EXHIBIT 99.4
ENTERPRISE PRODUCTS PARTNERS L.P.
RECAST OF CERTAIN SECTIONS OF THE QUARTERLY REPORT ON FORM 10-Q
FOR THE QUARTERLY PERIOD ENDING SEPTEMBER 30, 2009
TABLE OF CONTENTS
| Page No. | ||
| PART I. FINANCIAL INFORMATION. | ||
| Item 2. | Management’s Discussion and Analysis of Financial Condition | |
| and Results of Operations. | 2 | |
| Item 3. | Quantitative and Qualitative Disclosures about Market Risk. | 28 |
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Recast of Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations.
For the three and nine months ended September 30, 2009 and 2008.
The following information should be read in conjunction with our unaudited supplemental condensed consolidated financial statements and accompanying notes included in this Current Report on Form 8-K under Exhibit 99.3. In addition, the following information and such unaudited condensed consolidated financial statements should also be read in conjunction with the audited financial statements and related notes, together with our discussion and analysis of financial position and results of operations included in this Current Report on Form 8-K under Exhibits 99.1 and 99.2.
Our financial statements have been prepared in accordance with U.S. generally accepted accounting principles (“GAAP”).
Key References Used in this Report
Enterprise Products Partners L.P. is a publicly traded Delaware limited partnership, the common units of which are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “EPD.” Unless the context requires otherwise, references to “we,” “us,” “our,” or “Enterprise Products Partners” are intended to mean the business and operations of Enterprise Products Partners L.P. and its consolidated subsidiaries, which now includes TEPPCO Partners, L.P. and its general partner.
References to “EPO” mean Enterprise Products Operating LLC, which is a wholly owned subsidiary of Enterprise Products Partners through which Enterprise Products Partners conducts substantially all of its business.
References to “Duncan Energy Partners” mean Duncan Energy Partners L.P., which is a consolidated subsidiary of EPO and a publicly traded Delaware limited partnership, the common units of which are listed on the NYSE under the ticker symbol “DEP.” References to “DEP GP” mean DEP Holdings, LLC, which is the general partner of Duncan Energy Partners and is wholly owned by EPO.
References to “EPGP” mean Enterprise Products GP, LLC, which is our general partner.
References to “Enterprise GP Holdings” mean Enterprise GP Holdings L.P., a publicly traded limited partnership, the units of which are listed on the NYSE under the ticker symbol “EPE.” Enterprise GP Holdings owns EPGP. References to “EPE Holdings” mean EPE Holdings, LLC, which is the general partner of Enterprise GP Holdings.
References to “TEPPCO” and “TEPPCO GP” mean TEPPCO Partners, L.P. and Texas Eastern Products Pipeline Company, LLC (which is the general partner of TEPPCO) prior to their mergers with our subsidiaries. On October 26, 2009, we completed our merger with TEPPCO and TEPPCO GP (such related mergers referred to herein individually and together as the “TEPPCO Merger”). For additional information regarding the TEPPCO Merger, see “Recent Developments” included within this Item 2.
References to “Energy Transfer Equity” mean the business and operations of Energy Transfer Equity, L.P. and its consolidated subsidiaries, which include Energy Transfer Partners, L.P. Energy Transfer Equity is a publicly traded Delaware limited partnership, the common units of which are listed on the NYSE under the ticker symbol “ETE.” The general partner of Energy Transfer Equity is LE GP, LLC (“LE GP”). Enterprise GP Holdings owns a noncontrolling interest in both LE GP and Energy Transfer Equity. Enterprise GP Holdings accounts for its investments in LE GP and Energy Transfer Equity using the equity method of accounting.
References to “EPCO” mean EPCO, Inc. and its wholly owned, privately held affiliates, which are related parties to all of the foregoing named entities.
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We, EPO, Duncan Energy Partners, DEP GP, EPGP, Enterprise GP Holdings, EPE Holdings, TEPPCO and TEPPCO GP are affiliates under the common control of Dan L. Duncan, the Group Co-Chairman and controlling shareholder of EPCO.
As generally used in the energy industry and in this discussion, the identified terms have the following meanings:
| /d | = per day |
| BBtus | = billion British thermal units |
| MBPD | = thousand barrels per day |
| MMBbls | = million barrels |
| MMBtus | = million British thermal units |
| MMcf | = million cubic feet |
| Bcf | = billion cubic feet |
Cautionary Note Regarding Forward-Looking Statements
This discussion contains various forward-looking statements and information that are based on our beliefs and those of our general partner, as well as assumptions made by us and information currently available to us. When used in this document, words such as “anticipate,” “project,” “expect,” “plan,” “seek,” “goal,” “estimate,” “forecast,” “intend,” “could,” “should,” “will,” “believe,” “may,” “potential” and similar expressions and statements regarding our plans and objectives for future operations, are intended to identify forward-looking statements. Although we and our general partner believe that such expectations reflected in such forward-looking statements are reasonable, neither we nor our general partner can give any assurances that such expectations will prove to be correct. Such statements are subject to a variety of risks, uncertainties and assumptions as described in more detail in Item 1A “Risk Factors” included under Exhibit 99.1 of this Current Report on Form 8-K. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. You should not put undue reliance on any forward-looking statements. Except as required by federal and state securities laws, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or any other reason.
Critical Accounting Policies and Estimates
A summary of the significant accounting policies we have adopted and followed in the preparation of our supplemental consolidated financial statements is included under Exhibit 99.1 of this Current Report on Form 8-K. Certain of these accounting policies require the use of estimates. As more fully described therein, the following estimates, in our opinion, are subjective in nature, require the exercise of judgment and involve complex analysis: depreciation methods and estimated useful lives of property, plant and equipment; measuring recoverability of long-lived assets and equity method investments; amortization methods and estimated useful lives of qualifying intangible assets; methods we employ to measure the fair value of goodwill; revenue recognition policies and use of estimates for revenues and expenses; reserves for environmental matters; and natural gas imbalances. These estimates are based on our current knowledge and understanding and may change as a result of actions we may take in the future. Changes in these estimates will occur as a result of the passage of time and the occurrence of future events. Subsequent changes in these estimates may have a significant impact on our financial position, results of operations and cash flows.
Overview of Business
We are a North American midstream energy company providing a wide range of services to producers and consumers of natural gas, natural gas liquids (“NGLs”), crude oil, refined products and certain petrochemicals. Our midstream energy asset network links producers of natural gas, NGLs and crude oil from some of the largest supply basins in the United States, Canada and the Gulf of Mexico with domestic consumers and international markets. In addition, we are an industry leader in the development
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of pipeline and other midstream energy infrastructure in the continental United States and Gulf of Mexico. We are a publicly traded Delaware limited partnership formed in 1998, the common units of which are listed on the NYSE under the ticker symbol “EPD.”
In connection with the TEPPCO Merger, we revised our business segments. Our reorganized business segments reflect the manner in which these businesses are managed and reviewed by the chief executive officer of our general partner. Under our new business segment structure, we have five reportable business segments: NGL Pipelines & Services; Onshore Natural Gas Pipelines & Services; Onshore Crude Oil Pipelines & Services; Offshore Pipelines & Services; and Petrochemical & Refined Products Services. Our business segments are generally organized and managed according to the type of services rendered (or technologies employed) and products produced and/or sold.
We conduct substantially all of our business through EPO. We are owned 98% by our limited partners and 2% by our general partner, EPGP. EPGP is owned 100% by Enterprise GP Holdings.
Basis of Presentation
Since Enterprise Products Partners, TEPPCO and TEPPCO GP are under common control of Mr. Duncan, the TEPPCO Merger was accounted for at historical costs as a reorganization of entities under common control in a manner similar to a pooling of interests. The inclusion of TEPPCO and TEPPCO GP in our supplemental consolidated financial statements was effective January 1, 2005 because an affiliate of EPCO under common control with Enterprise Products Partners originally acquired ownership interests in TEPPCO GP in February 2005.
Our consolidated financial statements prior to the TEPPCO Merger reflect the combined financial information of Enterprise Products Partners, TEPPCO and TEPPCO GP on a 100% basis. Third party and related party ownership interests in TEPPCO and TEPPCO GP prior to the merger have been reflected as “Former owners of TEPPCO” a component of noncontrolling interest.
The financial statements of TEPPCO and TEPPCO GP were prepared from the separate accounting records maintained by TEPPCO and TEPPCO GP. All intercompany balances and transactions have been eliminated in consolidation.
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As previously noted, the TEPPCO Merger was accounted for as a reorganization of entities under common control. The following information is provided to reconcile total revenues and total gross operating margin for the three and nine months ended September 30, 2009 and 2008, as currently presented with those we previously presented. There was no change in net income attributable to Enterprise Products Partners L.P. for such periods since net income attributable to TEPPCO and TEPPCO GP was allocated to noncontrolling interests. Additionally, there was no change in our reported earnings per unit for such periods. See “Other Items” included within this Item 2 for information regarding total segment gross operating margin, which is a non-generally accepted account principle (“non-GAAP”) financial measure of segment performance.
| For the Three Months | For the Nine Months | |||||||||||||||
| Ended September 30, | Ended September 30, | |||||||||||||||
| 2009 | 2008 | 2009 | 2008 | |||||||||||||
| Total revenues, as previously reported | $ | 4,596.1 | $ | 6,297.9 | $ | 11,527.1 | $ | 18,322.1 | ||||||||
| Revenues from TEPPCO | 2,205.3 | 4,205.7 | 5,576.1 | 11,194.7 | ||||||||||||
| Revenues from Jonah Gas Gathering Company (“Jonah”) (1) | 60.2 | 58.7 | 180.8 | 177.0 | ||||||||||||
| Eliminations (2) | (72.2 | ) | (63.2 | ) | (173.4 | ) | (149.7 | ) | ||||||||
| Total revenues, as currently reported | $ | 6,789.4 | $ | 10,499.1 | $ | 17,110.6 | $ | 29,544.1 | ||||||||
| Total segment gross operating margin, as previously reported | $ | 560.9 | $ | 478.9 | $ | 1,618.8 | $ | 1,535.5 | ||||||||
| Gross operating margin from TEPPCO | 62.5 | 122.9 | 309.9 | 379.7 | ||||||||||||
| Gross operating margin from Jonah | 46.6 | 40.7 | 137.8 | 121.9 | ||||||||||||
| Eliminations (3) | (31.3 | ) | (26.9 | ) | (91.6 | ) | (79.5 | ) | ||||||||
| Total segment gross operating margin, as currently reported | $ | 638.7 | $ | 615.6 | $ | 1,974.9 | $ | 1,957.6 | ||||||||
(1) Prior to the TEPPCO Merger, we and TEPPCO were joint venture partners in Jonah. As a result of the TEPPCO Merger, Jonah became a consolidated subsidiary. (2) Represents the eliminations of revenues between us, TEPPCO and Jonah. (3) Represents equity earnings from Jonah recorded by us and TEPPCO prior to the merger. | ||||||||||||||||
Recent Developments
The following information highlights our significant developments since January 1, 2009 through November 9, 2009 (the original filing date of our Quarterly Report on Form 10-Q for the nine months ended September 30, 2009).
Merger of TEPPCO and TEPPCO GP with Enterprise Products Partners
On October 26, 2009, the related mergers of our wholly owned subsidiaries with TEPPCO and TEPPGO GP were completed. Under terms of the merger agreements, TEPPCO and TEPPCO GP became wholly owned subsidiaries of ours and each of TEPPCO's unitholders, except for a privately held affiliate of EPCO, were entitled to receive 1.24 of our common units for each TEPPCO unit. In total, we issued an aggregate of 126,932,318 common units and 4,520,431 Class B units (described below) as consideration in the TEPPCO Merger for both TEPPCO units and the TEPPCO GP membership interests. TEPPCO’s units, which had been trading on the NYSE under the ticker symbol TPP, have been delisted and are no longer publicly traded.
A privately held affiliate of EPCO exchanged a portion of its TEPPCO units, based on the 1.24 exchange rate, for 4,520,431 of our Class B units in lieu of common units. The Class B units are not entitled to regular quarterly cash distributions for the first sixteen quarters following the closing date of the merger. The Class B units automatically convert into the same number of common units on the date immediately following the payment date for the sixteenth quarterly distribution following the closing date of the merger. The Class B units are entitled to vote together with the common units as a single class on partnership matters and, except for the payment of distributions, have the same rights and privileges as our common units.
Under the terms of the TEPPCO Merger agreements, Enterprise GP Holdings received 1,331,681 of our common units and an increase in the capital account of EPGP to maintain its 2% general partner
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interest in us as consideration for 100% of the membership interests of TEPPCO GP. Following the closing of the TEPPCO Merger, affiliates of EPCO owned approximately 31.3% of our outstanding limited partner units, including 3.4% owned by Enterprise GP Holdings.
The post-merger partnership, which retains the name Enterprise Products Partners L.P., accesses the largest producing basins of natural gas, NGLs and crude oil in the U.S., and serves some of the largest consuming regions for natural gas, NGLs, refined products, crude oil and petrochemicals. The post-merger partnership owns almost 48,000 miles of pipelines comprised of over 22,000 miles of NGL, refined product and petrochemical pipelines, over 20,000 miles of natural gas pipelines and more than 5,000 miles of crude oil pipelines. The merged partnership’s logistical assets include approximately 200 MMBbls of NGL, refined product and crude oil storage capacity; 27 Bcf of natural gas storage capacity; one of the largest NGL import/export terminals in the U.S., located on the Houston Ship Channel; 60 NGL, refined product and chemical terminals spanning the U.S. from the west coast to the east coast; and crude oil import terminals on the Texas Gulf Coast. The post-merger partnership owns interests in 17 fractionation plants with over 600 MBPD of net capacity; 25 natural gas processing plants with a net capacity of approximately 9 Bcf/d; and 3 butane isomerization facilities with a capacity of 116 MBPD. The post-merger partnership is also one of the largest inland tank barge companies in the U.S.
The merger transactions will be accounted for as a reorganization of entities under common control in a manner similar to a pooling of interests. The financial and operating activities of Enterprise Products Partners, TEPPCO and Enterprise GP Holdings and their respective general partners, and EPCO and its privately held subsidiaries, are under the common control of Dan L. Duncan. See Note 18 of the Notes to Unaudited Supplemental Condensed Consolidated Financial Statements included under Exhibit 99.3 of this Current Report on Form 8-K for selected financial information, including selected unaudited pro forma data, related to the merger.
In connection with the TEPPCO Merger, EPO commenced offers in September 2009 to exchange all of TEPPCO’s outstanding notes (a combined principal amount of $2 billion) for a corresponding series of new EPO notes. The purpose of the exchange offer was to simplify our capital structure following the TEPPCO Merger. The exchanges were completed on October 27, 2009. The new EPO notes are guaranteed by Enterprise Products Partners L.P. The EPO notes issued in the exchange will be recorded at the same carrying value as the TEPPCO notes being replaced. Accordingly, we will recognize no gain or loss for accounting purposes related to this exchange. All note exchange direct costs paid to third parties will be expensed. In addition to the debt exchange, we gained approval from the requisite TEPPCO noteholders to eliminate substantially all of the restrictive covenants and reporting requirements associated with the remaining TEPPCO notes. Upon the consummation of the TEPPCO Merger, EPO repaid and terminated indebtedness under TEPPCO’s revolving credit facility.
Enterprise Products Partners and Duncan Energy Partners Announce Extension of
Acadian Gas System into Haynesville Shale Play
In October 2009, we and our affiliate, Duncan Energy Partners, announced plans for our jointly owned Acadian Gas System to extend its Louisiana intrastate natural gas pipeline system into Northwest Louisiana to provide producers in the rapidly expanding Haynesville Shale resource basin with access to additional markets through connections with the Acadian Gas System in South Louisiana and nine major interstate natural gas pipelines (“Haynesville Extension”). The Haynesville Shale covers about 2 million acres in Northwest Louisiana, almost all of which is under lease. Production from the approximately 200 wells drilled to date is estimated at more than 1 Bcf/d. Over 400 locations are in various stages of drilling and completion with approximately 150 rigs now working in the region.
As currently designed, our Haynesville Extension pipeline project will have the capacity to transport up to 1.4 Bcf/d of natural gas from the Haynesville area through a 249-mile pipeline that will connect with our existing Acadian Gas System. Subject to additional long-term commitments received before pipe orders are placed, the capacity of the Haynesville Extension could be increased to 2.0 Bcf/d. The pipeline is expected to be in service in September 2011.
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The Acadian Gas System serves major natural gas markets along the Mississippi River corridor between Baton Rouge and New Orleans and has the ability to make physical deliveries into the Henry Hub. The Haynesville Extension will also have interconnects with major interstate pipelines include Florida Gas, Texas Eastern, Transco, Sonat, Columbia Gulf, Trunkline, ANR, Tennessee Gas and Texas Gas. Together with the capacity of the existing Acadian Gas System, the extension project will provide approximately 5.5 Bcf/d of redelivery capacity into an estimated 12 Bcf/d of available downstream pipeline takeaway capacity. Initially, the project will connect to nine Haynesville Shale producer locations in DeSoto and Red River parishes.
Along with providing much needed natural gas takeaway capacity for growing Haynesville production, the new pipeline is expected to provide shippers the opportunity to benefit from more favorable pricing points and diverse service options and access to the South Louisiana marketplace. For producers, the more flexible contracting options associated with an intrastate pipeline environment would help facilitate a seamless transaction for the producer from the field to the end user.
Currently, Duncan Energy Partners owns a 66% equity interest in the entities that own the Acadian Gas System, with EPO owning the remaining 34% equity interests. Duncan Energy Partners and EPO are in discussions as to the funding of the Haynesville Extension project.
EPO Issues $1.1 Billion of Senior Notes
In October 2009, EPO issued $500.0 million in principal amount of 5.25% fixed-rate, unsecured senior notes due January 2020 (“Senior Notes Q”) and $600.0 million in principal amount of 6.125% fixed-rate, unsecured senior notes due October 2039 (“Senior Notes R”). Net proceeds from this offering were used (i) to repay $500.0 million in aggregate principal amount of senior notes that matured in October 2009 (“Senior Notes F”), (ii) to temporarily reduce borrowings outstanding under EPO’s Multi-Year Revolving Credit Facility and (iii) for general partnership purposes. For additional information regarding these issuances of debt, see Note 19 of the Notes to Unaudited Supplemental Condensed Consolidated Financial Statements included under Exhibit 99.3 of this Current Report on Form 8-K.
Enterprise Products Partners Issues $226.4 million of Common Units
In September 2009, we issued 8,337,500 common units (including an overallotment amount of 1,087,500 common units) in an underwritten public offering at a price of $28.00 per unit. We used the combined net offering proceeds of $226.4 million to reduce borrowings outstanding under EPO’s Multi-Year Revolving Credit Facility and for general partnership purposes.
Enterprise Products Partners to Provide Natural Gas Transportation and Processing Services
for Major Eagle Ford Shale Producer
In September 2009, we announced that we had entered into a long-term agreement to provide natural gas transportation and processing services on dedicated acreage owned by one of the largest and most active producers in the developing Eagle Ford Shale natural gas play in South Texas. The agreement covers more than 150,000 acres in the heart of the Eagle Ford Shale natural gas play. Stretching from the Mexico border along the Gulf Coast to near Louisiana, the Eagle Ford Shale production area covers more than 10 million acres in Texas and lies beneath or near our existing natural gas and NGL asset infrastructure in the region.
Enterprise Products Partners Enters into Agreement for $150.0 Million
Private Placement of Common Units
On September 4, 2009, we agreed to issue 5,940,594 common units in a private placement to EPCO Holdings, Inc., a privately held affiliate controlled by Dan L. Duncan, for approximately $150.0 million, or $25.25 per unit. In accordance with the terms of the private placement, as approved by the Audit, Conflicts and Governance Committee of EPGP’s Board of Directors on September 1, 2009, the per
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unit purchase price of $25.25 was calculated based on a five percent discount to the five-day volume weighted average price (“5-Day VWAP”) of our common units, as reported by the NYSE at the close of business on September 4, 2009. The 5-Day VWAP was based on (i) the closing price for the common units on the NYSE for each of the trading days in such five-day period and (ii) the total trading volume for the common units reported by the NYSE for each such trading day. We used the net proceeds from this private placement to temporarily reduce borrowings outstanding under EPO’s Multi-Year Revolving Credit Facility and for other general partnership purposes. The common units were issued on September 8, 2009.
Enterprise Products Partners Announces Expansion of NGL Fractionation Capacity at
Mont Belvieu, Texas Complex
In August 2009, we announced plans to build a new 75 MBPD NGL fractionator at our Mont Belvieu, Texas complex that will provide us with additional capacity to handle growing NGL volumes from producing areas in the Rockies, the Barnett Shale and the emerging Eagle Ford Shale play in South Texas. This expansion, which is supported by long-term contracts, will be based on the design of our 75 MBPD Hobbs fractionator in Gaines County, Texas that began service in August 2007. When completed, the project will increase our NGL fractionation capacity at Mont Belvieu to approximately 300 MBPD and net system-wide capacity to approximately 600 MBPD. The project is expected to be completed in the first quarter of 2011.
Duncan Energy Partners’ Equity Offering
In June 2009, Duncan Energy Partners completed an offering of 8,000,000 of its common units, which generated net proceeds of approximately $122.9 million. In July 2009, the underwriters to this offering exercised their option to purchase an additional 943,400 common units, which generated $14.5 million of additional net proceeds for Duncan Energy Partners. Duncan Energy Partners used the aggregate net proceeds from this offering to repurchase an equal number of its common units that were beneficially owned by EPO. Duncan Energy Partners subsequently cancelled the common units it repurchased from EPO.
Jicarilla Apache Nation and Enterprise Products Partners Announce
Long-Term Right-of-Way Agreement
In June 2009, the Jicarilla Apache Nation and an affiliate of ours announced they had signed a 20-year right-of-way agreement that will allow us to continue our natural gas gathering operations on the Nation’s reservation lands in Northwest New Mexico. Under the terms of the agreement, we will continue to own and operate existing infrastructure and related assets located on tribal land, including 545 miles of gathering lines connected to our San Juan Gathering system that have current throughput in excess of 30 MMcf/d of natural gas.
EPO Issues $500.0 Million of Senior Notes
In June 2009, EPO issued $500.0 million in principal amount of 4.60% fixed-rate, unsecured senior notes due August 2012 (“Senior Notes P”). Net proceeds from this offering were used (i) to repay the $200.0 Million Term Loan, (ii) to temporarily reduce borrowings outstanding under EPO’s Multi-Year Revolving Credit Facility and (iii) for general partnership purposes. For additional information regarding this issuance of debt, see Note 10 of the Notes to Unaudited Supplemental Condensed Consolidated Financial Statements included under Exhibit 99.3 of this Current Report on Form 8-K.
Acquisition of Marine Assets; Termination of Transitional Operating Agreement
In June 2009, TEPPCO acquired 19 tow boats and 28 tank barges from TransMontaigne Product Services Inc. (“TransMontaigne”) for $50.0 million in cash. The acquired assets provide marine vessel fueling services (referred to as bunkering) for cruise liners and cargo ships and other ship-assist services and transport fuel oil for electric generation plants. The acquisition complements TEPPCO’s existing fleet of marine vessels, which transport petroleum products along the nation’s inland waterway system and in
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the Gulf of Mexico. In general, the newly acquired marine assets are supported by contracts that have a three to five year term and are based primarily in Miami, Florida, with additional assets located in Mobile, Alabama, and Houston, Texas. See Note 8 of the Notes to Unaudited Supplemental Condensed Consolidated Financial Statements included under Exhibit 99.3 of this Current Report on Form 8-K for additional information regarding this business combination.
Effective August 1, 2009, personnel providing services to TEPPCO under a transitional operating agreement with Cenac Towing Co., L.L.C., Cenac Offshore, L.L.C. and Mr. Arlen B. Cenac, Jr. (collectively, “Cenac”) became employees of EPCO. The transitional operating agreement was then terminated. Concurrently with the termination, our marine services business entered into a two-year consulting agreement with Mr. Cenac and Cenac Marine Services, L.L.C. under which Mr. Cenac has agreed to supervise our marine services business’ day-to-day operations on a part-time basis and, at our marine services business’ request, provide related management and transitional services. The agreement entitles Mr. Cenac to $500,000 per year in fees, plus a one-time retainer of $200,000. The consulting agreement contains noncompetition and nonsolitation provisions similar to those contained in the transitional operating agreement, which apply until the expiration of the two-year period following the date of last service provided under the consulting agreement.
Enterprise Products Partners and TEPPCO Exit Texas Offshore Port System Partnership
In August 2008, our wholly owned subsidiaries together with Oiltanking Holding Americas, Inc. (“Oiltanking”) formed the Texas Offshore Port System partnership (“TOPS”). Effective April 16, 2009, our wholly owned subsidiaries dissociated (exited) from TOPS. As a result, operating costs and expenses and net income for the nine months ended September 30, 2009 reflect a non-cash charge of $68.4 million. This loss represented the forfeiture of our cumulative investment in TOPS through the date of dissociation and reflected our capital contributions to TOPS for construction in progress amounts. On September 17, 2009, we entered into a settlement agreement with certain affiliates of Oiltanking that resolved all disputes between the parties related to the business and affairs of the TOPS project. We recognized approximately $66.9 million of expense during the third quarter of 2009 in connection with the payment of this cash settlement.
Service Begins on Shenzi Crude Oil Export Pipeline
In April 2009, we announced that construction of our crude oil pipeline serving the Shenzi field in the Gulf of Mexico had been completed and is now transporting production from the deepwater discovery. The 83-mile pipeline has a transportation capacity of 230 MBPD of crude oil and gives Shenzi producers access to the Cameron Highway Oil Pipeline and Poseidon Oil Pipeline systems, in which we have ownership interests and operate.
Service Begins on Sherman Extension Pipeline
In late February 2009, we and Duncan Energy Partners announced that construction had been completed on the 174-mile Sherman Extension expansion of our Texas Intrastate System, which extends through the heart of the prolific Barnett Shale natural gas play of North Texas. The completion of the Sherman Extension adds 1.1 Bcf/d of incremental natural gas takeaway capacity from the region, while providing producers in the Barnett Shale, and as far away as the Waha area of West Texas, with greater flexibility to reach the most attractive natural gas markets. The Texas Intrastate System is part of our Onshore Natural Gas Pipelines & Services business segment.
Initially, the Sherman Extension was in very limited service due to pipeline integrity issues on the connecting third party take-away pipeline, the Gulf Crossing Pipeline owned by Boardwalk Pipeline Partners, LP (“Boardwalk”). The Gulf Crossing Pipeline began ramping up its operations on August 1, 2009. As a result, the Sherman Extension started billing its demand charges at 95% of contracted volumes, which are 950 MMcf/d. Effective September 1, 2009, the Sherman Extension started billing demand charges at 100% of contracted volumes irrespective of actual transportation volumes. We are currently flowing approximately 700 MMcf/d. The demand charges are approximately $5.0 million a month.
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Review of Consolidated Results
We have five reportable business segments: NGL Pipelines & Services, Onshore Natural Gas Pipelines & Services, Onshore Crude Oil Pipelines & Services, Offshore Pipelines & Services and Petrochemical & Refined Products Services. Our business segments are generally organized and managed according to the type of services rendered (or technologies employed) and products produced and/or sold. For additional information regarding our business segments, see Note 12 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Exhibit 99.3 of this Current Report on Form 8-K.
Selected Price and Volumetric Data
The following table illustrates selected annual and quarterly industry index prices for natural gas, crude oil and selected NGL and petrochemical products for the periods presented:
| Polymer | Refinery | |||||||||||||||||||||||||||||||||||
| Natural | NYMEX | Normal | Natural | Grade | Grade | |||||||||||||||||||||||||||||||
| Gas, | Crude Oil, | Ethane, | Propane, | Butane, | Isobutane, | Gasoline, | Propylene, | Propylene, | ||||||||||||||||||||||||||||
| $/MMBtus | $/barrel | $/gallon | $/gallon | $/gallon | $/gallon | $/gallon | $/pound | $/pound | ||||||||||||||||||||||||||||
| (1) | (2) | (1) | (1) | (1) | (1) | (1) | (1) | (1) | ||||||||||||||||||||||||||||
| 2008 | ||||||||||||||||||||||||||||||||||||
| 1st Quarter | $ | 8.03 | $ | 97.82 | $ | 1.01 | $ | 1.47 | $ | 1.80 | $ | 1.87 | $ | 2.12 | $ | 0.61 | $ | 0.54 | ||||||||||||||||||
| 2nd Quarter | $ | 10.94 | $ | 123.80 | $ | 1.05 | $ | 1.70 | $ | 2.05 | $ | 2.08 | $ | 2.64 | $ | 0.70 | $ | 0.67 | ||||||||||||||||||
| 3rd Quarter | $ | 10.25 | $ | 118.22 | $ | 1.09 | $ | 1.68 | $ | 1.97 | $ | 1.99 | $ | 2.52 | $ | 0.78 | $ | 0.66 | ||||||||||||||||||
| 4th Quarter | $ | 6.95 | $ | 59.08 | $ | 0.42 | $ | 0.80 | $ | 0.90 | $ | 0.96 | $ | 1.09 | $ | 0.37 | $ | 0.22 | ||||||||||||||||||
| 2008 Averages | $ | 9.04 | $ | 99.73 | $ | 0.89 | $ | 1.41 | $ | 1.68 | $ | 1.72 | $ | 2.09 | $ | 0.62 | $ | 0.52 | ||||||||||||||||||
| 2009 | ||||||||||||||||||||||||||||||||||||
| 1st Quarter | $ | 4.91 | $ | 43.31 | $ | 0.36 | $ | 0.68 | $ | 0.87 | $ | 0.97 | $ | 0.96 | $ | 0.26 | $ | 0.20 | ||||||||||||||||||
| 2nd Quarter | $ | 3.51 | $ | 59.79 | $ | 0.43 | $ | 0.73 | $ | 0.93 | $ | 1.11 | $ | 1.21 | $ | 0.34 | $ | 0.28 | ||||||||||||||||||
| 3rd Quarter | $ | 3.39 | $ | 68.24 | $ | 0.47 | $ | 0.87 | $ | 1.12 | $ | 1.19 | $ | 1.42 | $ | 0.48 | $ | 0.43 | ||||||||||||||||||
| 2009 Averages | $ | 3.93 | $ | 57.11 | $ | 0.42 | $ | 0.76 | $ | 0.97 | $ | 1.09 | $ | 1.20 | $ | 0.36 | $ | 0.30 | ||||||||||||||||||
(1) Natural gas, NGL, polymer grade propylene and refinery grade propylene prices represent an average of various commercial index prices including Oil Price Information Service (“OPIS”) and Chemical Market Associates, Inc. (“CMAI”). Natural gas price is representative of Henry-Hub I-FERC. NGL prices are representative of Mont Belvieu Non-TET pricing. Refinery grade propylene represents a weighted-average of CMAI spot prices. Polymer-grade propylene represents average CMAI contract pricing. (2) Crude oil price is representative of an index price for West Texas Intermediate as measured on the New York Mercantile Exchange (“NYMEX”). | ||||||||||||||||||||||||||||||||||||
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The following table presents our material average throughput, production and processing volumetric data. These statistics are reported on a net basis, taking into account our ownership interests in certain joint ventures and reflect the periods in which we owned an interest in such operations. Our operating statistics include volumes for newly constructed assets since the dates such assets were placed into service and for recently purchased assets since the date of acquisition.
| For the Three Months | For the Nine Months | |||||||||||||||
| Ended September 30, | Ended September 30, | |||||||||||||||
| 2009 | 2008 | 2009 | 2008 | |||||||||||||
| NGL Pipelines & Services, net: | ||||||||||||||||
| NGL transportation volumes (MBPD) | 2,179 | 1,944 | 2,098 | 1,991 | ||||||||||||
| NGL fractionation volumes (MBPD) | 467 | 424 | 456 | 436 | ||||||||||||
| Equity NGL production (MBPD) | 116 | 109 | 116 | 108 | ||||||||||||
| Fee-based natural gas processing (MMcf/d) | 2,247 | 2,064 | 2,685 | 2,469 | ||||||||||||
| Onshore Natural Gas Pipelines & Services, net: | ||||||||||||||||
| Natural gas transportation volumes (BBtus/d) | 10,495 | 9,766 | 10,502 | 9,422 | ||||||||||||
| Onshore Crude Oil Pipelines & Services, net: | ||||||||||||||||
| Crude oil transportation volumes (MBPD) | 654 | 618 | 683 | 690 | ||||||||||||
| Offshore Pipelines & Services, net: | ||||||||||||||||
| Natural gas transportation volumes (BBtus/d) | 1,374 | 1,244 | 1,458 | 1,449 | ||||||||||||
| Crude oil transportation volumes (MBPD) | 369 | 147 | 278 | 190 | ||||||||||||
| Platform natural gas processing (MMcf/d) | 694 | 583 | 741 | 588 | ||||||||||||
| Platform crude oil processing (MBPD) | 17 | 14 | 10 | 19 | ||||||||||||
| Petrochemical & Refined Products Services, net: | ||||||||||||||||
| Butane isomerization volumes (MBPD) | 104 | 71 | 98 | 85 | ||||||||||||
| Propylene fractionation volumes (MBPD) | 67 | 58 | 67 | 59 | ||||||||||||
| Octane enhancement production volumes (MBPD) | 13 | 8 | 9 | 9 | ||||||||||||
Transportation volumes, primarily petrochemicals and refined products (MBPD) | 762 | 761 | 797 | 815 | ||||||||||||
| Total transportation volumes, net: | ||||||||||||||||
NGL, crude oil, petrochemical and refined products transportation volumes (MBPD) | 3,964 | 3,470 | 3,856 | 3,686 | ||||||||||||
| Natural gas transportation volumes (BBtus/d) | 11,869 | 11,010 | 11,960 | 10,871 | ||||||||||||
| Equivalent transportation volumes (MBPD) (1) | 7,087 | 6,367 | 7,003 | 6,547 | ||||||||||||
| (1) Reflects equivalent energy volumes where 3.8 MMBtus of natural gas are equivalent to one barrel of NGLs. | ||||||||||||||||
Comparison of Consolidated Results of Operations
The following table summarizes key components of our consolidated income statement for the periods indicated (dollars in millions):
| For the Three Months | For the Nine Months | |||||||||||||||
| Ended September 30, | Ended September 30, | |||||||||||||||
| 2009 | 2008 | 2009 | 2008 | |||||||||||||
| Revenues | $ | 6,789.4 | $ | 10,499.1 | $ | 17,110.6 | $ | 29,544.1 | ||||||||
| Operating costs and expenses | 6,395.8 | 10,074.3 | 15,796.9 | 28,150.2 | ||||||||||||
| General and administrative costs | 52.3 | 33.9 | 133.3 | 100.4 | ||||||||||||
| Equity in income of unconsolidated affiliates | 15.0 | 10.1 | 32.0 | 31.8 | ||||||||||||
| Operating income | 356.3 | 401.0 | 1,212.4 | 1,325.3 | ||||||||||||
| Interest expense | 161.0 | 137.0 | 472.0 | 396.3 | ||||||||||||
| Provision for income taxes | 7.7 | 7.7 | 26.8 | 20.1 | ||||||||||||
| Net income | 187.8 | 258.1 | 715.8 | 914.1 | ||||||||||||
| Net income (loss) attributable to noncontrolling interest | (25.1 | ) | 55.0 | 91.0 | 188.1 | |||||||||||
| Net income attributable to Enterprise Products Partners L.P. | 212.9 | 203.1 | 624.8 | 726.0 | ||||||||||||
Effective January 1, 2009, we adopted new accounting guidance that has been codified under ASC 810, which established accounting and reporting standards for noncontrolling interests, which were previously identified as minority interest in our financial statements. The new guidance requires, among other things, that (i) noncontrolling interests be presented as a component of equity on our consolidated balance sheet (i.e., elimination of the “mezzanine” presentation previously used for minority interest); (ii) minority interest amounts be eliminated as a deduction in deriving net income or loss and, as a result, that
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net income or loss be allocated between controlling and noncontrolling interests; and (iii) comprehensive income or loss to be allocated between controlling and noncontrolling interest. Earnings per unit amounts are not affected by these changes. See Note 2 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Exhibit 99.3 of this Current Report on Form 8-K for additional information regarding the establishment of the ASC by the Financial Accounting Standards Board (“FASB”). See Note 11 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Exhibit 99.3 of this Current Report on Form 8-K for additional information regarding noncontrolling interest.
The new presentation and disclosure requirements pertaining to noncontrolling interests have been applied retroactively to the consolidated financial information presented within Exhibits 99.3 and 99.4. As a result, net income reported for the three and nine months ended September 30, 2008 in these financial statements is higher than that disclosed previously; however, the allocation of such net income results in our unitholders, general partner and noncontrolling interests (i.e., the former minority interest) receiving the same amounts as they did previously.
We evaluate segment performance based on the non-GAAP financial measure of gross operating margin. Gross operating margin (either in total or by individual segment) is an important performance measure of the core profitability of our operations. This measure forms the basis of our internal financial reporting and is used by management in deciding how to allocate capital resources among business segments. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating segment results. The GAAP financial measure most directly comparable to total segment gross operating margin is operating income. Our non-GAAP financial measure of total segment gross operating margin should not be considered as an alternative to GAAP operating income.
Our consolidated gross operating margin amounts include the gross operating margin amounts of Duncan Energy Partners on a 100% basis. Volumetric data associated with the operations of Duncan Energy Partners are also included on a 100% basis in our consolidated statistical data.
Our gross operating margin by segment and in total is as follows for the periods indicated (dollars in millions):
| For the Three Months | For the Nine Months | |||||||||||||||
| Ended September 30, | Ended September 30, | |||||||||||||||
| 2009 | 2008 | 2009 | 2008 | |||||||||||||
| Gross operating margin by segment: | ||||||||||||||||
| NGL Pipelines & Services | $ | 403.4 | $ | 342.4 | $ | 1,118.1 | $ | 970.9 | ||||||||
| Onshore Natural Gas Pipelines & Services | 108.4 | 133.0 | 391.5 | 452.8 | ||||||||||||
| Onshore Crude Oil Pipelines & Services | 34.1 | 35.4 | 126.7 | 109.5 | ||||||||||||
| Offshore Pipelines & Services | 22.8 | 16.4 | 83.0 | 133.3 | ||||||||||||
| Petrochemical & Refined Products Services | 70.0 | 88.4 | 255.6 | 291.1 | ||||||||||||
| Total segment gross operating margin | $ | 638.7 | $ | 615.6 | $ | 1,974.9 | $ | 1,957.6 | ||||||||
For a reconciliation of non-GAAP gross operating margin to GAAP operating income and income before provision for income taxes, see “Other Items – Non-GAAP Reconciliations” included within this Item 2.
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The following table summarizes the contribution to revenues from each business segment (including the effects of eliminations and adjustments) during the periods indicated (dollars in millions):
| For the Three Months | For the Nine Months | |||||||||||||||
| Ended September 30, | Ended September 30, | |||||||||||||||
| 2009 | 2008 | 2009 | 2008 | |||||||||||||
| NGL Pipelines & Services: | ||||||||||||||||
| Sales of NGLs | $ | 3,015.4 | $ | 4,212.6 | $ | 7,527.6 | $ | 12,433.2 | ||||||||
| Sales of other petroleum and related products | 0.6 | 0.5 | 1.5 | 1.9 | ||||||||||||
| Midstream services | 172.9 | 181.0 | 483.8 | 556.0 | ||||||||||||
| Total | 3,188.9 | 4,394.1 | 8,012.9 | 12,991.1 | ||||||||||||
| Onshore Natural Gas Pipelines & Services: | ||||||||||||||||
| Sales of natural gas | 585.8 | 859.2 | 1,645.4 | 2,400.4 | ||||||||||||
| Midstream services | 182.5 | 182.0 | 535.3 | 550.6 | ||||||||||||
| Total | 768.3 | 1,041.2 | 2,180.7 | 2,951.0 | ||||||||||||
| Onshore Crude Oil Pipelines & Services: | ||||||||||||||||
| Sales of crude oil | 1,991.3 | 3,980.5 | 4,946.1 | 10,580.7 | ||||||||||||
| Midstream services | 18.7 | 18.3 | 60.8 | 56.0 | ||||||||||||
| Total | 2,010.0 | 3,998.8 | 5,006.9 | 10,636.7 | ||||||||||||
| Offshore Pipelines & Services: | ||||||||||||||||
| Sales of natural gas | 0.3 | 0.9 | 0.9 | 2.5 | ||||||||||||
| Sales of crude oil | 2.0 | 3.7 | 3.1 | 10.7 | ||||||||||||
| Midstream services | 99.4 | 60.3 | 243.5 | 191.9 | ||||||||||||
| Total | 101.7 | 64.9 | 247.5 | 205.1 | ||||||||||||
| Petrochemical and Refined Products Services: | ||||||||||||||||
| Sales of products | 597.2 | 848.4 | 1,272.0 | 2,329.2 | ||||||||||||
| Midstream services | 123.3 | 151.7 | 390.6 | 431.0 | ||||||||||||
| Total | 720.5 | 1,000.1 | 1,662.6 | 2,760.2 | ||||||||||||
| Total consolidated revenues | $ | 6,789.4 | $ | 10,499.1 | $ | 17,110.6 | $ | 29,544.1 | ||||||||
Comparison of Three Months Ended September 30, 2009 with
Three Months Ended September 30, 2008
Revenues for the third quarter of 2009 were $6.79 billion compared to $10.50 billion for the third quarter of 2008. The $3.71 billion quarter-to-quarter decrease in consolidated revenues is primarily due to lower energy commodity sales prices associated with our NGL, natural gas, crude oil and petrochemical marketing activities during the third quarter of 2009 compared to the third quarter of 2008. Consolidated revenues for the third quarter of 2009 include $19.2 million of cash proceeds from business interruption insurance due to the effects of Hurricane Ike on our operations.
Operating costs and expenses were $6.39 billion for the third quarter of 2009 versus $10.07 billion for the third quarter of 2008, a $3.68 billion quarter-to-quarter decrease. The cost of sales of our marketing activities decreased $3.46 billion quarter-to-quarter primarily due to lower energy commodity prices. Likewise, the operating costs and expenses of our natural gas processing plants decreased $316.1 million quarter-to-quarter primarily due to lower plant thermal reduction (i.e., PTR) costs attributable to the decline in energy commodity prices. Consolidated operating costs and expenses for the third quarter of 2009 include $66.9 million of expenses related to the settlement of litigation involving TOPS. General and administrative costs increased $18.4 million quarter-to-quarter primarily due to expenses we incurred during the third quarter of 2009 related to the TEPPCO Merger.
Changes in our revenues and costs and expenses quarter-to-quarter are primarily explained by fluctuations in energy commodity prices. The weighted-average indicative market price for NGLs was $0.88 per gallon during the third quarter of 2009 versus $1.68 per gallon during the third quarter of 2008 – a 48% decrease quarter-to-quarter. Our determination of the weighted-average indicative market price for NGLs is based on U.S. Gulf Coast prices for such products at Mont Belvieu, Texas, which is the primary industry hub for domestic NGL production. The market price of natural gas (as measured at Henry Hub in
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Louisiana) decreased 67% quarter-to-quarter to an average of $3.39 per MMBtu during the third quarter of 2009 versus $10.25 per MMBtu during the third quarter of 2008. The market price of crude oil (as measured on the NYMEX) averaged $68.24 per barrel during the third quarter of 2009 compared to $118.22 per barrel during the third quarter of 2008. See “Results of Operations - Selected Price and Volumetric Data” within this Item 2 for additional historical energy commodity pricing information.
Equity in income from our unconsolidated affiliates was $15.0 million for the third quarter of 2009 compared to $10.1 million for the third quarter of 2008, a $4.9 million quarter-to-quarter increase. Collectively, equity in income from our investments in Cameron Highway Oil Pipeline Company (“Cameron Highway”) and Poseidon Oil Pipeline, L.L.C. (“Poseidon”) increased $8.7 million quarter-to-quarter due to higher transportation volumes during the third quarter of 2009 relative to the third quarter of 2008. Our investments in White River Hub, LLC (“White River Hub”) and Skelly-Belvieu Pipeline Company, L.L.C. (“Skelly-Belvieu”) contributed equity in income of $0.9 million and $0.3 million, respectively, for the third quarter of 2009. The assets owned by White River Hub began commercial operations in December 2008. We acquired a 49% equity interest in Skelly-Belvieu during December 2008. Collectively, equity in income from our other equity investments decreased $5.0 million quarter-to-quarter primarily due to expiration of demand fee revenues in March 2009 at our Marco Polo platform and lower crude oil transportation volumes on the pipeline owned by Seaway Crude Pipeline Company (“Seaway”). The Marco Polo platform is owned through our investment in Deepwater Gateway, L.L.C. (“Deepwater Gateway”).
Operating income for the third quarter of 2009 was $356.3 million compared to $401.0 million for the third quarter of 2008. Consolidated revenues and certain operating costs and expenses can fluctuate significantly due to changes in energy commodity prices without necessarily affecting our operating income to the same degree. Consequently, the aforementioned changes in revenues, costs and expenses and equity earnings contributed to the $44.7 million quarter-to-quarter decrease in operating income.
Interest expense increased to $161.0 million for the third quarter of 2009 from $137.0 million for the third quarter of 2008. The $24.0 million quarter-to-quarter increase in interest expense is primarily due to our issuance of Senior Notes O in the fourth quarter of 2008, Senior Notes P in the second quarter of 2009 and a $10.2 million decrease in capitalized interest during the third quarter of 2009 relative to the third quarter of 2008. Average debt principal outstanding increased to $12.20 billion during the third quarter of 2009 from $10.63 billion during the third quarter of 2008 primarily due to debt incurred to fund growth capital projects.
As a result of items noted in the previous paragraphs, net income decreased $70.3 million quarter-to-quarter to $187.8 million for the third quarter of 2009 compared to $258.1 million for the third quarter of 2008. Net loss attributable to noncontrolling interests was $25.1 million for the third quarter of 2009 compared to net income attributable to noncontrolling interests of $55.0 million for the third quarter of 2008. Net loss attributable to noncontrolling interests for the third quarter of 2009 reflects a net loss of $42.1 million attributable to TEPPCO Partners, L.P. Likewise, net income attributable to noncontrolling interest for the third quarter of 2008 includes $47.1 million attributable to TEPPCO Partners, L.P. Net income attributable to Enterprise Products Partners increased $9.8 million quarter-to-quarter to $212.9 million for the third quarter of 2009 compared to $203.1 million for the third quarter of 2008.
In general, Hurricanes Gustav and Ike had an adverse effect on our operations in the Gulf of Mexico and onshore along the U.S. Gulf Coast during the third quarter of 2008. Storm-related disruptions in natural gas, NGL and crude oil production in these regions resulted in reduced volumes available to our pipeline systems, natural gas processing plants, NGL fractionators and offshore platforms, which in turn caused a decrease in gross operating margin for certain operations. In addition, property damage caused by these hurricanes resulted in lower revenues due to facility downtime as well as higher operating costs and expenses at certain of our plants and pipelines. As a result of insurance deductibles for windstorm damage, gross operating margin for the third quarter of 2008 includes $46.4 million of repair expenses for property damage sustained by our assets as a result of Hurricanes Gustav and Ike. Gross operating margin for the third quarter of 2009 includes $19.2 million of proceeds from business interruption insurance due to the
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effects of Hurricane Ike on our operations. For more information regarding our insurance program and claims related to these storms, see “Other Items – Insurance Matters” included within this Item 2.
The following information highlights significant quarter-to-quarter variances in gross operating margin by business segment:
NGL Pipelines & Services. Gross operating margin from this business segment was $403.4 million for the third quarter of 2009 compared to $342.4 million for the third quarter of 2008, a $61.0 million quarter-to-quarter increase. In general, this business segment benefited from a quarter-to-quarter increase in NGL transportation and fractionation volumes, improved results from our NGL marketing activities and lower fuel costs during the third quarter of 2009 compared to the third quarter of 2008. The third quarter of 2009 includes $1.2 million of cash proceeds from business interruption insurance claims. The following paragraphs provide a discussion of segment results excluding cash proceeds from business interruption insurance claims.
Gross operating margin from our natural gas processing and related NGL marketing business was $238.0 million for the third quarter of 2009 compared to $237.6 million for the third quarter of 2008. Equity NGL production increased to 116 MBPD during the third quarter of 2009 from 109 MBPD during the third quarter of 2008. Gross operating margin from our NGL marketing activities increased $16.5 million quarter-to-quarter due to higher NGL sales margins and volumes during the third quarter of 2009 relative to the third quarter of 2008. Gross operating margin from our South Louisiana natural gas processing plants increased $8.1 million quarter-to-quarter. These facilities were negatively impacted by downtime and property damage repair expenses caused by Hurricanes Gustav and Ike during the third quarter of 2008. Collectively, gross operating margin from the remainder of our natural gas processing plants decreased $24.2 million quarter-to-quarter primarily due to lower processing margins in South Texas, the Permian Basin and Rocky Mountains.
Gross operating margin from our NGL pipelines and related storage business was $131.0 million for the third quarter of 2009 compared to $77.2 million for the third quarter of 2008, a $53.8 million quarter-to-quarter increase. Total NGL transportation volumes increased to 2,179 MBPD during the third quarter of 2009 from 1,944 MBPD during the third quarter of 2008. Gross operating margin from our Mid-America and Seminole pipeline systems increased $24.9 million quarter-to-quarter due to higher volumes and lower fuel costs. Collectively, gross operating margin from the remainder of our NGL pipelines, export dock and storage assets increased $28.9 million quarter-to-quarter largely due to increased storage volumes and fees at our Mont Belvieu storage complex, increased NGL export volumes, improved results from our assets in South Louisiana and lower fuel costs during the third quarter of 2009.
Gross operating margin from our NGL fractionation business was $33.2 million for the third quarter of 2009 compared to $27.6 million for the third quarter of 2008. Fractionation volumes increased to 467 MBPD during the third quarter of 2009 from 424 MBPD during the third quarter of 2008. The $5.6 million quarter-to-quarter increase in gross operating margin from this business is primarily due to increased fractionation volumes at our Mont Belvieu, Norco and Promix fractionators and lower fuel costs during the third quarter of 2009 relative to the third quarter of 2008.
Onshore Natural Gas Pipelines & Services. Gross operating margin from this business segment was $108.4 million for the third quarter of 2009 compared to $133.0 million for the third quarter of 2008, a $24.6 million quarter-to-quarter decrease. Our onshore natural gas transportation volumes were 10,495 BBtus/d during the third quarter of 2009 compared to 9,766 BBtus/d during the third quarter of 2008.
Gross operating margin from our onshore natural gas pipeline and related natural gas marketing business was $94.9 million for the third quarter of 2009 compared to $122.3 million for the third quarter of 2008, a $27.4 million quarter-to-quarter decrease. The Sherman Extension pipeline segment of our Texas Intrastate System began commercial operations on August 1, 2009 and contributed $9.0 million of gross operating margin during the third quarter of 2009, primarily from firm capacity fee revenues. Gross operating margin from our San Juan gathering system decreased $27.0 million quarter-to-quarter primarily due to lower commodity prices, which resulted in reduced revenues earned from natural gas gathering
15
contracts where fees are indexed to regional natural gas prices and lower condensate sales revenues. Collectively, gross operating margin from the remainder of this business decreased $9.4 million quarter-to-quarter largely due to a decrease in natural gas transportation volumes and condensate sales revenues, both of which relate primarily to our Texas operations, during the third quarter of 2009 compared to the third quarter of 2008.
Gross operating margin from our natural gas storage business was $13.5 million for the third quarter of 2009 compared to $10.7 million for the third quarter of 2008. The $2.8 million quarter-to-quarter increase in gross operating margin is primarily due to increased storage activity at our Petal and Wilson natural gas storage facilities.
Onshore Crude Oil Pipelines & Services. Gross operating margin from this business segment was $34.1 million for the third quarter of 2009 compared to $35.4 million for the third quarter of 2008. Total onshore crude oil transportation volumes were 654 MBPD during the third quarter of 2009 compared to 618 MBPD during the third quarter of 2008. Gross operating margin decreased $1.3 million quarter-to-quarter primarily as a result of operational measurement gains recorded during the third quarter of 2008 compared to nominal operational measurement losses during the third quarter of 2009
Offshore Pipelines & Services. Gross operating margin from this business segment was $22.8 million for the third quarter of 2009 compared to $16.4 million for the third quarter of 2008. Results from this business segment for the third quarter of 2009 include $18.0 million of cash proceeds from business interruption insurance claims and $66.9 million of expenses for the TOPS litigation settlement. Results for the third quarter of 2008 were negatively impacted by downtime, reduced volumes and $35.5 million of property damage repair expenses resulting from Hurricanes Gustav and Ike. The following paragraphs provide a discussion of segment results excluding the effect of cash proceeds from business interruption insurance claims.
Gross operating margin from our offshore natural gas pipeline business was $8.7 million for the third quarter of 2009 compared to a loss of $22.8 million for the third quarter of 2008. The $31.5 million quarter-to-quarter increase in gross operating margin is primarily due to the impact of Hurricanes Gustav and Ike on this business during the third quarter of 2008, which includes $32.1 million of hurricane-related property damage repair expenses. Gross operating margin from our Independence Trail pipeline increased $6.3 million quarter-to-quarter due to higher transportation volumes. Collectively, gross operating margin from our other offshore natural gas pipelines decreased $6.9 million quarter-to-quarter primarily due to higher maintenance and repair expenses during the third quarter of 2009 associated with our Anaconda and HIOS pipeline systems. Offshore natural gas transportation volumes were 1,374 BBtus/d during the third quarter of 2009 compared to 1,244 BBtus/d during the third quarter of 2008.
Gross operating margin from our offshore crude oil pipeline business was a loss of $39.1 million for the third quarter of 2009 compared to earnings of $4.6 million for the third quarter of 2008, a $43.7 million quarter-to-quarter decrease. Excluding the $66.9 million of expenses we recorded during the third quarter of 2009 as a result of the TOPS litigation settlement, gross operating margin from this business increased $23.2 million quarter-to-quarter primarily due to the start-up of our Shenzi crude oil pipeline and higher transportation volumes on Cameron Highway and Poseidon crude oil pipelines, which were both impacted by last year’s hurricanes. We completed the Shenzi crude oil pipeline and began commercial operation during April 2009. Offshore crude oil transportation volumes were 369 MBPD during the third quarter of 2009 versus 147 MBPD during the third quarter of 2008.
We completed the Shenzi crude oil pipeline and began commercial operation during April 2009. Collectively, gross operating margin from our crude oil pipelines increased $23.2 million quarter-to-quarter primarily due to the start-up of our Shenzi crude oil pipeline and higher transportation volumes on Cameron Highway and Poseidon crude oil pipelines, which were both impacted by last year’s hurricanes. Offshore crude oil transportation volumes were 369 MBPD during the third quarter of 2009 versus 147 MBPD during the third quarter of 2008.
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Gross operating margin from our offshore platform services business was $35.2 million for the third quarter of 2009 compared to $34.6 million for the third quarter of 2008, a $0.6 million quarter-to-quarter increase. Gross operating margin from our Independence Hub platform increased $3.1 million quarter-to-quarter due to higher natural gas processing volumes during the third quarter of 2009 relative to the third quarter of 2008. Collectively, gross operating margin from our other offshore platforms decreased $2.5 million quarter-to-quarter primarily due to the expiration of demand fee revenues at our Marco Polo platform in March 2009. Our net platform natural gas processing volumes increased to 694 MMcf/d during the third quarter of 2009 from 583 MMcf/d during the third quarter of 2008. Our net platform crude oil processing volumes increased to 17 MBPD during the third quarter of 2009 compared to 14 MBPD during the third quarter of 2008.
Petrochemical & Refined Products Services. Gross operating margin from this business segment was $70.0 million for the third quarter of 2009 compared to $88.4 million for the third quarter of 2008.
Gross operating margin from propylene fractionation and related activities was $23.2 million for the third quarter of 2009 compared to $31.3 million for the third quarter of 2008. The $8.1 million quarter-to-quarter decrease in gross operating margin is due to lower propylene sales margins, which more than offset the benefit of increased propylene fractionation volumes. Propylene fractionation volumes increased to 67 MBPD during the third quarter of 2009 from 58 MBPD during the third quarter of 2008.
Gross operating margin from butane isomerization was $22.5 million for the third quarter of 2009 compared to $19.1 million for the third quarter of 2008. The $3.4 million quarter-to-quarter increase in gross operating margin from this business is attributable to increased isomerization volumes, partially offset by lower by-product revenues. Butane isomerization volumes increased to 104 MBPD during the third quarter of 2009 from 71 MBPD during the third quarter of 2008.
Gross operating margin from octane enhancement was $5.3 million for the third quarter of 2009 compared to a loss of $12.9 million for the third quarter of 2008. The $18.2 million quarter-to-quarter increase in gross operating margin is due to higher volumes and lower operating expenses in the third quarter of 2009 compared to the third quarter of 2008. During the third quarter of 2008, in addition to downtime associated with Hurricane Ike, the octane enhancement facility had operational issues that resulted in higher operating expenses, downtime and decreased production volumes. Octane enhancement production volumes increased to 13 MBPD during the third quarter of 2009 from 8 MBPD during the third quarter of 2008.
Gross operating margin from refined products pipelines and related activities was $2.4 million for the third quarter of 2009 compared to $31.2 million for the third quarter of 2008, a $28.8 million quarter-to-quarter decrease. Gross operating margin for the third quarter of 2009 includes $28.7 million of expenses to accrue a liability for pipeline transportation deficiency fees owed to a third party. See Note 15 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Exhibit 99.3 of this Current Report on Form 8-K for information related to the liability for pipeline transportation deficiency fees. Transportation volumes on our refined products pipelines were 630 MBPD during the third quarter of 2009 compared to 661 MBPD during the third quarter of 2008.
Gross operating margin from marine transportation and other services was $16.6 million for the third quarter of 2009 compared to $19.7 million for the third quarter of 2008, a $3.1 million quarter-to-quarter decrease. Gross operating margin from marine transportation decreased $1.6 million quarter-to-quarter primarily due to higher operating expenses. The utilization of our fleet of marine vessels averaged 88% during the third quarter of 2009 versus 92% during the third quarter of 2008. Gross operating margin from the distribution of lubrication oils and specialty chemicals decreased $1.5 million quarter-to-quarter primarily due to lower margins from the sale of specialty chemicals during the third quarter of 2009 relative to the third quarter of 2008.
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Comparison of Nine Months Ended September 30, 2009 with
Nine Months Ended September 30, 2008
Revenues for the first nine months of 2009 were $17.11 billion compared to $29.54 billion for the first nine months of 2008. The $12.43 billion period-to-period decrease in consolidated revenues is primarily due to lower energy commodity sales prices associated with our NGL, natural gas, crude oil and petrochemical marketing activities during the first nine months of 2009 compared to the first nine months of 2008.
Operating costs and expenses were $15.80 billion for the first nine months of 2009 compared to $28.15 billion for the first nine months of 2008, a $12.35 billion period-to-period decrease. The cost of sales of our marketing activities decreased $11.46 billion period-to-period primarily due to lower energy commodity prices. Likewise, the operating costs and expenses of our natural gas processing plants decreased $981.9 million period-to-period primarily due to lower PTR costs attributable to the decline in energy commodity prices. Consolidated operating costs and expenses for the first nine months of 2009 include $66.9 million of expenses related to the settlement of litigation involving TOPS and $68.4 million of expenses related to the forfeiture of our interest in TOPS. General and administrative costs increased $32.9 million period-to-period primarily due to expenses we incurred during the first nine months of 2009 in connection with the TEPPCO Merger.
Changes in our revenues and costs and expenses period-to-period are primarily explained by fluctuations in energy commodity prices. The weighted-average indicative market price for NGLs was $0.77 per gallon during the first nine months of 2009 versus $1.62 per gallon during the first nine months of 2008. The Henry Hub market price of natural gas decreased 60% period-to-period to an average of $3.93 per MMBtu during the first nine months of 2009 versus $9.74 per MMBtu during the first nine months of 2008. The NYMEX market price of crude oil averaged $57.11 per barrel during the first nine months of 2009 compared to $113.28 per barrel during the first nine months of 2008.
Equity in income from our unconsolidated affiliates was $32.0 million for the first nine months of 2009 compared to $31.8 million for the first nine months of 2008. Equity in income from our investment in Poseidon increased $5.0 million period-to-period due to higher transportation volumes during the first nine months of 2009 relative to the first nine months of 2008. Our investments in White River Hub and Skelly-Belvieu contributed equity in income of $2.9 million and $1.4 million, respectively, for the first nine months of 2009. Equity in income decreased $11.9 million period-to-period from our Marco Polo platform due to the expiration of demand fee revenues during March 2009. Collectively, equity in income of unconsolidated affiliates from our other equity investments increased $2.8 million period-to-period.
Operating income for the first nine months of 2009 was $1.21 billion compared to $1.33 billion for the first nine months of 2008. Consolidated revenues and certain operating costs and expenses can fluctuate significantly due to changes in energy commodity prices without necessarily affecting our operating income to the same degree. Consequently, the aforementioned changes in revenues, costs and expenses and equity in income of unconsolidated affiliates contributed to the $112.9 million period-to-period decrease in operating income.
Interest expense increased to $472.0 million for the first nine months of 2009 from $396.3 million for the first nine months of 2008. The $75.7 million period-to-period increase in interest expense is primarily due to our issuance of Senior Notes M and N in the second quarter of 2008, Senior Notes O in the fourth quarter of 2008 and a $27.8 million decrease in capitalized interest during the first nine months of 2009 relative to the first nine months of 2008. Average debt principal outstanding increased to $11.99 billion during the first nine months of 2009 from $9.83 billion during the first nine months of 2008 primarily due to debt incurred to fund growth capital investments. Provision for income taxes increased $6.7 million period-to-period primarily due to a one-time charge of $6.6 million associated with taxable gains arising from Dixie Pipeline Company’s (“Dixie”) sale of certain assets during the first nine months of 2009.
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As a result of items noted in the previous paragraphs, net income decreased $198.3 million period-to-period to $715.8 million for the first nine months of 2009 compared to $914.1 million for the first nine months of 2008. Net income attributable to noncontrolling interests was $91.0 million for the first nine months of 2009 compared to $188.1 million for the first nine months of 2008. Such amounts reflect $48.5 million and $158.8 million of net income for the first nine months of 2009 and 2008, respectively, attributable to TEPPCO Partners, L.P. Net income attributable to Enterprise Products Partners decreased $101.2 million period-to-period to $624.8 million for the first nine months of 2009 compared to $726.0 million for the first nine months of 2008.
The following information highlights significant period-to-period variances in gross operating margin by business segment:
NGL Pipelines & Services. Gross operating margin from this business segment was $1.12 billion for the first nine months of 2009 compared to $970.9 million for the first nine months of 2008, a $147.2 million period-to-period increase. In general, this business segment benefited from a period-to-period increase in gross operating margin from our recently constructed Rocky Mountain natural gas processing plants and related hedging program, improved results from our NGL marketing activities and lower fuel costs during the first nine months of 2009 compared to the first nine months of 2008. The first nine months of 2009 include $1.2 million of proceeds from business interruption insurance claims compared to $1.1 million of proceeds during the first nine months of 2008. The following paragraphs provide a discussion of segment results excluding the effect of cash proceeds from business interruption insurance.
Gross operating margin from our natural gas processing and related NGL marketing business was $652.0 million for the first nine months of 2009 compared to $611.8 million for the first nine months of 2008. Equity NGL production increased to 116 MBPD during the first nine months of 2009 from 108 MBPD during the first nine months of 2008. The $40.2 million period-to-period increase in gross operating margin from this business is attributable to our Rocky Mountain natural gas processing facilities and related hedging program and our NGL marketing activities, which benefited from higher sales margins and increased equity NGL production.
Gross operating margin from our NGL pipelines and related storage business was $363.8 million for the first nine months of 2009 compared to $275.6 million for the first nine months of 2008, an $88.2 million period-to-period increase. Total NGL transportation volumes increased to 2,098 MBPD during the first nine months of 2009 from 1,991 MBPD during the first nine months of 2008. Gross operating margin from our Mid-America and Seminole Pipeline Systems increased $33.6 million period-to-period due to increased volumes and lower fuel costs. Gross operating margin from our Mont Belvieu storage complex increased $13.4 million period-to-period primarily due to higher volumes and fees. Collectively, gross operating margin from the remainder of our NGL pipelines, export dock and related storage assets increased $41.2 million period-to-period largely due to lower fuel costs, higher NGL export volumes and higher volumes and fees at certain of our South Louisiana assets during the first nine months of 2009 relative to the first nine months of 2008.
Gross operating margin from our NGL fractionation business was $101.1 million for the first nine months of 2009 compared to $82.4 million for the first nine months of 2008. Fractionation volumes increased to 456 MBPD during the first nine months of 2009 from 436 MBPD during the first nine months of 2008. Gross operating margin from this business increased $18.7 million period-to-period largely due to higher NGL fractionation volumes at our Mont Belvieu and Baton Rouge fractionators and lower fuel costs during the first nine months of 2009 relative to the first nine months of 2008.
Onshore Natural Gas Pipelines & Services. Gross operating margin from this business segment was $391.5 million for the first nine months of 2009 compared to $452.8 million for the first nine months of 2008, a $61.3 million period-to-period decrease. Our onshore natural gas transportation volumes were 10,502 BBtus/d during the first nine months of 2009 compared to 9,422 BBtus/d during the first nine months of 2008.
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Gross operating margin from our onshore natural gas pipeline and related natural gas marketing business was $352.6 million for the first nine months of 2009 compared to $423.8 million for the first nine months of 2008, a $71.2 million period-to-period decrease. Gross operating margin from our Jonah gathering system increased $15.9 million period-to-period due to increased gathering volumes and lower fuel costs. The Sherman Extension pipeline segment of our Texas Intrastate System began commercial operations on August 1, 2009 and contributed $9.0 million of gross operating margin during 2009, primarily from firm capacity fee revenues. Gross operating margin from our San Juan gathering system decreased $89.2 million period-to-period due to lower fees indexed to regional natural gas prices and condensate sales revenues as a result of the period-to-period decrease in commodity prices. Lower natural gas gathering volumes in the Permian Basin resulted in a $9.2 million period-to-period decrease in gross operating margin on our Carlsbad gathering system. Collectively, gross operating margin from the remainder of the businesses classified within this segment increased $2.3 million period-to-period.
Gross operating margin from our natural gas storage business was $38.9 million for the first nine months of 2009 compared to $29.0 million for the first nine months of 2008. The $9.9 million period-to-period increase in gross operating margin is primarily due to increased storage activity at our Petal and Wilson natural gas storage facilities.
Onshore Crude Oil Pipelines & Services. Gross operating margin from this business segment was $126.7 million for the first nine months of 2009 compared to $109.5 million for the first nine months of 2008. Total onshore crude oil transportation volumes were 683 MBPD during the first nine months of 2009 compared to 690 MBPD during the first nine months of 2008. The $17.2 million period-to-period increase in segment gross operating margin is primarily due to increased crude oil sales margins during the first nine months of 2009 relative to the first nine months of 2008.
Offshore Pipelines & Services. Gross operating margin from this business segment was $83.0 million for the first nine months of 2009 compared to $133.3 million for the first nine months of 2008, a $50.3 million period-to-period decrease. Results for the first nine months of 2009 include $18.0 million of cash proceeds from business interruption insurance claims and $135.3 million of total expenses related to TOPS. Results for the first nine months of 2008 include $0.2 million of proceeds from business interruption insurance claims and $35.5 million of property damage repair expenses resulting from Hurricanes Gustav and Ike. Combined gross operating margin from our Independence Hub platform and Trail pipeline increased $55.1 million period-to-period reflecting downtime and repair expenses incurred during the first nine months of 2008. The following paragraphs provide a discussion of segment results excluding cash proceeds from business interruption insurance.
Gross operating margin from our offshore natural gas pipeline business was $43.1 million for the first nine months of 2009 compared to a loss of $8.3 million for the first nine months of 2008, a $51.4 million period-to-period increase. Offshore natural gas transportation volumes were 1,458 BBtus/d during the first nine months of 2009 versus 1,449 BBtus/d during the first nine months of 2008. Gross operating margin from our Independence Trail pipeline increased $37.4 million period-to-period. Collectively, gross operating margin from our other offshore natural gas pipelines increased $14.0 million period-to-period primarily due to hurricane-related property damage repair expenses recorded during the first nine months of 2008.
Gross operating margin from our offshore crude oil pipeline business was a loss of $88.0 million for the first nine months of 2009 compared to earnings of $31.6 million for the first nine months of 2008, a $119.6 million period-to-period decrease. Results for the first nine months of 2009 include $135.3 million of expenses related to TOPS. Gross operating margin from our offshore crude oil pipelines increased $15.7 million period-to-period primarily due to the start-up of our Shenzi crude oil pipeline and higher transportation volumes on our Poseidon crude oil pipeline. Total offshore crude oil transportation volumes were 278 MBPD during the first nine months of 2009 versus 190 MBPD during the first nine months of 2008.
Gross operating margin from our offshore platform services business was $109.9 million for the first nine months of 2009 compared to $109.8 million for the first nine months of 2008. Gross operating
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margin from our Independence Hub platform increased $17.7 million period-to-period. Collectively, gross operating margin from our other offshore platforms and related assets decreased $17.6 million period-to-period primarily due to lower natural gas and crude oil processing volumes at our Marco Polo platform as a result of continuing hurricane-related disruptions and the expiration of demand fee revenues at our Marco Polo and Falcon platforms. Our net platform natural gas processing volumes increased to 741 MMcf/d during the first nine months of 2009 compared to 588 MMcf/d during the first nine months of 2008. Our net platform crude oil processing volumes decreased to 10 MBPD during the first nine months of 2009 compared to 19 MBPD during the first nine months of 2008.
Petrochemical & Refined Products Services. Gross operating margin from this business segment was $255.6 million for the first nine months of 2009 compared to $291.1 million for the first nine months of 2008.
Gross operating margin from propylene fractionation and related activities was $68.8 million for the first nine months of 2009 compared to $66.2 million for the first nine months of 2008. The $2.6 million period-to-period increase in gross operating margin is largely due to higher propylene sales volumes during the first nine months of 2009 relative to the first nine months of 2008. Propylene fractionation volumes increased to 67 MBPD during the first nine months of 2009 from 59 MBPD during the first nine months of 2008.
Gross operating margin from butane isomerization was $56.5 million for the first nine months of 2009 compared to $77.9 million for the first nine months of 2008. The $21.4 million period-to-period decrease in gross operating margin from this business is primarily due to lower proceeds from the sale of plant by-products as a result of lower commodity prices. Butane isomerization volumes increased to 98 MBPD during the first nine months of 2009 from 85 MBPD during the first nine months of 2008.
Gross operating margin from octane enhancement was $4.1 million for the first nine months of 2009 compared to a loss of $5.7 million for the first nine months of 2008. The $9.8 million period-to-period increase in gross operating margin is due to lower operating expenses during the first nine months of 2009 compared to the first nine months of 2008. During the third quarter of 2008, in addition to downtime associated with Hurricane Ike, the octane enhancement facility had operational issues that resulted in higher operating expenses, downtime and decreased production volumes.
Gross operating margin from refined products pipelines and related activities was $78.2 million for the first nine months of 2009 compared to $103.3 million for the first nine months of 2008, a $25.1 million period-to-period decrease. Gross operating margin for the first nine months of 2009 includes $28.7 million of expenses to accrue a liability for pipeline transportation deficiency fees owed to a third party. Gross operating margin from the remainder of this business increased $3.6 primarily due lower operating expenses on our Products Pipeline System. Transportation volumes on our refined products pipelines were 674 MBPD during the first nine months of 2009 compared to 699 MBPD during the first nine months of 2008.
Gross operating margin from marine transportation and other services was $48.0 million for the first nine months of 2009 compared to $49.4 million for the first nine months of 2008. Gross operating margin from marine transportation increased $0.6 million period-to-period. The utilization of our fleet of marine vessels averaged 88% during the first nine months of 2009 versus 92% during the same period in 2008. Gross operating margin from the distribution of lubrication oils and specialty chemicals decreased $2.0 million period-to-period primarily due to lower margins from the sale of specialty chemicals and higher operating expense during the first nine months of 2009 compared to the first nine months of 2008.
Liquidity and Capital Resources
Our primary cash requirements, in addition to normal operating expenses and debt service, are for working capital, capital expenditures, business acquisitions and distributions to partners. We expect to fund our short-term needs for such items as operating expenses and sustaining capital expenditures with operating cash flows and revolving credit arrangements. Capital expenditures for long-term needs resulting
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from business expansion projects and acquisitions are expected to be funded by a variety of sources (either separately or in combination) including operating cash flows, borrowings under credit facilities, the issuance of additional equity and debt securities and proceeds from divestitures of ownership interests in assets to affiliates or third parties. We expect to fund cash distributions to partners primarily with operating cash flows. Our debt service requirements are expected to be funded by operating cash flows and/or refinancing arrangements.
At September 30, 2009, we had $77.3 million of unrestricted cash on hand and approximately $1.36 billion of available credit under our revolving credit facilities, which includes the available borrowing capacity of our consolidated subsidiaries such as Duncan Energy Partners. We had approximately $11.94 billion in principal outstanding under consolidated debt agreements at September 30, 2009. In total, our consolidated liquidity at September 30, 2009 was approximately $1.44 billion.
Registration Statements
We have a universal shelf registration statement on file with the SEC that allows us to issue an unlimited amount of debt and equity securities for general partnership purposes. In January 2009, we issued 10,590,000 common units (including an over-allotment of 990,000 common units) to the public at an offering price of $22.20 per unit under this registration statement. We used the net proceeds of $225.6 million from the January 2009 equity offering to temporarily reduce borrowings outstanding under EPO’s Multi-Year Revolving Credit Facility and for general partnership purposes. In June 2009, EPO issued $500.0 million in principal amount of Senior Notes P under this registration statement. Net proceeds from this senior note offering were used to repay the $200.0 Million Term Loan, to temporarily reduce borrowings outstanding under EPO’s Multi-Year Revolving Credit Facility and for general partnership purposes.
In September 2009, we issued 8,337,500 common units (including an over-allotment of 1,087,500 common units) to the public at an offering price of $28.00 per unit under this registration statement. We used the net proceeds of $226.4 million from the September 2009 equity offering to temporarily reduce borrowings outstanding under EPO’s Multi-Year Revolving Credit Facility and for general partnership purposes. In October 2009, EPO issued $1.1 billion in principal amount of Senior Notes Q and R under this registration statement. Net proceeds from this senior note offering were used to repay $500.0 million in aggregate principal amount of Senior Notes F that matured in October 2009, to temporarily reduce borrowings outstanding under EPO’s Multi-Year Revolving Credit Facility and for general partnership purposes.
We also have a registration statement on file with the SEC authorizing the issuance of up to 40,000,000 common units in connection with our distribution reinvestment plan (“DRIP”). During the nine months ended September 30, 2009, we issued 10,731,084 common units in connection with our DRIP, which generated proceeds of $254.7 million from plan participants. Affiliates of EPCO reinvested $226.5 million in connection with the DRIP during the nine months ended September 30, 2009.
In addition, we have a registration statement on file related to our employee unit purchase plan (“EUPP”), under which we can issue up to 1,200,000 common units. During the nine months ended September 30, 2009, we issued 141,512 common units to employees under this plan, which generated proceeds of $3.5 million.
Duncan Energy Partners has a universal shelf registration statement filed with the SEC that allows it to issue up to $1 billion of debt and equity securities. In June 2009, Duncan Energy Partners completed an offering of 8,000,000 of its common units, which generated net proceeds of approximately $122.9 million. In July 2009, the underwriters to this offering exercised their option to purchase an additional 943,400 common units, which generated approximately $14.5 million of additional net proceeds for Duncan Energy Partners. Duncan Energy Partners used the aggregate net proceeds from this offering to repurchase an equal number of its common units that were beneficially owned by EPO. Duncan Energy Partners subsequently cancelled the common units it repurchased from EPO. At September 30, 2009,
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Duncan Energy Partners can issue approximately $856.4 million of additional securities under its registration statement.
For information regarding our public debt obligations or partnership equity, see Notes
10 and 11, respectively, of the Notes to Unaudited Supplemental Condensed Consolidated Financial Statements included under Exhibit 99.3 of this Current Report of Form 8-K.
Letter of Credit Facilities
At September 30, 2009, EPO had outstanding a $50.0 million letter of credit relating to its commodity derivative instruments and a $58.3 million letter of credit related to its Petal GO Zone Bonds. These letter of credit facilities do not reduce the amount available for borrowing under EPO’s credit facilities. In addition, Duncan Energy Partners had an outstanding letter of credit in the amount of $1.0 million at September 30, 2009, which reduces the amount available for borrowing under its credit facility.
Credit Ratings of EPO
EPO’s senior notes are rated investment-grade. Moody’s Investor Services has assigned a rating of Baa3 and Standard & Poor’s and Fitch Ratings have each assigned a rating of BBB-. Such ratings reflect only the view of a rating agency and should not be interpreted as a recommendation to buy, sell or hold any security. Any rating can be revised upward or downward or withdrawn at any time by a rating agency if it determines that the circumstances warrant such a change and should be evaluated independently of any other rating.
Cash Flows from Operating, Investing and Financing Activities
The following table summarizes our cash flows from operating, investing and financing activities for the periods indicated (dollars in millions). For information regarding the individual components of our cash flow amounts, see the Unaudited Condensed Statements of Consolidated Cash Flows included under Exhibit 99.3 of this Current Report on Form 8-K.
| For the Nine Months | ||||||||
| Ended September 30, | ||||||||
| 2009 | 2008 | |||||||
| Net cash flows provided by operating activities | $ | 891.7 | $ | 1,251.1 | ||||
| Cash used in investing activities | 1,072.2 | 2,364.5 | ||||||
| Cash provided by financing activities | 196.5 | 1,130.7 | ||||||
The following information highlights the significant period-to-period variances in our cash flow amounts:
Comparison of Nine Months Ended September 30, 2009
with Nine Months Ended September 30, 2008
Operating Activities. Net cash flows provided by operating activities were $891.7 million for the nine months ended September 30, 2009 compared to $1.25 billion for the nine months ended September 30, 2008. This $359.4 million decrease in net cash flows provided by operating activities was primarily due to the following:
| § | Net cash flows from consolidated operations (excluding cash payments for interest and distributions received from unconsolidated affiliates) decreased $397.7 million period-to-period. Although our gross operating margin increased period-to-period (see “Results of Operations” within this Item 2), the reduction in operating cash flow is generally due to the timing of related cash receipts and disbursements and an increase cash outlays for in forward sales inventory. As a result of energy market conditions, we significantly increased our physical inventory purchases and related forward physical sales commitments during 2009. In general, the significant increase |
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in volumes dedicated to forward physical sales contracts improves the overall utilization and profitability of our fee-based assets. |
| § | Cash payments for interest increased $33.6 million period-to-period primarily due to increased borrowings to finance our capital spending program and for general partnership purposes. |
| § | Distributions received from unconsolidated affiliates increased $4.7 million period-to-period primarily due to higher distributions received from Cameron Highway and Seaway, partially offset by lower distributions received from Deepwater Gateway. |
Investing Activities. Cash used in investing activities was $1.07 billion for the nine months ended September 30, 2009 compared to $2.36 billion for the nine months ended September 30, 2008. This $1.29 billion decrease in cash used in investing activities was primarily due to the following:
| § | Capital spending for property, plant and equipment, net of contributions in aid of construction costs, decreased $734.6 million period-to-period. For additional information related to our capital spending program, see “Capital Spending” included within this Item 2. |
| § | Restricted cash related to our hedging activities decreased $100.8 million (a cash inflow) during the nine months ended September 30, 2009 primarily due to the reduction of margin requirements related to derivative instruments we utilized. For the nine months ended September 30, 2008, restricted cash related to our hedging activities increased $112.2 million (a cash outflow). |
| § | Cash used for business combinations decreased $334.3 million period-to-period primarily due to reduced business combination activity in 2009. During the nine months ended September 30, 2009, we acquired rail and truck terminal facilities located in Mont Belvieu, Texas in May 2009 for $23.7 million and tow boats and tank barges primarily located in Miami, Florida in June 2009 for $50.0 million. During the nine months ended September 30, 2008, our combinations primarily involved marine assets in February 2008 for a total of $345.6 million and additional interests in Dixie in August 2008 for $57.0 million. |
Financing Activities. Cash provided by financing activities was $196.5 million for the nine months ended September 30, 2009 compared to $1.13 billion for the nine months ended September 30, 2008. The $934.2 million decrease in cash provided by financing activities was primarily due to the following:
| § | Net borrowings under our consolidated debt agreements were $369.8 million during the nine months ended September 30, 2009 compared to $1.94 billion during the nine months ended September 30, 2008. The $1.57 billion decrease in net borrowings was primarily attributable to lower amounts of senior notes issued period-to-period. During the nine months ended September 30, 2008, EPO and TEPPCO issued $2.1 billion in senior notes, compared to $500.0 million in senior notes during the nine months ended September 30, 2009. |
| § | Cash distributions to our partners increased $89.8 million period-to-period due to increases in our common units outstanding and quarterly distribution rates. |
| § | Cash distributions to the noncontrolling interest increased $48.5 million period-to-period primarily due to increases in the units outstanding and quarterly cash distribution rates to limited partners of Duncan Energy Partners and former owners of TEPPCO. |
| § | Net proceeds from the issuance of common units increased $878.2 million period-to-period primarily due to (i) the January and September 2009 issuances of common units that generated net proceeds of $452.0 million, (ii) the September 2009 private placement of common units that generated net proceeds of $150.0 million and (iii) an increase of $206.9 million in proceeds generated by our DRIP and EUPP period-to-period. Affiliates of EPCO reinvested $226.5 million of their distributions through the DRIP during the nine months ended September 30, 2009. |
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| § | Contributions from noncontrolling interests were $140.9 million for the nine months ended September 30, 2009 compared to $271.3 million for the nine months ended September 30, 2008. This $130.4 million decrease is primarily attributable to the net proceeds that Duncan Energy Partners received from the issuance of an aggregate 8,943,400 of its common units in June and July 2009 compared to net proceeds of $271.3 million received from unit offerings to former owners of TEPPCO during the nine months ended September 30, 2008. |
Capital Spending
The following table summarizes our capital spending by activity for the periods indicated (dollars in millions):
For the Nine Months Ended September 30, | ||||||||
| 2009 | 2008 | |||||||
| Capital spending for property, plant and equipment, net | ||||||||
| of contributions in aid of construction costs | $ | 1,087.6 | $ | 1,822.2 | ||||
| Capital spending for business combinations | 74.5 | 408.8 | ||||||
| Capital spending for intangible assets | 1.4 | 5.4 | ||||||
| Capital spending for investments in unconsolidated affiliates | 13.9 | 23.9 | ||||||
| Total capital spending | $ | 1,177.4 | $ | 2,260.3 | ||||
Based on information currently available, we estimate our consolidated capital spending for the fourth quarter of 2009 will approximate $700.0 million, which includes estimated expenditures of $630.0 million for growth capital projects and acquisitions and $70.0 million for sustaining capital expenditures.
Our forecast of consolidated capital expenditures is based on our current announced strategic operating and growth plans. Our strategic operating and growth plans are dependent upon our ability to generate the required funds from either operating cash flows or from other means, including borrowings under debt agreements, issuance of equity, and potential divestitures of certain assets to third and/or related parties. Our forecast of capital expenditures may change due to factors beyond our control, such as weather-related issues, changes in supplier prices or adverse economic conditions. Furthermore, our forecast may change as a result of decisions made by management at a later date, which may include acquisitions or decisions to take on additional partners.
Our success in raising capital, including the formation of joint ventures to share costs and risks, continues to be a principal factor that determines how much capital we can invest. We believe our access to capital resources is sufficient to meet the demands of our current and future operating growth needs, and although we currently intend to make the forecasted expenditures discussed above, we may adjust the timing and amounts of projected expenditures in response to changes in capital markets.
At September 30, 2009, we had approximately $497.0 million in purchase commitments outstanding that relate to our capital spending for property, plant and equipment. These remaining commitments primarily relate to construction of our Barnett Shale and Piceance Basin natural gas pipeline projects and the construction of a new NGL fractionator in Mont Belvieu, Texas.
Pipeline Integrity Costs
Our NGL, petrochemical and natural gas pipelines are subject to pipeline safety programs administered by the U.S. Department of Transportation, through its Pipeline and Hazardous Materials Safety Administration, and participating state agencies. These federal and state agencies have issued safety regulations containing requirements for the development of integrity management programs for hazardous liquid pipelines (which include NGL and petrochemical pipelines) and natural gas pipelines. In general, these regulations require companies to assess the condition of their pipelines in certain areas (such as high consequence areas as defined by the regulations) and to perform any necessary repairs.
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The following table summarizes our accrued pipeline integrity costs for the periods indicated (dollars in millions):
| For the Three Months | For the Nine Months | |||||||||||||||
| Ended September 30, | Ended September 30, | |||||||||||||||
| 2009 | 2008 | 2009 | 2008 | |||||||||||||
| Expensed | $ | 11.7 | $ | 16.1 | $ | 33.4 | $ | 42.6 | ||||||||
| Capitalized | 11.4 | 19.8 | 26.6 | 52.1 | ||||||||||||
| Total | $ | 23.1 | $ | 35.9 | $ | 60.0 | $ | 94.7 | ||||||||
We expect our cash outlays for the pipeline integrity program, irrespective of whether such costs are capitalized or expensed, to approximate $39.4 million for the remainder of 2009.
Other Items
Contractual Obligations
For information regarding year-to-date changes in our contractual obligations, please see Note 15 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Exhibit 99.3 of this Current Report on Form 8-K.
Off-Balance Sheet Arrangements
There have been no significant changes with regards to our off-balance sheet arrangements since those presented under Exhibit 99.2 of this Current Report on Form 8-K.
Summary of Related Party Transactions
On October 26, 2009, the TEPPCO Merger was completed. Under terms of the merger agreements, TEPPCO and TEPPCO GP became our wholly owned subsidiaries. For additional information regarding this material related party transaction, see “Recent Developments – Merger of TEPPCO and TEPPCO GP with Enterprise Products Partners” within this Item 2. The following table summarizes other related party transactions for the periods indicated (dollars in millions):
| For the Three Months | For the Nine Months | |||||||||||||||
| Ended September 30, | Ended September 30, | |||||||||||||||
| 2009 | 2008 | 2009 | 2008 | |||||||||||||
| Revenues from consolidated operations: | ||||||||||||||||
| Energy Transfer Equity and subsidiaries | $ | 54.5 | $ | 99.6 | $ | 266.5 | $ | 413.0 | ||||||||
| Unconsolidated affiliates | 55.9 | 153.4 | 155.7 | 318.7 | ||||||||||||
| Total | $ | 110.4 | $ | 253.0 | $ | 422.2 | $ | 731.7 | ||||||||
| Cost of sales: | ||||||||||||||||
| EPCO and affiliates | $ | 19.5 | $ | 10.3 | $ | 46.4 | $ | 31.0 | ||||||||
| Energy Transfer Equity and subsidiaries | 100.6 | 50.6 | 286.5 | 119.4 | ||||||||||||
| Unconsolidated affiliates | 13.9 | 25.5 | 38.2 | 80.3 | ||||||||||||
| Total | $ | 134.0 | $ | 86.4 | $ | 371.1 | $ | 230.7 | ||||||||
| Operating costs and expenses: | ||||||||||||||||
| EPCO and affiliates | $ | 119.9 | $ | 105.4 | $ | 338.2 | $ | 318.2 | ||||||||
| Energy Transfer Equity and subsidiaries | 12.5 | 5.9 | 23.6 | 15.0 | ||||||||||||
| Cenac and affiliates | 6.0 | 13.0 | 33.0 | 30.2 | ||||||||||||
| Unconsolidated affiliates | (4.8 | ) | (11.5 | ) | (15.4 | ) | (37.4 | ) | ||||||||
| Total | $ | 133.6 | $ | 112.8 | $ | 379.4 | $ | 326.0 | ||||||||
| General and administrative expenses: | ||||||||||||||||
| EPCO and affiliates | $ | 24.9 | $ | 20.7 | $ | 74.9 | $ | 68.9 | ||||||||
| Cenac and affiliates | 0.5 | 0.8 | 2.1 | 2.1 | ||||||||||||
| Total | $ | 25.4 | $ | 21.5 | $ | 77.0 | $ | 71.0 | ||||||||
| Other expense: | ||||||||||||||||
| EPCO and affiliates | $ | -- | $ | -- | $ | -- | $ | 0.3 | ||||||||
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The following table summarizes our related party receivable and payable amounts at the dates indicated:
| September 30, | December 31, | |||||||
| 2009 | 2008 | |||||||
| Accounts receivable - related parties: | ||||||||
| EPCO and affiliates | $ | -- | $ | 0.2 | ||||
| Energy Transfer Equity and subsidiaries | 6.4 | 35.0 | ||||||
| Other | 3.2 | 0.1 | ||||||
| Total | $ | 9.6 | $ | 35.3 | ||||
| Accounts payable - related parties: | ||||||||
| EPCO and affiliates | $ | 12.0 | $ | 14.1 | ||||
| Energy Transfer Equity and subsidiaries | 27.2 | 0.1 | ||||||
| Other | 5.0 | 3.2 | ||||||
| Total | $ | 44.2 | $ | 17.4 | ||||
For additional information regarding our related party transactions, see Note 13 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Exhibit 99.3 of this Current Report on Form 8-K.
Non-GAAP Reconciliations
The following table presents a reconciliation of our measurement of total non-GAAP gross operating margin to GAAP operating income and income before provision for income taxes (dollars in millions):
| For the Three Months | For the Nine Months | |||||||||||||||
| Ended September 30, | Ended September 30, | |||||||||||||||
| 2009 | 2008 | 2009 | 2008 | |||||||||||||
| Total segment gross operating margin | $ | 638.7 | $ | 615.6 | $ | 1,974.9 | $ | 1,957.6 | ||||||||
| Adjustments to reconcile total segment gross operating margin | ||||||||||||||||
| to operating income: | ||||||||||||||||
| Depreciation, amortization and accretion in operating costs and expenses | (206.0 | ) | (181.3 | ) | (602.9 | ) | (532.3 | ) | ||||||||
| Impairment charges included in operating costs and expenses | (24.0 | ) | -- | (26.3 | ) | -- | ||||||||||
| Operating lease expense paid by EPCO | (0.2 | ) | (0.5 | ) | (0.5 | ) | (1.6 | ) | ||||||||
Gain from asset sales and related transactions in operating costs and expenses | 0.1 | 1.1 | 0.5 | 2.0 | ||||||||||||
| General and administrative costs | (52.3 | ) | (33.9 | ) | (133.3 | ) | (100.4 | ) | ||||||||
| Operating income | 356.3 | 401.0 | 1,212.4 | 1,325.3 | ||||||||||||
| Other expense, net | (160.8 | ) | (135.2 | ) | (469.8 | ) | (391.1 | ) | ||||||||
| Income before provision for income taxes | $ | 195.5 | $ | 265.8 | $ | 742.6 | $ | 934.2 | ||||||||
Recent Accounting Developments
The accounting standard setting bodies have recently issued accounting guidance since those reported in this Current Report on Form 8-K under Exhibit 99.2 that will or may affect our future financial statements. The recently issued accounting guidance relates to:
| § | The hierarchy of GAAP and the establishment of the ASC (codified under ASC 105, Generally Accepted Accounting Principles); |
| § | Estimating fair value when the volume and level of activity for the asset or liability have significantly decreased and identifying circumstances that indicate a transaction is not orderly (codified under ASC 820, Fair Value Measurement and Disclosures); |
| § | Measuring liabilities at fair value (codified under ASC 820); |
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| § | Providing quarterly disclosures about fair value estimates for all financial instruments not measured on the balance sheet at fair value (codified under ASC 825, Financial Instruments); |
| § | The accounting for, and disclosure of, events that occur after the balance sheet date but before financial statements are issued or are available to be issued (codified under ASC 855, Subsequent Events); and |
| § | Consolidation of variable interest entities (codified under ASC 810). |
For additional information regarding recent accounting developments, see Note 2 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Exhibit 99.3 of this Current Report on Form 8-K.
Insurance Matters
EPCO completed its annual insurance renewal process during the second quarter of 2009. In light of recent hurricane and other weather-related events, the renewal of policies for weather-related risks resulted in significant increases in premiums and certain deductibles, as well as changes in the scope of coverage.
EPCO’s deductible for onshore physical damage from windstorms increased from $10.0 million per storm to $25.0 million per storm. EPCO’s onshore program currently provides $150.0 million per occurrence for named windstorm events compared to $175.0 million per occurrence in the prior year. With respect to offshore assets, the windstorm deductible increased significantly from $10.0 million per storm (with a one-time aggregate deductible of $15.0 million) to $75.0 million per storm. EPCO’s offshore program currently provides $100.0 million in the aggregate compared to $175.0 million in the aggregate for the prior year. For non-windstorm events, EPCO’s deductible for both onshore and offshore physical damage remained at $5.0 million per occurrence. For certain of our major offshore assets, our producer customers have agreed to provide a specified level of physical damage insurance for named windstorms. For example, the producers associated with our Independence Hub and Marco Polo platforms have agreed to cover windstorm generated physical damage costs up to $250.0 million for each platform.
Business interruption coverage in connection with a windstorm event remains in place for onshore assets, but was eliminated for offshore assets. Onshore assets covered by business interruption insurance must be out-of-service in excess of 60 days before any losses from business interruption will be covered. Furthermore, pursuant to the current policy, we will now absorb 50% of the first $50.0 million of any loss in excess of deductible amounts for our onshore assets.
For additional information regarding weather-related risks, including insurance matters in connection with Hurricanes Ivan, Katrina, Rita, Gustav and Ike, see Note 16 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Exhibit 99.3 of this Current Report on Form 8-K.
Item 3. Quantitative and Qualitative Disclosures about Market Risk.
In the course of our normal business operations, we are exposed to certain risks, including changes in interest rates, commodity prices and, to a limited extent, foreign exchange rates. In order to manage risks associated with certain identifiable and anticipated transactions, we use derivative instruments. Derivatives are financial instruments whose fair value is determined by changes in a specified benchmark such as interest rates, commodity prices or currency values. Typical derivative instruments include futures, forward contracts, swaps and other instruments with similar characteristics. Substantially all of our derivatives are used for non-trading activities. See Note 4 of the Notes to Unaudited Supplemental Condensed Consolidated Financial Statements included under Exhibit 99.3 of this Current Report on Form 8-K for additional information regarding our derivative instruments and hedging activities.
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Our exposures to market risk have not changed materially since those reported under Item 7A “Quantitative and Qualitative Disclosures About Market Risk” under Exhibit 99.1 of this Current Report on Form 8-K.
Interest Rate Derivative Instruments
We utilize interest rate swaps, treasury locks and similar derivative instruments to manage our exposure to changes in the interest rates of certain consolidated debt agreements. This strategy is a component in controlling our cost of capital associated with such borrowings.
The following tables show the effect of hypothetical price movements on the estimated fair value (“FV”) of interest rate swap portfolios at the dates presented (dollars in millions):
| Enterprise Products Partners | Swap Fair Value at | ||||||||
| Scenario | Resulting Classification | September 30, 2009 | October 20, 2009 | ||||||
| FV assuming no change in underlying interest rates | Asset | $ | 46.5 | $ | 43.7 | ||||
| FV assuming 10% increase in underlying interest rates | Asset | 40.4 | 37.7 | ||||||
| FV assuming 10% decrease in underlying interest rates | Asset | 52.7 | 49.6 | ||||||
| Duncan Energy Partners | Swap Fair Value at | ||||||||
| Scenario | Resulting Classification | September 30, 2009 | October 20, 2009 | ||||||
| FV assuming no change in underlying interest rates | Liability | $ | (6.0 | ) | $ | (6.2 | ) | ||
| FV assuming 10% increase in underlying interest rates | Liability | (5.8 | ) | (6.0 | ) | ||||
| FV assuming 10% decrease in underlying interest rates | Liability | (6.2 | ) | (6.4 | ) | ||||
The following table shows the effect of hypothetical price movements on the estimated fair value of our forward starting swap portfolio at the dates presented (dollars in millions):
| Swap Fair Value at | |||||||||
| Scenario | Resulting Classification | September 30, 2009 | October 20, 2009 | ||||||
| FV assuming no change in underlying interest rates | Asset | $ | 8.1 | $ | 10.4 | ||||
| FV assuming 10% increase in underlying interest rates | Asset | 16.4 | 20.3 | ||||||
| FV assuming 10% decrease in underlying interest rates | Asset | 0.1 | 0.5 | ||||||
Commodity Derivative Instruments
The prices of natural gas, NGLs, crude oil and certain petrochemical products are subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are beyond our control. In order to manage the price risk associated with such products, we enter into commodity derivative instruments such as forwards, basis swaps and futures contracts.
The following table shows the effect of hypothetical price movements on the estimated fair value of our natural gas marketing portfolio at the dates presented (dollars in millions):
| Portfolio Fair Value at | |||||||||
| Scenario | Resulting Classification | September 30, 2009 | October 20, 2009 | ||||||
| FV assuming no change in underlying commodity prices | Liability | $ | (2.8 | ) | $ | (4.2 | ) | ||
| FV assuming 10% increase in underlying commodity prices | Liability | (11.6 | ) | (13.1 | ) | ||||
| FV assuming 10% decrease in underlying commodity prices | Asset | 6.1 | 4.7 | ||||||
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The following table shows the effect of hypothetical price movements on the estimated fair value of our NGL and petrochemical operations portfolio at the dates presented (dollars in millions):
| Portfolio Fair Value at | |||||||||
| Scenario | Resulting Classification | September 30, 2009 | October 20, 2009 | ||||||
| FV assuming no change in underlying commodity prices | Liability | $ | (84.1 | ) | $ | (119.2 | ) | ||
| FV assuming 10% increase in underlying commodity prices | Liability | (114.6 | ) | (162.1 | ) | ||||
| FV assuming 10% decrease in underlying commodity prices | Liability | (53.6 | ) | (76.3 | ) | ||||
The following table shows the effect of hypothetical price movements on the estimated fair value of our crude oil marketing portfolio at the dates presented (dollars in millions):
| Portfolio Fair Value at | |||||||||
| Scenario | Resulting Classification | September 30, 2009 | October 20, 2009 | ||||||
| FV assuming no change in underlying commodity prices | Asset | $ | 1.1 | $ | 0.5 | ||||
| FV assuming 10% increase in underlying commodity prices | Asset | 1.3 | 0.6 | ||||||
| FV assuming 10% decrease in underlying commodity prices | Asset | 0.9 | 0.4 | ||||||
Foreign Currency Derivative Instruments
We are exposed to foreign currency exchange risk in connection with our NGL marketing activities in Canada. As a result, we could be adversely affected by fluctuations in currency rates between the U.S. dollar and Canadian dollar. In order to manage this risk, we may enter into foreign exchange purchase contracts to lock in the exchange rate.
In addition, we were exposed to foreign currency exchange risk in connection with a term loan denominated in Japanese yen. We entered into this loan agreement in November 2008 and the loan matured in March 2009. The derivative instrument used to hedge this risk was accounted for as a cash flow hedge and settled upon repayment of the loan.
At September 30, 2009, we had foreign currency derivative instruments with a notional amount of $5.5 million Canadian outstanding. The fair market value of this instrument was an asset of $0.3 million at September 30, 2009.
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