1, 2009. Our adoption of this guidance is not expected to have a material impact on our consolidated financial statements.
SFAS No. 157, Fair Value Measurements. SFAS 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. Although certain provisions of SFAS 157 were effective January 1, 2008, the remaining guidance of this new standard applicable to nonfinancial assets and liabilities was effective January 1, 2009. See Note 6 for information regarding fair value-related disclosures required for 2008 in connection with SFAS 157.
SFAS 157 applies to fair-value measurements that are already required (or permitted) by other accounting standards and is expected to increase the consistency of those measurements. SFAS 157 emphasizes that fair value is a market-based measurement that should be determined based on the assumptions that market participants would use in pricing an asset or liability. Companies are required to disclose the extent to which fair value is used to measure assets and liabilities, the inputs used to develop such measurements, and the effect of certain of the measurements on earnings (or changes in net assets) during a period. Our adoption of this guidance is not expected to have a material impact on our consolidated financial statements. SFAS 157 will impact the valuation of assets and liabilities (and related disclosures) in connection with future business combinations and impairment testing.
SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities - An Amendment of FASB Statement No. 133. SFAS 161 revised the disclosure requirements for financial instruments and related hedging activities to provide users of financial statements with an enhanced understanding of (i) why and how an entity uses financial instruments, (ii) how an entity accounts for financial instruments and related hedged items under SFAS 133, Accounting for Derivative Instruments and Hedging Activities, and its related interpretations and (iii) how financial instruments and related hedged items affect an entity’s financial position, financial performance and cash flows.
SFAS 161 requires qualitative disclosures about objectives and strategies for using financial instruments, quantitative disclosures about fair value amounts of and gains and losses on financial instruments and disclosures
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
about credit risk-related contingent features in financial instrument agreements. SFAS 161 was effective January 1, 2009, and we will apply its requirements beginning with the first quarter of 2009.
EITF 08-6, Equity Method Investment Accounting Considerations. EITF 08-6 clarifies the accounting for certain transactions and impairment considerations involving equity method investments under SFAS 141(R) and SFAS 160. EITF 08-6 generally requires that (i) transaction costs should be included in the initial carrying value of an equity method investment; (ii) an equity method investor shall not test separately an investee’s underlying assets for impairment, rather such testing should be performed in accordance with Accounting Principles Board Opinion No. 18 (i.e., on the equity method investment itself); (iii) an equity method investor shall account for a share issuance by an investee as if the investor had sold a proportionate share of its investment (any gain or loss to the investor resulting from the investee’s share issuance shall be recognized in earnings); and (iv) a gain or loss should not be recognized when changing the method of accounting for an investment from the equity method to the cost method. EITF 08-6 was effective January 1, 2009.
EITF 07-4, Application of the Two Class Method Under FASB Statement No. 128, Earnings Per Share, to MLPs. EITF 07-4 prescribes the manner in which an MLP should allocate and present earnings per unit using the two-class method set forth in SFAS No. 128, Earnings per Share. Under the two-class method, current period earnings are allocated to the general partner (including earnings attributable to any embedded incentive distribution rights) and limited partners according to the distribution formula for available cash set forth in the MLP’s partnership agreement. EITF 07-4 was effective for us on January 1, 2009. Our adoption of EITF 07-4 did not have a material impact on our earnings per unit computations and disclosures.
NOTE 4. ACCOUNTING FOR EQUITY AWARDS
The following table summarizes compensation expense by plan for the years ended December 31, 2008, 2007 and 2006:
| For Year Ended December 31, | ||||||||||||
| 2008 | 2007 | 2006 | ||||||||||
| Phantom Unit Plans: (1) (2) | ||||||||||||
| 1994 Long-Term Incentive Plan (“1994 LTIP”) (3) | $ | -- | $ | -- | $ | 4 | ||||||
| 1999 Phantom Unit Retention Plan | (128 | ) | 865 | 885 | ||||||||
| 2000 Long Term Incentive Plan | (265 | ) | 397 | 352 | ||||||||
| 2005 Phantom Unit Plan | (144 | ) | 976 | 1,152 | ||||||||
| EPCO, Inc. 2006 TPP Long-Term Incentive Plan: | ||||||||||||
| Unit options | 158 | 65 | -- | |||||||||
| Restricted units (4) | 1,019 | 338 | -- | |||||||||
| Unit appreciation rights (“UARs”) (1) (2) | 2 | 67 | -- | |||||||||
| Phantom units (1) | 8 | 12 | -- | |||||||||
| TEPPCO Unit L.P. | 113 | -- | -- | |||||||||
| TEPPCO Unit II L.P. | 35 | -- | -- | |||||||||
| Compensation expense allocated under ASA (5) | 1,683 | 1,062 | 201 | |||||||||
| Total compensation expense | $ | 2,481 | $ | 3,782 | $ | 2,594 | ||||||
_________________
| (1) | These awards are accounted for as liability awards under the provisions of SFAS 123(R). Accruals for plan award payouts are based on the Unit price. |
| (2) | The decrease in compensation expense for the year ended December 31, 2008, is primarily due to a decrease in the Unit price at December 31, 2008, as compared to the Unit price at December 31, 2007. |
| (3) | The 1994 LTIP provided certain key employees with an incentive award whereby the participant was granted an option to purchase Units and performance units. The 1994 LTIP was terminated effective as of June 19, 2006. |
| (4) | As used in the context of the EPCO, Inc. 2006 TPP Long-Term Incentive Plan, the term “restricted unit” represents a time-vested unit under SFAS 123(R). Such awards are non-vested until the required service period expires. |
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
| (5) | Represents compensation expense under equity awards under other EPCO compensation plans allocated to us from EPCO under the ASA in connection with shared service employees working on our behalf (see Note 15). |
1999 Plan
The Texas Eastern Products Pipeline Company, LLC 1999 Phantom Unit Retention Plan (“1999 Plan”) provides for the issuance of phantom unit awards as incentives to key employees. These liability awards are settled for cash based on the fair market value of the vested portion of the phantom units at redemption dates in each award. The fair market value of each phantom unit award is equal to the closing price of a Unit on the NYSE on the redemption date. Each participant is required to redeem their phantom units as they vest. Each participant is also entitled to cash distributions equal to the product of the number of phantom units granted to the participant and the per Unit cash distribution that we paid to our unitholders. Grants under the 1999 Plan are subject to forfeiture if the participant’s employment with EPCO is terminated.
A total of 18,600 phantom units and 31,600 phantom units were outstanding under the 1999 Plan at December 31, 2008 and 2007, respectively. In April 2008, 13,000 phantom units vested and $0.4 million was paid out to one participant in the second quarter of 2008. The remaining awards outstanding at December 31, 2008 cliff vest as follows: 13,000 in April 2009 and 5,600 in January 2010. At December 31, 2008 and 2007, we had accrued liability balances of $0.4 million and $1.0 million, respectively, for compensation related to the 1999 Plan. For the years ended December 31, 2008 and 2007, participants received $62 thousand and $95 thousand, respectively, in cash distributions.
2000 LTIP
The Texas Eastern Products Pipeline Company, LLC 2000 Long Term Incentive Plan (“2000 LTIP”) provides key employees incentives to achieve improvements in our financial performance. Generally, upon the close of a three-year performance period, the participant will receive a cash payment equal to (i) the applicable “performance percentage” as specified in the award multiplied by (ii) the number of phantom units granted under the award multiplied by (iii) the average of the closing prices of a Unit over the ten consecutive trading days immediately preceding the last day of the performance period. In addition, during the performance period, each participant is entitled to cash distributions equal to the product of the number of phantom units granted to the participant and the per Unit cash distribution that we paid to our unitholders. Grants under the 2000 LTIP are accounted for as liability awards and subject to forfeiture if the participant’s employment with EPCO is terminated, with customary exceptions for death, disability or retirement.
A participant’s “performance percentage” is based upon an improvement in Economic Value Added during a given three-year performance period over the Economic Value Added for the three-year period immediately preceding the performance period. The term “Economic Value Added” means our average annual EBITDA for the performance period minus the product of our average asset base and our cost of capital for the performance period. In this context, EBITDA means earnings before net interest expense, other income, depreciation and amortization and our proportional interest in the EBITDA of our joint ventures, except that our chief executive officer may exclude gains or losses from extraordinary, unusual or non-recurring items. Average asset base means the quarterly average, during the performance period, of our gross carrying value of property, plant and equipment, plus long-term inventory, and the gross carrying value of intangible assets and equity investments. The cost of capital is determined at the date each award is granted.
On December 31, 2007, 19,700 phantom units were outstanding, of which 8,400 phantom units vested on December 31, 2007, and $0.5 million was paid out to participants in the first quarter of 2008. At December 31, 2008, a total of 11,300 phantom units vested and will be paid out to participants in the first quarter of 2009. At December 31, 2008 and 2007, we had accrued liability balances of $0.2 million and $0.9 million, respectively, for compensation related to the 2000 LTIP. After payout in the first quarter of 2009 on awards which vested on December 31, 2008, there will be no remaining phantom units outstanding under the 2000 LTIP. For the years
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
ended December 31, 2008 and 2007, participants received $38 thousand and $54 thousand, respectively, in cash distributions.
2005 Phantom Unit Plan
The Texas Eastern Products Pipeline Company, LLC 2005 Phantom Unit Plan (“2005 Phantom Unit Plan”) provides key employees incentives to achieve improvements in our financial performance. Generally, upon the close of a three-year performance period, the participant will receive a cash payment equal to (i) the applicable “performance percentage” as specified in the award multiplied by (ii) the number of phantom units granted under the award multiplied by (iii) the average of the closing prices of a Unit over the ten consecutive trading days immediately preceding the last day of the performance period. In addition, during the performance period, each participant is entitled to cash distributions equal to the product of the number of phantom units granted to the participant and the per Unit cash distribution that we paid to our unitholders. Grants under the 2005 Phantom Unit Plan are accounted for as liability awards and subject to forfeiture if the participant’s employment with EPCO is terminated, with customary exceptions for death, disability or retirement.
Generally, a participant’s performance percentage is based upon the achievement of a cumulative EBITDA for the performance period of an amount equal to the sum of the EBITDA targets established for each of the three years of the performance period. In this context, EBITDA means earnings before net interest expense, other income, depreciation and amortization and our proportional interest in the EBITDA of our joint ventures, except that our chief executive officer may exclude gains or losses from extraordinary, unusual or non-recurring items.
On December 31, 2007, 36,200 phantom units vested and $1.6 million was paid out to participants in the first quarter of 2008. At December 31, 2008, a total of 36,600 phantom units vested and will be paid out to participants in the first quarter of 2009. At December 31, 2008 and 2007, we had accrued liability balances of $0.6 million and $2.6 million, respectively, for compensation related to the 2005 Phantom Unit Plan. After the payout in the first quarter of 2009 on awards which vested on December 31, 2008, there will be no remaining phantom units outstanding under the 2005 Phantom Unit Plan. For the years ended December 31, 2008 and 2007, participants received $0.1 million and $0.2 million, respectively, in cash distributions.
2006 LTIP
The EPCO, Inc. 2006 TPP Long-Term Incentive Plan (“2006 LTIP”) provides for awards of our Units and other rights to our non-employee directors and to certain employees of EPCO and its affiliates providing services to us. Awards granted under the 2006 LTIP may be in the form of restricted units, phantom units, unit options, UARs and distribution equivalent rights. The exercise price of unit options or UARs awarded to participants is determined by the Audit, Conflicts and Governance Committee of the board of directors of our General Partner (“ACG Committee”) (at its discretion) at the date of grant and may be no less than the fair market value of the option award as of the date of grant. The 2006 LTIP is administered by the ACG Committee. Subject to adjustment as provided in the 2006 LTIP, awards with respect to up to an aggregate of 5,000,000 Units may be granted under the 2006 LTIP. We reimburse EPCO for the costs allocable to 2006 LTIP awards made to employees who work in our business. The 2006 LTIP is effective until the earlier of (i) December 8, 2016, (ii) the time by which all available Units under the 2006 LTIP have been delivered to participants, or (iii) the time of termination of the 2006 LTIP by EPCO or the ACG Committee. The 2006 LTIP may be amended or terminated at any time by the board of directors of EPCO, which is an affiliate of our General Partner, or the ACG Committee; however, any material amendment, such as a material increase in the number of Units available under the plan or a change in the types of awards available under the plan, would require the approval of at least 50% of our unitholders. The ACG Committee is also authorized to make adjustments in the terms and conditions of, and the criteria included in awards under the 2006 LTIP in specified circumstances. After giving effect to outstanding unit options and restricted units at December 31, 2008, and the forfeiture of restricted units through December 31, 2008, a total of 4,487,084 additional Units could be issued under the 2006 LTIP in the future.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Unit Options
The information in the following table presents unit option activity under the 2006 LTIP for the periods indicated:
| Weighted- | ||||||||||||
| Weighted- | Average | |||||||||||
| Average | Remaining | |||||||||||
| Number | Strike Price | Contractual | ||||||||||
| of Units | (dollars/Unit) | Term (in years) | ||||||||||
| Unit Options: | ||||||||||||
Outstanding at December 31, 2006 | -- | $ | -- | |||||||||
Granted (1) (2) | 155,000 | 45.35 | ||||||||||
| Outstanding at December 31, 2007 | 155,000 | 45.35 | ||||||||||
| Granted (3) | 200,000 | 35.86 | ||||||||||
| Outstanding at December 31, 2008 | 355,000 | 40.00 | 4.57 | |||||||||
| Options exercisable at: | ||||||||||||
| December 31, 2008 | -- | $ | -- | -- | ||||||||
________________
| (1) | During 2008, these unit option grants were amended. The expiration dates of these awards granted on May 22, 2007 were modified from May 22, 2017 to December 31, 2012. |
| (2) | The total grant date fair value of these awards was $0.4 million based upon the following assumptions: (i) expected life of the option of 7 years, (ii) risk-free interest rate of 4.78%; (iii) expected distribution yield on Units of 7.92%; and (iv) expected Unit price volatility on Units of 18.03%. |
| (3) | The total grant date fair value of these awards granted on May 19, 2008 was $0.3 million based upon the following assumptions: (i) expected life of the option of 4.7 years; (ii) risk-free interest rate of 3.3%; (iii) expected distribution yield on Units of 7.9%; (iv) estimated forfeiture rate of 17%; and (v) expected Unit price volatility on Units of 18.7%. |
At December 31, 2008, total unrecognized compensation cost related to nonvested unit options granted under the 2006 LTIP was an estimated $0.6 million. We expect to recognize this cost over a weighted-average period of 2.95 years.
Restricted Units
The following table summarizes information regarding our restricted units for the periods indicated:
| Weighted- | ||||||||
| Average Grant | ||||||||
| Number | Date Fair Value | |||||||
| of Units | per Unit (1) | |||||||
Restricted Units at December 31, 2006 | -- | |||||||
Granted (2) | 62,900 | $ | 37.64 | |||||
Forfeited | (500 | ) | $ | 37.64 | ||||
Restricted Units at December 31, 2007 | 62,400 | |||||||
Granted (3) | 96,900 | $ | 29.54 | |||||
Vested | (1,000 | ) | $ | 40.61 | ||||
Forfeited | (1,000 | ) | $ | 35.86 | ||||
Restricted Units at December 31, 2008 | 157,300 | |||||||
____________________________
| (1) | Determined by dividing the aggregate grant date fair value of awards (including an allowance for forfeitures) by the number of awards issued. |
| (2) | Aggregate grant date fair value of restricted unit awards issued during 2007 was $2.4 million based on a grant date market price of $45.35 per Unit and an estimated forfeiture rate of 17%. |
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
| (3) | Aggregate grant date fair value of restricted unit awards issued during 2008 was $2.8 million based on grant date market prices ranging from $34.63 to $35.86 per Unit and an estimated forfeiture rate of 17%. |
The total fair value of our restricted unit awards that vested during the year ended December 31, 2008 was $24 thousand. At December 31, 2008, total unrecognized compensation cost related to restricted units was $3.7 million, and these costs are expected to be recognized over a weighted-average period of 2.8 years.
Phantom Units
At December 31, 2008 and 2007, a total of 1,647 phantom units were outstanding, which have been awarded under the 2006 LTIP to three of the non-executive members of the board of directors. Each phantom unit will pay out in cash on April 30, 2011 or, if earlier, the date the director is no longer serving on the board of directors, whether by voluntarily resignation or otherwise. Each participant is also entitled to cash distributions equal to the product of the number of phantom units granted to the participant and the per Unit cash distribution that we paid to our unitholders. Phantom unit awards to non-executive directors are accounted for in a manner similar to SFAS 123(R) liability awards.
UARs
At December 31, 2008 and 2007, a total of 431,377 UARs and 401,948 UARs, respectively, were outstanding, which have been awarded under the 2006 LTIP to non-executive members of the board of directors and to certain employees providing services directly to us.
Non-Executive Members of the Board of Directors. At December 31, 2008, a total of 95,654 UARs, awarded to non-executive members of the board of directors under the 2006 LTIP, were outstanding at a weighted average exercise price of $41.82 per Unit (66,225 UARs issued in 2007 at an exercise price of $45.30 per Unit to the then three non-executive members of the board of directors and 29,429 UARs issued in 2008 at an exercise price of $33.98 per Unit to a non-executive member of the board of directors in connection with his election to the board). The UARs are subject to five year cliff vesting and will vest earlier if the director dies or is removed from, or not re-elected or appointed to, the board of directors for reasons other than his voluntary resignation or unwillingness to serve. When the UARs become payable, the director will receive a payment in cash equal to the fair market value of the Units subject to the UARs on the payment date over the fair market value of the Units subject to the UARs on the date of grant. UARs awarded to non-executive directors are accounted for in a manner similar to SFAS 123(R) liability awards.
Employees. At December 31, 2008 and 2007, a total of 335,723 UARs, awarded under the 2006 LTIP to certain employees providing services directly to us, were outstanding at an exercise price of $45.35 per Unit. The UARs are subject to five year cliff vesting and are subject to forfeiture. When the UARs become payable, the awards will be redeemed in cash (or, in the sole discretion of the ACG Committee, Units or a combination of cash and Units) equal to the fair market value of the Units subject to the UARs on the payment date over the fair market value of the Units subject to the UARs on the date of grant. In addition, for each calendar quarter from the grant date until the UARs become payable, each holder will receive a cash payment equal to the product of (i) the per Unit cash distribution paid to our unitholders during such calendar quarter less the quarterly distribution amount in effect at the time of grant multiplied by (ii) the number of Units subject to the UAR. UARs awarded to employees are accounted for as liability awards under SFAS 123(R) since the current intent is to settle the awards in cash.
Employee Partnerships
EPCO formed TEPPCO Unit L.P. (“TEPPCO Unit”) and TEPPCO Unit II L.P. (“TEPPCO Unit II”) (collectively, “Employee Partnerships”) to serve as an incentive arrangement for key employees of EPCO by providing them with a “profits interest” in the Employee Partnerships. Certain EPCO employees who perform services for us, including our chief executive officer and other executive officers, were issued Class B limited
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TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
partner interests and admitted as Class B limited partners without any capital contribution. The profits interest awards (i.e., the Class B limited partner interests) in the Employee Partnerships entitles each holder to participate in the appreciation in value of our Units. The Class B limited partner interests are subject to forfeiture if the participating employee’s employment with EPCO is terminated prior to vesting of the profits interest, with customary exceptions for death, disability and certain retirements. The risk of forfeiture associated with the Class B limited partner interests in the Employee Partnerships will also lapse upon certain change in control events.
The following is a discussion of the significant terms of TEPPCO Unit and TEPPCO Unit II.
TEPPCO Unit. On September 4, 2008, EPCO formed a Delaware limited partnership, TEPPCO Unit, for which it serves as the general partner, to serve as an incentive arrangement for certain employees of EPCO, including our executive officers. EPCO Holdings, Inc. (“EPCO Holdings”), an affiliate of EPCO, contributed approximately $7.0 million to TEPPCO Unit as a capital contribution with respect to its interest and was admitted as the Class A limited partner of TEPPCO Unit. TEPPCO Unit purchased 241,380 Units directly from us in an unregistered transaction at the public offering price concurrently with the closing of our September 2008 equity offering (see Note 13). Certain EPCO employees who perform services for us, including executive officers, were issued Class B limited partner interests and admitted as Class B limited partners of TEPPCO Unit without any capital contribution. The Class B limited partner interests, which entitle the holder to participate in the appreciation in value of our Units, are equity-based compensatory awards designed to incentivize officers and employees of EPCO who perform services for us to enhance the long-term value of our Units.
Compensation expense attributable to these awards is based on the estimated grant date fair value of each award. A portion of the fair value of these equity-based awards is allocated to us under the ASA as a non-cash expense. We are not responsible for reimbursing EPCO for any expenses of TEPPCO Unit, including the value of any contributions of cash or our Units made by private company affiliates of EPCO at the formation of TEPPCO Unit.
Unless otherwise agreed to by EPCO, EPCO Holdings and a majority in interest of the Class B limited partners or unless other specified dissolution events occur, TEPPCO Unit will terminate at the earlier of (i) thirty days following September 4, 2013 (five years from the date of TEPPCO Unit’s agreement of limited partnership) or (ii) a change in control of EPCO, Enterprise GP Holdings, or us. Summarized below are certain material terms regarding distributions by TEPPCO Unit to its partners:
| § | Distributions of Cash Flow – Each quarter, 100% of the cash distributions received by TEPPCO Unit from us in that quarter will be distributed to the Class A limited partner until the Class A limited partner has received an amount equal to the Class A preferred return (as defined below), and any excess distributions received by TEPPCO Unit in that quarter will be distributed to the Class B limited partners. The Class A preferred return equals the Class A capital base (as defined below) multiplied by a floating rate determined by EPCO, in its sole discretion, that will be no less than 4.5% and no greater than 5.725% per annum. The Class A limited partner’s capital base equals the amount of any contributions of cash or cash equivalents made by the Class A limited partner to TEPPCO Unit, plus any unpaid Class A preferred return from prior periods, less any distributions of cash or Units previously made to the Class A limited partner by TEPPCO Unit. |
| § | Liquidating Distributions – Upon liquidation of TEPPCO Unit (after satisfaction of any debt or other obligations of TEPPCO Unit), Units having a fair market value equal to the Class A capital base will be distributed to EPCO Holdings, plus any accrued Class A preferred return for the quarter in which liquidation occurs. Any remaining Units will be distributed to the Class B limited partners. |
| § | Sale Proceeds – If TEPPCO Unit sells any Units that it owns, the sale proceeds will be distributed to the Class A limited partner and the Class B limited partners in the same manner as liquidating distributions described above. |
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The grant date fair value of the Class B limited partner interests in TEPPCO Unit was $2.1 million. This fair value was estimated using the Black-Scholes option pricing model, which incorporates various assumptions including (i) an expected life of the awards of five years, (ii) a risk-free interest rate of 2.87%, (iii) an expected distribution yield on our Units of 7.28%, and (iv) an expected Unit price volatility for our Units of 16.42%. At December 31, 2008, there was an estimated $1.7 million of unrecognized compensation cost related to TEPPCO Unit. We will recognize our share of these costs in accordance with the ASA over a weighted average period of 4.68 years.
TEPPCO Unit II. On November 13, 2008, EPCO formed a Delaware limited partnership, TEPPCO Unit II, for which it serves as the general partner, to serve as an incentive arrangement for Mr. Thompson, our chief executive officer and an employee of EPCO. On the same date, Duncan Family Interests, Inc. (“DFI”), an affiliate of EPCO, contributed to TEPPCO Unit II 123,185 Units (with a value of approximately $3.1 million, based on the closing price of our Units on the NYSE on November 12, 2008) and was admitted as the Class A limited partner of TEPPCO Unit II. Mr. Thompson was issued 100% of the Class B limited partner interests and admitted as Class B limited partner of TEPPCO Unit II without any capital contribution. The Class B limited partner interest, which entitles Mr. Thompson to participate in the appreciation in value of our Units, is an equity-based compensatory award designed to incentivize him to enhance the long-term value of our Units.
Compensation expense attributable to this award is based on the estimated grant date fair value of the award and the fair value is allocated to us under the ASA. We are responsible for reimbursing EPCO for the amount of distributions of cash or securities, if any, made by TEPPCO Unit II to Mr. Thompson.
Unless otherwise agreed to by EPCO, DFI and the Class B limited partner or unless other specified dissolution events occur, TEPPCO Unit II will terminate at the earlier of (i) thirty days following November 13, 2013 (five years from the date of TEPPCO Unit II’s agreement of limited partnership) or (ii) a change in control of EPCO or us. Summarized below are certain material terms regarding distributions by TEPPCO Unit II to its partners:
| § | Distributions of Cash Flow – Each quarter, 100% of the cash distributions received by TEPPCO Unit II from us in that quarter will be distributed to the Class A limited partner until the Class A limited partner has received an amount equal to the Class A preferred return (as defined below), and any remaining excess distributions received by TEPPCO Unit II in that quarter will be distributed to the Class B limited partner. The Class A preferred return equals the Class A capital base (as defined below) multiplied by a rate of 6.31% per annum. The Class A limited partner’s capital base equals the amount of any contributions of cash or cash equivalents made by the Class A limited partner to TEPPCO Unit II, plus any unpaid Class A preferred return from prior periods, less any distributions of cash or Units previously made to the Class A limited partner by TEPPCO Unit II (as described below). |
| § | Liquidating Distributions – Upon liquidation of TEPPCO Unit II (after satisfaction of any debt or other obligations of TEPPCO Unit II), Units having a fair market value equal to the Class A capital base will be distributed to DFI, plus any accrued Class A preferred return for the quarter in which liquidation occurs. Any remaining Units will be distributed to the Class B limited partner. |
| § | Sale Proceeds – If TEPPCO Unit II sells any Units that it owns, the sale proceeds will be distributed to the Class A limited partner and the Class B limited partner in the same manner as liquidating distributions described above. |
The grant date fair value of the Class B limited partner interest in TEPPCO Unit II was $1.4 million. This fair value was estimated using the Black-Scholes option pricing model, which incorporates various assumptions including (i) an expected life of the awards of five years, (ii) a risk-free interest rate of 2.37%, (iii) an expected distribution yield on our Units of 13.87%, and (iv) an expected Unit price volatility for our Units of 66.38%. At
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
December 31, 2008, there was an estimated $1.3 million of unrecognized compensation cost related to TEPPCO Unit II. We will recognize our share of these costs in accordance with the ASA over a weighted average period of 4.87 years.
NOTE 5. EMPLOYEE BENEFIT PLANS
Retirement Plan
The TEPPCO Retirement Cash Balance Plan (“TEPPCO RCBP”) was a non-contributory, trustee-administered pension plan. The benefit formula for all eligible employees was a cash balance formula. Under a cash balance formula, a plan participant accumulated a retirement benefit based upon pay credits and current interest credits. The pay credits were based on a participant’s salary, age and service. We used a December 31 measurement date for this plan.
Effective May 31, 2005, participation in the TEPPCO RCBP was frozen, and no new participants were eligible to be covered by the plan after that date. Effective June 1, 2005, EPCO adopted the TEPPCO RCBP for the benefit of its employees providing services to us. Effective December 31, 2005, all plan benefits accrued were frozen, participants received no additional pay credits after that date, and all plan participants were 100% vested regardless of their years of service. The TEPPCO RCBP plan was terminated effective December 31, 2005, and plan participants had the option to receive their benefits either through a lump sum payment or through an annuity. In April 2006, we received a determination letter from the Internal Revenue Service (“IRS”) providing IRS approval of the plan termination. For those plan participants who elected to receive an annuity, we purchased an annuity contract from an insurance company in which the plan participants own the annuity, absolving us of any future obligation to the participants.
In accordance with SFAS No. 88, Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits, we recorded settlement charges of approximately $0.1 million and $3.5 million during the years ended December 31, 2007 and 2006, respectively, relating to the TEPPCO RCBP for any existing unrecognized losses upon the plan termination and final distribution of the assets to the plan participants. As of December 31, 2008, all benefit obligations to TEPPCO RCBP plan participants have been settled. During the first quarter of 2008, the remaining balance of the TEPPCO RCBP was transferred to an EPCO benefit plan.
The components of net pension benefits costs for the TEPPCO RCBP for the years ended December 31, 2007 and 2006 were as follows:
For Year Ended December 31, | ||||||||
| 2007 | 2006 | |||||||
| Interest cost on projected benefit obligation | $ | 14 | $ | 891 | ||||
| Expected return on plan assets | 103 | (412 | ) | |||||
| Recognized net actuarial loss | 38 | 135 | ||||||
| SFAS 88 settlement charge | 87 | 3,545 | ||||||
Net pension benefits costs | $ | 242 | $ | 4,159 | ||||
The weighted average assumptions used to determine net periodic benefit cost for the TEPPCO RCBP for the year ended December 31, 2007, were a discount rate of 4.73% and an expected long-term rate of return on plan assets of 2%.
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TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The following table sets forth our pension benefits changes in benefit obligation, fair value of plan assets and funded status as of December 31, 2007:
| Change in benefit obligation | ||||
| Benefit obligation at January 1, 2007 | $ | 477 | ||
| Interest cost | 14 | |||
| Actuarial loss | 60 | |||
| Benefits paid | (534 | ) | ||
| Impact of settlement | (17 | ) | ||
| Benefit obligation at December 31, 2007 | $ | -- | ||
| Change in plan assets | ||||
| Fair value of plan assets at January 1, 2007 | $ | 1,311 | ||
| Actual return on plan assets | (72 | ) | ||
| Benefits paid | (534 | ) | ||
| Impact of settlement | (46 | ) | ||
| Fair value of plan assets at December 31, 2007 | $ | 659 | ||
| Funded status | $ | 659 | ||
| Amount Recognized in the Balance Sheet: | ||||
Noncurrent assets | $ | 659 | ||
Net pension asset at December 31, 2007 | $ | 659 | ||
| Amount Recognized in Other Comprehensive Income: | ||||
| Net actuarial loss | $ | 57 | ||
| Amortization of net actuarial gain | (124 | ) | ||
Total recognized in other comprehensive income | $ | (67 | ) | |
Plan Assets
At December 31, 2007, all plan assets for the TEPPCO RCBP were invested in money market securities.
Other Plans
EPCO maintains defined contribution plans for the benefit of employees providing services to us, and we reimburse EPCO for the cost of maintaining these plans in accordance with the ASA (see Note 15 for additional information related to the costs and expenses allocated to us for employee benefits).
F-30
TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
NOTE 6. FINANCIAL INSTRUMENTS
The following table presents the estimated fair values of our financial instruments at December 31, 2008 and 2007:
| December 31, | ||||||||||||||||
| 2008 | 2007 | |||||||||||||||
| Carrying | Fair | Carrying | Fair | |||||||||||||
| Financial Instruments | Value | Value | Value | Value | ||||||||||||
| Financial assets: | ||||||||||||||||
| Cash and cash equivalents (1) | $ | 28 | $ | 28 | $ | 23 | $ | 23 | ||||||||
Accounts receivable (1) | 790,374 | 790,374 | 1,381,871 | 1,381,871 | ||||||||||||
Commodity financial instruments (2) (3) | 15,711 | 15,711 | 10,458 | 10,458 | ||||||||||||
Interest rate swaps (3) (4) | -- | -- | 254 | 254 | ||||||||||||
| Financial liabilities: | ||||||||||||||||
Accounts payable and accrued liabilities (1) | 792,469 | 792,469 | 1,413,447 | 1,413,447 | ||||||||||||
Fixed-rate debt (principal amount) (5) | 2,000,000 | 1,553,218 | 1,355,000 | 1,370,830 | ||||||||||||
Variable-rate debt (6) | 516,654 | 516,654 | 490,000 | 490,000 | ||||||||||||
Commodity financial instruments (2) (3) | 15,708 | 15,708 | 29,355 | 29,355 | ||||||||||||
Treasury rate locks (3) (4) | -- | -- | 25,296 | 25,296 | ||||||||||||
_______________
| (1) | Cash and cash equivalents, accounts receivable and accounts payable and accrued liabilities are carried at amounts which reasonably approximate their fair values due to their short-term nature. |
| (2) | Represents commodity financial instrument transactions that either have not settled or have settled and not been invoiced. Settled and invoiced transactions are reflected in either accounts receivable or accounts payable depending on the outcome of the transaction. |
| (3) | The fair values associated with our interest rate and commodity hedging portfolios were developed using available market information and appropriate valuation techniques. |
| (4) | Represents interest rate hedging financial instrument transactions that have not settled. Settled transactions are reflected in either accounts receivable or accounts payable depending on the outcome of the transaction. |
| (5) | The estimated fair values of our fixed rate debt are based on quoted market prices for such debt or debt of similar terms and maturities (see Note 12). |
| (6) | The carrying amount of our variable-rate debt obligation reasonably approximates its fair value due to its variable interest rate. |
Fair value is generally defined as the amount at which a financial instrument could be exchanged in a current transaction between willing parties, not in a forced or liquidation sale. The estimated fair values of our financial instruments have been determined using available market information and appropriate valuation techniques. We must use considerable judgment, however, in interpreting market data and developing these estimates. Accordingly, our fair value estimates are not necessarily indicative of the amounts that we could realize upon disposition of these instruments. The use of different market assumptions and/or estimation techniques could have a material effect on our estimates of fair value.
We are exposed to financial market risks, including changes in commodity prices and interest rates. We do not have foreign exchange risks. We may use financial instruments (i.e., futures, forwards, swaps, options and other financial instruments with similar characteristics) to mitigate the risks of certain identifiable and anticipated transactions. In general, the type of risks we attempt to hedge are those related to fair values of certain debt instruments and cash flows resulting from changes in applicable interest rates or commodity prices.
We routinely review our outstanding financial instruments in light of current market conditions. If market conditions warrant, some financial instruments may be closed out in advance of their contractual settlement dates, resulting in the realization of income or loss depending on the specific hedging criteria. When this occurs, we may enter into a new financial instrument to reestablish the hedge to which the closed instrument relates.
F-31
TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Interest Rate Risk Hedging Program
Our interest rate exposure results from variable and fixed interest rate borrowings under various debt agreements. From time to time we utilize interest rate swaps and similar arrangements to manage a portion of our interest rate exposure, which allow us to convert a portion of fixed rate debt into variable rate debt or a portion of variable rate debt into fixed rate debt. At December 31, 2008, there were no interest related financial instruments outstanding.
Fair Value Hedges – Interest Rate Swaps
In January 2006, we entered into interest rate swap agreements with a total notional value of $200.0 million to hedge our exposure to increases in the benchmark interest rate underlying our variable rate revolving credit facility. Under the swap agreements, we paid a fixed rate of interest ranging from 4.67% to 4.695% and received a floating rate based on the three-month U.S. Dollar LIBOR rate. At December 31, 2007, the fair value of these interest rate swaps was an asset of $0.3 million. These interest rate swaps expired in January 2008.
In October 2001, TE Products entered into an interest rate swap agreement to hedge its exposure to changes in the fair value of its fixed rate 7.51% Senior Notes due 2028. This swap agreement, designated as a fair value hedge, had a notional value of $210.0 million and was set to mature in January 2028 to match the principal and maturity of the TE Products Senior Notes. During the years ended December 31, 2007 and 2006, we recognized reductions in interest expense of $0.5 million and $1.9 million, respectively, related to the difference between the fixed rate and the floating rate of interest on the interest rate swap. In September 2007, we terminated this swap agreement, resulting in a loss of $1.2 million. This loss was deferred as an adjustment to the carrying value of the 7.51% Senior Notes, and approximately $0.2 million of the loss was amortized to interest expense in 2007, with the remaining $1.0 million recognized in interest expense in January 2008 at the time the 7.51% Senior Notes were redeemed (see Note 12).
During 2002, we entered into interest rate swap agreements, designated as fair value hedges, to hedge our exposure to changes in the fair value of our fixed rate 7.625% Senior Notes due 2012. The swap agreements had a combined notional value of $500.0 million and were set to mature in 2012 to match the principal and maturity of the underlying debt. These swap agreements were terminated in 2002 resulting in deferred gains of $44.9 million, which are being amortized using the effective interest method as reductions to future interest expense over the remaining term of the 7.625% Senior Notes. At December 31, 2008 and 2007, the unamortized balance of the deferred gains was $18.1 million and $23.2 million, respectively. In the event of early extinguishment of the 7.625% Senior Notes, any remaining unamortized gains would be recognized in the statement of consolidated income at the time of extinguishment.
Cash Flow Hedges – Treasury Locks
At times, we may use treasury lock financial instruments to hedge the underlying U.S. treasury rates related to anticipated debt incurrence. Gains or losses on the termination of such instruments are amortized to earnings using the effective interest method over the estimated term of the underlying fixed-rate debt. Each of our treasury lock transactions was designated as a cash flow hedge under SFAS No. 133 as amended and interpreted.
In October 2006 and February 2007, we entered into treasury lock agreements, accounted for as cash flow hedges, which extended through June 2007 for a notional value totaling $300.0 million. In May 2007, these treasury locks were terminated concurrent with the issuance of junior subordinated notes (see Note 12). The termination of the treasury locks resulted in gains of $1.4 million, and these gains were recorded in accumulated other comprehensive income. These gains are being amortized using the effective interest method as reductions to future interest expense over the term of the forecasted fixed rate interest payments, which is ten years. Over the next twelve months, we expect to reclassify $0.1 million of accumulated other comprehensive income that was generated
F-32
TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
by these treasury locks as a reduction to interest expense. In the event of early extinguishment of the junior subordinated notes, any remaining unamortized gains would be recognized in the statement of consolidated income at the time of extinguishment.
In 2007, we entered into treasury locks, accounted for as cash flow hedges, which extended through January 31, 2008 for a notional value totaling $600.0 million. At December 31, 2007, the fair value of the treasury locks was a liability of $25.3 million. In January 2008, these treasury locks were extended through April 30, 2008. In March 2008, these treasury locks were settled concurrently with the issuance of senior notes (see Note 12). The settlement of the treasury locks resulted in losses of $52.1 million, and these losses were recorded in accumulated other comprehensive income. We recognized approximately $3.6 million of this loss in interest expense as a result of interest payments hedged under the treasury locks not occurring as forecasted. The remaining losses are being amortized using the effective interest method as increases to future interest expense over the terms of the forecasted interest payments, which range from five to ten years. Over the next twelve months, we expect to reclassify $5.8 million of accumulated other comprehensive loss that was generated by these treasury locks as an increase to interest expense. In the event of early extinguishment of these senior notes, any remaining unamortized losses would be recognized in the statement of consolidated income at the time of extinguishment.
Commodity Risk Hedging Program
We seek to maintain a position that is substantially balanced between crude oil purchases and related sales and future delivery obligations. As part of our crude oil marketing business, we enter into financial instruments such as swaps and other hedging instruments. The purpose of such hedging activity is to either balance our inventory position or to lock in a profit margin.
At December 31, 2008, we had no commodity financial instruments that were accounted for as cash flow hedges. At December 31, 2007, we had a limited number of commodity financial instruments that were accounted for as cash flow hedges. Gains and losses on financial instruments used in cash flow hedges are offset against corresponding gains or losses of the hedged item and are deferred through other comprehensive income, thus minimizing exposure to cash flow risk. No ineffectiveness was recognized as of December 31, 2008. In addition, we had some commodity financial instruments that did not qualify for hedge accounting. These financial instruments had a minimal impact on our earnings. The fair values of the open positions at December 31, 2008 and 2007 was an asset of $3 thousand and a liability of $18.9 million, respectively.
Adoption of SFAS 157 – Fair Value Measurements
On January 1, 2008, we adopted the provisions of SFAS No. 157 that apply to financial assets and liabilities. We adopted the provisions of SFAS 157 that apply to nonfinancial assets and liabilities on January 1, 2009. SFAS 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.
Our fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability. These assumptions include estimates of risk. Recognized valuation techniques employ inputs such as product prices, operating costs, discount factors and business growth rates. These inputs may be either readily observable, corroborated by market data, or generally unobservable. In developing our estimates of fair value, we endeavor to utilize the best information available and apply market-based data to the extent possible. Accordingly, we utilize valuation techniques (such as the market approach) that maximize the use of observable inputs and minimize the use of unobservable inputs.
SFAS 157 established a three-tier hierarchy that classifies fair value amounts recognized or disclosed in the financial statements based on the observability of inputs used to estimate such fair values. The hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2) to be more reliable and predictable than those based
F-33
TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
primarily on unobservable inputs (Level 3). At each balance sheet reporting date, we categorize our financial assets and liabilities using this hierarchy. The characteristics of fair value amounts classified within each level of the SFAS 157 hierarchy are described as follows:
| § | Level 1 fair values are based on quoted prices, which are available in active markets for identical assets or liabilities as of the measurement date. Active markets are defined as those in which transactions for identical assets or liabilities occur in sufficient frequency so as to provide pricing information on an ongoing basis (e.g., the NYSE or New York Mercantile Exchange). Level 1 primarily consists of financial assets and liabilities such as exchange-traded financial instruments, publicly-traded equity securities and U.S. government treasury securities. |
| § | Level 2 fair values are based on pricing inputs other than quoted prices in active markets (as reflected in Level 1 fair values) and are either directly or indirectly observable as of the measurement date. Level 2 fair values include instruments that are valued using financial models or other appropriate valuation methodologies. Such financial models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value of money, volatility factors for stocks, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data, or are validated by inputs other than quoted prices (e.g., interest rates and yield curves at commonly quoted intervals). Level 2 includes non-exchange-traded instruments such as over-the-counter forward contracts, options, and repurchase agreements. |
| § | Level 3 fair values are based on unobservable inputs. Unobservable inputs are used to measure fair value to the extent that observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date. Unobservable inputs reflect the reporting entity’s own ideas about the assumptions that market participants would use in pricing an asset or liability (including assumptions about risk). Unobservable inputs are based on the best information available in the circumstances, which might include the reporting entity’s internally-developed data. The reporting entity must not ignore information about market participant assumptions that is reasonably available without undue cost and effort. Level 3 inputs are typically used in connection with internally developed valuation methodologies where management makes its best estimate of an instrument’s fair value. Level 3 generally includes specialized or unique financial instruments that are tailored to meet a customer’s specific needs. |
The following table sets forth by level within the fair value hierarchy our financial assets and liabilities measured on a recurring basis at December 31, 2008. These financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value assets and liabilities and their placement within the fair value hierarchy levels. At December 31, 2008, we had no Level 1 financial assets and liabilities.
F-34
TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
| Level 2 | Level 3 | Total | ||||||||||
| Financial assets: | ||||||||||||
Commodity financial instruments | $ | 15,488 | $ | 223 | $ | 15,711 | ||||||
Total | $ | 15,488 | $ | 223 | $ | 15,711 | ||||||
| Financial liabilities: | ||||||||||||
Commodity financial instruments | $ | 15,338 | $ | 370 | $ | 15,708 | ||||||
Total | $ | 15,338 | $ | 370 | $ | 15,708 | ||||||
| Net financial liabilities, Level 3 | $ | (147 | ) | |||||||||
The determination of fair values above associated with our commodity financial instrument portfolios are developed using available market information and appropriate valuation techniques in accordance with SFAS 157.
The following table sets forth a reconciliation of changes in the fair value of our net financial assets and liabilities classified as Level 3 in the fair value hierarchy:
| Net | ||||
| Commodity | ||||
| Financial | ||||
| Instruments | ||||
| Balance, January 1, 2008 | $ | (394 | ) | |
Total gains included in net income (1) | 247 | |||
| Balance, December 31, 2008 | $ | (147 | ) | |
_________
| (1) | Total commodity financial instrument gains, recognized in revenues and included in net income on our statements of consolidated income, was $0.2 million for the year ended December 31, 2008. |
NOTE 7. INVENTORIES
Inventories are valued at the lower of cost (based on weighted average cost method) or market. The major components of inventories were as follows:
| December 31, | ||||||||
| 2008 | 2007 | |||||||
| Crude oil (1) | $ | 32,792 | $ | 44,542 | ||||
| Refined products and LPGs (2) | 406 | 18,616 | ||||||
| Lubrication oils and specialty chemicals | 11,127 | 9,160 | ||||||
| Materials and supplies | 8,581 | 7,178 | ||||||
| NGLs | -- | �� | 803 | |||||
| Total | $ | 52,906 | $ | 80,299 | ||||
_____________________
| (1) | At December 31, 2008 and 2007, $30.7 million and $16.5 million, respectively, of our crude oil inventory was subject to forward sales contracts. Decrease in crude oil inventory is primarily due to a decrease in the market price of crude oil from December 31, 2007 to December 31, 2008. |
| (2) | Refined products and LPGs inventory is managed on a combined basis. Decrease in refined products and LPGs inventory is primarily due to sales of product inventory in 2008. |
F-35
TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Due to fluctuating commodity prices, we recognize lower of cost or market (“LCM”) adjustments when the carrying value of our inventories exceed their net realizable value. These non-cash charges are a component of costs and expenses in the period they are recognized. For the years ended December 31, 2008, 2007 and 2006, we recognized LCM adjustments of approximately $12.3 million, $0.8 million and $1.7 million, respectively.
NOTE 8. PROPERTY, PLANT AND EQUIPMENT
Major categories of property, plant and equipment at December 31, 2008 and 2007, were as follows:
| Estimated | ||||||||||||
| Useful Life | December 31, | |||||||||||
| In Years | 2008 | 2007 | ||||||||||
| Plants and pipelines (1) | 5-40 (4) | $ | 1,919,646 | $ | 1,810,195 | |||||||
| Underground and other storage facilities (2) | 5-40 (5) | 296,806 | 254,677 | |||||||||
| Transportation equipment (3) | 5-10 | 11,303 | 7,780 | |||||||||
| Marine vessels | 20-30 | 453,041 | -- | |||||||||
| Land and right of way | 143,823 | 117,628 | ||||||||||
| Construction work in progress | 294,075 | 185,579 | ||||||||||
Total property, plant and equipment | 3,118,694 | 2,375,859 | ||||||||||
Less accumulated depreciation | 678,784 | 582,225 | ||||||||||
Property, plant and equipment, net | $ | 2,439,910 | $ | 1,793,634 | ||||||||
_____________________
| (1) | Plants and pipelines include refined products, LPGs, NGL, petrochemical, crude oil and natural gas pipelines; terminal loading and unloading facilities; office furniture and equipment; buildings, laboratory and shop equipment; and related assets. |
| (2) | Underground and other storage facilities include underground product storage caverns, storage tanks and other related assets. |
| (3) | Transportation equipment includes vehicles and similar assets used in our operations. |
| (4) | The estimated useful lives of major components of this category are as follows: pipelines, 20-40 years (with some equipment at 5 years); terminal facilities, 10-40 years; office furniture and equipment, 5-10 years; buildings 20-40 years; and laboratory and shop equipment, 5-40 years. |
| (5) | The estimated useful lives of major components of this category are as follows: underground storage facilities, 20-40 years (with some components at 5 years) and storage tanks, 20-30 years. |
The following table summarizes our depreciation expense and capitalized interest amounts for the years ended December 31, 2008, 2007 and 2006:
| For Year Ended December 31, | ||||||||||||
| 2008 | 2007 | 2006 | ||||||||||
Depreciation expense (1) | $ | 96,252 | $ | 81,093 | $ | 78,888 | ||||||
Capitalized interest (2) | 19,170 | 11,030 | 10,681 | |||||||||
_________________________
| (1) | Depreciation expense is a component of depreciation and amortization expense as presented in our statements of consolidated income. |
| (2) | Capitalized interest increases the carrying value of the associated asset and reduces interest expense during the period it is recorded. |
Asset Retirement Obligations
We have conditional AROs related to the retirement of the Val Verde natural gas gathering system and to structural restoration work to be completed on leased office space that is required upon our anticipated office lease termination.
F-36
TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The following table presents information regarding our AROs:
| ARO liability balance, December 31, 2006 | $ | 1,228 | ||
| Accretion expense | 118 | |||
| ARO liability balance, December 31, 2007 | 1,346 | |||
| Accretion expense | 128 | |||
| ARO liability balance, December 31, 2008 | $ | 1,474 |
Property, plant and equipment at December 31, 2008, includes $0.5 million of asset retirement costs capitalized as an increase in the associated long-lived asset. Additionally, based on information currently available, we estimate that accretion expense will approximate $0.1 million for 2009, $0.2 million for 2010, $0.2 million for 2011, $0.2 million for 2012 and $0.2 million for 2013.
NOTE 9. INVESTMENTS IN UNCONSOLIDATED AFFILIATES
We own interests in related businesses that are accounted for using the equity method of accounting. These investments are identified below by reporting business segment (see Note 14 for a general discussion of our business segments). The following table presents our investments in unconsolidated affiliates as of December 31, 2008 and 2007:
| Ownership Percentage at | ||||||||||||
| December 31, | December 31, | |||||||||||
| 2008 | 2008 | 2007 | ||||||||||
| Downstream Segment: | ||||||||||||
Centennial | 50.0% | $ | 71,841 | $ | 78,962 | |||||||
Other | 25.0% | 332 | 362 | |||||||||
| Upstream Segment: | ||||||||||||
Seaway | 50.0% | 190,129 | 188,650 | |||||||||
Texas Offshore Port System | 33.3% | 35,915 | -- | |||||||||
| Midstream Segment: | ||||||||||||
Jonah | 80.64% | 957,706 | 879,021 | |||||||||
| Total | $ | 1,255,923 | $ | 1,146,995 | ||||||||
The following table summarizes equity earnings (losses) by business segment for the years ended December 31, 2008, 2007 and 2006:
| For Year Ended December 31, | ||||||||||||
| 2008 | 2007 | 2006 | ||||||||||
| Equity earnings (losses): | ||||||||||||
Downstream Segment (1) | $ | (14,603 | ) | $ | (12,396 | ) | $ | (8,018 | ) | |||
Upstream Segment | 11,693 | 2,602 | 11,905 | |||||||||
Midstream Segment | 90,004 | 83,060 | 35,052 | |||||||||
Intersegment eliminations | (4,401 | ) | (4,511 | ) | (2,178 | ) | ||||||
| Total equity earnings | $ | 82,693 | $ | 68,755 | $ | 36,761 | ||||||
______________________
| (1) | On March 1, 2007, we sold our ownership interest in Mont Belvieu Storage Partners, L.P. (“MB Storage”) to Louis Dreyfus Energy Services L.P. (“Louis Dreyfus”) (see Note 10). |
F-37
TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
On a quarterly basis, we monitor the underlying business fundamentals of our investments in unconsolidated affiliates and test such investments for impairment when impairment indicators are present. As a result of our reviews for the year ended December 31, 2008, no impairment charges were required. We have the intent and ability to hold these investments, which are integral to our operations.
Centennial
TE Products owns a 50% ownership interest in Centennial, and Marathon Petroleum Company LLC (“Marathon”) owns the remaining 50% interest. Centennial owns an interstate refined petroleum products pipeline extending from the upper Texas Gulf Coast to central Illinois. Marathon operates the mainline Centennial pipeline, and TE Products operates the Beaumont origination point and the Creal Springs terminal. During the year ended December 31, 2008, we did not invest any funds in Centennial. During the year ended December 31, 2007, TE Products contributed $11.1 million to Centennial, of which $6.1 million was for contractual obligations that were created upon formation of Centennial and $5.0 million was for debt service requirements. During the year ended December 31, 2006, TE Products contributed $2.5 million to Centennial. TE Products has received no cash distributions from Centennial since its formation.
Seaway
Through one of our indirect wholly owned subsidiaries, we own a 50% ownership interest in Seaway. The remaining 50% interest is owned by ConocoPhillips. We operate and commercially manage the Seaway assets. Seaway owns pipelines and terminals that carry imported, offshore and domestic onshore crude oil from a marine terminal at Freeport, Texas, to Cushing, Oklahoma, and from a marine terminal at Texas City, Texas, to refineries in the Texas City and Houston, Texas, areas. Seaway also has a connection to our South Texas system that allows it to receive both onshore and offshore domestic crude oil in the Texas Gulf Coast area for delivery to Cushing. The Seaway Crude Pipeline Company Partnership Agreement provides for varying participation ratios throughout the life of Seaway. The sharing ratio (including the amount of distributions we receive) changed from 60% to 40% on March 12, 2006, and as such, our share of revenue and expense of Seaway was 47% for 2006. Thereafter, we receive 40% of revenue and expense (and distributions) of Seaway. During the years ended December 31, 2008, 2007 and 2006, we received distributions from Seaway of $13.8 million, $12.4 million and $20.5 million, respectively. During the years ended December 31, 2008, 2007 and 2006, we did not invest any funds in Seaway. Our share of undistributed earnings of Seaway totaled approximately $1.4 million at December 31, 2008.
Texas Offshore Port System
In August 2008, we, together with Enterprise Products Partners and Oiltanking Holding Americas, Inc. (“Oiltanking”) formed Texas Offshore Port System, a joint venture to design, construct, operate and own a new Texas offshore crude oil port and pipeline system to facilitate delivery of waterborne crude oil to refining centers located along the upper Texas Gulf Coast. The joint venture’s primary project, referred to as “TOPS,” includes (i) an offshore port (which will be located approximately 36 miles from Freeport, Texas), (ii) an onshore storage facility with approximately 3.9 million barrels of total crude oil storage capacity, and (iii) an 85-mile pipeline system that will have the capacity to deliver up to 1.8 million barrels per day of crude oil, that will extend from the offshore port to a storage facility near Texas City, Texas. The joint venture’s complementary project, referred to as the Port Arthur Crude Oil Express (“PACE”) will transport crude oil from Texas City, including crude oil from TOPS, and will consist of a 75-mile pipeline and 1.2 million barrels of crude oil storage capacity in the Port Arthur, Texas area. Development of the TOPS and PACE projects is supported by long-term contracts with affiliates of Motiva Enterprises, LLC and Exxon Mobil Corporation, which have committed a combined 725,000 barrels per day of crude oil to the projects. The timing of the construction and related capital costs of the TOPS and PACE projects will be affected by the acquisition of requisite permits.
We, Enterprise Products Partners and Oiltanking each own, through our respective subsidiaries, a one-third interest in the joint venture. A subsidiary of Enterprise Products Partners acts as construction manager and will act
F-38
TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
as operator. The aggregate cost of the TOPS and PACE projects is expected to be approximately $1.8 billion (excluding capitalized interest), with the majority of such capital expenditures currently expected to occur in 2010 and 2011. We and an affiliate of Enterprise Products Partners have each guaranteed up to approximately $700.0 million, which includes a contingency amount for potential cost overruns, of the capital contribution obligations of our respective subsidiary partners in the joint venture. At December 31, 2008, we have invested $36.0 million in the joint venture.
Jonah
Enterprise Products Partners, through its affiliate, Enterprise Gas Processing, LLC, is our joint venture partner in Jonah, the partnership through which we have owned our interest in the system serving the Jonah and Pinedale fields in the greater Green River Basin in southwestern Wyoming. The joint venture is governed by a management committee comprised of two representatives approved by Enterprise Products Partners and two representatives approved by us, each with equal voting power. Enterprise Products Partners serves as operator. In June 2008, Jonah completed the Phase V expansion, which increased the combined system capacity of the Jonah and Pinedale fields from 1.5 billion cubic feet (“Bcf”) per day to 2.35 Bcf per day. The increased capacity from the expansion has reduced system operating pressures and increased production rates and ultimate reserve recoveries. Enterprise Products Partners managed the Phase V construction project.
From August 1, 2006 through July 2007, we and Enterprise Products Partners equally shared the costs of the Phase V expansion, and Enterprise Products Partners shared in the incremental cash flow resulting from the operation of those new facilities. During August 2007, with the completion of the first portion of the expansion, we and Enterprise Products Partners began sharing joint venture cash distributions and earnings based on a formula that takes into account the capital contributions of the parties, including expenditures by us prior to the expansion. Based on this formula in the partnership agreement, beginning in August 2007, our ownership interest in Jonah was approximately 80.64%, and Enterprise Products Partners’ ownership interest in Jonah was approximately 19.36%. Amounts exceeding an agreed upon base cost estimate of $415.2 million were shared 19.36% by Enterprise Products Partners and 80.64% by us. Our ownership interest in Jonah is currently anticipated to remain at 80.64%. Through December 31, 2008, we have reimbursed Enterprise Products Partners $306.5 million ($44.9 million in 2008, $152.2 million in 2007 and $109.4 million in 2006) for our share of the Phase V cost incurred by it (including its cost of capital incurred prior to the formation of the joint venture of $1.3 million). At December 31, 2008 and 2007, we had payables to Enterprise Products Partners for costs incurred of $1.0 million and $9.9 million, respectively.
In early 2008, Jonah began an expansion of the portion of its system serving the Pinedale field, which is expected to further increase the combined system capacity of the Jonah and Pinedale fields from 2.35 Bcf per day to approximately 2.55 Bcf per day. This project will include an additional 17,000 horsepower of compression at the Paradise and Bird Canyon stations in Sublette County, Wyoming and involve construction of approximately 52 miles of 30-inch and 24-inch diameter pipelines. This expansion is expected to be completed in phases, with final completion expected in early 2009. The total anticipated cost of this system expansion is expected to be approximately $125.0 million. Our share of the costs of the construction is expected to be 80.64%, and Enterprise Products Partners’ share is expected to be 19.36%. Enterprise Products Partners is managing this construction project.
During the years ended December 31, 2008, 2007 and 2006, we received distributions from Jonah of $132.2 million, $100.0 million and $0, respectively. The 2007 amount included $11.6 million of distributions declared in 2006 and paid during the first quarter of 2007. During the years ended December 31, 2008, 2007 and 2006, we invested cash of $129.8 million, $187.5 million and $121.0 million, respectively, in Jonah.
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TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Summarized Financial Information of Unconsolidated Affiliates
Summarized combined income statement data by reporting segment for the years ended December 31, 2008 and 2007 is presented below (on a 100% basis):
| For Year Ended December 31, | ||||||||||||||||||||||||||||||||||||
| 2008 | 2007 | 2006 | ||||||||||||||||||||||||||||||||||
| Revenues | Operating Income | Net Income (Loss) | Revenues | Operating Income | Net Income | Revenues | Operating Income | Net Income (Loss) | ||||||||||||||||||||||||||||
| Downstream Segment (1) | $ | 39,109 | $ | 6,335 | $ | (4,428 | ) | $ | 56,816 | $ | 13,156 | $ | 2,365 | $ | 73,124 | $ | 10,374 | $ | (583 | ) | ||||||||||||||||
| Upstream Segment | 93,878 | 45,783 | 45,969 | 67,337 | 21,266 | 21,589 | 87,284 | 34,206 | 34,608 | |||||||||||||||||||||||||||
| Midstream Segment (2) | 232,825 | 111,070 | 111,791 | 204,146 | 92,212 | 93,120 | 79,618 | 34,646 | 34,743 | |||||||||||||||||||||||||||
______________________
| (1) | On March 1, 2007, we sold our ownership interest in MB Storage to Louis Dreyfus (see Note 10). |
| (2) | Effective August 1, 2006, with the formation of a joint venture with Enterprise Products Partners, Jonah was deconsolidated and has been subsequently accounted for as an equity investment. |
Summarized combined balance sheet information by reporting segment as of December 31, 2008 and 2007, is presented below:
| December 31, 2008 | ||||||||||||||||||||||||
Current Assets | Noncurrent Assets | Current Liabilities | Long-term Debt | Noncurrent Liabilities | Equity | |||||||||||||||||||
| Downstream Segment | $ | 12,870 | $ | 239,414 | $ | 20,673 | $ | 120,000 | $ | 358 | $ | 111,253 | ||||||||||||
| Upstream Segment (1) | 52,423 | 338,616 | 11,155 | -- | 22 | 379,862 | ||||||||||||||||||
| Midstream Segment | 53,810 | 1,163,257 | 28,224 | -- | 378 | 1,188,465 | ||||||||||||||||||
| December 31, 2007 | ||||||||||||||||||||||||
Current Assets | Noncurrent Assets | Current Liabilities | Long-term Debt | Noncurrent Liabilities | Equity | |||||||||||||||||||
| Downstream Segment | $ | 20,864 | $ | 248,896 | $ | 23,814 | $ | 129,900 | $ | 365 | $ | 115,681 | ||||||||||||
| Upstream Segment | 16,429 | 251,635 | 6,457 | -- | 38 | 261,569 | ||||||||||||||||||
| Midstream Segment | 55,396 | 1,065,304 | 22,545 | -- | 264 | 1,097,891 | ||||||||||||||||||
____________________
| (1) | Includes our ownership interest in Texas Offshore Port System as of December 31, 2008. |
NOTE 10. ACQUISITIONS, DISPOSITIONS AND DISCONTINUED OPERATIONS
Acquisitions
Cenac
On February 1, 2008, we, through our subsidiary, TEPPCO Marine Services, entered the marine transportation business for refined products, crude oil and condensate. We acquired transportation assets and certain intangible assets that comprised the marine transportation business of Cenac Towing Co., Inc. (“Cenac Towing”), Cenac Offshore, L.L.C. and Mr. Arlen B. Cenac, Jr., the sole owner of Cenac Towing Co., Inc. and Cenac Offshore, L.L.C. (collectively, “Cenac”). The aggregate value of total consideration we paid or issued to complete the Cenac acquisition was $444.7 million, which consisted of $258.2 million in cash and 4,854,899 newly issued Units.
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TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Additionally, we assumed $63.2 million of Cenac’s long-term debt in this transaction. On February 1, 2008, we repaid the $63.2 million of assumed debt in full with borrowings under our term credit agreement (see Note 12).
The following table summarizes the components of total consideration paid or issued in this transaction.
| Cash payment for Cenac acquisition | $ | 256,593 | ||
| Fair value of our 4,854,899 Units | 186,558 | |||
| Other cash acquisition costs paid to third-parties | 1,589 | |||
| Total consideration | $ | 444,740 |
We financed the cash portion of the consideration with borrowings under our term credit agreement (see Note 12). In accordance with purchase accounting, the value of our Units issued in connection with the Cenac acquisition was based on the average closing price of such Units immediately prior to and on the day of February 1, 2008. For the purpose of this calculation, the average closing price was $38.43 per Unit.
We acquired 42 tow boats, 89 tank barges and the economic benefit of certain related commercial agreements. This business serves refineries and storage terminals along the Mississippi, Illinois and Ohio rivers, and the Intracoastal Waterway between Texas and Florida. These assets also gather crude oil from production facilities and platforms along the U.S. Gulf Coast and in the Gulf of Mexico. This acquisition is a natural extension of our existing assets and complements two of our core franchise businesses: the transportation and storage of refined products and the gathering, transportation and storage of crude oil.
The results of operations for the Cenac acquisition are included in our consolidated financial statements beginning at the date of acquisition, in a newly created business segment, Marine Services Segment. Our fleet of acquired tow boats and tank barges will continue to be operated by employees of Cenac under a transitional operating agreement with TEPPCO Marine Services for a period of up to two years following the acquisition. These operations will remain headquartered in Houma, Louisiana during such time.
The purchase agreement gives us the right to repurchase the approximately 4.9 million Units issued in the transaction in connection with proposed sales thereof by Cenac and specified related persons for 10 years. If we or any of our affiliates sell any of the assets acquired from Cenac Towing prior to June 30, 2018 and recognize certain “built-in gains” for federal income tax purposes that are allocable to Cenac Towing, we have indemnification obligations under the purchase agreement to pay Cenac Towing an amount generally intended to compensate for the incremental level of double taxation imposed on Cenac Towing as a result of the sale. The purchase agreement prohibits Cenac from competing with our marine services business for two years or from soliciting employees and service providers of TEPPCO Marine Services and its affiliates for four years. The purchase agreement contains other customary representations, warranties, covenants and indemnification provisions.
This acquisition was accounted for using the purchase method of accounting and, accordingly, the cost has been allocated to assets acquired and liabilities assumed based on estimated fair values. Such fair values have been developed using recognized business valuation techniques.
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TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The following table summarizes estimated fair values of the assets acquired and liabilities assumed at the date of acquisition.
| Property, plant and equipment | $ | 360,146 | ||
| Intangible assets | 63,500 | |||
| Other assets | 2,726 | |||
| Total assets acquired | 426,372 |
| Long-term debt | (63,157 | ) | ||
| Total liabilities assumed | (63,157 | ) | ||
| Total assets acquired less liabilities assumed | 363,215 | |||
| Total consideration given | 444,740 | |||
| Goodwill | $ | 81,525 |
The $63.5 million fair value of acquired intangible assets represents customer relationships and non-compete agreements. Customer relationship intangible assets represent the estimated economic value attributable to certain relationships acquired in connection with the Cenac acquisition whereby (i) we acquired information about or access to customers and now have regular contact with them and (ii) the customers now have the ability to make direct contact with us. In this context, customer relationships arise from contractual arrangements (such as transportation contracts) and through means other than contracts, such as regular contact by sales or service representative. The values assigned to these intangible assets are amortized to earnings on a straight-line basis over the expected period of economic benefit, which ranges from 2 to 20 years.
Of the $444.7 million in consideration we paid or issued to complete the Cenac acquisition, $81.5 million has been assigned to goodwill. Management attributes the value of this goodwill to potential future benefits we expect to realize as a result of acquiring these assets.
Since the closing date of the Cenac acquisition was February 1, 2008, our statements of consolidated income do not include any earnings from these assets prior to this date. The following table presents selected pro forma earnings information for the years ended December 31, 2008 and 2007 as if the Cenac acquisition had been completed on January 1, 2008 and 2007, respectively, instead of February 1, 2008. This information was prepared based on financial data available to us and reflects certain estimates and assumptions made by our management. Our pro forma financial information is not necessarily indicative of what our consolidated financial results would have been had the Cenac acquisition actually occurred on January 1, 2007 or 2008.
For the Year Ended December 31, | ||||||||
| 2008 | 2007 | |||||||
| Pro forma earnings data: | ||||||||
| Revenues | $ | 13,544,440 | $ | 9,762,597 | ||||
| Costs and expenses | 13,288,363 | 9,502,334 | ||||||
| Operating income | 256,077 | 260,263 | ||||||
| Net income | 195,626 | 282,902 | ||||||
| Basic and diluted earnings per Unit: | ||||||||
| Units outstanding, as reported | 97,530 | 89,850 | ||||||
| Units outstanding, pro forma | 100,000 | 94,690 | ||||||
| Basic and diluted earnings per Unit, as reported | $ | 1.65 | $ | 2.60 | ||||
| Basic and diluted earnings per Unit, pro forma | $ | 1.63 | $ | 2.50 | ||||
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TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Horizon
On February 29, 2008, we expanded our Marine Services Segment with the acquisition of marine assets from Horizon Maritime, L.L.C. (“Horizon”), a privately-held Houston-based company and an affiliate of Mr. Cenac for $80.8 million in cash. We acquired 7 tow boats, 17 tank barges, rights to two tow boats under construction and certain related commercial and other agreements (or the associated economic benefits). In April 2008, we paid $3.0 million to Horizon pursuant to the purchase agreement upon delivery of one of the tow boats under construction, and in June 2008, we paid $3.8 million upon delivery of the second tow boat. The acquired vessels transport asphalt, heavy fuel oil and other heated oil products to storage facilities and refineries along the Mississippi, Illinois and Ohio Rivers, and the Intracoastal Waterway. We financed the acquisition with borrowings under our term credit agreement.
The results of operations for the Horizon acquisition are included in our consolidated financial statements beginning at the date of acquisition, in our Marine Services Segment. This acquisition was accounted for using the purchase method of accounting and, accordingly, the cost has been allocated to assets acquired and liabilities assumed based on estimated fair values. Such fair values have been developed using recognized business valuation techniques. The following table summarizes estimated fair values of the assets acquired and liabilities assumed at the date of acquisition.
| Property, plant and equipment | $ | 71,216 | ||
| Intangible assets | 6,500 | |||
| Other assets | 981 | |||
| Total assets acquired | 78,697 | |||
| Total consideration given | 87,584 | |||
| Goodwill | $ | 8,887 |
The $6.5 million fair value of acquired intangible assets represents customer relationships and non-compete agreements. Customer relationship intangible assets represent the estimated economic value attributable to certain relationships acquired in connection with the Horizon acquisition whereby (i) we acquired information about or access to customers and now have regular contact with them and (ii) the customers now have the ability to make direct contact with us. In this context, customer relationships arise from contractual arrangements (such as transportation contracts) and through means other than contracts, such as regular contact by sales or service representative. The values assigned to these intangible assets are amortized to earnings on a straight-line basis over the expected period of economic benefit, which ranges from 2 to 9 years.
Of the $87.6 million in consideration we paid to complete the acquisition of the Horizon business, $8.9 million has been assigned to goodwill. Management attributes the value of this goodwill to potential future benefits we expect to realize as a result of acquiring these assets and further expanding our Marine Services Segment.
Lubrication and Other Fuel Oil Assets
On August 1, 2008, we purchased lubrication and other fuel oil assets, located in Wyoming, from Quality Petroleum, Inc. for approximately $6.8 million, which includes $1.3 million related to a non-compete agreement. The assets, included in our Upstream Segment, consist of operating inventory, buildings, land and various equipment and the assignment of certain distributor agreements. We funded the purchase through borrowings under our revolving credit facility, and we allocated the purchase price primarily to property, plant and equipment, goodwill, inventory and intangible assets. We recorded $0.7 million of goodwill related to this acquisition.
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TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Cavern Assets
On July 31, 2007, we purchased assets from Duke Energy Ohio, Inc. and Ohio River Valley Propane, LLC for approximately $6.1 million. The assets, included in our Downstream Segment, consist of an active 170,000 barrel LPG storage cavern, the associated piping and related equipment and a one bay truck rack. These assets are located adjacent to our Todhunter facility near Middleton, Ohio and are connected to our existing LPG pipeline. We funded the purchase through borrowings under our revolving credit facility, and we allocated the purchase price to property, plant and equipment.
Crude Oil Pipeline Assets
On September 27, 2007, we purchased assets from Shell Pipeline Company LP for approximately $6.8 million. The assets, included in our Upstream Segment, consisted of approximately 44 miles of pipeline in South Texas and related equipment. We funded the purchase through borrowings under our revolving credit facility, and we allocated the purchase price to property, plant and equipment.
Dispositions
MB Storage and Other Related Assets
On March 1, 2007, TE Products sold its 49.5% ownership interest in MB Storage, its 50% ownership interest in Mont Belvieu Venture, LLC (the general partner of MB Storage) and other related assets to Louis Dreyfus for a total of approximately $155.8 million in cash, which includes approximately $18.5 million for other TE Products assets. This sale was in compliance with the October 2006 order and consent agreement with the FTC and was completed in accordance with the terms and conditions approved by the FTC in February 2007. We used the proceeds from the transaction to partially fund our 2007 portion of the Jonah Phase V expansion and other organic growth projects. We recognized gains of approximately $59.6 million and $13.2 million related to the sale of our equity interests and other related assets of TE Products, respectively, which are included in gain on sale of ownership interest in MB Storage and gain on the sale of assets, respectively, in our statements of consolidated income.
In accordance with a transition services agreement between TE Products and Louis Dreyfus, TE Products provides certain administrative services to MB Storage for a period of up to two years after the sale, for a fee equal to 110% of the direct costs and expenses TE Products and its affiliates incur to provide the transition services to MB Storage. Payments for these services are made according to the terms specified in the transition services agreement.
Other Refined Products Assets
On January 23, 2007, we sold a 10-mile, 18-inch diameter segment of pipeline to an affiliate of Enterprise Products Partners for approximately $8.0 million in cash. These assets were part of our Downstream Segment and had a net book value of approximately $2.5 million. The sales proceeds were used to fund construction of a replacement pipeline in the area, in which the new pipeline provides greater operational capability and flexibility. We recognized a gain of approximately $5.5 million on this transaction, which is included in gain on sale of assets in our statements of consolidated income.
Discontinued Operations
Pioneer Plant
On March 31, 2006, we sold our ownership interest in the Pioneer silica gel natural gas processing plant located near Opal, Wyoming, together with Jonah’s rights to process natural gas originating from the Jonah and
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TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Pinedale fields, located in southwest Wyoming, to an affiliate of Enterprise Products Partners for $38.0 million in cash. The Pioneer plant was not an integral part of our Midstream Segment operations, and natural gas processing is not a core business for us. We have no continuing involvement in the operations or results of this plant. This transaction was reviewed and recommended for approval by our ACG Committee and a fairness opinion was rendered by an investment banking firm. The sales proceeds were used to fund organic growth projects, retire debt and for other general partnership purposes. The carrying value of the Pioneer plant at March 31, 2006, prior to the sale, was $19.7 million. Costs associated with the completion of the transaction were approximately $0.4 million.
A condensed statement of income for the Pioneer plant, which is classified as discontinued operations, for the year ended December 31, 2006, is presented below:
| For Year Ended | ||||
| December 31, | ||||
| 2006 | ||||
| Operating revenues: | ||||
| Sales of petroleum products | $ | 3,828 | ||
| Other | 932 | |||
| Total operating revenues | 4,760 | |||
| Costs and expenses: | ||||
| Purchases of petroleum products | 3,000 | |||
| Operating expense | 182 | |||
| Depreciation and amortization | 51 | |||
| Taxes – other than income taxes | 30 | |||
| Total costs and expenses | 3,263 | |||
| Income from discontinued operations | $ | 1,497 | ||
Net operating cash provided by discontinued operations for the year ended December 31, 2006, is presented below:
| For Year Ended | ||||
| December 31, | ||||
| 2006 | ||||
| Cash flows from discontinued operations: | ||||
| Net income | $ | 19,369 | ||
| Depreciation and amortization | 51 | |||
| Gain on sale of Pioneer plant | (17,872 | ) | ||
| Increase in inventories | (27 | ) | ||
| Net operating cash provided by discontinued operations | $ | 1,521 | ||
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TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
NOTE 11. INTANGIBLE ASSETS AND GOODWILL
Intangible Assets
The following table summarizes our intangible assets, including excess investments, being amortized at December 31, 2008 and 2007:
| December 31, 2008 | December 31, 2007 | |||||||||||||||
Gross Carrying Amount | Accumulated Amortization | Gross Carrying Amount | Accumulated Amortization | |||||||||||||
| Intangible assets: | ||||||||||||||||
Downstream Segment: | ||||||||||||||||
Transportation agreements | $ | 1,000 | $ | (408 | ) | $ | 1,000 | $ | (358 | ) | ||||||
Other | 5,621 | (764 | ) | 4,927 | (325 | ) | ||||||||||
Subtotal | 6,621 | (1,172 | ) | 5,927 | (683 | ) | ||||||||||
Upstream Segment: | ||||||||||||||||
Transportation agreements | 888 | (395 | ) | 888 | (335 | ) | ||||||||||
Other | 10,580 | (3,009 | ) | 10,005 | (3,046 | ) | ||||||||||
Subtotal | 11,468 | (3,404 | ) | 10,893 | (3,381 | ) | ||||||||||
Midstream Segment: | ||||||||||||||||
Gathering agreements | 239,649 | (125,811 | ) | 239,649 | (107,356 | ) | ||||||||||
Fractionation agreements | 38,000 | (20,425 | ) | 38,000 | (18,525 | ) | ||||||||||
Other | 306 | (164 | ) | 306 | (149 | ) | ||||||||||
Subtotal | 277,955 | (146,400 | ) | 277,955 | (126,030 | ) | ||||||||||
Marine Services Segment: | ||||||||||||||||
Customer relationship intangibles | 51,320 | (3,121 | ) | -- | -- | |||||||||||
Other | 18,680 | (4,294 | ) | -- | -- | |||||||||||
Subtotal | 70,000 | (7,415 | ) | -- | -- | |||||||||||
Total intangible assets | 366,044 | (158,391 | ) | 294,775 | (130,094 | ) | ||||||||||
| Excess investments: (1) | ||||||||||||||||
Downstream Segment (2) | 33,390 | (26,128 | ) | 33,390 | (21,861 | ) | ||||||||||
Upstream Segment (3) | 26,908 | (5,820 | ) | 26,908 | (5,135 | ) | ||||||||||
Midstream Segment (4) | 12,580 | (241 | ) | 6,988 | (95 | ) | ||||||||||
| Subtotal | 72,878 | (32,189 | ) | 67,286 | (27,091 | ) | ||||||||||
Total intangible assets, including excess investments | $ | 438,922 | $ | (190,580 | ) | $ | 362,061 | $ | (157,185 | ) | ||||||
| (1) | Excess investments are included in “Equity Investments” in our consolidated balance sheets. |
| (2) | Relates to our investment in Centennial. |
| (3) | Relates to our investment in Seaway. |
| (4) | Relates to our investment in Jonah. |
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TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The following table presents the amortization expense of our intangible assets and excess investments by segment for the years ended December 31, 2008, 2007 and 2006:
| For Year Ended December 31, | ||||||||||||
| 2008 | 2007 | 2006 | ||||||||||
| Intangible assets: | ||||||||||||
Downstream Segment | $ | 489 | $ | 628 | $ | 59 | ||||||
Upstream Segment | 698 | 652 | 716 | |||||||||
Midstream Segment | 20,370 | 22,734 | 28,044 | |||||||||
Marine Services Segment | 7,415 | -- | -- | |||||||||
| Subtotal | 28,972 | 24,014 | 28,819 | |||||||||
| Excess investments: (1) | ||||||||||||
Downstream Segment | 4,267 | 5,282 | 3,632 | |||||||||
Upstream Segment | 685 | 685 | 686 | |||||||||
Midstream Segment | 146 | 95 | -- | |||||||||
| Subtotal | 5,098 | 6,062 | 4,318 | |||||||||
| Total amortization expense | $ | 34,070 | $ | 30,076 | $ | 33,137 | ||||||
_______________________
| (1) | Amortization of excess investments is included in equity earnings. |
SFAS 142 requires that intangible assets with finite useful lives be amortized over their respective estimated useful lives. If an intangible asset has a finite useful life, but the precise length of that life is not known, that intangible asset shall be amortized over the best estimate of its useful life. At a minimum, we will assess the useful lives and residual values of all intangible assets on an annual basis to determine if adjustments are required.
The values assigned to our intangible assets for natural gas gathering contracts on the Val Verde system are amortized on a unit-of-production basis, based upon the actual throughput of the systems compared to the expected total throughput for the lives of the contracts. From time to time, we may obtain limited production forecasts and updated throughput estimates from some of the producers on the system, and as a result, we evaluate the remaining expected useful lives of the contract assets based on the best available information. Further revisions to these estimates may occur as additional production information is made available to us.
The values assigned to our fractionation agreement and other intangible assets are generally amortized on a straight-line basis. Our fractionation agreement is being amortized over its contract period of 20 years. The amortization periods for our other intangible assets, which include non-compete and other agreements, range from 3 years to 15 years. The value of $8.7 million assigned to our crude supply and transportation intangible customer contracts is being amortized on a unit-of-production basis. The values assigned to our customer relationships and non-compete agreements related to the acquisition of the marine assets are generally amortized on a straight-line basis from 2 to 20 years (see Note 10).
The value assigned to our excess investment in Centennial was created upon its formation. Approximately $30.0 million is related to a contract and is being amortized on a unit-of-production basis based upon the volumes transported under the contract compared to the guaranteed total throughput of the contract over a 10-year life. The remaining $3.4 million is related to a pipeline and is being amortized on a straight-line basis over the life of the pipeline, which is 35 years. The value assigned to our excess investment in Seaway was created upon acquisition of our 50% ownership interest in 2000. We are amortizing the excess investment in Seaway on a straight-line basis over a 39-year life related primarily to the life of the pipeline. The value assigned to our excess investment in Jonah was created as a result of interest capitalized on the construction of Jonah’s expansion. We are amortizing the excess investment in Jonah on a straight-line basis over the life of the assets constructed.
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TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The following table sets forth the estimated amortization expense of intangible assets and the estimated amortization expense from excess investments allocated to equity earnings for the years ending December 31:
| Intangible Assets | Excess Investments | |||||||
| 2009 | $ | 26,417 | $ | 5,771 | ||||
| 2010 | 24,558 | 1,141 | ||||||
| 2011 | 22,672 | 1,141 | ||||||
| 2012 | 17,200 | 1,141 | ||||||
| 2013 | 15,543 | 1,141 | ||||||
Goodwill
Goodwill represents the excess of purchase price over fair value of net assets acquired. We account for goodwill under SFAS No. 142, Goodwill and Other Intangible Assets, which was issued by the FASB in July 2001. SFAS 142 prohibits amortization of goodwill, but instead requires testing for impairment at least annually. We test goodwill for impairment annually at December 31.
To perform an impairment test of goodwill, we have identified our reporting units and have determined the carrying value of each reporting unit by assigning the assets and liabilities, including the existing goodwill, to those reporting units. We then determine the fair value of each reporting unit and compare it to the carrying value of the reporting unit. We will continue to compare the fair value of each reporting unit to its carrying value on an annual basis to determine if an impairment loss has occurred. There have been no goodwill impairment losses recorded since the adoption of SFAS 142.
The following table presents the carrying amount of goodwill at December 31, 2008 and 2007, by business segment:
| December 31, | ||||||||
| 2008 | 2007 | |||||||
| Downstream Segment | $ | 1,339 | $ | 1,339 | ||||
| Upstream Segment | 14,860 | 14,167 | ||||||
| Marine Services Segment | 90,412 | -- | ||||||
| Total goodwill | $ | 106,611 | $ | 15,506 | ||||
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TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
NOTE 12. DEBT OBLIGATIONS
The following table summarizes the principal amounts outstanding under all of our debt instruments at December 31, 2008 and 2007:
| December 31, | ||||||||
| 2008 | 2007 | |||||||
| Short-term senior debt obligations: | ||||||||
| 6.45% TE Products Senior Notes, due January 2008 (1) | $ | -- | $ | 180,000 | ||||
| 7.51% TE Products Senior Notes, due January 2028 (1) | -- | 175,000 | ||||||
| Total principal amount of short-term senior debt obligations | -- | 355,000 | ||||||
Adjustment to carrying value associated with hedges of | ||||||||
Fair value and unamortized discounts (2) | -- | (1,024 | ) | |||||
| Total short-term senior debt obligations | $ | -- | $ | 353,976 | ||||
| Long-term: | ||||||||
Senior debt obligations: (3) | ||||||||
| Revolving Credit Facility, due December 2012 | $ | 516,654 | $ | 490,000 | ||||
| 7.625% Senior Notes, due February 2012 | 500,000 | 500,000 | ||||||
| 6.125% Senior Notes, due February 2013 | 200,000 | 200,000 | ||||||
| 5.90% Senior Notes, due April 2013 | 250,000 | -- | ||||||
| 6.65% Senior Notes, due April 2018 | 350,000 | -- | ||||||
| 7.55% Senior Notes, due April 2038 | 400,000 | -- | ||||||
Total principal amount of long-term senior debt obligations | 2,216,654 | 1,190,000 | ||||||
| 7.000% Junior Subordinated Notes, due June 2067 (3) | 300,000 | 300,000 | ||||||
Total principal amount of long-term debt obligations | 2,516,654 | 1,490,000 | ||||||
Adjustment to carrying value associated with hedges of fair value and unamortized discounts (4) | 12,865 | 21,083 | ||||||
| Total long-term debt obligations | 2,529,519 | 1,511,083 | ||||||
| Total Debt Instruments (4) | $ | 2,529,519 | $ | 1,865,059 | ||||
| Standby letters of credit outstanding (5) | $ | -- | $ | 23,494 | ||||
_________________
| (2) | Includes $1.0 million related to fair value hedges and $2 thousand in unamortized discount. In January 2008, with the redemption of the 7.51% TE Products Senior Notes, the remaining unamortized loss was recognized in the statement of consolidated income. |
| (3) | TE Products, TCTM, TEPPCO Midstream and Val Verde (collectively, the “Subsidiary Guarantors”) have issued full, unconditional, joint and several guarantees of our senior notes, junior subordinated notes and revolving credit facility. |
| (4) | From time to time we enter into interest rate swap agreements to hedge our exposure to changes in the fair value on a portion of the debt obligations presented above (see Note 6). At December 31, 2008 and 2007, amount includes $5.2 million and $2.1 million of unamortized discounts, respectively, and $18.1 million and $23.2 million related to fair value hedges, respectively. |
| (5) | Letters of credit were issued in connection with crude oil purchased during 2007. |
F-49
TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Revolving Credit Facility
We have in place an unsecured revolving credit facility (“Revolving Credit Facility”), which matures on December 12, 2012. The Revolving Credit Facility allows us to request unlimited one-year extensions of the maturity date, subject to lender approval and satisfaction of certain other conditions. In July 2008, commitments under our facility were increased from $700.0 million to $950.0 million. The aggregate outstanding principal amount of swing line loans or same day borrowings permitted under the Revolving Credit Facility is $40.0 million. The interest rate is based, at our option, on either the lender’s base rate, or LIBOR rate, plus a margin, in effect at the time of the borrowings. The applicable margin with respect to LIBOR rate borrowings is based on our senior unsecured non-credit enhanced long-term debt rating issued by Standard & Poor’s Rating Services (“S&P”) and Moody’s Investors Service, Inc. (“Moody’s”). The Revolving Credit Facility contains a term-out option in which we may, on the maturity date, convert the principal balance of all revolving loans then outstanding into a non-revolving one-year term loan. Upon the conversion of the revolving loans to term loans pursuant to the term-out option, the applicable LIBOR spread will increase by 0.125% per year, and if immediately prior to such borrowing the total outstanding revolver borrowings then outstanding exceeds 50% of the total lender commitments, the applicable LIBOR spread with respect to borrowings will increase by an additional 10 basis points.
During September 2008, Lehman Brothers Bank, FSB (“Lehman”), which had a 4.05% participation in our Revolving Credit Facility, stopped funding its commitment following the bankruptcy filing of its parent. Assuming that future fundings are not received for the Lehman percentage commitment, aggregate available capacity would be reduced by approximately $28.9 million.
The Revolving Credit Facility contains financial covenants that require us to maintain a ratio of Consolidated Funded Debt to Pro Forma EBITDA (as defined and calculated in the facility) of less than 5.00 to 1.00 (and, if after giving effect to a permitted acquisition the ratio exceeds 5.00 to 1.00, the threshold ratio will be increased to 5.50 to 1.00 for the fiscal quarter in which such acquisition occurs and the first full fiscal quarter following such acquisition). Other restrictive covenants in the Revolving Credit Facility limit our ability, and the ability of certain of our subsidiaries, to, among other things, incur certain additional indebtedness, make distributions in excess of Available Cash (see Note 12), incur certain liens, engage in specified transactions with affiliates and complete mergers, acquisitions and sales of assets. The credit agreement restricts the amount of outstanding debt of the Jonah joint venture to debt owing to the owners of its partnership interests and other third-party debt in the aggregate principal amount of $50.0 million and allows for the issuance of certain hybrid securities of up to 15% of our Consolidated Total Capitalization (as defined therein). At December 31, 2008, $516.7 million was outstanding under the Revolving Credit Facility at a weighted average interest rate of 1.4%, and our available borrowing capacity under the facility was approximately $404.4 million. At December 31, 2008, we were in compliance with the covenants of the Revolving Credit Facility.
Senior Notes
On January 27, 1998, TE Products issued $180.0 million principal amount of 6.45% Senior Notes due 2008 and $210.0 million principal amount of 7.51% Senior Notes due 2028 (collectively the “TE Products Senior Notes”). Interest on the TE Products Senior Notes was payable semiannually in arrears on January 15 and July 15 of each year. The 6.45% TE Products Senior Notes were issued at a discount of $0.3 million and were being accreted to their face value over the term of the notes. The 6.45% TE Products Senior Notes due 2008 were redeemed at maturity on January 15, 2008. The 7.51% TE Products Senior Notes due 2028, issued at par, became redeemable at any time after January 15, 2008, at the option of TE Products, in whole or in part, at varying fixed annual redemption prices. In October 2007, TE Products repurchased $35.0 million principal amount of the 7.51% TE Products Senior Notes for $36.1 million and accrued interest. On January 28, 2008, TE Products redeemed the remaining $175.0 million of 7.51% TE Products Senior Notes at a redemption price of 103.755% of the principal amount plus accrued and unpaid interest at the date of redemption. We funded the retirement of both series of senior notes with borrowings under our term credit agreement.
F-50
TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
On February 20, 2002 and January 30, 2003, we issued $500.0 million principal amount of 7.625% Senior Notes due 2012 and $200.0 million principal amount of 6.125% Senior Notes due 2013, respectively. These senior notes were issued at discounts of $2.2 million and $1.4 million, respectively, and are being accreted to their face value over the applicable term of the senior notes. The senior notes may be redeemed at any time at our option with the payment of accrued interest and a make-whole premium determined by discounting remaining interest and principal payments using a discount rate equal to the rate of the United States Treasury securities of comparable remaining maturity plus 35 basis points.
On March 27, 2008, we issued (i) $250.0 million principal amount of 5.90% Senior Notes due 2013, (ii) $350.0 million principal amount of 6.65% Senior Notes due 2018, and (iii) $400.0 million principal amount of 7.55% Senior Notes due 2038. The senior notes were issued at discounts of $0.2 million, $1.3 million and $2.2 million, respectively, and are being accreted to their face value over the applicable terms of the senior notes. The senior notes may be redeemed at any time at our option with the payment of accrued interest and a make-whole premium determined by discounting remaining interest and principal payments using a discount rate equal to the rate of the United States Treasury securities of comparable remaining maturity plus 50 basis points.
The indentures governing our senior notes contain covenants, including, but not limited to, covenants limiting the creation of liens securing indebtedness and sale and leaseback transactions. However, the indentures do not limit our ability to incur additional indebtedness. At December 31, 2008, we were in compliance with the covenants of our senior notes.
Junior Subordinated Notes
In May 2007, we issued and sold $300.0 million in principal amount of fixed/floating, unsecured, long-term subordinated notes due June 1, 2067 (“Junior Subordinated Notes”). Our payment obligations under the Junior Subordinated Notes are subordinated to all of our current and future senior indebtedness (as defined in the related indenture). The Subsidiary Guarantors have issued full, unconditional, and joint and several guarantees, on a junior subordinated basis, of payment of the principal of, premium, if any, and interest on the Junior Subordinated Notes.
The indenture governing the Junior Subordinated Notes does not limit our ability to incur additional debt, including debt that ranks senior to or equally with the Junior Subordinated Notes. The indenture allows us to defer interest payments on one or more occasions for up to ten consecutive years, subject to certain conditions. The indenture also provides that during any period in which we defer interest payments on the Junior Subordinated Notes, subject to certain exceptions, (i) we cannot declare or make any distributions with respect to, or redeem, purchase or make a liquidation payment with respect to, any of our equity securities; (ii) neither we nor the Subsidiary Guarantors will make, and we and the Subsidiary Guarantors will cause our respective majority-owned subsidiaries not to make, any payment of interest, principal or premium, if any, on or repay, purchase or redeem any of our or the Subsidiary Guarantors’ debt securities (including securities similar to the Junior Subordinated Notes) that contractually rank equally with or junior to the Junior Subordinated Notes or the guarantees, as applicable; and (iii) neither we nor the Subsidiary Guarantors will make, and we and the Subsidiary Guarantors will cause our respective majority-owned subsidiaries not to make, any payments under a guarantee of debt securities (including under a guarantee of debt securities that are similar to the Junior Subordinated Notes) that contractually ranks equally with or junior to the Junior Subordinated Notes or the guarantees, as applicable.
The Junior Subordinated Notes bear interest at a fixed annual rate of 7.000% from May 2007 to June 1, 2017, payable semi-annually in arrears. After June 1, 2017, the Junior Subordinated Notes will bear interest at a variable annual rate equal to the 3-month LIBOR rate for the related interest period plus 2.7775%, payable quarterly in arrears. Interest payments may be deferred on a cumulative basis for up to ten consecutive years, subject to certain provisions. Deferred interest will accumulate additional interest at the then-prevailing interest rate on the Junior Subordinated Notes. The Junior Subordinated Notes mature in June 2067. The Junior Subordinated Notes are redeemable in whole or in part prior to June 1, 2017 for a “make-whole” redemption price determined by
F-51
TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
discounting remaining interest and principal payments using a discount rate equal to the rate of the United States Treasury securities of comparable remaining maturity plus 50 basis points; and thereafter at a redemption price equal to 100% of their principal amount plus accrued and unpaid interest. The Junior Subordinated Notes are also redeemable prior to June 1, 2017 in whole (but not in part) upon the occurrence of certain tax or rating agency events at specified redemption prices. At December 31, 2008, we were in compliance with the covenants of the Junior Subordinated Notes.
In connection with the issuance of the Junior Subordinated Notes, we and our Subsidiary Guarantors entered into a replacement capital covenant in favor of holders of a designated series of senior long-term indebtedness (as provided in the underlying documents) pursuant to which we and our Subsidiary Guarantors agreed for the benefit of such debt holders that we would not redeem or repurchase or otherwise satisfy, discharge or defease any of the Junior Subordinated Notes on or before June 1, 2037, unless, subject to certain limitations, during the 180 days prior to the date of that redemption, repurchase, defeasance or purchase, we have or one of our subsidiaries has received a specified amount of proceeds from the sale of qualifying securities that have characteristics that are the same as, or more equity-like than, the applicable characteristics of the Junior Subordinated Notes. The replacement capital covenant is not a term of the indenture or the Junior Subordinated Notes.
Fair Values
The following table summarizes the estimated fair values of the Senior Notes and Junior Subordinated Notes at December 31, 2008 and 2007:
| Fair Value | ||||||||||||
| December 31, | ||||||||||||
| Face Value | 2008 | 2007 | ||||||||||
| 6.45% TE Products Senior Notes, due January 2008 (1) | $ | 180,000 | $ | -- | $ | 179,982 | ||||||
| 7.625% Senior Notes, due February 2012 | 500,000 | 468,083 | 536,765 | |||||||||
| 6.125% Senior Notes, due February 2013 | 200,000 | 174,201 | 202,027 | |||||||||
| 7.51% TE Products Senior Notes, due January 2028 (1) | 175,000 | -- | 181,571 | |||||||||
| 5.90% Senior Notes, due April 2013 | 250,000 | 214,506 | -- | |||||||||
| 6.65% Senior Notes, due April 2018 | 350,000 | 280,698 | -- | |||||||||
| 7.55% Senior Notes, due April 2038 | 400,000 | 295,190 | -- | |||||||||
| 7.000% Junior Subordinated Notes, due June 2067 | 300,000 | 120,540 | 270,485 | |||||||||
_________________
| (1) | In October 2007, TE Products redeemed $35.0 million principal amount of the 7.51% TE Products Senior Notes for $36.1 million and accrued interest, and on January 28, 2008, TE Products redeemed the remaining $175.0 million of 7.51% TE Products Senior Notes at a redemption price of 103.755% of the principal amount plus accrued and unpaid interest at the date of redemption. Additionally, the $180.0 million principal amount of 6.45% TE Products Senior Notes matured and was repaid on January 15, 2008. We funded the retirement of both series with borrowings under our term credit agreement. |
Term Credit Agreement
In December 2007, we put in place a senior unsecured term credit agreement (“Term Credit Agreement”), with a borrowing capacity of $1.0 billion and a maturity date of December 19, 2008. During the first quarter of 2008, we borrowed $1.0 billion under the Term Credit Agreement to finance the retirement of TE Products’ senior notes, the Cenac and Horizon acquisitions and for other partnership purposes. In March 2008, we repaid the outstanding balance of the Term Credit Agreement with proceeds from the issuance of senior notes and other cash on hand and terminated the agreement.
F-52
TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Debt Obligations of Unconsolidated Affiliates
We have one unconsolidated affiliate, Centennial, with long-term debt obligations. The following table shows the total debt of Centennial at December 31, 2008 (on a 100% basis) and the corresponding scheduled maturities of such debt.
| Scheduled Maturities of Debt | ||||
| 2009 | $ | 9,900 | ||
| 2010 | 9,100 | |||
| 2011 | 9,000 | |||
| 2012 | 8,900 | |||
| 2013 | 8,600 | |||
| After 2013 | 84,400 | |||
| Total scheduled maturities of debt | $ | 129,900 | ||
At December 31, 2008 and 2007, Centennial’s debt obligations consisted of $129.9 million and $140.0 million, respectively, borrowed under a master shelf loan agreement. Borrowings under the master shelf agreement mature in May 2024 and are collateralized by substantially all of Centennial’s assets and severally guaranteed by Centennial’s owners.
In January 2008, we entered into an amended and restated guaranty agreement (“Amended Guaranty”) in which we, TCTM, TEPPCO Midstream and TE Products (collectively, “TEPPCO Guarantors”) are required, on a joint and several basis, to pay 50% of any past-due amount under Centennial’s master shelf loan agreement not paid by Centennial (see Note 17).
NOTE 13. PARTNERS’ CAPITAL AND DISTRIBUTIONS
Our Units represent limited partner interests, which give the holders thereof the right to participate in distributions and to exercise the other rights or privileges available to them under our Partnership Agreement. We are managed by our General Partner.
In accordance with the Partnership Agreement, capital accounts are maintained for our General Partner and limited partners. The capital account provisions of our Partnership Agreement incorporate principles established for U.S. federal income tax purposes and are not comparable to the equity accounts reflected under GAAP in our consolidated financial statements. In connection with the amendment of our Partnership Agreement in December 2006, the General Partner’s obligation to make capital contributions to maintain its 2% capital account was eliminated.
Our Partnership Agreement sets forth the calculation to be used in determining the amount and priority of cash distributions that our limited partners and General Partner will receive. Net income reflected under GAAP in our financial statements is allocated between the General Partner and the limited partners in the same proportion as aggregate cash distributions made to the General Partner and the limited partners during the period. Net income determined under our Partnership Agreement, however, incorporates principles established for U.S. federal income tax purposes and is not comparable to net income reflected under GAAP in our financial statements.
F-53
TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Equity Offerings and Registration Statements
In general, the Partnership Agreement authorizes us to issue an unlimited number of additional limited partner interests and other equity securities for such consideration and on such terms and conditions as may be established by our General Partner in its sole discretion (subject, under certain circumstances, to the approval of our unitholders).
In September 2008, we filed a universal shelf registration statement with the U.S. Securities and Exchange Commission (“SEC”) that allows us to issue an unlimited amount of debt and equity securities and removed from registration securities remaining under our previous universal shelf registration statement.
On September 9, 2008, we issued and sold in an underwritten public offering 9.2 million Units at a price to the public of $29.00 per Unit, including 1.2 million Units sold upon exercise of the underwriters’ over-allotment option granted in connection with the offering. The proceeds from the offering, net of underwriting discount and offering expenses, totaled approximately $257.0 million. Concurrently with this offering, we sold 241,380 unregistered Units at the public offering price of $29.00 to TEPPCO Unit, an affiliate of EPCO in which certain EPCO employees who perform services for us, including our executive officers, were issued Class B limited partner interests to incentivize them to enhance the long-term value of our Units. The net proceeds from the offering and the unregistered issuance to TEPPCO Unit were used to reduce indebtedness under our Revolving Credit Facility. For additional information regarding TEPPCO Unit and the equity-based compensatory awards issued therein, please see Note 4.
Quarterly Distributions of Available Cash
We make quarterly cash distributions of all of our available cash, generally defined in our Partnership Agreement as consolidated cash receipts less consolidated cash disbursements and cash reserves established by the General Partner in its reasonable discretion (“Available Cash”). Pursuant to the Partnership Agreement, the General Partner receives incremental incentive cash distributions when unitholders’ cash distributions exceed certain target thresholds as shown in the following table. Effective December 8, 2006, upon approval of our unitholders, our Partnership Agreement was amended and the 50%/50% distribution tier was eliminated in exchange for the issuance of 14,091,275 Units to the General Partner (see Note 1).
| General | ||||||||
| Unitholders | Partner | |||||||
| Quarterly Cash Distribution per Unit: | ||||||||
Up to Minimum Quarterly Distribution ($0.275 per Unit) | 98 | % | 2 | % | ||||
First Target – $0.276 per Unit up to $0.325 per Unit | 85 | % | 15 | % | ||||
Over First Target – Cash distributions greater than $0.325 per Unit | 75 | % | 25 | % | ||||
The following table reflects the allocation of total distributions paid during the years ended December 31, 2008, 2007 and 2006.
| For Year Ended December 31, | ||||||||||||
| 2008 | 2007 | 2006 | ||||||||||
| Limited Partner Units | $ | 273,071 | $ | 246,152 | $ | 196,665 | ||||||
| General Partner Ownership Interest | 5,573 | 5,024 | 4,014 | |||||||||
| General Partner Incentive | 49,353 | 43,274 | 77,887 | |||||||||
Total Cash Distributions Paid | $ | 327,997 | $ | 294,450 | $ | 278,566 | ||||||
| Total Cash Distributions Paid Per Unit | $ | 2.84 | $ | 2.74 | $ | 2.70 | ||||||
F-54
TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Our quarterly cash distributions for 2007 and 2008 are presented in the following table:
| Cash Distribution History | ||||||
Distribution per Unit | Record Date | Payment Date | ||||
| 2007 | ||||||
| 1st Quarter | $ | 0.6850 | Apr. 28, 2007 | May 7, 2007 | ||
| 2nd Quarter | 0.6850 | Jul. 31, 2007 | Aug. 7, 2007 | |||
| 3rd Quarter | 0.6950 | Oct. 31, 2007 | Nov. 7, 2007 | |||
| 4th Quarter | 0.6950 | Jan. 31, 2008 | Feb. 7, 2008 | |||
| 2008 | ||||||
| 1st Quarter | $ | 0.7100 | Apr. 30, 2008 | May 7, 2008 | ||
| 2nd Quarter | 0.7100 | Jul. 31, 2008 | Aug. 7, 2008 | |||
| 3rd Quarter | 0.7250 | Oct. 31, 2008 | Nov. 6, 2008 | |||
| 4th Quarter (1) | 0.7250 | Jan. 30, 2009 | Feb. 6, 2009 | |||
______________________
| (1) | The fourth quarter 2008 cash distribution totaled approximately $91.4 million. |
EPCO, Inc. TPP Employee Unit Purchase Plan
The EPCO, Inc. TPP Employee Unit Purchase Plan (the “Unit Purchase Plan”) provides for discounted purchases of our Units by employees of EPCO and its affiliates. A maximum of 1,000,000 Units may be delivered under the Unit Purchase Plan (subject to adjustment as provided in the plan). The Unit Purchase Plan is effective until the earlier of (i) December 8, 2016, (ii) the time that all available Units under the plan have been purchased on behalf of the participants or (iii) the time of termination of the plan by EPCO or the Chairman or Vice Chairman of EPCO. As of December 31, 2008, 27,604 Units have been issued to employees under this plan.
Distribution Reinvestment Plan
Our distribution reinvestment plan (“DRIP”) provides for the issuance of up to 10,000,000 Units. Units purchased through the DRIP may be acquired at a discount rating from 0% to 5% (currently set at 5%), which will be set from time to time by us. As of December 31, 2008, 418,233 Units have been issued in connection with the DRIP.
F-55
TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Summary of Changes in Outstanding Units
The following table summarizes changes in our outstanding Units since December 31, 2005:
| Limited | ||||||||||||||||
| Partner | Restricted | Treasury | ||||||||||||||
| Units | Units | Units | Total | |||||||||||||
| Balance, December 31, 2005 | 69,963,554 | -- | -- | 69,963,554 | ||||||||||||
Units issued in connection with underwritten public offering | 5,750,000 | -- | -- | 5,750,000 | ||||||||||||
Issuance of Units to General Partner | 14,091,275 | -- | -- | 14,091,275 | ||||||||||||
| Balance, December 31, 2006 | 89,804,829 | -- | -- | 89,804,829 | ||||||||||||
Issuance of restricted units under 2006 LTIP | -- | 62,900 | -- | 62,900 | ||||||||||||
Forfeiture of restricted units | -- | (500 | ) | -- | (500 | ) | ||||||||||
Units issued in connection with Unit Purchase Plan | 4,507 | -- | -- | 4,507 | ||||||||||||
Units issued in connection with DRIP | 39,796 | -- | -- | 39,796 | ||||||||||||
| Balance, December 31, 2007 | 89,849,132 | 62,400 | -- | 89,911,532 | ||||||||||||
Issuance of Units in connection with Cenac acquisition on February 1, 2008 | 4,854,899 | -- | -- | 4,854,899 | ||||||||||||
Units issued in connection with DRIP | 378,437 | ---- | ---- | 378,437 | ||||||||||||
Units issued in connection with Unit Purchase Plan | 23,097 | -- | -- | 23,097 | ||||||||||||
Issuance of restricted units under 2006 LTIP | -- | 96,900 | -- | 96,900 | ||||||||||||
Forfeiture of restricted units | -- | (1,000 | ) | -- | (1,000 | ) | ||||||||||
Conversion of restricted units to Units | 1,000 | (1,000 | ) | -- | -- | |||||||||||
Acquisition of treasury units | (384 | ) | -- | 384 | -- | |||||||||||
Cancellation of treasury units | -- | -- | (384 | ) | (384 | ) | ||||||||||
Issuance of unregistered Units to TEPPCO Unit | 241,380 | -- | -- | 241,380 | ||||||||||||
Units issued in connection with underwritten public offering | 9,200,000 | -- | -- | 9,200,000 | ||||||||||||
Balance, December 31, 2008 | 104,547,561 | 157,300 | -- | 104,704,861 | ||||||||||||
During the year ended December 31, 2008, 1,000 restricted units awards vested and were converted into Units. Of this amount, 384 were sold back to us by an employee to cover related withholding tax requirements. The total cost of these treasury units were approximately $9 thousand, which was allocated to our limited partners. Immediately upon acquisition, we cancelled such treasury units.
General Partner’s Interest
At December 31, 2008 and 2007, we had deficit balances of $110.3 million and $88.0 million, respectively, in our General Partner’s equity account. These negative balances do not represent assets to us and do not represent obligations of the General Partner to contribute cash or other property to us. The General Partner’s equity account generally consists of its cumulative share of our net income less cash distributions made to it plus capital contributions that it has made to us (see our Statements of Consolidated Partners’ Capital for a detail of the General Partner’s equity account). For the years ended December 31, 2008, 2007 and 2006, our General Partner was allocated $32.6 million (representing 16.83%), $46.0 million (representing 16.47%) and $57.7 million (representing 28.57%), respectively, of our net income and received $54.9 million, $48.3 million and $81.9 million, respectively, in cash distributions.
Cash distributions that we make during a period may exceed our net income for the period. We make quarterly cash distributions of all of our Available Cash, generally defined as consolidated cash receipts less
F-56
TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
consolidated cash disbursements and cash reserves established by the General Partner in its reasonable discretion. Cash distributions in excess of net income allocations and capital contributions during previous years resulted in a deficit in the General Partner’s equity account at December 31, 2008 and 2007. Future cash distributions that exceed net income will result in an increase in the deficit balance in the General Partner’s equity account.
According to the Partnership Agreement, in the event of our dissolution, after satisfying our liabilities, our remaining assets would be divided among our limited partners and the General Partner generally in the same proportion as Available Cash but calculated on a cumulative basis over the life of the Partnership. If a deficit balance still remains in the General Partner’s equity account after all allocations are made between the partners, the General Partner would not be required to make whole any such deficit.
Accumulated Other Comprehensive Income (Loss)
SFAS No. 130, Reporting Comprehensive Income requires certain items such as foreign currency translation adjustments, gains or losses associated with pension or other postretirement benefits, prior service costs or credits associated with pension or other postretirement benefits, transition assets or obligations associated with pension or other postretirement benefits and unrealized gains and losses on certain investments in debt and equity securities to be reported in a financial statement. As of and for the years ended December 31, 2008 and 2007, the components of accumulated other comprehensive income reflected on our consolidated balance sheets were composed of crude oil hedges, interest rate swaps, treasury locks and unrecognized losses associated with the TEPPCO RCBP. The crude oil hedges had forward positions that expired during 2008. While the crude oil hedges were in effect, changes in their fair values, to the extent the hedges were effective, are recognized in accumulated other comprehensive income until they are recognized in net income in future periods upon the contract expiration. The amounts related to settlements of treasury lock agreements are being amortized into earnings over the terms of the respective debt (see Note 6). Our accumulated other comprehensive loss balance consisted of a $23.9 million loss related to interest rate and treasury lock financial instruments and a $18.6 million loss associated with crude oil financial instruments at December 31, 2007. Our accumulated other comprehensive loss balance consisted of a $45.8 million loss related to interest rate and treasury lock financial instruments at December 31, 2008.
NOTE 14. BUSINESS SEGMENTS
We have four reporting segments:
| § | Our Downstream Segment, which is engaged in the pipeline transportation, marketing and storage of refined products, LPGs and petrochemicals; |
| § | Our Upstream Segment, which is engaged in the gathering, pipeline transportation, marketing and storage of crude oil, distribution of lubrication oils and specialty chemicals and fuel transportation services; |
| § | Our Midstream Segment, which is engaged in the gathering of natural gas, fractionation of NGLs and pipeline transportation of NGLs; and |
| § | Our Marine Services Segment, which is engaged in the marine transportation of refined products, crude oil, condensate, asphalt, heavy fuel oil and other heated oil products via tow boats and tank barges. |
The amounts indicated below as “Partnership and Other” for income and expense items (including operating income) relate primarily to intersegment eliminations from activities among our reporting segments. Amounts indicated below as “Partnership and Other” for assets and capital expenditures include the elimination of intersegment related party receivables and investment balances among our reporting segments and assets that we hold that have not been allocated to any of our reporting segments (including such items as corporate furniture and
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TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
fixtures, vehicles, computer hardware and software, prepaid insurance and unamortized debt issuance costs on debt issued at the Partnership level).
Our Downstream Segment revenues are earned from pipeline transportation, marketing and storage of refined products and LPGs, intrastate pipeline transportation of petrochemicals, sale of product inventory and other ancillary services. We generally realize higher revenues in the Downstream Segment during the first and fourth quarters of each year since LPGs volumes are generally higher from November through March due to higher demand for propane, a major fuel for residential heating. Refined products volumes are generally higher during the second and third quarters because of greater demand for gasoline during the spring and summer driving seasons, although recent high gasoline prices have moderated this trend somewhat. The two largest operating expense items of the Downstream Segment are labor and electric power. Our Downstream Segment also includes the results of operations of the northern portion of the Dean Pipeline, which transports refinery grade propylene from Mont Belvieu to Point Comfort, Texas. Our Downstream Segment also includes our equity investment in Centennial (see Note 9).
Our Upstream Segment revenues are earned from gathering, pipeline transporting, marketing and storing crude oil and distributing lubrication oils and specialty chemicals, principally in Oklahoma, Texas, New Mexico and the Rocky Mountain region. Marketing operations consist primarily of aggregating crude oil purchased at the lease along our pipeline systems, and from third party pipeline systems, and arranging the necessary transportation logistics for the ultimate sale or delivery of the crude oil to local refineries, marketers or other end users. Revenues are also generated from trade documentation and terminaling services, primarily at Cushing, Oklahoma, and Midland, Texas. Our Upstream Segment also includes our equity investments in Seaway and Texas Offshore Port System (see Note 9). The Seaway system consists of large diameter pipelines that transport crude oil from Seaway’s marine terminals on the U.S. Gulf Coast to Cushing, Oklahoma, a crude oil distribution point for the central United States, and to refineries in the Texas City and Houston areas. Seaway also has a connection to our South Texas system that allows it to receive both onshore and offshore domestic crude oil in the Texas Gulf Coast area for delivery to Cushing. Texas Offshore Port System, a joint venture between us and affiliates of Enterprise Products Partners and Oiltanking, was formed to design, construct, operate and own a new Texas offshore crude oil port and pipeline system.
Our Midstream Segment revenues are earned from the gathering of coal bed methane and conventional natural gas in the San Juan Basin in New Mexico and Colorado, through Val Verde; transportation of NGLs from two trunkline NGL pipelines in South Texas, two NGL pipelines in East Texas and a pipeline system from West Texas and New Mexico to Mont Belvieu; and the fractionation of NGLs in Colorado. Our Midstream Segment also includes our equity investment in Jonah (see Note 9). Jonah, a joint venture between an affiliate of Enterprise Products Partners and us, owns a natural gas gathering system in the Green River Basin in southwestern Wyoming. Prior to August 1, 2006, when Jonah was wholly-owned by us, operating results for Jonah were included in the consolidated Midstream Segment operating results. Effective August 1, 2006, we entered into the joint venture with an Enterprise Products Partners’ affiliate, upon which Jonah was deconsolidated, and its operating results since August 1, 2006, have been accounted for under the equity method of accounting. Operating results of the Pioneer plant, which we sold to an Enterprise Products Partners’ affiliate in March 2006, are shown as discontinued operations for the year ended December 31, 2006.
Our Marine Services Segment revenues are earned from the marine transportation of refined products, crude oil, condensate, asphalt, heavy fuel oil and other heated oil products via tow boats and tank barges. We entered the marine transportation business in February 2008 with the acquisition of assets and certain intangible assets from Cenac and Horizon on February 1, 2008 and February 29, 2008, respectively (see Note 10). These businesses service refineries and storage terminals along the Mississippi, Illinois and Ohio rivers, the Intracoastal Waterway between Texas and Florida and the Tennessee-Tombigbee Waterway system. These assets also gather crude oil from production facilities and platforms along the U.S. Gulf Coast and in the Gulf of Mexico.
F-58
TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The following table presents our measurement of earnings before interest expense for the years ended December 31, 2008, 2007 and 2006:
| For Year Ended December 31, | ||||||||||||
| 2008 | 2007 | 2006 | ||||||||||
| Total operating revenues | $ | 13,532,889 | $ | 9,658,060 | $ | 9,607,485 | ||||||
| Less: Total costs and expenses | 13,279,469 | 9,408,505 | 9,377,706 | |||||||||
| Operating income | 253,420 | 249,555 | 229,779 | |||||||||
| Add: Gain on sale of ownership interest in MB Storage | -- | 59,628 | -- | |||||||||
Equity earnings | 82,693 | 68,755 | 36,761 | |||||||||
Interest income | 1,091 | 1,676 | 2,077 | |||||||||
Other income | 953 | 1,346 | 888 | |||||||||
Earnings before interest expense, provision for income taxes and discontinued operations | $ | 338,157 | $ | 380,960 | $ | 269,505 | ||||||
A reconciliation of our earnings before interest expense, provision for income taxes and discontinued operations to net income for the years ended December 31, 2008, 2007 and 2006 is as follows:
| For Year Ended December 31, | ||||||||||||
| 2008 | 2007 | 2006 | ||||||||||
Earnings before interest expense, provision for income taxes and discontinued operations | $ | 338,157 | $ | 380,960 | $ | 269,505 | ||||||
| Interest expense – net | (139,988 | ) | (101,223 | ) | (86,171 | ) | ||||||
| Income before provision for income taxes | 198,169 | 279,737 | 183,334 | |||||||||
| Provision for income taxes | 4,617 | 557 | 652 | |||||||||
| Income from continuing operations | 193,552 | 279,180 | 182,682 | |||||||||
| Discontinued operations | -- | -- | 19,369 | |||||||||
Net income | $ | 193,552 | $ | 279,180 | $ | 202,051 | ||||||
F-59
TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The table below includes information by segment, together with reconciliations to our consolidated totals for the periods indicated:
| Downstream Segment | Upstream Segment | Midstream Segment | Marine Services Segment | Partnership and Other | Consolidated | |||||||||||||||||||
| Revenues from third parties: | ||||||||||||||||||||||||
| Year ended December 31, 2008 | $ | 350,896 | $ | 12,872,544 | $ | 108,531 | $ | 164,274 | $ | -- | $ | 13,496,245 | ||||||||||||
| Year ended December 31, 2007 | 355,495 | 9,172,707 | 109,082 | -- | -- | 9,637,284 | ||||||||||||||||||
| Year ended December 31, 2006 | 298,866 | 9,108,283 | 181,486 | -- | -- | 9,588,635 | ||||||||||||||||||
| Revenues from related parties: | ||||||||||||||||||||||||
| Year ended December 31, 2008 | $ | 22,068 | $ | 882 | $ | 13,886 | $ | -- | $ | (192 | ) | $ | 36,644 | |||||||||||
| Year ended December 31, 2007 | 7,196 | 896 | 13,153 | -- | (469 | ) | 20,776 | |||||||||||||||||
| Year ended December 31, 2006 | 5,435 | 598 | 13,137 | -- | (320 | ) | 18,850 | |||||||||||||||||
| Intersegment and intrasegment revenues: | ||||||||||||||||||||||||
| Year ended December 31, 2008 | $ | -- | $ | -- | $ | -- | $ | -- | $ | -- | $ | -- | ||||||||||||
| Year ended December 31, 2007 | -- | 80 | -- | -- | (80 | ) | -- | |||||||||||||||||
| Year ended December 31, 2006 | -- | 748 | 6,646 | -- | (7,394 | ) | -- | |||||||||||||||||
| Total revenues: | ||||||||||||||||||||||||
| Year ended December 31, 2008 | $ | 372,964 | $ | 12,873,426 | $ | 122,417 | $ | 164,274 | $ | (192 | ) | $ | 13,532,889 | |||||||||||
| Year ended December 31, 2007 | 362,691 | 9,173,683 | 122,235 | -- | (549 | ) | 9,658,060 | |||||||||||||||||
| Year ended December 31, 2006 | 304,301 | 9,109,629 | 201,269 | -- | (7,714 | ) | 9,607,485 | |||||||||||||||||
| Depreciation and amortization: | ||||||||||||||||||||||||
| Year ended December 31, 2008 | $ | 43,063 | $ | 20,928 | $ | 39,323 | $ | 23,015 | $ | -- | $ | 126,329 | ||||||||||||
| Year ended December 31, 2007 | 46,141 | 18,257 | 40,827 | -- | -- | 105,225 | ||||||||||||||||||
| Year ended December 31, 2006 | 41,405 | 14,400 | 52,447 | -- | -- | 108,252 | ||||||||||||||||||
| Operating income: | ||||||||||||||||||||||||
| Year ended December 31, 2008 | $ | 91,270 | $ | 95,683 | $ | 27,559 | $ | 34,507 | $ | 4,401 | $ | 253,420 | ||||||||||||
| Year ended December 31, 2007 | 135,055 | 84,222 | 25,767 | -- | 4,511 | 249,555 | ||||||||||||||||||
| Year ended December 31, 2006 | 91,262 | 70,840 | 65,499 | -- | 2,178 | 229,779 | ||||||||||||||||||
| Equity earnings (losses): | ||||||||||||||||||||||||
| Year ended December 31, 2008 | $ | (14,603 | ) | $ | 11,693 | $ | 90,004 | $ | -- | $ | (4,401 | ) | $ | 82,693 | ||||||||||
| Year ended December 31, 2007 | (12,396 | ) | 2,602 | 83,060 | -- | (4,511 | ) | 68,755 | ||||||||||||||||
| Year ended December 31, 2006 | (8,018 | ) | 11,905 | 35,052 | -- | (2,178 | ) | 36,761 | ||||||||||||||||
F-60
TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
| Downstream Segment | Upstream Segment | Midstream Segment | Marine Services Segment | Partnership and Other | Consolidated | |||||||||||||||||||
| Earnings before interest expense, provision for income taxes and discontinued operations: | ||||||||||||||||||||||||
| Year ended December 31, 2008 | $ | 77,526 | $ | 108,164 | $ | 117,947 | $ | 34,520 | $ | -- | $ | 338,157 | ||||||||||||
| Year ended December 31, 2007 | 184,251 | 87,246 | 109,463 | -- | -- | 380,960 | ||||||||||||||||||
| Year ended December 31, 2006 | 84,746 | 83,540 | 101,219 | -- | -- | 269,505 | ||||||||||||||||||
| Capital expenditures: | ||||||||||||||||||||||||
| At December 31, 2008 | $ | 209,753 | $ | 33,429 | $ | 5,215 | $ | 43,557 | $ | 8,549 | $ | 300,503 | ||||||||||||
| At December 31, 2007 | 165,353 | 54,583 | 7,412 | -- | 924 | 228,272 | ||||||||||||||||||
| At December 31, 2006 | 75,344 | 48,351 | 42,929 | -- | 3,422 | 170,046 | ||||||||||||||||||
| Segment assets: | ||||||||||||||||||||||||
| At December 31, 2008 | $ | 1,320,870 | $ | 1,586,345 | $ | 1,529,125 | $ | 653,262 | $ | (39,782 | ) | $ | 5,049,820 | |||||||||||
| At December 31, 2007 | 1,221,316 | 2,084,830 | 1,512,621 | -- | (68,710 | ) | 4,750,057 | |||||||||||||||||
| Investments in unconsolidated affiliates: | ||||||||||||||||||||||||
| At December 31, 2008 | $ | 63,222 | $ | 226,044 | $ | 957,706 | $ | -- | $ | 8,951 | $ | 1,255,923 | ||||||||||||
| At December 31, 2007 | 79,324 | 188,650 | 879,021 | -- | -- | 1,146,995 | ||||||||||||||||||
| Intangible assets: | ||||||||||||||||||||||||
| At December 31, 2008 | $ | 5,449 | $ | 8,064 | $ | 131,555 | $ | 62,585 | $ | -- | $ | 207,653 | ||||||||||||
| At December 31, 2007 | 5,244 | 7,512 | 151,925 | -- | -- | 164,681 | ||||||||||||||||||
| Goodwill: | ||||||||||||||||||||||||
| At December 31, 2008 | $ | 1,339 | $ | 14,860 | $ | -- | $ | 90,412 | $ | -- | $ | 106,611 | ||||||||||||
| At December 31, 2007 | 1,339 | 14,167 | -- | -- | -- | 15,506 | ||||||||||||||||||
F-61
TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
NOTE 15. RELATED PARTY TRANSACTIONS
The following table summarizes related party transactions for the years ended December 31, 2008, 2007 and 2006:
| For Year Ended December 31, | ||||||||||||
| 2008 | 2007 | 2006 | ||||||||||
| Revenues from EPCO and affiliates: | ||||||||||||
| Sales of petroleum products (1) | $ | 715 | $ | 320 | $ | 3,165 | ||||||
| Transportation – NGLs (2) | 13,785 | 13,153 | 10,225 | |||||||||
| Transportation – LPGs (3) | 8,735 | 5,191 | 3,648 | |||||||||
| Other operating revenues (4) | 13,318 | 1,761 | 1,517 | |||||||||
| Revenues from unconsolidated affiliates: | ||||||||||||
| Other operating revenues (5) | 91 | 351 | 295 | |||||||||
| Related party revenues | $ | 36,644 | $ | 20,776 | $ | 18,850 | ||||||
| Costs and Expenses from EPCO and affiliates: | ||||||||||||
| Purchases of petroleum products (6) | $ | 132,624 | $ | 61,596 | $ | 52,982 | ||||||
| Operating expense (7) | 104,878 | 96,947 | 103,924 | |||||||||
| General and administrative (8) | 31,601 | 25,500 | 21,709 | |||||||||
| Costs and Expenses from unconsolidated affiliates: | ||||||||||||
| Purchases of petroleum products (9) | 7,143 | 5,493 | 2,987 | |||||||||
| Operating expense (10) | 7,926 | 8,736 | 5,094 | |||||||||
| Costs and Expenses from Cenac and affiliates: | ||||||||||||
| Operating expense (11) | 45,382 | -- | -- | |||||||||
| General and administrative (12) | 2,912 | -- | -- | |||||||||
| Related party costs and expenses | $ | 332,466 | $ | 198,272 | $ | 186,696 | ||||||
___________________________
| (1) | Includes sales from Lubrication Services, LLC (“LSI”) to Enterprise Products Partners and certain of its subsidiaries. |
| (2) | Includes revenues from NGL transportation on the Chaparral and Panola NGL pipelines from Enterprise Products Partners and certain of its subsidiaries. |
| (3) | Includes revenues from LPG transportation on the TE Products pipeline from Enterprise Products Partners and certain of its subsidiaries. |
| (4) | Includes sales of product inventory from TE Products to Enterprise Products Partners and other operating revenues on the TE Products pipeline and the Val Verde system from Enterprise Products Partners and certain of its subsidiaries. |
| (5) | Includes sales of petroleum products, management fees and rental revenues from Centennial, Jonah and Seaway. |
| (6) | Includes TCO purchases of petroleum products of $113.9 million, $45.1 million and $41.6 million from Enterprise Products Partners and certain of its subsidiaries for the years ended December 31, 2008, 2007 and 2006, respectively, and expenses related to TCO’s and LSI’s use of an affiliate of EPCO as a transporter. |
| (7) | Includes operating payroll, payroll related expenses and other operating expenses, including reimbursements related to employee benefits and employee benefit plans, incurred by EPCO in managing us and our subsidiaries in accordance with the ASA. Also includes insurance expense for the years ended December 31, 2008, 2007 and 2006, of $10.4 million, $13.6 million and $15.8 million, respectively, related to premiums paid by EPCO on our behalf. The majority of our insurance coverage, including property, liability, business interruption, auto and directors’ and officers’ liability insurance, is obtained through EPCO. |
| (8) | Includes administrative payroll, payroll related expenses and other administrative expenses, including reimbursements related to employee benefits and employee benefit plans, incurred by EPCO in managing and operating us and our subsidiaries in accordance with the ASA. |
| (9) | Includes TCO purchases of petroleum products from Jonah and Seaway and pipeline transportation expense from Seaway. |
| (10) | Includes rental expense and other operating expense. |
| (11) | Includes reimbursement for operating payroll, payroll related expenses, certain repairs and maintenance expenses and insurance premiums on our equipment under the transitional operating agreement with Cenac, pursuant to which, our fleet of acquired tow boats and tank barges (including those acquired from Horizon) are operated by employees of Cenac for a period of up to two years following the acquisition. |
F-62
TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
| (12) | Includes reimbursement for administrative payroll and payroll related expenses, as well as payment of a $42 thousand monthly service fee and a 5% overhead fee charged on direct costs incurred by Cenac to operate the marine assets in accordance with the transitional operating agreement. |
The following table summarizes related party balances at December 31, 2008 and 2007:
| December 31, | ||||||||
| 2008 | 2007 | |||||||
| Accounts receivable, related parties (1) | $ | 15,758 | $ | 6,525 | ||||
| Accounts payable, related parties (2) | 17,219 | 38,980 | ||||||
_____________________
| (1) | Relates to sales and transportation services provided to Enterprise Products Partners and certain of its subsidiaries and EPCO and certain of its affiliates and direct payroll, payroll related costs and other operational expenses charged to unconsolidated affiliates. |
| (2) | Relates to direct payroll, payroll related costs and other operational related charges from Enterprise Products Partners and certain of its subsidiaries and EPCO and certain of its affiliates, transportation and other services provided by unconsolidated affiliates and advances from Seaway for operating expenses and $3.4 million related to operational related charges from Cenac. |
As an affiliate of EPCO and other companies controlled by Mr. Duncan, our transactions and agreements with them are not necessarily on an arm’s length basis. As a result, we cannot provide assurance that the terms and provisions of such transactions or agreements are at least as favorable to us as we could have obtained from unaffiliated third parties.
Relationship with EPCO and Affiliates
We have an extensive and ongoing relationship with EPCO and its affiliates, which include the following significant entities:
| § | EPCO and its consolidated private company subsidiaries; |
| § | Texas Eastern Products Pipeline Company, LLC, our General Partner; |
| § | Enterprise GP Holdings, which owns and controls our General Partner; |
| § | Enterprise Products Partners, which is controlled by affiliates of EPCO, including Enterprise GP Holdings; |
| § | Duncan Energy Partners, which is controlled by affiliates of EPCO; |
| § | Enterprise Gas Processing LLC, which is controlled by affiliates of EPCO and is our joint venture partner in Jonah; |
| § | Enterprise Offshore Port System, LLC, which is controlled by affiliates of EPCO and is one of our joint venture partners in Texas Offshore Port System; and |
| § | the Employee Partnerships, which are controlled by EPCO (see Note 4). |
Dan L. Duncan directly owns and controls EPCO and, through Dan Duncan LLC, owns and controls EPE Holdings, the general partner of Enterprise GP Holdings. Enterprise GP Holdings owns all of the membership interests of our General Partner. The principal business activity of our General Partner is to act as our managing partner. The executive officers of our General Partner are employees of EPCO (see Note 1).
We and our General Partner are both separate legal entities apart from each other and apart from EPCO and its other affiliates, with assets and liabilities that are separate from those of EPCO and its other affiliates. EPCO and its consolidated private company subsidiaries and affiliates depend on the cash distributions they receive from our General Partner and other investments to fund their operations and to meet their debt obligations. We paid cash distributions to our General Partner of $54.9 million, $48.3 million and $81.9 million during the years ended December 31, 2008, 2007 and 2006, respectively.
F-63
TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The limited partner interests in us that are owned or controlled by EPCO and certain of its affiliates, other than those interests owned by Dan Duncan LLC and certain trusts affiliated with Dan L. Duncan, are pledged as security under the credit facility of an affiliate of EPCO. All of the membership interests in our General Partner and the limited partner interests in us that are owned or controlled by Enterprise GP Holdings are pledged as security under its credit facility. If Enterprise GP Holdings were to default under its credit facility, its lender banks could own our General Partner.
EPCO Administrative Services Agreement
We do not have any employees. We are managed by our General Partner, and all of our management, administrative and operating functions are performed by employees of EPCO, pursuant to the ASA or by other service providers. We, Enterprise Products Partners, Duncan Energy Partners, Enterprise GP Holdings and our respective general partners are parties to the ASA. The ACG Committees of each general partner have approved the ASA.
Under the ASA, we reimburse EPCO for all costs and expenses it incurs in providing management, administrative and operating services for us, including compensation of employees (i.e., salaries, medical benefits and retirement benefits) (see Note 1). Since the vast majority of such expenses are charged to us on an actual basis (i.e., no mark-up or subsidy is charged or received by EPCO), we believe that such expenses are representative of what the amounts would have been on a standalone basis. With respect to allocated costs, we believe that the proportional direct allocation method employed by EPCO is reasonable and reflective of the estimated level of costs we would have incurred on a standalone basis.
The significant terms of the ASA are as follows:
| § | EPCO provides administrative, management and operating services as may be necessary to manage and operate our business, properties and assets (in accordance with prudent industry practices). EPCO will employ or otherwise retain the services of such personnel as may be necessary to provide such services. |
| § | We are required to reimburse EPCO for its services in an amount equal to the sum of all costs and expenses (direct and indirect) incurred by EPCO which are directly or indirectly related to our business or activities (including EPCO expenses reasonably allocated to us). In addition, we have agreed to pay all sales, use, excise, value added or similar taxes, if any, that may be applicable from time to time in respect of the services provided to us by EPCO. |
| § | EPCO allows us to participate as named insureds in its overall insurance program with the associated costs being allocated to us. |
Our operating costs and expenses for the years ended December 31, 2008, 2007 and 2006 include reimbursement payments to EPCO for the costs it incurs to operate our facilities, including compensation of employees. We reimburse EPCO for actual direct and indirect expenses it incurs related to the operation of our assets.
Likewise, our general and administrative costs for the years ended December 31, 2008, 2007 and 2006 include amounts we reimburse to EPCO for administrative services, including compensation of employees. We are responsible to reimburse EPCO for the amount of distributions of cash or securities, if any, made by TEPPCO Unit II to Mr. Thompson. In general, our reimbursement to EPCO for administrative services is either (i) on an actual basis for direct expenses it may incur on our behalf (e.g., the purchase of office supplies) or (ii) based on an allocation of such charges between the various parties to the ASA based on the estimated use of such services by each party (e.g., the allocation of general legal or accounting salaries based on estimates of time spent on each entity’s business and affairs).
F-64
TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
EPCO and its affiliates have no obligation to present business opportunities to us or our subsidiaries, and we and our subsidiaries have no obligation to present business opportunities to EPCO and its affiliates. However, the ASA requires that business opportunities offered to or discovered by EPCO be offered first to certain Enterprise Products Partners’ affiliates before they may be pursued by EPCO and its other affiliates or offered to us.
On January 30, 2009, we entered into the Fifth Amended and Restated ASA, which amended the previous ASA to provide for the cash reimbursement to EPCO by us of distributions of cash or securities, if any, made by TEPPCO Unit II to its Class B limited partner, Mr. Thompson, our chief executive officer and an employee of EPCO (see Note 4). The Fifth Amended and Restated ASA also extends the term of EPCO’s service obligations from December 2010 to December 2013.
Sale of Pioneer Plant
On March 31, 2006, we sold our ownership interest in the Pioneer silica gel natural gas processing plant located near Opal, Wyoming, together with Jonah’s rights to process natural gas originating from the Jonah and Pinedale fields, located in southwest Wyoming, to an affiliate of Enterprise Products Partners for $38.0 million in cash. The Pioneer plant was not an integral part of our Midstream Segment operations, and natural gas processing is not a core business. We have no continuing involvement in the operations or results of this plant. This transaction was reviewed and recommended for approval by our ACG Committee and a fairness opinion was rendered by an investment banking firm. The sales proceeds were used to fund organic growth projects, retire debt and for other general partnership purposes. The carrying value of the Pioneer plant at March 31, 2006, prior to the sale, was $19.7 million. Costs associated with the completion of the transaction were approximately $0.4 million.
Jonah Joint Venture
Enterprise Products Partners (through an affiliate) is our joint venture partner in Jonah, the partnership through which we have owned our interest in the system serving the Jonah and Pinedale fields. Through December 31, 2008, we have reimbursed Enterprise Products Partners $306.5 million ($44.9 million in 2008, $152.2 million in 2007 and $109.4 million in 2006) for our share of the Phase V cost incurred by it (including its cost of capital incurred prior to the formation of the joint venture of $1.3 million). At December 31, 2008 and 2007, we had payables to Enterprise Products Partners for costs incurred of $1.0 million and $9.9 million, respectively (see Note 9). At December 31, 2008 and 2007, we had receivables from Jonah of $4.7 million and $6.0 million, respectively, for operating expenses. During the years ended December 31, 2008, 2007 and 2006, we received distributions from Jonah of $132.2 million, $100.0 million and $0, respectively. The 2007 amount included $11.6 million of distributions declared in 2006 and paid during the first quarter of 2007. During the years ended December 31, 2008, 2007 and 2006, Jonah paid distributions of $31.7 million, $9.5 million and $0, respectively, to the affiliate of Enterprise Products Partners that is our joint venture partner.
We have agreed to indemnify Enterprise Products Partners from any and all losses, claims, demands, suits, liability, costs and expenses arising out of or related to breaches of our representations, warranties, or covenants related to the formation of the Jonah joint venture, Jonah’s ownership or operation of the Jonah-Pinedale system prior to the effective date of the joint venture, and any environmental activity, or violation of or liability under environmental laws arising from or related to the condition of the Jonah-Pinedale system prior to the effective date of the joint venture. In general, a claim for indemnification cannot be filed until the losses suffered by Enterprise Products Partners exceed $1.0 million, and the maximum potential amount of future payments under the indemnity is limited to $100.0 million. However, if certain representations or warranties are breached, the maximum potential amount of future payments under the indemnity is capped at $207.6 million. All indemnity payments are net of insurance recoveries that Enterprise Products Partners may receive from third-party insurers. We carry insurance coverage that may offset any payments required under the indemnity. We do not expect that these indemnities will have a material adverse effect on our financial position, results of operations or cash flows.
F-65
TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Texas Offshore Port System Joint Venture
Enterprise Products Partners (through an affiliate) is one of our joint venture partners in Texas Offshore Port System which was formed in August 2008 to design, construct, operate and own a new Texas offshore crude oil port and pipeline system to facilitate delivery of waterborne crude oil to refining centers located along the upper Texas Gulf Coast. We, Enterprise Products Partners and Oiltanking each own, through our respective subsidiaries, a one-third interest in the joint venture. A subsidiary of Enterprise Products Partners acts as construction manager and will act as operator. We and an affiliate of Enterprise Products Partners have each guaranteed up to approximately $700.0 million, which includes a contingency amount for potential cost overruns, of the capital contribution obligations of our respective subsidiary partners in the joint venture. Through December 31, 2008, we have invested $36.0 million in Texas Offshore Port System (see Note 9).
Sale of General Partner to Enterprise GP Holdings; Relationship with Energy Transfer Equity
On May 7, 2007, all of the membership interests in our General Partner, together with 4,400,000 of our Units, were sold by DFIGP to Enterprise GP Holdings, a publicly traded partnership also controlled indirectly by Dan L. Duncan. As of May 7, 2007, Enterprise GP Holdings owns and controls the 2% general partner interest in us and has the right (through its 100% ownership of our General Partner) to receive the incentive distribution rights associated with the general partner interest. Enterprise GP Holdings, DFIGP and other entities controlled by Mr. Duncan own 17,073,315 of our Units.
Concurrently with the acquisition of our General Partner, Enterprise GP Holdings acquired non-controlling ownership interests, accounted for as equity method investments, in Energy Transfer Equity, L.P. (“Energy Transfer Equity”) and LE GP, LLC, the general partner of Energy Transfer Equity.
Other Transactions
On October 6, 2006, we sold certain crude oil pipeline assets and refined products pipeline assets in the Houston, Texas area, to a subsidiary of Enterprise Products Partners for approximately $11.7 million. These assets, which had been idle since acquisition, were part of the assets acquired by us in 2005. The sales proceeds were used to fund organic growth projects, retire debt and for other general partnership purposes. The carrying value of these pipeline assets at September 30, 2006, was approximately $6.0 million. We recognized a gain of $5.7 million on this transaction.
In November 2006, we entered into a lease with Duncan Energy Partners, for a 12-mile, 10-inch interconnecting pipeline extending from Pasadena, Texas to Baytown, Texas. The primary term of this lease expired on September 15, 2007, and was continued on a month-to-month basis through March 2008.
In December 2006, we constructed a new 20-inch diameter lateral pipeline to connect our Downstream Segment mainline system to the Enterprise Products Partners facilities at Mont Belvieu, Texas, at a cost of approximately $8.6 million. The new connection, which provides delivery of propane from Enterprise Products Partners into our system at full line flow rates, complements our current ability to source product from Mont Belvieu. The new connection also offers the ability to deliver other liquid products such as butanes and natural gasoline from Enterprise Products Partners’ storage facilities into our system at reduced flow rates until enhancements can be made. This new pipeline replaces a 10-mile, 18-inch segment of pipeline that we sold to an Enterprise Products Partners’ affiliate on January 23, 2007 for approximately $8.0 million. These assets had a net book value of approximately $2.5 million, and we recognized a gain on the sale of approximately $5.5 million. The sales proceeds were used to fund construction of the replacement pipeline.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
In June 2007, we purchased 300,000 barrels of propane linefill from an affiliate of Enterprise Products Partners for approximately $14.4 million. In November 2007, we purchased 100,000 barrels of butane inventory from an affiliate of Enterprise Products Partners for approximately $8.0 million.
In December 2008, we entered into a lease agreement with Seminole Pipeline Company (“Seminole”) and Mid-America Pipeline Company, LLC, (“MAPL”) for the use of excess capacity on the Seminole pipeline system, a pipeline extending from Hobbs, New Mexico to Mont Belvieu, Texas. For Chaparral to use the excess capacity on Seminole, it must also access a segment of the MAPL pipeline as well. The primary term of this lease expired on January 31, 2009, and will continue on a month-to-month basis. Seminole and MAPL are subsidiaries of Enterprise Products Partners.
Relationship with Unconsolidated Affiliates
Our significant related party revenues and expense transactions with unconsolidated affiliates consist of management, rental and other revenues, transportation expense related to movements on Centennial and Seaway and rental expense related to the lease of pipeline capacity on Centennial. For additional information regarding our unconsolidated affiliates, see Note 9.
See “Jonah Joint Venture” and “Texas Offshore Port System Joint Venture” within this Note 15 for descriptions of ongoing transactions involving our Jonah and Texas Offshore Port System joint ventures with Enterprise Products Partners.
NOTE 16. EARNINGS PER UNIT
Basic earnings per Unit is computed by dividing net income or loss allocated to limited partner interests by the weighted average number of distribution-bearing Units outstanding during a period. The amount of net income allocated to limited partner interests is derived by subtracting our General Partner’s share of the net income from net income. Our General Partner’s percentage interest in our net income is based on its percentage of cash distributions from Available Cash for each period (see Note 13). Diluted earnings per Unit is computed by dividing net income or loss allocated to limited partner interests by the sum of (i) the weighted-average number of distribution-bearing Units outstanding during a period (as used in determining basic earnings per Unit); and (ii) the number of incremental Units resulting from the assumed exercise of dilutive unit options outstanding during a period (the “incremental option units”).
In a period of net operating losses, restricted units and incremental option units are excluded from the calculation of diluted earnings per Unit due to their anti-dilutive effect. The dilutive incremental option units are calculated using the treasury stock method, which assumes that proceeds from the exercise of all in-the-money options at the end of each period are used to repurchase Units at an average market value during the period. The amount of Units remaining after the proceeds are exhausted represents the potentially dilutive effect of the securities. In May 2007 and 2008, we granted 155,000 and 200,000 unit options, respectively, to employees providing services to us (see Note 4).
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The following table shows the computation of basic and diluted earnings per Unit for the years ended December 31, 2008, 2007 and 2006:
| For Year Ended December 31, | ||||||||||||
| 2008 | 2007 | 2006 | ||||||||||
| Income from continuing operations | $ | 193,552 | $ | 279,180 | $ | 182,682 | ||||||
| Discontinued operations | -- | -- | 19,369 | |||||||||
| Net income | 193,552 | 279,180 | 202,051 | |||||||||
| General Partner’s interest in net income | 16.83 | % | 16.47 | % | 28.57 | % | ||||||
| Earnings allocated to General Partner: | ||||||||||||
| Income from continuing operations | $ | 32,583 | $ | 45,987 | $ | 52,199 | ||||||
| Discontinued operations | -- | -- | 5,534 | |||||||||
| Net income allocated | 32,583 | 45,987 | 57,733 | |||||||||
| BASIC EARNINGS PER UNIT: | ||||||||||||
| Numerator: | ||||||||||||
| Income from continuing operations | $ | 160,969 | $ | 233,193 | $ | 130,483 | ||||||
| Discontinued operations | -- | -- | 13,835 | |||||||||
| Limited partners’ interest in net income | $ | 160,969 | $ | 233,193 | $ | 144,318 | ||||||
| Denominator: | ||||||||||||
| Units | 97,408 | 89,812 | 73,657 | |||||||||
| Time-vested restricted units | 122 | 38 | -- | |||||||||
| Total Weighted average Units outstanding | 97,530 | 89,850 | 73,657 | |||||||||
| Basic earnings per Unit: | ||||||||||||
| Income from continuing operations | $ | 1.65 | $ | 2.60 | $ | 1.77 | ||||||
| Discontinued operations | -- | -- | 0.19 | |||||||||
| Limited partners’ interest in net income | $ | 1.65 | $ | 2.60 | $ | 1.96 | ||||||
| DILUTED EARNINGS PER UNIT: | ||||||||||||
| Numerator: | ||||||||||||
| Income from continuing operations | $ | 160,969 | $ | 233,193 | $ | 130,483 | ||||||
| Discontinued operations | -- | -- | 13,835 | |||||||||
| Limited partners’ interest in net income | $ | 160,969 | $ | 233,193 | $ | 144,318 | ||||||
Denominator: | ||||||||||||
| Units | 97,408 | 89,812 | 73,657 | |||||||||
| Time-vested restricted units | 122 | 38 | -- | |||||||||
| Total Weighted average Units outstanding | 97,530 | 89,850 | 73,657 | |||||||||
| Diluted earnings per Unit: | ||||||||||||
| Income from continuing operations | $ | 1.65 | $ | 2.60 | $ | 1.77 | ||||||
| Discontinued operations | -- | -- | 0.19 | |||||||||
| Limited partners’ interest in net income | $ | 1.65 | $ | 2.60 | $ | 1.96 | ||||||
Our General Partner’s percentage interest in our net income increases as cash distributions paid per Unit increase, in accordance with our Partnership Agreement. At December 31, 2008, 2007 and 2006, we had outstanding 104,704,861, 89,911,532 and 89,804,829 Units, respectively.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
NOTE 17. COMMITMENTS AND CONTINGENCIES
Litigation
In 1991, we were named as a defendant in a matter styled Jimmy R. Green, et al. v. Cities Service Refinery, et al. as filed in the 26th Judicial District Court of Bossier Parish, Louisiana. The plaintiffs in this matter reside or formerly resided on land that was once the site of a refinery owned by one of our co-defendants. The former refinery is located near our Bossier City facility. Plaintiffs have claimed personal injuries and property damage arising from alleged contamination of the refinery property. The plaintiffs have pursued certification as a class and have significantly increased their demand to approximately $175.0 million. We have never owned any interest in the refinery property made the basis of this action, and we do not believe that we contributed to any alleged contamination of this property. While we cannot predict the ultimate outcome, we do not believe that the outcome of this lawsuit will have a material adverse effect on our financial position, results of operations or cash flows.
On September 18, 2006, Peter Brinckerhoff, a purported unitholder of TEPPCO, filed a complaint in the Court of Chancery of New Castle County in the State of Delaware, in his individual capacity, as a putative class action on behalf of our other unitholders, and derivatively on our behalf, concerning proposals made to our unitholders in our definitive proxy statement filed with the SEC on September 11, 2006 (“Proxy Statement”) and other transactions involving us and Enterprise Products Partners or its affiliates. Mr. Brinckerhoff filed an amended complaint on July 12, 2007. The amended complaint names as defendants the General Partner; the Board of Directors of the General Partner; EPCO; Enterprise Products Partners and certain of its affiliates and Dan L. Duncan. We are named as a nominal defendant.
The amended complaint alleges, among other things, that certain of the transactions adopted at a special meeting of our unitholders on December 8, 2006, including a reduction of the General Partner’s maximum percentage interest in our distributions in exchange for Units (the “Issuance Proposal”), were unfair to our unitholders and constituted a breach by the defendants of fiduciary duties owed to our unitholders and that the Proxy Statement failed to provide our unitholders with all material facts necessary for them to make an informed decision whether to vote in favor of or against the proposals. The amended complaint further alleges that, since Mr. Duncan acquired control of the General Partner in 2005, the defendants, in breach of their fiduciary duties to us and our unitholders, have caused us to enter into certain transactions with Enterprise Products Partners or its affiliates that were unfair to us or otherwise unfairly favored Enterprise Products Partners or its affiliates over us. The amended complaint alleges that such transactions include the Jonah joint venture entered into by us and an Enterprise Products Partners affiliate in August 2006 (citing the fact that our ACG Committee did not obtain a fairness opinion from an independent investment banking firm in approving the transaction), and the sale by us to an Enterprise Products Partners’ affiliate of the Pioneer plant in March 2006. As more fully described in the Proxy Statement, the ACG Committee recommended the Issuance Proposal for approval by the Board of Directors of the General Partner. The amended complaint also alleges that Richard S. Snell, Michael B. Bracy and Murray H. Hutchison, constituting the three members of the ACG Committee at the time, cannot be considered independent because of their alleged ownership of securities in Enterprise Products Partners and its affiliates and/or their relationships with Mr. Duncan.
The amended complaint seeks relief (i) awarding damages for profits and special benefits allegedly obtained by defendants as a result of the alleged wrongdoings in the complaint; (ii) rescinding all actions taken pursuant to the Proxy vote and (iii) awarding plaintiff costs of the action, including fees and expenses of his attorneys and experts. Pre-trial discovery in this proceeding is underway. While we cannot predict the ultimate outcome, we do not believe that the outcome of this lawsuit will have a material adverse effect on our financial position, results of operations or cash flows.
In October 2005, Williams Gas Processing, n/k/a Williams Field Services Company, LLC (“Williams”) notified Jonah that the gas delivered to Williams’ Opal Gas Processing Plant (“Opal Plant”) allegedly failed to conform to quality specifications of the Interconnect and Operator Balancing Agreement (“Interconnect Agreement”) which has allegedly caused damages to the Opal Plant in excess of $28.0 million. On July 24, 2007,
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TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Jonah filed suit against Williams in Harris County, Texas seeking a declaratory order that Jonah was not liable to Williams. In addition, on August 24, 2007, Williams filed a complaint in the 3rd Judicial District Court of Lincoln County, Wyoming alleging that Jonah was delivering non-conforming gas from its gathering customers in the Jonah system to the Opal Plant, in violation of the Interconnect Agreement. Jonah denies any liability to Williams. Discovery is ongoing.
In addition to the proceedings discussed above, we have been, in the ordinary course of business, a defendant in various lawsuits and a party to various other legal proceedings, some of which are covered in whole or in part by insurance. We believe that the outcome of these other proceedings will not individually or in the aggregate have a future material adverse effect on our consolidated financial position, results of operations or cash flows.
Regulatory Matters
Our pipelines and other facilities are subject to multiple environmental obligations and potential liabilities under a variety of federal, state and local laws and regulations. These include, without limitation: the Comprehensive Environmental Response, Compensation, and Liability Act; the Resource Conservation and Recovery Act; the Clean Air Act; the Federal Water Pollution Control Act or the Clean Water Act; the Oil Pollution Act; and analogous state and local laws and regulations. Such laws and regulations affect many aspects of our present and future operations, and generally require us to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals, with respect to air emissions, water quality, wastewater discharges, and solid and hazardous waste management. Failure to comply with these requirements may expose us to fines, penalties and/or interruptions in our operations that could influence our results of operations. If an accidental leak, spill or release of hazardous substances occurs at any facilities that we own, operate or otherwise use, or where we send materials for treatment or disposal, we could be held jointly and severally liable for all resulting liabilities, including investigation, remedial and clean-up costs. Likewise, we could be required to remove or remediate previously disposed wastes or property contamination, including groundwater contamination. Any or all of this could materially affect our results of operations and cash flows.
We believe that our operations and facilities are in substantial compliance with applicable environmental laws and regulations, and that the cost of compliance with such laws and regulations will not have a material adverse effect on our results of operations or financial position. We cannot ensure, however, that existing environmental regulations will not be revised or that new regulations will not be adopted or become applicable to us. The clear trend in environmental regulation is to place more restrictions and limitations on activities that may be perceived to affect the environment, and thus there can be no assurance as to the amount or timing of future expenditures for environmental regulation compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, could have a material adverse effect on our business, financial position, results of operations and cash flows. At December 31, 2008 and 2007, we had accrued liabilities of $6.9 million and $4.0 million, respectively, related to sites requiring environmental remediation activities.
In 1999, our Arcadia, Louisiana, facility and adjacent terminals were directed by the Remediation Services Division of the Louisiana Department of Environmental Quality (“LDEQ”) to pursue remediation of environmental contamination. Effective March 2004, we executed an access agreement with an adjacent industrial landowner who is located upgradient of the Arcadia facility. This agreement enables the landowner to proceed with remediation activities at our Arcadia facility for which it has accepted shared responsibility. At December 31, 2008, we have an accrued liability of $0.5 million for remediation costs at our Arcadia facility. We do not expect that the completion of the remediation program proposed to the LDEQ will have a future material adverse effect on our financial position, results of operations or cash flows.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
We received a notice of probable violation from the U.S. Department of Transportation on April 25, 2005, for alleged violations of pipeline safety regulations at our Todhunter facility, with a proposed $0.4 million civil penalty. We responded on June 30, 2005, by admitting certain of the alleged violations, contesting others and requesting a reduction in the proposed civil penalty. We do not expect any settlement, fine or penalty to have a material adverse effect on our financial position, results of operations or cash flows.
The FERC, pursuant to the Interstate Commerce Act of 1887, as amended, the Energy Policy Act of 1992 and rules and orders promulgated thereunder, regulates the tariff rates for our interstate common carrier pipeline operations. To be lawful under that Act, interstate tariff rates, terms and conditions of service must be just and reasonable and not unduly discriminatory, and must be on file with FERC. In addition, pipelines may not confer any undue preference upon any shipper. Shippers may protest, and the FERC may investigate, the lawfulness of new or changed tariff rates. The FERC can suspend those tariff rates for up to seven months. It can also require refunds of amounts collected with interest pursuant to rates that are ultimately found to be unlawful. The FERC and interested parties can also challenge tariff rates that have become final and effective. Because of the complexity of rate making, the lawfulness of any rate is never assured. A successful challenge of our rates could adversely affect our revenues.
The FERC uses prescribed rate methodologies for approving regulated tariff rates for transporting crude oil and refined products. Our interstate tariff rates are either market-based or derived in accordance with the FERC’s indexing methodology, which currently allows a pipeline to increase its rates by a percentage linked to the producer price index for finished goods. These methodologies may limit our ability to set rates based on our actual costs or may delay the use of rates reflecting increased costs. Changes in the FERC’s approved methodology for approving rates could adversely affect us. Adverse decisions by the FERC in approving our regulated rates could adversely affect our cash flow.
The intrastate liquids pipeline transportation and gas gathering services we provide are subject to various state laws and regulations that apply to the rates we charge and the terms and conditions of the services we offer. Although state regulation typically is less onerous than FERC regulation, the rates we charge and the provision of our services may be subject to challenge.
Although our natural gas gathering systems are generally exempt from FERC regulation under the Natural Gas Act of 1938, FERC regulation still significantly affects our natural gas gathering business. Our natural gas gathering operations could be adversely affected in the future should they become subject to the application of federal regulation of rates and services or if the states in which we operate adopt policies imposing more onerous regulation on gathering. Additional rules and legislation pertaining to these matters are considered and adopted from time to time at both state and federal levels. We cannot predict what effect, if any, such regulatory changes and legislation might have on our operations or revenues.
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TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Contractual Obligations
The following table summarizes our various contractual obligations at December 31, 2008. A description of each type of contractual obligation follows:
| Payment or Settlement due by Period | ||||||||||||||||||||||||||||
| Total | 2009 | 2010 | 2011 | 2012 | 2013 | Thereafter | ||||||||||||||||||||||
| Maturities of long-term debt (1) | $ | 2,516,654 | $ | -- | $ | -- | $ | -- | $ | 1,016,654 | $ | 450,000 | $ | 1,050,000 | ||||||||||||||
| Interest payments (2) | $ | 2,624,102 | $ | 146,838 | $ | 146,838 | $ | 146,839 | $ | 127,474 | $ | 87,975 | $ | 1,968,138 | ||||||||||||||
| Operating leases (3) | $ | 55,696 | $ | 12,467 | $ | 10,640 | $ | 9,712 | $ | 9,045 | $ | 6,156 | $ | 7,676 | ||||||||||||||
| Purchase obligations (4): | ||||||||||||||||||||||||||||
| Product purchase commitments: | ||||||||||||||||||||||||||||
| Estimated payment obligation: | ||||||||||||||||||||||||||||
| Crude oil | $ | 212,435 | $ | 212,435 | $ | -- | $ | -- | $ | -- | $ | -- | $ | -- | ||||||||||||||
| Refined Products | $ | 10,594 | $ | 10,594 | $ | -- | $ | -- | $ | -- | $ | -- | $ | -- | ||||||||||||||
| Other | $ | 3,057 | $ | 1,772 | $ | 884 | $ | 401 | $ | -- | $ | -- | $ | -- | ||||||||||||||
| Underlying major volume commitments: | ||||||||||||||||||||||||||||
| Crude oil (in barrels) | $ | 4,409 | $ | 4,409 | $ | -- | $ | -- | $ | -- | $ | -- | $ | -- | ||||||||||||||
| Refined Products (in barrels) | $ | 353 | $ | 353 | $ | -- | $ | -- | $ | -- | $ | -- | $ | -- | ||||||||||||||
| Service payment commitments (5) | $ | 5,024 | $ | 4,675 | $ | 349 | $ | -- | $ | -- | $ | -- | $ | -- | ||||||||||||||
| Contributions to Jonah (6) | $ | 27,000 | $ | 27,000 | $ | -- | $ | -- | $ | -- | $ | -- | $ | -- | ||||||||||||||
Contributions to Texas Offshore Port System (7) | $ | 70,000 | $ | 70,000 | $ | -- | $ | -- | $ | -- | $ | -- | $ | -- | ||||||||||||||
| Capital expenditure obligations (8) | $ | 116,733 | $ | 116,733 | $ | -- | $ | -- | $ | -- | $ | -- | $ | -- | ||||||||||||||
| Other liabilities and deferred credits (9) | $ | 28,826 | $ | -- | $ | 5,616 | $ | 5,607 | $ | 5,607 | $ | 2,096 | $ | 9,900 | ||||||||||||||
__________________
| (1) | We have long-term payment obligations under our Revolving Credit Facility, our senior notes and our junior subordinated notes. Amounts shown in the table represent our scheduled future maturities of long-term debt principal for the periods indicated (see Note 12 for additional information regarding our consolidated debt obligations). |
| (2) | Includes interest payments due on our senior notes and junior subordinated notes and interest payments and commitment fees due on our Revolving Credit Facility. The interest amount calculated on the Revolving Credit Facility and the junior subordinated notes is based on the assumption that the amount outstanding and the interest rate charged both remain at their current levels. |
| (3) | We lease certain property, plant and equipment under noncancelable and cancelable operating leases. Amounts shown in the table represent minimum cash lease payment obligations under our operating leases with terms in excess of one year for the periods indicated. Lease expense is charged to operating costs and expenses on a straight line basis over the period of expected economic benefit. Contingent rental payments are expensed as incurred. Total rental expense for the years ended December 31, 2008, 2007 and 2006, was $20.0 million, $22.1 million and $25.3 million, respectively. |
| (4) | We have long and short-term purchase obligations for products and services with third-party suppliers. The prices that we are obligated to pay under these contracts approximate current market prices. The preceding table shows our commitments and estimated payment obligations under these contracts for the periods indicated. Our estimated future payment obligations are based on the contractual price under each contract for products and services at December 31, 2008. The majority of contractual commitments we make for the purchase of crude oil range in term from a thirty-day evergreen to one year. A substantial portion of the contracts for the purchase of crude oil that extend beyond thirty days include cancellation provisions that allow us to cancel the contract with thirty days written notice. |
| (5) | Includes approximately $4.5 million related to a shipment commitment on Centennial, approximately $0.4 million related to a commitment to pay for compression services on Val Verde and approximately $0.1 million related to the monthly service fee we pay Cenac to operate the marine assets in accordance with the transitional operating agreement. |
| (6) | Expected contributions to Jonah in 2009 for our share of capital expenditures. |
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
| (7) | Expected contributions to Texas Offshore Port System for our share of costs related to the TOPS and PACE projects. We are obligated under the joint venture agreement to contribute one-third of the funds to complete the projects, which we currently estimate will total $600.0 million for our share. |
| (8) | We have short-term payment obligations relating to capital projects we have initiated. These commitments represent unconditional payment obligations that we have agreed to pay vendors for services rendered or products purchased. |
| (9) | Includes approximately $9.6 million of long-term deferred revenue payments, primarily in the Downstream and Upstream segments, which are being recognized into income as the services are performed and approximately $12.0 million related to our estimated long-term portions of our liabilities under our guarantees to Centennial for its credit agreement and for a catastrophic event. The amount of commitment by year is our best estimate of projected payments of these long-term liabilities. |
Other
Guarantees
At December 31, 2008 and 2007, Centennial’s debt obligations consisted of $129.9 million and $140.0 million, respectfully, borrowed under a master shelf loan agreement. In January 2008, we entered into an Amended Guaranty agreement with Centennial’s lenders, under which the TEPPCO Guarantors are required, on a joint and several basis, to pay 50% of any past-due amount under Centennial’s master shelf loan agreement not paid by Centennial. The Amended Guaranty also has a credit maintenance requirement whereby we may be required to provide additional credit support in the form of a letter of credit or pay certain fees if either of our credit ratings from S&P and Moody’s falls below investment grade levels as specified in the Amended Guaranty. If Centennial defaults on its debt obligations, the estimated maximum potential amount of future payments for the TEPPCO Guarantors and Marathon is $65.0 million each at December 31, 2008. At December 31, 2008, we have a liability of $9.0 million, which is based upon the expected present value of amounts we would have to pay under the guarantee.
TE Products, Marathon and Centennial have also entered into a limited cash call agreement, which allows each member to contribute cash in lieu of Centennial procuring separate insurance in the event of a third-party liability arising from a catastrophic event. There is an indefinite term for the agreement and each member is to contribute cash in proportion to its ownership interest, up to a maximum of $50.0 million each. As a result of the catastrophic event guarantee, at December 31, 2008, TE Products has a liability of $3.9 million, which is based upon the expected present value of amounts we would have to pay under the guarantee. If a catastrophic event were to occur and we were required to contribute cash to Centennial, such contributions might be covered by our insurance (net of deductible), depending upon the nature of the catastrophic event.
One of our subsidiaries, TCO, has entered into master equipment lease agreements with finance companies for the use of various pieces of equipment. We currently estimate that our minimum lease payment related to this equipment will be $3.9 million for 2009. We have guaranteed the full and timely payment and performance of TCO’s obligations under the agreements. Generally, events of default would trigger our performance under the guarantee. The maximum potential amount of future payments under the guarantee is not estimable, but would include base rental payments for both current and future equipment, stipulated loss payments in the event any equipment is stolen, damaged, or destroyed and any future indemnity payments. We carry insurance coverage that may offset any payments required under the guarantees. We do not believe that any performance under the guarantee would have a material effect on our financial condition, results of operations or cash flows.
Motiva Project
In December 2006, we signed an agreement with Motiva Enterprises, LLC (“Motiva”) for us to construct and operate a new refined products storage facility to support the expansion of Motiva’s refinery in Port Arthur, Texas. Under the terms of the agreement, we are constructing a 5.4 million barrel refined products storage facility for gasoline and distillates. The agreement also provides for a 15-year throughput and dedication of volume, which will commence upon completion of the refinery expansion or July 1, 2010, which ever comes first. The project includes the construction of 20 storage tanks, five 5.4-mile product pipelines connecting the storage facility to
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Motiva’s refinery, 21,000 horsepower of pumping capacity, and distribution pipeline connections to the Colonial, Explorer and Magtex pipelines. As a part of a separate but complementary initiative, we are constructing an 11-mile, 20-inch pipeline to connect the new storage facility in Port Arthur to our refined products terminal in Beaumont, Texas, which is one of the primary origination facilities for our mainline system. These projects will facilitate connections to additional markets through the Colonial, Explorer and Magtex pipeline systems and provide the Motiva refinery with access to our pipeline system. The total cost of the project is expected to be approximately $355.0 million, which includes $25.0 million for the 11-mile, 20-inch pipeline, $24.0 million of capitalized interest and $17.0 million of mutually agreed upon scope changes requested by Motiva. Through December 31, 2008, we have spent approximately $170.1 million on this construction project. Under the terms of the agreement, if Motiva cancels the agreement prior to the commencement date of the project, Motiva will reimburse us the actual reasonable expenses we have incurred after the effective date of the agreement, including both internal and external costs that would be capitalized as a part of the project, plus a ten percent cancellation fee.
Texas Offshore Port System
We, through a subsidiary, own a one-third interest in the Texas Offshore Port System joint venture. The aggregate cost of the TOPS and PACE projects is expected to be approximately $1.8 billion (excluding capitalized interest), with the majority of such expenditures currently expected to occur in 2010 and 2011. We have guaranteed up to approximately $700.0 million, which includes a contingency amount for potential cost overruns, of the capital expenditure obligations of our subsidiary in the joint venture. See Note 9 for further information.
Other
Substantially all of the petroleum products that we transport and store are owned by our customers. At December 31, 2008, TCTM and TE Products had approximately 5.2 million barrels and 11.3 million barrels, respectively, of products in their custody that were owned by customers. We are obligated for the transportation, storage and delivery of such products on behalf of our customers. We maintain insurance to cover product losses through circumstances beyond our control at levels we believe are consistent with the associated exposures.
Insurance
We carry insurance coverage we believe to be consistent with the exposures associated with the nature and scope of our operations. As of December 31, 2008, our current insurance coverage includes (1) commercial general liability insurance for liabilities to third parties for bodily injury and property damage resulting from our operations; (2) workers’ compensation coverage to required statutory limits; (3) automobile liability insurance for all owned, non-owned and hired vehicles covering liabilities to third parties for bodily injury and property damage, (4) property insurance covering the replacement value of all real and personal property damage, including damages arising from earthquake, flood damage and business interruption/extra expense and (5) hulls and certain liabilities which may arise from marine vessel operations. For select assets, we also carry pollution liability insurance that provides coverage for historical and gradual pollution events. All coverages are subject to certain deductibles, limits or sub-limits and policy terms and conditions.
We also maintain excess liability insurance coverage above the established primary limits for commercial general liability and automobile liability insurance. Limits, terms, conditions and deductibles are commensurate with the nature and scope of our operations. The cost of our general insurance coverage has increased over the past year reflecting the changing conditions of the insurance markets. These insurance policies, except for the pollution liability policies, are through EPCO (see Note 15).
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Commitments under our EPCO equity compensation plans
In accordance with our agreements with EPCO, we reimburse EPCO for our share of its compensation expense associated with certain employees who perform management, administrative and operating functions for us (see Note 1). This includes costs associated with unit option awards granted to these employees to purchase our Units. At December 31, 2008, there were 355,000 unit options outstanding for which we were responsible for reimbursing EPCO for the costs of such awards (see Note 4).
The weighted-average strike price of unit option awards outstanding at December 31, 2008 was $40.00 per Unit. At December 31, 2008, none of these unit options were exercisable. As these options are exercised, we will reimburse EPCO for the gross unit option value of the options exercised to make EPCO whole for related employee tax withholding requirements. See Note 4 for additional information regarding our accounting for equity awards.
NOTE 18. CONCENTRATIONS OF CREDIT RISK
Our primary market areas are located in the Northeast, Midwest and Southwest regions of the United States. We have a concentration of trade receivable balances due from major integrated oil companies, independent oil companies and other pipelines and wholesalers. These concentrations of customers may affect our overall credit risk in that the customers may be similarly affected by changes in economic, regulatory or other factors. We analyze our customers’ historical and future credit positions prior to extending credit. We manage our exposure to credit risk through credit analysis, credit approvals, credit limits and monitoring procedures, and for certain transactions may utilize letters of credit, prepayments and guarantees.
For the years ended December 31, 2008, 2007 and 2006, Valero Energy Corp. accounted for 21%, 16% and 14%, respectively, of our total consolidated revenues, and for the years ended December 31, 2008, 2007 and 2006, BP Oil Supply Company accounted for 16%, 14% and 11%, respectively, of our total consolidated revenues. Additionally, for the year ended December 31, 2007, Shell Trading Company accounted for 12% of our total consolidated revenues. No other single customer accounted for 10% or more of our total consolidated revenues for the years ended December 31, 2008, 2007 and 2006.
F-75
TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
NOTE 19. SUPPLEMENTAL CASH FLOW INFORMATION
The following table provides information regarding (i) the net effect of changes in our operating assets and liabilities, (ii) non-cash investing and financing activities and (iii) cash payments for interest for the years ended December 31, 2008, 2007 and 2006:
| For Year Ended December 31, | ||||||||||||
| 2008 | 2007 | 2006 | ||||||||||
| Decrease (increase) in: | ||||||||||||
Accounts receivable, trade | $ | 591,498 | $ | (529,055 | ) | $ | (67,317 | ) | ||||
Accounts receivable, related parties | (8,884 | ) | (5,986 | ) | 1,736 | |||||||
Inventories | 28,526 | (8,255 | ) | (45,002 | ) | |||||||
Other current assets | 4,669 | (7,356 | ) | 25,850 | ||||||||
Other | (13,763 | ) | (17,527 | ) | (10,740 | ) | ||||||
| Increase (decrease) in: | ||||||||||||
Accounts payable and accrued liabilities | (627,198 | ) | 558,111 | 44,348 | ||||||||
Accounts payable, related parties | (12,877 | ) | 3,374 | 15,696 | ||||||||
Other | (10,079 | ) | (1,946 | ) | (1,268 | ) | ||||||
| Net effect of changes in operating accounts | $ | (48,108 | ) | $ | (8,640 | ) | $ | (36,697 | ) | |||
| Non-cash investing activities: | ||||||||||||
| Net assets transferred to Jonah Gas Gathering Company. | $ | -- | $ | -- | $ | 572,609 | ||||||
Payable to Enterprise Gas Processing, LLC for spending for Phase V expansion of Jonah Gas Gathering Company (see Note 9) | $ | 995 | $ | 9,878 | $ | 8,732 | ||||||
| Liabilities for Construction work in progress | $ | 17,213 | $ | 11,334 | $ | 10,786 | ||||||
| Non-cash financing activities: | ||||||||||||
Issuance of Units in Cenac acquisition (see Note 10) | $ | 186,558 | $ | -- | $ | -- | ||||||
| Supplemental disclosure of cash flows: | ||||||||||||
| Cash paid for interest (net of amounts capitalized) | $ | 128,136 | $ | 104,220 | $ | 88,107 | ||||||
| Cash payments for state income taxes | $ | 1,947 | $ | 20 | $ | -- | ||||||
We determine net cash flows provided by operating activities using the indirect method, which adjusts net income for items that did not affect cash. Under GAAP, we use the accrual basis of accounting to determine net income. This basis requires that we record revenue when earned and expenses when incurred. Earned revenues may include credit sales that have not been collected in cash and expenses incurred that may not have been paid in cash. The extent to which changes in operating accounts influence net cash flows provided by operating activities generally depends on the following:
| § | The timing of cash receipts from revenue transactions and cash payments for expense transactions near the end of each reporting period. For example, if significant cash receipts are posted on the last day of the current reporting period, but subsequent payments on expense invoices are made on the first day of the next reporting period, net cash flows provided by operating activities will reflect an increase in the current reporting period that will be reduced as payments are made in the next period. |
| § | If commodity or other prices increase between reporting periods, changes in accounts receivable and accounts payable and accrued expenses may appear larger than in previous periods; however, overall levels of receivables and payables may still reflect normal ranges. |
F-76
TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
| § | Additions to inventory for forward sales transactions or other reasons or increased expenditures for prepaid items would be reflected as a use of cash and reduce overall cash provided by operating activities in a given reporting period. As these assets are charged to expense in subsequent periods, the expense amount is reflected as a positive change in operating accounts; however, there is no impact on operating cash flows. |
In addition to the adjustments noted above, non-cash charges in the income statement are added back to net income and noncash credits are deducted to compute net cash flows provided by operating activities. Examples of noncash charges include depreciation and amortization.
NOTE 20. SELECTED QUARTERLY DATA (UNAUDITED)
| First | Second | Third | Fourth | |||||||||||||
| Quarter | Quarter | Quarter | Quarter | |||||||||||||
2008: | ||||||||||||||||
| Operating revenues | $ | 2,808,488 | $ | 4,180,463 | $ | 4,205,744 | $ | 2,338,194 | ||||||||
| Operating income | 83,519 | 59,276 | 59,860 | 50,765 | ||||||||||||
| Net income | 64,139 | 47,682 | 47,031 | 34,700 | ||||||||||||
Basic and diluted net income per Limited Partner Unit (1) (2) | $ | 0.57 | $ | 0.42 | $ | 0.40 | $ | 0.28 | ||||||||
| First | Second | Third | Fourth | |||||||||||||
| Quarter | Quarter | Quarter | Quarter | |||||||||||||
2007: | ||||||||||||||||
| Operating revenues | $ | 1,978,429 | $ | 2,049,436 | $ | 2,580,657 | $ | 3,049,538 | ||||||||
| Operating income | 83,434 | 50,729 | 54,719 | 60,673 | ||||||||||||
| Net income | 138,191 | 47,760 | 47,631 | 45,598 | ||||||||||||
Basic and diluted net income per Limited Partner Unit (1) (2) | $ | 1.29 | $ | 0.44 | $ | 0.44 | $ | 0.42 | ||||||||
______________________
| (1) | Per Unit calculations include 14,793,329 Units issued in 2008 (4,854,899 Units issued in connection with Cenac acquisition, 378,437 Units issued under the DRIP, 23,097 Units issued under the Unit Purchase Plan, 95,516 net restricted units issued and 9,441,380 Units issued in September 2008) and 106,703 Units issued in 2007 (62,400 restricted units issued, 4,507 Units issued under the Unit Purchase Plan and 39,796 Units issued under the DRIP). |
| (2) | The sum of the four quarters does not equal the total year due to rounding. |
NOTE 21. SUPPLEMENTAL CONDENSED CONSOLIDATING FINANCIAL INFORMATION
TE Products, TCTM, TEPPCO Midstream and Val Verde have issued full, unconditional, and joint and several guarantees of our senior notes, our Junior Subordinated Notes (collectively “the Guaranteed Debt”), our Revolving Credit Facility, and prior to its termination, our Term Credit Facility. TE Products, TCTM, TEPPCO Midstream and Val Verde are collectively referred to as the “Guarantor Subsidiaries.”
The following supplemental condensed consolidating financial information reflects our separate accounts, the combined accounts of the Guarantor Subsidiaries, the combined accounts of our other non-guarantor subsidiaries, the combined consolidating adjustments and eliminations and our consolidated accounts for the dates and periods indicated. For purposes of the following consolidating information, our investments in our subsidiaries and the Guarantor Subsidiaries’ investments in their subsidiaries are accounted for under the equity method of
F-77
TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
accounting. Earnings of subsidiaries are therefore reflected in the Partnership’s and Guarantor Subsidiaries’ investment accounts and earnings. The elimination entries presented herein eliminate investments in subsidiaries and intercompany balances and transactions.
| December 31, 2008 | ||||||||||||||||||||
| TEPPCO Partners, L.P. | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Consolidating Adjustments | TEPPCO Partners, L.P. Consolidated | ||||||||||||||||
| Assets | ||||||||||||||||||||
| Current assets | $ | 23,095 | $ | 145,146 | $ | 1,147,976 | $ | (408,655 | ) | $ | 907,562 | |||||||||
| Property, plant and equipment – net | 13,505 | 1,294,785 | 1,131,620 | -- | 2,439,910 | |||||||||||||||
| Equity investments | 8,951 | 1,020,928 | 226,044 | -- | 1,255,923 | |||||||||||||||
| Investments | 1,685,985 | 398,946 | 21 | (2,084,952 | ) | -- | ||||||||||||||
| Intercompany notes receivable | 2,628,274 | -- | -- | (2,628,274 | ) | -- | ||||||||||||||
| Intangible assets | -- | 117,936 | 89,717 | -- | 207,653 | |||||||||||||||
| Goodwill | -- | -- | 106,611 | -- | 106,611 | |||||||||||||||
| Other assets | 14,371 | 33,373 | 84,417 | -- | 132,161 | |||||||||||||||
Total assets | $ | 4,374,181 | $ | 3,011,114 | $ | 2,786,406 | $ | (5,121,881 | ) | $ | 5,049,820 | |||||||||
| Liabilities and partners’ capital | ||||||||||||||||||||
| Current liabilities | $ | 244,452 | $ | 215,397 | $ | 848,802 | $ | (408,655 | ) | $ | 899,996 | |||||||||
| Long-term debt | 2,529,519 | -- | -- | -- | 2,529,519 | |||||||||||||||
| Intercompany notes payable | -- | 1,424,240 | 1,204,034 | (2,628,274 | ) | -- | ||||||||||||||
| Other long term liabilities | 8,731 | 17,035 | 3,060 | -- | 28,826 | |||||||||||||||
| Total partners’ capital | 1,591,479 | 1,354,442 | 730,510 | (2,084,952 | ) | 1,591,479 | ||||||||||||||
Total liabilities and partners’ capital | $ | 4,374,181 | $ | 3,011,114 | $ | 2,786,406 | $ | (5,121,881 | ) | $ | 5,049,820 | |||||||||
| December 31, 2007 | ||||||||||||||||||||
| TEPPCO Partners, L.P. | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Consolidating Adjustments | TEPPCO Partners, L.P. Consolidated | ||||||||||||||||
| Assets | ||||||||||||||||||||
| Current assets | $ | 32,302 | $ | 77,083 | $ | 1,499,653 | $ | (93,049 | ) | $ | 1,515,989 | |||||||||
| Property, plant and equipment – net | -- | 1,142,630 | 651,004 | -- | 1,793,634 | |||||||||||||||
| Equity investments | -- | 958,345 | 188,650 | -- | 1,146,995 | |||||||||||||||
| Investments | 1,286,021 | 388,968 | 19 | (1,675,008 | ) | -- | ||||||||||||||
| Intercompany notes receivable | 1,511,168 | -- | -- | (1,511,168 | ) | -- | ||||||||||||||
| Intangible assets | -- | 136,050 | 28,631 | -- | 164,681 | |||||||||||||||
| Goodwill | -- | -- | 15,506 | -- | 15,506 | |||||||||||||||
| Other assets | 8,580 | 34,839 | 69,895 | (62 | ) | 113,252 | ||||||||||||||
Total assets | $ | 2,838,071 | $ | 2,737,915 | $ | 2,453,358 | $ | (3,279,287 | ) | $ | 4,750,057 | |||||||||
| Liabilities and partners’ capital | ||||||||||||||||||||
| Current liabilities | $ | 61,926 | $ | 493,184 | $ | 1,485,164 | $ | (93,049 | ) | $ | 1,947,225 | |||||||||
| Long-term debt | 1,511,083 | -- | -- | -- | 1,511,083 | |||||||||||||||
| Intercompany notes payable | -- | 1,006,801 | 504,367 | (1,511,168 | ) | -- | ||||||||||||||
| Other long term liabilities | 435 | 24,466 | 2,283 | (62 | ) | 27,122 | ||||||||||||||
| Total partners’ capital | 1,264,627 | 1,213,464 | 461,544 | (1,675,008 | ) | 1,264,627 | ||||||||||||||
Total liabilities and partners’ capital | $ | 2,838,071 | $ | 2,737,915 | $ | 2,453,358 | $ | (3,279,287 | ) | $ | 4,750,057 | |||||||||
F-78
TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
| For Year Ended December 31, 2008 | ||||||||||||||||||||
| TEPPCO Partners, L.P. | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Consolidating Adjustments | TEPPCO Partners, L.P. Consolidated | ||||||||||||||||
| Operating revenues | $ | -- | $ | 383,771 | $ | 13,149,310 | $ | (192 | ) | $ | 13,532,889 | |||||||||
| Costs and expenses | -- | 292,741 | 12,991,319 | (4,593 | ) | 13,279,467 | ||||||||||||||
| Gains (losses) on sales of assets | -- | (2 | ) | 4 | -- | 2 | ||||||||||||||
| Operating income | -- | 91,032 | 157,987 | 4,401 | 253,420 | |||||||||||||||
| Interest expense – net | �� | -- | (83,139 | ) | (56,849 | ) | -- | (139,988 | ) | |||||||||||
| Equity earnings | 193,552 | 175,393 | 11,693 | (297,945 | ) | 82,693 | ||||||||||||||
| Other income | -- | 959 | 1,085 | -- | 2,044 | |||||||||||||||
| Income before provision for income taxes | 193,552 | 184,245 | 113,916 | (293,544 | ) | 198,169 | ||||||||||||||
| Provision for income taxes | -- | 1,492 | 3,125 | -- | 4,617 | |||||||||||||||
| Net income | $ | 193,552 | $ | 182,753 | $ | 110,791 | $ | (293,544 | ) | $ | 193,552 | |||||||||
| For Year Ended December 31, 2007 | ||||||||||||||||||||
| TEPPCO Partners, L.P. | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Consolidating Adjustments | TEPPCO Partners, L.P. Consolidated | ||||||||||||||||
| Operating revenues | $ | -- | $ | 385,902 | $ | 9,272,707 | $ | (549 | ) | $ | 9,658,060 | |||||||||
| Costs and expenses | -- | 278,630 | 9,153,588 | (5,060 | ) | 9,427,158 | ||||||||||||||
| Gains on sales of assets | -- | (18,653 | ) | -- | -- | (18,653 | ) | |||||||||||||
| Operating income | -- | 125,925 | 119,119 | 4,511 | 249,555 | |||||||||||||||
| Interest expense – net | -- | (72,705 | ) | (28,518 | ) | -- | (101,223 | ) | ||||||||||||
| Gain on sale of ownership interest in MB | ||||||||||||||||||||
| Storage | -- | 59,628 | -- | -- | 59,628 | |||||||||||||||
| Equity earnings | 279,180 | 164,107 | 2,602 | (377,134 | ) | 68,755 | ||||||||||||||
| Other income | -- | 2,255 | 767 | -- | 3,022 | |||||||||||||||
| Income before provision for income taxes | 279,180 | 279,210 | 93,970 | (372,623 | ) | 279,737 | ||||||||||||||
| Provision for income taxes | -- | 30 | 527 | -- | 557 | |||||||||||||||
| Net income | $ | 279,180 | $ | 279,180 | $ | 93,443 | $ | (372,623 | ) | $ | 279,180 | |||||||||
| For Year Ended December 31, 2006 | ||||||||||||||||||||
| TEPPCO Partners, L.P. | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Consolidating Adjustments | TEPPCO Partners, L.P. Consolidated | ||||||||||||||||
| Operating revenues | $ | -- | $ | 352,844 | $ | 9,263,451 | $ | (8,810 | ) | $ | 9,607,485 | |||||||||
| Costs and expenses | -- | 278,973 | 9,117,359 | (11,222 | ) | 9,385,110 | ||||||||||||||
| Gains on sales of assets | -- | (1,415 | ) | (5,989 | ) | -- | (7,404 | ) | ||||||||||||
| Operating income | -- | 75,286 | 152,081 | 2,412 | 229,779 | |||||||||||||||
| Interest expense – net | -- | (52,980 | ) | (33,191 | ) | -- | (86,171 | ) | ||||||||||||
| Equity earnings | 202,051 | 178,335 | 11,896 | (355,521 | ) | 36,761 | ||||||||||||||
| Other income | -- | 1,545 | 1,420 | -- | 2,965 | |||||||||||||||
| Income before provision for income taxes | 202,051 | 202,186 | 132,206 | (353,109 | ) | 183,334 | ||||||||||||||
| Provision for income taxes | -- | 135 | 517 | -- | 652 | |||||||||||||||
| Income from continuing operations | 202,051 | 202,051 | 131,689 | (353,109 | ) | 182,682 | ||||||||||||||
| Discontinued operations | -- | -- | 19,369 | -- | 19,369 | |||||||||||||||
| Net income | $ | 202,051 | $ | 202,051 | $ | 151,058 | $ | (353,109 | ) | $ | 202,051 | |||||||||
F-79
TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
| For Year Ended December 31, 2008 | ||||||||||||||||||||
| TEPPCO Partners, L.P. | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Consolidating Adjustments | TEPPCO Partners, L.P. Consolidated | ||||||||||||||||
| Operating activities: | ||||||||||||||||||||
| Net income | $ | 193,552 | $ | 182,753 | $ | 110,791 | $ | (293,544 | ) | $ | 193,552 | |||||||||
| Adjustments to reconcile net income to net cash from operating activities: | ||||||||||||||||||||
| Depreciation and amortization | -- | 70,457 | 55,872 | -- | 126,329 | |||||||||||||||
| Earnings in equity investments | -- | (75,401 | ) | (11,693 | ) | 4,401 | (82,693 | ) | ||||||||||||
| Distributions from equity investments | -- | 132,295 | 13,800 | -- | 146,095 | |||||||||||||||
| Other, net | (71,475 | ) | 138,403 | (338,563 | ) | 235,213 | (36,422 | ) | ||||||||||||
| Net cash from operating activities | 122,077 | 448,507 | (169,793 | ) | (53,930 | ) | 346,861 | |||||||||||||
| Cash flows from investing activities: | ||||||||||||||||||||
| Cash used for business combinations | -- | -- | (351,327 | ) | -- | (351,327 | ) | |||||||||||||
| Investment in Jonah | -- | (129,759 | ) | -- | -- | (129,759 | ) | |||||||||||||
| Investment in Texas Offshore Port System | -- | -- | (35,953 | ) | -- | (35,953 | ) | |||||||||||||
| Capital expenditures | -- | (193,313 | ) | (98,641 | ) | (8,549 | ) | (300,503 | ) | |||||||||||
| Other, net | -- | (694 | ) | (12,784 | ) | -- | (13,478 | ) | ||||||||||||
| Net cash flows from investing activities | -- | (323,766 | ) | (498,705 | ) | (8,549 | ) | (831,020 | ) | |||||||||||
| Cash flows from financing activities: | ||||||||||||||||||||
| Proceeds from term credit facility | 1,000,000 | -- | -- | -- | 1,000,000 | |||||||||||||||
| Repayments on term credit facility | (1,000,000 | ) | -- | -- | -- | (1,000,000 | ) | |||||||||||||
| Proceeds on revolving credit facility | 2,508,089 | -- | -- | -- | 2,508,089 | |||||||||||||||
| Repayments on revolving credit facility | (2,481,436 | ) | -- | -- | -- | (2,481,436 | ) | |||||||||||||
| Repayment of debt assumed in Cenac acquisition | -- | -- | (63,157 | ) | -- | (63,157 | ) | |||||||||||||
| Redemption of 7.51% TE Products Senior Notes | -- | (181,571 | ) | -- | -- | (181,571 | ) | |||||||||||||
| Repayment of 6.45% TE Products Senior Notes | -- | (180,000 | ) | -- | -- | (180,000 | ) | |||||||||||||
| Issuance of Limited Partner Units, net | 275,856 | -- | -- | -- | 275,856 | |||||||||||||||
| Issuance of senior notes | 996,349 | -- | -- | -- | 996,349 | |||||||||||||||
| Acquisition of treasury units | (9 | ) | -- | -- | -- | (9 | ) | |||||||||||||
| Debt issuance costs | (9,862 | ) | -- | -- | -- | (9,862 | ) | |||||||||||||
| Settlement of treasury lock agreements | (52,098 | ) | -- | -- | -- | (52,098 | ) | |||||||||||||
| Intercompany debt activities | (1,023,002 | ) | 564,757 | 882,971 | (424,726 | ) | -- | |||||||||||||
| Distributions | (327,997 | ) | (327,997 | ) | (151,316 | ) | 479,313 | (327,997 | ) | |||||||||||
| Net cash flows from financing activities | (114,110 | ) | (124,811 | ) | 668,498 | 54,587 | 484,164 | |||||||||||||
| Net change in cash and cash equivalents | 7,967 | (70 | ) | -- | (7,892 | ) | 5 | |||||||||||||
| Cash and cash equivalents, January 1 | 8,147 | 70 | 22 | (8,216 | ) | 23 | ||||||||||||||
| Cash and cash equivalents, December 31 | $ | 16,114 | $ | -- | $ | 22 | $ | (16,108 | ) | $ | 28 | |||||||||
F-80
TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
| For Year Ended December 31, 2007 | ||||||||||||||||||||
| TEPPCO Partners, L.P. | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Consolidating Adjustments | TEPPCO Partners, L.P. Consolidated | ||||||||||||||||
| Operating activities: | ||||||||||||||||||||
| Net income | $ | 279,180 | $ | 279,180 | $ | 93,443 | $ | (372,623 | ) | $ | 279,180 | |||||||||
| Adjustments to reconcile net income to net cash from operating activities: | ||||||||||||||||||||
| Depreciation and amortization | -- | 75,377 | 29,848 | -- | 105,225 | |||||||||||||||
| Earnings in equity investments | -- | (70,664 | ) | (2,602 | ) | 4,511 | (68,755 | ) | ||||||||||||
| Distributions from equity investments | -- | 110,500 | 12,400 | -- | 122,900 | |||||||||||||||
| Gains in sales of assets | -- | (18,653 | ) | -- | -- | (18,653 | ) | |||||||||||||
| Gain on sale of ownership interest in Mont Belvieu Storage Partners, L.P. | -- | (59,628 | ) | -- | -- | (59,628 | ) | |||||||||||||
| Other, net | (286,162 | ) | (68,940 | ) | 56,230 | 289,175 | (9,697 | ) | ||||||||||||
| Net cash from operating activities | (6,982 | ) | 247,172 | 189,319 | (78,937 | ) | 350,572 | |||||||||||||
| Cash flows from investing activities: | ||||||||||||||||||||
| Proceeds from sales of assets | -- | 26,550 | 1,234 | -- | 27,784 | |||||||||||||||
| Proceeds from sale of ownership interest | -- | 137,326 | -- | -- | 137,326 | |||||||||||||||
| Purchase of assets | -- | (6,180 | ) | (6,729 | ) | -- | (12,909 | ) | ||||||||||||
| Investment in Centennial | -- | (11,081 | ) | -- | -- | (11,081 | ) | |||||||||||||
| Investment in Jonah | -- | (187,547 | ) | -- | -- | (187,547 | ) | |||||||||||||
| Capital expenditures | -- | (153,715 | ) | (74,557 | ) | -- | (228,272 | ) | ||||||||||||
| Other, net | -- | (18,144 | ) | (24,557 | ) | -- | (42,701 | ) | ||||||||||||
| Net cash flows from investing activities | -- | (212,791 | ) | (104,609 | ) | -- | (317,400 | ) | ||||||||||||
| Cash flows from financing activities: | ||||||||||||||||||||
| Proceeds on revolving credit facility | 1,305,750 | -- | -- | -- | 1,305,750 | |||||||||||||||
| Repayments on revolving credit facility | (1,305,750 | ) | -- | -- | -- | (1,305,750 | ) | |||||||||||||
| Issuance of Limited Partner Units, net | 1,696 | -- | -- | -- | 1,696 | |||||||||||||||
| Redemption of portion of 7.51% Senior Notes | -- | (36,138 | ) | -- | -- | (36,138 | ) | |||||||||||||
| Issuance of Junior Subordinated Notes | 299,517 | -- | -- | -- | 299,517 | |||||||||||||||
| Debt issuance costs | (4,052 | ) | -- | -- | -- | (4,052 | ) | |||||||||||||
| Intercompany debt activities | -- | 297,512 | 2,005 | (299,517 | ) | -- | ||||||||||||||
| Distributions | (294,450 | ) | (294,450 | ) | (86,765 | ) | 381,215 | (294,450 | ) | |||||||||||
| Other, net | 1,443 | (1,235 | ) | 2 | (2 | ) | 208 | |||||||||||||
| Net cash flows from financing activities | 4,154 | (34,311 | ) | (84,758 | ) | 81,696 | (33,219 | ) | ||||||||||||
| Net change in cash and cash equivalents | (2,828 | ) | 70 | (48 | ) | 2,759 | (47 | ) | ||||||||||||
| Cash and cash equivalents, January 1 | 10,975 | -- | 70 | (10,975 | ) | 70 | ||||||||||||||
| Cash and cash equivalents, December 31 | $ | 8,147 | $ | 70 | $ | 22 | $ | (8,216 | ) | $ | 23 | |||||||||
F-81
TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
| For Year Ended December 31, 2006 | ||||||||||||||||||||
| TEPPCO Partners, L.P. | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Consolidating Adjustments | TEPPCO Partners, L.P. Consolidated | ||||||||||||||||
| Operating activities: | ||||||||||||||||||||
| Net income | $ | 202,051 | $ | 202,051 | $ | 151,058 | $ | (353,109 | ) | $ | 202,051 | |||||||||
| Adjustments to reconcile net income to net cash from operating activities: | ||||||||||||||||||||
| Depreciation and amortization | -- | 71,100 | 37,152 | -- | 108,252 | |||||||||||||||
| Earnings in equity investments | -- | (27,034 | ) | (11,905 | ) | 2,178 | (36,761 | ) | ||||||||||||
| Distributions from equity investments | -- | 42,965 | 20,518 | -- | 63,483 | |||||||||||||||
| Other, net | 1,412 | (31,926 | ) | (47,279 | ) | 13,841 | (63,952 | ) | ||||||||||||
| Net cash from operating activities | 203,463 | 257,156 | 149,544 | (337,090 | ) | 273,073 | ||||||||||||||
| Cash flows from investing activities: | ||||||||||||||||||||
| Proceeds from sales of assets | -- | 11,888 | 39,670 | -- | 51,558 | |||||||||||||||
| Purchase of assets | -- | (20,473 | ) | -- | -- | (20,473 | ) | |||||||||||||
| Investment in MB Storage | -- | (4,767 | ) | -- | (4,767 | ) | ||||||||||||||
| Investment in Centennial | -- | (2,500 | ) | -- | -- | (2,500 | ) | |||||||||||||
| Investment in Jonah | -- | (121,035 | ) | -- | -- | (121,035 | ) | |||||||||||||
| Capital expenditures | -- | (54,430 | ) | (118,132 | ) | 2,516 | (170,046 | ) | ||||||||||||
| Intercompany activities | (195,060 | ) | 243,823 | -- | (48,763 | ) | -- | |||||||||||||
| Other, net | -- | (4,270 | ) | (2,183 | ) | -- | (6,453 | ) | ||||||||||||
| Net cash flows from investing activities | (195,060 | ) | 48,236 | (80,645 | ) | (46,247 | ) | (273,716 | ) | |||||||||||
| Cash flows from financing activities: | ||||||||||||||||||||
| Proceeds on revolving credit facility | 924,125 | -- | -- | -- | 924,125 | |||||||||||||||
| Repayments on revolving credit facility | (840,025 | ) | -- | -- | -- | (840,025 | ) | |||||||||||||
| Issuance of Limited Partner Units, net | 195,060 | -- | -- | -- | 195,060 | |||||||||||||||
| Intercompany debt activities | -- | 37,219 | 90,163 | (127,382 | ) | -- | ||||||||||||||
| Distributions | (278,566 | ) | (342,611 | ) | (159,099 | ) | 501,710 | (278,566 | ) | |||||||||||
| Net cash flows from financing activities | 594 | (305,392 | ) | (68,936 | ) | 374,328 | 594 | |||||||||||||
| Net change in cash and cash equivalents | 8,997 | -- | (37 | ) | (9,009 | ) | (49 | ) | ||||||||||||
| Cash and cash equivalents, January 1 | 1,978 | -- | 107 | (1,966 | ) | 119 | ||||||||||||||
| Cash and cash equivalents, December 31 | $ | 10,975 | $ | -- | $ | 70 | $ | (10,975 | ) | $ | 70 | |||||||||
F-82