TEPPCO Partners, L.P. 10-Q 2008
Documents found in this filing:
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934>
For the quarterly period ended March 31, 2008
¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934>
For the transition period from _____ to _____.
Commission File No. 1-10403
TEPPCO Partners, L.P.
(Exact name of Registrant as specified in its charter)
1100 Louisiana Street, Suite 1600
Houston, Texas 77002
(Address of principal executive offices, including zip code)
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes þ No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date. Limited Partner Units outstanding as of May 1, 2008: 94,839,660
LIABILITIES AND PARTNERS’ CAPITAL
See Notes to Unaudited Condensed Consolidated Financial Statements.
See Notes to Unaudited Condensed Consolidated Financial Statements.
See Notes to Unaudited Condensed Consolidated Financial Statements.
See Notes to Unaudited Condensed Consolidated Financial Statements.
See Notes to Unaudited Condensed Consolidated Financial Statements.
NOTE 1. PARTNERSHIP ORGANIZATION AND BASIS OF PRESENTATION
TEPPCO Partners, L.P. (the “Partnership”), is a publicly traded Delaware limited partnership and our limited partner units are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “TPP”. 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. At formation in March 1990, we completed an initial public offering of 26,500,000 units representing limited partner interests (“Units”) at $10.00 per Unit.
Through June 29, 2007, we operated through TE Products Pipeline Company, Limited Partnership, TCTM, L.P. (“TCTM”) and TEPPCO Midstream Companies, L.P. On June 30, 2007, each of TE Products Pipeline Company, Limited Partnership and TEPPCO Midstream Companies, L.P. separately converted into Texas limited partnerships and immediately thereafter each merged into separate newly-formed Texas limited liability companies that had no business operations prior to the merger. The resulting limited liability companies are called TE Products Pipeline Company, LLC (“TE Products”) and TEPPCO Midstream Companies, LLC (“TEPPCO Midstream”). Beginning June 30, 2007 and through January 31, 2008, we operated through TE Products, TCTM and TEPPCO Midstream. As of February 1, 2008, we operate through TE Products, TCTM, TEPPCO Midstream and 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”) holds a 0.001% general partner interest in TCTM and a 0.001% managing member interest in each of TE Products and TEPPCO Midstream.
Through May 6, 2007, our General Partner was owned by DFI GP Holdings L.P. (“DFIGP”), an affiliate of EPCO, Inc. (“EPCO”), a privately held company controlled by Dan L. Duncan. On May 7, 2007, DFIGP sold all of the membership interests in our General Partner, together with 4,400,000 of our Units, to Enterprise GP Holdings L.P. (“Enterprise GP Holdings”), a publicly traded partnership, also controlled indirectly by Dan L. Duncan. Mr. Duncan and certain of his affiliates, including 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. 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 16,691,550 of our Units. Under an amended and restated administrative services agreement (“ASA”), EPCO 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.
Basis of Presentation
The accompanying unaudited condensed consolidated financial statements reflect all adjustments that are, in the opinion of our management, of a normal and recurring nature and necessary for a fair statement of our financial position as of March 31, 2008, and the results of our operations and cash flows for the periods presented. The results of operations for the three months ended March 31, 2008, are not necessarily indicative of results of our operations for the full year 2008. The unaudited condensed consolidated financial statements have been prepared pursuant to the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”). Certain information and note disclosures normally included in annual financial statements prepared in accordance with U.S. generally accepted accounting principals (“GAAP”) have been condensed or omitted pursuant to those rules and regulations.
You should read these interim financial statements in conjunction with our consolidated financial statements and notes thereto presented in the TEPPCO Partners, L.P. Annual Report on Form 10-K for the year ended December 31, 2007.
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 2. GENERAL ACCOUNTING POLICIES AND RELATED MATTERS
We operate and report in four business segments:
Our reportable segments offer different products and services and are managed separately because each requires different business strategies (see Note 13).
Our interstate pipeline 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.”
The preparation of financial statements in conformity with 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.
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. We are subject to the Revised Texas Franchise Tax, enacted by the State of Texas in May 2006. At March 31, 2008 and December 31, 2007, we had current tax liabilities of $2.0 million and $1.2 million, respectively, and deferred tax assets of less than $0.1 million and less than $0.1 million, respectively. During the three months ended March 31, 2008 and 2007, we recorded increases in current income tax liabilities of $0.8 million and $0.7 million, respectively. During the three months ended March 31, 2007, we recorded a $0.6 million reduction to deferred tax liability. 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.
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 12). 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 15).
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.
Recent Accounting Developments
Certain provisions of Statement of Financial Accounting Standards (“SFAS”) No. 157, Fair Value Measurements, became effective for us on January 1, 2008. See Note 5 for information regarding new fair value related disclosures required in connection with SFAS 157.
In March 2008, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities an – amendment of FASB Statement No. 133. SFAS 161 requires enhanced disclosures regarding (i) how and why an entity uses derivative instruments, (ii) how derivative instruments and related hedged items are accounted for under SFAS 133, Accounting for Derivative Instruments and Hedging Activities, and its related interpretations, and (iii) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. SFAS 161 requires disclosure of (i) the fair values of derivative instruments and their gains and losses in a tabular format, (ii) derivative features that are credit risk-related and (iii) cross-referencing within financial statement footnotes to locate important information about derivative instruments. SFAS 161 is effective for us on January 1, 2009. Management is currently evaluating the impact that SFAS 161 will have on our financial statement disclosures. At present, we do not believe that this standard will impact how we record financial instruments.
In March 2008, the Emerging Issues Task Force (“EITF”), reached consensus on EITF Issue No. 07-4, Application of the Two-Class Method under FASB Statement No. 128 to Master Limited Partnerships. This guidance prescribes the manner in which a master limited partnership (“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 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 is effective for us on January 1, 2009. Management is currently evaluating the impact that EITF 07-4 will have on our earnings per unit computations and disclosures.
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. Terminaling revenues are recognized as products are out-loaded. Revenues 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 partners and establishing a margin by selling refined products for physical delivery through spot sales at the Aberdeen truck rack to independent wholesalers and retailers of refined products. These purchases and sales are generally contracted to occur on the same day.
Our Upstream Segment revenues are earned from gathering, transporting, marketing and storing crude oil, and distributing lubrication oils and specialty chemicals 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.
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. Fractionation revenues are recognized ratably over the contract year as products are delivered. We generally do not take title to the natural gas gathered, NGLs transported or NGLs fractionated, with the exception of inventory imbalances. Therefore, the results of our Midstream Segment are not directly affected by changes in the prices of natural gas or NGLs.
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 well-testing and other offshore services. 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 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. 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 and other specified operational fees and costs are directly reimbursed by the customer under most of the contracts.
NOTE 3. ACCOUNTING FOR UNIT-BASED AWARDS
The following table summarizes compensation expense by plan for the three months ended March 31, 2008 and 2007:
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. A total of 31,600 phantom units were outstanding under the 1999 Plan at March 31, 2008. In April 2008, 13,000 phantom units vested resulting in a cash payment of $0.4 million. The remaining awards cliff vest as follows: 13,000 in April 2009 and 5,600 in January 2010. At March 31, 2008 and December 31, 2007, we had accrued liability balances of $1.0 million and $1.0 million, respectively, for compensation related to the 1999 Plan.
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. On December 31, 2007, 8,400 phantom units vested and $0.5 million was paid out to participants in the first quarter of 2008. At March 31, 2008, there were a total of 11,300 phantom units outstanding under the 2000 LTIP that cliff vest on December 31, 2008 and will be paid out to participants in 2009. At March 31, 2008 and December 31, 2007, we had accrued liability balances of $0.2 million and $0.9 million, respectively, related to the 2000 LTIP.
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. 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 March 31, 2008, there were a total of 38,200 phantom units outstanding under the 2005 Phantom Unit Plan that cliff vest on December 31, 2008 and will be paid out to participants in 2009. At March 31, 2008 and December 31, 2007, we had accrued liability balances of $1.0 million and $2.6 million, respectively, for compensation related to the 2005 Phantom Unit Plan.
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. 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 December 8, 2016 or, if earlier, the time which all available Units under the 2006 LTIP have been delivered to participants or the time of termination of the 2006 LTIP by EPCO or the Audit, Conflicts and Governance Committee of the Board of Directors of our General Partner (“ACG Committee”). After giving effect to outstanding unit options and restricted units at March 31, 2008, and the forfeiture of restricted units through March 31, 2008, a total of 4,782,600 additional Units could be issued under the 2006 LTIP in the future.
The information in the following table presents unit option activity under the 2006 LTIP for the periods indicated:
At March 31, 2008, total unrecognized compensation cost related to nonvested unit options granted under the 2006 LTIP was an estimated $0.4 million. We expect to recognize this cost over a weighted-average period of 3.14 years.
The following table summarizes information regarding our restricted units for the periods indicated:
None of our restricted units vested during the three months ended March 31, 2008. At March 31, 2008, total unrecognized compensation cost related to restricted units was $1.9 million, and these costs are expected to be recognized over a weighted-average period of 3.14 years.
Phantom Units and UARs
At March 31, 2008, a total of 1,647 phantom units were outstanding, which have been awarded under the 2006 LTIP to 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. Phantom unit awards to non-executive directors are accounted for similar to SFAS 123(R) liability awards.
At March 31, 2008, a total of 66,225 UARs were outstanding, which have been awarded under the 2006 LTIP at an exercise price of $45.30 per Unit to the non-executive members of the board of directors. The UARs will be 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 similar to SFAS 123(R) liability awards.
At March 31, 2008, a total of 335,723 UARs were outstanding, which have been awarded under the 2006 LTIP at an exercise price of $45.35 per Unit to certain employees providing services directly to us. 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.
NOTE 4. EMPLOYEE BENEFIT PLANS
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 in 2006 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.
As of December 31, 2007, all benefit obligations to 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.
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 14).
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.
Interest Rate Risk Hedging Program
Our interest rate exposure results from variable and fixed interest rate borrowings under various debt agreements. We manage a portion of our interest rate exposure by utilizing interest rate swaps and similar arrangements, 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.
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 three months ended March 31, 2007, we recognized a reduction in interest expense of $0.3 million 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 11).
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 March 31, 2008 and December 31, 2007, the unamortized balance of the deferred gains was $21.9 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.
In October 2006 and February 2007, we entered into treasury lock agreements, accounted for as cash flow hedges, that 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 11). 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 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, that 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 11). 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 $2.8 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 March 31, 2008 and December 31, 2007, we had a limited number of commodity derivatives that were accounted for as cash flow hedges. These contracts will expire during 2008, and any amounts remaining in accumulated other comprehensive income will be recorded in net income. Gains and losses on these derivatives 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 March 31, 2008. In addition, we had some commodity derivatives that did not qualify for hedge accounting. These financial instruments had a minimal impact on our earnings. The fair values of these open positions at March 31, 2008 and December 31, 2007 were liabilities of $15.4 million and $18.9 million, respectively.
Adoption of SFAS 157 – Fair Value Measurements
On January 1, 2008, we adopted the provisions of SFAS No. 157, Fair Value Measurements, that apply to financial assets and liabilities. We will adopt 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 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:
The following table sets forth by level within the fair value hierarchy our financial assets and liabilities measured on a recurring basis at March 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 March 31, 2008, there were no level 1 financial assets and liabilities.
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:
NOTE 6. INVENTORIES
Inventories are valued at the lower of cost (based on weighted average cost method) or market. The costs of inventories did not exceed market values at March 31, 2008 and December 31, 2007. The major components of inventories were as follows:
Due to fluctuating commodity prices in the crude oil, refined products and LPG industries, 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 three months ended March 31, 2008 and 2007, we recognized LCM adjustments of approximately $12 thousand and $0.6 million, respectively.
NOTE 7. PROPERTY, PLANT AND EQUIPMENT
Major categories of property, plant and equipment at March 31, 2008 and December 31, 2007, were as follows:
The following table summarizes our depreciation expense and capitalized interest amounts for the three months ended March 31, 2008 and 2007:
Asset Retirement Obligations
We have conditional asset retirement obligations (“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. At March 31, 2008, we have a $1.3 million liability, which represents the fair values of these conditional AROs. We assigned probabilities for settlement dates and settlement methods for use in an expected present value measurement of fair value and recorded conditional AROs.
The following table presents information regarding our AROs:
Property, plant and equipment at March 31, 2008, includes $0.5 million of asset retirement costs capitalized as an increase in the associated long-lived asset.
NOTE 8. 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 13 for a general discussion of our business segments). The following table presents our investments in unconsolidated affiliates as of March 31, 2008 and December 31, 2007:
The following table summarizes equity earnings by business segment for the three months ended March 31, 2008 and 2007:
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, 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. Our sharing ratio (including the amount of distributions we receive) of Seaway for each of the three months ended March 31, 2008 and 2007 was 40% of revenue and expense (and distributions) and will remain at that level in the future. During the three months ended March 31, 2007, we received distributions from Seaway of $3.8 million. During the three months ended March 31, 2008, Seaway paid no distributions due to its operating cash requirements. During the three months ended March 31, 2008 and 2007, we did not invest any funds in Seaway.
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 three months ended March 31, 2008, we did not invest any funds in Centennial. During the three months ended March 31, 2007, we contributed $6.1 million to Centennial for contractual obligations that were created upon formation of Centennial. TE Products has received no cash distributions from Centennial since its formation.
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. 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 connection with the joint venture arrangement, Jonah is nearing the completion of the Phase V expansion, which is expected to increase the combined system capacity of the Jonah and Pinedale fields from 1.5 billion cubic feet (“Bcf”) per day to approximately 2.35 Bcf per day and to significantly reduce system operating pressures, which is anticipated to lead to increased production rates and ultimate reserve recoveries. The expansion is expected to be completed in the second quarter of 2008. Enterprise Products Partners manages 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, at March 31, 2008, 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 are 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 March 31, 2008, we have reimbursed Enterprise Products Partners $281.1 million ($19.5 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 March 31, 2008 and December 31, 2007, we had payables to Enterprise Products Partners for costs incurred of $7.4 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 increase the combined system capacity of the Jonah and Pinedale fields from 2.35 Bcf per day (upon completion of the Phase V expansion as described above) 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 24-inch and 30-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%.
During the three months ended March 31, 2008 and 2007, we received distributions from Jonah of $37.2 million and $26.1 million, respectively. The 2007 amount included $11.6 million of distributions declared in 2006 and paid during the first quarter of 2007. During the three months ended March 31, 2008 and 2007, we invested $31.8 million and $30.9 million, respectively, in Jonah.
Summarized Financial Information of Unconsolidated Affiliates
Summarized combined income statement data by reporting segment for the three months ended March 31, 2008 and 2007, is presented below (on a 100% basis):
Summarized combined balance sheet information by reporting segment as of March 31, 2008 and December 31, 2007, is presented below:
NOTE 9. ACQUISITIONS AND DISPOSITIONS
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 $444.3 million, which consisted of $256.6 million in cash and 4,854,899 newly issued Units. 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 11).
The following table summarizes the components of total consideration paid or issued in this transaction.
We financed the cash portion of the consideration with borrowings under our term credit agreement (see Note 11). 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, as well as 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 Cenac or related persons sell Units during a specified 30-day window for a per unit price that is less than the market value of such Units (as determined under the purchase agreement) on February 1, 2008, we are obligated to pay the difference in such values to Cenac or such related persons. In addition, 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 preliminary fair values. Such preliminary fair values have been developed using recognized business valuation techniques and are subject to change pending a final valuation analysis. We expect to finalize the purchase price allocation for this transaction during 2008.
The following table summarizes estimated fair values of the assets acquired and liabilities assumed at the date of acquisition.
The $52.9 million preliminary 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 $444.3 million in consideration we paid or issued to complete the Cenac acquisition, $94.6 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 three months ended March 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.
On February 29, 2008, we expanded our Marine Services Segment with the acquisition of marine assets from Horizon Maritime, L.L.C., a privately-held Houston-based company and an affiliate of Mr. Cenac (“Horizon”) 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 we expect to pay $3.8 million upon delivery of the second tow boat (see Note 19). 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, as well as 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 preliminary fair values. Such preliminary fair values have been developed using recognized business valuation techniques and are subject to change pending a final valuation analysis. We expect to finalize the purchase price allocation for this transaction during 2008. The following table summarizes estimated fair values of the assets acquired and liabilities assumed at the date of acquisition.
The $6.8 million preliminary 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 $80.8 million in consideration we paid to complete the acquisition of the Horizon business, $10.1 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 this business and further expanding our Marine Services Segment and complementing two of our core businesses.
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 $157.2 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 Bureau of Competition of the Federal Trade Commission (“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 $59.8 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 effective as of March 1, 2007, TE Products will provide 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 will be 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 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.
NOTE 10. INTANGIBLE ASSETS AND GOODWILL
The following table summarizes our intangible assets, including excess investments, being amortized at March 31, 2008 and December 31, 2007:
The following table presents the amortization expense of our intangible assets by segment for the three months ended March 31, 2008 and 2007: