On September 6, 2006, the U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration, referred to in this report as the PHMSA, published a notice of proposed rulemaking (PHMSA 71 FR 52504) that proposed to extend certain threat-focused pipeline safety regulations to rural onshore low-stress hazardous liquid pipelines within a prescribed buffer of previously defined U.S. states. Low-stress hazardous liquid pipelines, except those in populated areas or that cross commercially navigable waterways, have not been subject to the safety regulations in PHMSA 49 C.F.R. Part 195.1. According to the PHMSA, unusually sensitive areas are areas requiring extra protection because of the presence of sole-source drinking water resources, endangered species, or other ecological resources that could be adversely affected by accidents or leaks occurring on hazardous liquid pipelines.
The notice proposed to define a category of “regulated rural onshore low-stress lines” (rural lines operating at or below 20% of specified minimum yield strength, with a diameter of eight and five-eighths inches or greater, located in or within a quarter-mile of a U.S. state) and to require operators of these lines to comply with a threat-focused set of requirements in Part 195 that already apply to other hazardous liquid pipelines. The proposed safety requirements addressed the most common threats—corrosion and third party damage—to the integrity of these rural lines. The proposal is intended to provide additional integrity protection, to avoid significant adverse environmental consequences, and to improve public confidence in the safety of unregulated low-stress lines.
Since the new notice is a proposed rulemaking in which the PHMSA will consider initial and reply comments from industry participants, it is not clear what impact the final rule will have on the business of our intrastate and interstate pipeline companies.
We operate and own a 51% ownership interest in West2East Pipeline LLC, a limited liability company that is the sole owner of Rockies Express Pipeline LLC. ConocoPhillips owns a 24% ownership interest in West2East Pipeline LLC and Sempra Energy holds the remaining 25% interest. When construction of the entire Rockies Express Pipeline project is completed, our ownership interest will be reduced to 50% at which time the capital accounts of West2East Pipeline LLC will be trued up to reflect our 50% economics in the project. According to the provisions of current accounting standards, due to the fact that we will receive 50% of the economics of the Rockies Express project on an ongoing basis, we are not considered the primary beneficiary of West2East Pipeline LLC and thus, we account for our investment under the equity method of accounting.
On August 9, 2005, the FERC approved the application of Rockies Express Pipeline LLC, formerly known as Entrega Gas Pipeline LLC, to construct 327 miles of pipeline facilities in two phases. For phase I (consisting of two pipeline segments), Rockies Express was granted authorization to construct and operate approximately 136 miles of pipeline extending northward from the Meeker Hub, located at the northern end of our TransColorado pipeline system in Rio Blanco County, Colorado, to the Wamsutter Hub in Sweetwater County, Wyoming (segment 1), and then construct approximately 191 miles of pipeline eastward to the Cheyenne Hub in Weld County, Colorado (segment 2). Construction of segments 1 and 2 has been completed, with interim service commencing on segment 1 on February 24, 2006, and full in-service of both segments on February 14, 2007. For phase II, Rockies Express was authorized to construct three compressor stations referred to as the Meeker, Big Hole and Wamsutter compressor stations. The Meeker and Wamsutter stations went into service in January 2008. Construction of the Big Hole compressor station has commenced with an expected in-service date of June 30, 2009.
On April 19, 2007, the FERC issued a final order approving the Rockies Express application for authorization to construct and operate certain facilities comprising its proposed “Rockies Express-West Project.” This project is the first planned segment extension of the Rockies Express’ currently certificated facilities, and is comprised of approximately 713 miles of 42-inch diameter pipeline extending from the Cheyenne Hub to an interconnection with
Panhandle Eastern Pipe Line located in Audrain County, Missouri. The project also includes certain improvements to existing Rockies Express facilities located to the west of the Cheyenne Hub. Construction on Rockies Express-West commenced on May 21, 2007, and interim service for up to 1.4 billion cubic feet per day of natural gas on the segment’s first 503 miles of pipe began on January 12, 2008. The project commenced deliveries to Panhandle Eastern Pipe Line at Audrain County, Missouri on the remaining 210 miles of pipe on May 20, 2008. The Rockies Express West pipeline segment transports approximately 1.5 million cubic feet per day of natural gas across five states: Wyoming, Colorado, Nebraska, Kansas and Missouri.
Rockies Express expects to conduct further hydrostatic testing of portions of its system during September 2008 to satisfy U.S. Department of Transportation testing requirements to operate at its targeted higher operating pressure. This hydrostatic test will result in the temporary outage of pipeline delivery points and an overall reduction of firm capacity available to firm shippers. By the terms of the Rockies Express FERC Gas Tariff, firm shippers are entitled to daily reservation revenue credits for non-force majeure and planned maintenance outages; however, we believe any revenue credits resulting from the temporary pipeline outage will not have a material adverse impact on our business, cash flows, financial position or results of operations.
Rockies Express Pipeline-East Project
On April 30, 2007, Rockies Express filed an application with the FERC requesting a certificate of public convenience and necessity that would authorize construction and operation of the Rockies Express-East Project. The Rockies Express-East Project will be comprised of approximately 639 miles of 42-inch diameter pipeline commencing from the terminus of the Rockies Express-West pipeline to a terminus near the town of Clarington in Monroe County, Ohio and will be capable of transporting approximately 1.8 billion cubic feet per day of natural gas.
By order issued May 30, 2008, the FERC authorized the certificate to construct the Rockies Express Pipeline-East Project. Construction commenced on the Rockies Express-East pipeline on June 26, 2008. Subject to receipt of regulatory approvals, the project is expected to begin interim service to the Lebanon Hub in Warren County, Ohio by December 31, 2008, and be fully operational in the third quarter of 2009. We are overseeing construction of the project and we will operate the pipeline.
Current market conditions for consumables, labor and construction equipment along with certain provisions in the final Environmental Impact Study have resulted in increased costs for the project and have impacted certain projected completion dates. For example, our current estimate of total construction costs on the Rockies Express Pipeline is approximately $5.6 billion (consistent with our July 16, 2008 second quarter earnings press release), and we now expect that interim service on the East Project will begin by year-end to the Lebanon Hub, as opposed to our initial projection of Clarington, Ohio.
TransColorado Pipeline
On April 19, 2007, the FERC issued an order approving TransColorado Gas Transmission Company LLC’s application for authorization to construct and operate certain facilities comprising its proposed “Blanco-Meeker Expansion Project.” This project provides for the transportation of up to approximately 250 million cubic feet per day of natural gas from the Blanco Hub area in San Juan County, New Mexico through TransColorado’s existing interstate pipeline for delivery to the Rockies Express Pipeline at an existing point of interconnection located in the Meeker Hub in Rio Blanco County, Colorado. Construction commenced on May 9, 2007, and the project was completed and entered service January 1, 2008.
Kinder Morgan Interstate Gas Transmission Pipeline
On August 6, 2007, Kinder Morgan Interstate Gas Transmission Pipeline, referred to in this report as KMIGT, filed, in FERC Docket CP07-430, for regulatory approval to construct and operate a 41-mile, $30 million natural gas pipeline, referred to in this report as the Colorado Lateral, from the Cheyenne Hub to markets in and around Greeley, Colorado. When completed, the Colorado Lateral will provide firm transportation of up to 55 million cubic feet per day to a local utility under long-term contract. The FERC issued a draft environmental assessment on the project on January 11, 2008, and comments on the project were received February 11, 2008. On February 21, 2008, the FERC granted the certificate application. On July 8, 2008, in response to a rehearing request by Public Service Company of Colorado, referred to in this report as PSCo, the FERC granted rehearing and denied KMIGT recovery in initial transportation rates $6.2 million in costs associated with non-jurisdictional laterals constructed by KMIGT to serve Atmos. The recourse rate adjustment is not expected to have any material effect on the negotiated rate paid by Atmos to KMIGT or the economics of the project. On July 25, 2008, KMIGT filed an amendment to its certificate application, seeking authorization to revise its initial rates for transportation service on the Colorado Lateral to reflect updated construction costs for jurisdictional mainline facilities.
PSCo, a competitor serving markets off the Colorado Lateral, also filed a complaint before the State of Colorado Public Utilities Commission against Atmos, the anchor shipper on the project. The Colorado Public Utilities Commission conducted a hearing on April 14, 2008 on the complaint, which is pending a ruling. On June 9, 2008, PSCo also filed before the Colorado Public Utilities Commission seeking a temporary cease and desist order to halt construction of the lateral facilities being constructed by KMIGT to serve
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Atmos. Atmos filed a response to that motion on June 24, 2008. By order dated June 27, 2008 an administrative law judge for the Colorado Public Utilities Commission denied PSCo’s request for cease and desist. The Colorado Lateral facilities are currently planned to be in service by October 1, 2008.
On December 21, 2007, KMIGT filed, in Docket CP 08-44, for approval to expand its system in Nebraska to serve incremental ethanol and industrial load. No protests to the application were filed and the project was approved by the FERC. Construction commenced on April 9, 2008. These facilities are currently planned to be in service by October 1, 2008.
Kinder Morgan Louisiana Pipeline
On September 8, 2006, in FERC Docket No. CP06-449-000, we filed an application with the FERC requesting approval to construct and operate our Kinder Morgan Louisiana Pipeline. The natural gas pipeline will extend approximately 135 miles from Cheniere’s Sabine Pass liquefied natural gas terminal in Cameron Parish, Louisiana, to various delivery points in Louisiana and will provide interconnects with many other natural gas pipelines, including Natural Gas Pipeline Company of America LLC. The project is supported by fully subscribed capacity and long-term customer commitments with Chevron and Total. The entire project cost is approximately $594 million, and it is expected to be in service by April 1, 2009.
On March 15, 2007, the FERC issued a preliminary determination that the authorizations requested, subject to some minor modifications, will be in the public interest. This order does not consider or evaluate any of the environmental issues in this proceeding. On April 19, 2007, the FERC issued the final EIS, which addressed the potential environmental effects of the construction and operation of the Kinder Morgan Louisiana Pipeline. The final EIS was prepared to satisfy the requirements of the National Environmental Policy Act. It concluded that approval of the Kinder Morgan Louisiana Pipeline project would have limited adverse environmental impacts. On June 22, 2007, the FERC issued an order granting construction and operation of the project. Kinder Morgan Louisiana Pipeline officially accepted the order on July 10, 2007.
On July 11, 2008, Kinder Morgan Louisiana Pipeline filed an amendment to its certificate application, seeking authorization to revise its initial rates for transportation service on the Kinder Morgan Louisiana Pipeline system to reflect updated construction costs for the project.
Midcontinent Express Pipeline
On October 9, 2007, in Docket No. CP08-6-000, Midcontinent Express Pipeline LLC filed an application with the FERC requesting a certificate of public convenience and necessity that would authorize construction and operation of the approximate 500-mile Midcontinent Express Pipeline natural gas transmission system.
The Midcontinent Express Pipeline will create long-haul, firm transportation takeaway capacity either directly or indirectly connected to natural gas producing regions located in Texas, Oklahoma and Arkansas. The pipeline will originate in southeastern Oklahoma and traverse east through Texas, Louisiana, Mississippi, and terminate at an interconnection with the Transco Pipeline near Butler, Alabama. The Midcontinent Express Pipeline is a 50/50 joint venture between us and Energy Transfer Partners, L.P., and it has a total capital cost of approximately $1.45 billion (consistent with our July 16, 2008 second quarter earnings press release). Initial design capacity for the pipeline was 1.5 billion cubic feet of natural gas per day, which was fully subscribed with long-term binding commitments from creditworthy shippers. A successful binding open season was recently completed which will increase the main segment of the pipeline’s capacity to 1.8 billion cubic feet per day, subject to regulatory approval.
On July 25, 2008, the FERC approved the application made by Midcontinent Express Pipeline to construct and operate the 500-mile Midcontinent Express Pipeline natural gas transmission system along with the lease of 272 million cubic feet of capacity on the Oklahoma intrastate system of Enogex Inc. Midcontinent Express Pipeline accepted the FERC Certificate on July 30, 2008. Construction of the pipeline is expected to commence in the September of 2008 and be in service by the second quarter of 2009.
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Kinder Morgan Liquid Terminals
With regard of to six of our liquids terminals, we have undertaken a U.S. Department of Transportation compliance program for certain of our tanks and internal piping. We anticipate the program will call for an incremental $3 million to $5 million of annual capital spending over the next six to ten years to improve and/or add facilities. These improvements will allow the tanks and piping previously considered as in-plant piping to conduct DOT jurisdictional transfers of products.
15. Recent Accounting Pronouncements
EITF 04-5
In June 2005, the Emerging Issues Task Force reached a consensus on Issue No. 04-5, or EITF 04-5, “Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights.” EITF 04-5 provides guidance for purposes of assessing whether certain limited partners rights might preclude a general partner from controlling a limited partnership.
For general partners of all new limited partnerships formed, and for existing limited partnerships for which the partnership agreements are modified, the guidance in EITF 04-5 is effective after June 29, 2005. For general partners in all other limited partnerships, the guidance is effective no later than the beginning of the first reporting period in fiscal years beginning after December 15, 2005 (January 1, 2006, for us). The adoption of EITF 04-5 did not have an effect on our consolidated financial statements.
Nonetheless, as a result of EITF 04-5, as of January 1, 2006, our financial statements are consolidated into the consolidated financial statements of Knight. Notwithstanding the consolidation of our financial statements into the consolidated financial statements of Knight pursuant to EITF 04-5, Knight is not liable for, and its assets are not available to satisfy, the obligations of us and/or our subsidiaries and vice versa. Responsibility for payments of obligations reflected in our or Knight’s financial statements is a legal determination based on the entity that incurs the liability. The determination of responsibility for payment among entities in our consolidated group of subsidiaries was not impacted by the adoption of EITF 04-5.
FIN 48
In July 2006, the FASB issued Interpretation (FIN) No. 48, “Accounting for Uncertainty in Income Taxes—an Interpretation of FASB Statement No. 109,” which became effective January 1, 2007. FIN 48 addressed the determination of how tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. Under FIN 48, we must recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based not only on the technical merits of the tax position based on tax law, but also the past administrative practices and precedents of the taxing authority. The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate resolution.
Our adoption of FIN No. 48 on January 1, 2007 did not result in a cumulative effect adjustment to “Partners’ Capital” on our consolidated balance sheet. Our continuing practice is to recognize interest and/or penalties related to income tax matters in income tax expense, and as of January 1, 2007, we had $1.1 million of accrued interest and no accrued penalties. As of December 31, 2007 (i) we had$0.6 million of accrued interest and no accrued penalties; (ii) we believe it is reasonably possible that our liability for unrecognized tax benefits will decrease by approximately$1.2 million during the next twelve months; and (iii) we believe approximately$5.4 million of the total$6.3 million of unrecognized tax benefits on our consolidated balance sheet as of December 31, 2007 would affect our effective income tax rate in future periods in the event those unrecognized tax benefits were recognized. In addition, we have U.S. and state tax years open to examination for the periods2003 through 2007. As of June 30, 2008, there have been no material changes to our December 31, 2007 liability for unrecognized tax benefits, interest, penalties or to our estimated change in the liability during 2008.
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SFAS No. 157
For information on SFAS No. 157, see Note 10 “—SFAS No. 157.”
SFAS No. 159
On February 15, 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities.” This Statement provides companies with an option to report selected financial assets and liabilities at fair value. The Statement’s objective is to reduce both complexity in accounting for financial instruments and the volatility in earnings caused by measuring related assets and liabilities differently. The Statement also establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities.
SFAS No. 159 requires companies to provide additional information that will help investors and other users of financial statements to more easily understand the effect of the company’s choice to use fair value on its earnings. It also requires entities to display the fair value of those assets and liabilities for which the company has chosen to use fair value on the face of the balance sheet. The Statement does not eliminate disclosure requirements included in other accounting standards, including requirements for disclosures about fair value measurements included in SFAS No. 157, discussed in Note 10 “—SFAS No. 157”, and SFAS No. 107 “Disclosures about Fair Value of Financial Instruments.”
This Statement was adopted by us effective January 1, 2008, at which time no financial assets or liabilities, not previously required to be recorded at fair value by other authoritative literature, were designated to be recorded at fair value. As such, the adoption of this Statement did not have any impact on our financial statements.
SFAS 141(R)
On December 4, 2007, the FASB issued SFAS No. 141R (revised 2007), “Business Combinations.” Although this statement amends and replaces SFAS No. 141, it retains the fundamental requirements in SFAS No. 141 that (i) the purchase method of accounting be used for all business combinations; and (ii) an acquirer be identified for each business combination. SFAS No. 141R defines the acquirer as the entity that obtains control of one or more businesses in the business combination and establishes the acquisition date as the date that the acquirer achieves control. This Statement applies to all transactions or other events in which an entity (the acquirer) obtains control of one or more businesses (the acquiree), including combinations achieved without the transfer of consideration; however, this Statement does not apply to a combination between entities or businesses under common control.
Significant provisions of SFAS No. 141R concern principles and requirements for how an acquirer (i) recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree; (ii) recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase; and (iii) determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination.
This Statement applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008 (January 1, 2009 for us). Early adoption is not permitted. We are currently reviewing the effects of this Statement.
SFAS No. 160
On December 4, 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51.” This Statement changes the accounting and reporting for noncontrolling interests in consolidated financial statements. A noncontrolling interest, sometimes referred to as a minority interest, is the portion of equity in a subsidiary not attributable, directly or indirectly, to a parent.
Specifically, SFAS No. 160 establishes accounting and reporting standards that require (i) the ownership interests in subsidiaries held by parties other than the parent to be clearly identified, labeled, and presented in the
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consolidated balance sheet within equity, but separate from the parent’s equity; (ii) the equity amount of consolidated net income attributable to the parent and to the noncontrolling interest to be clearly identified and presented on the face of the consolidated income statement (consolidated net income and comprehensive income will be determined without deducting minority interest, however, earnings-per-share information will continue to be calculated on the basis of the net income attributable to the parent’s shareholders); and (iii) changes in a parent’s ownership interest while the parent retains its controlling financial interest in its subsidiary to be accounted for consistently and similarly—as equity transactions.
This Statement is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008 (January 1, 2009 for us). Early adoption is not permitted. SFAS No. 160 is to be applied prospectively as of the beginning of the fiscal year in which it is initially applied, except for its presentation and disclosure requirements, which are to be applied retrospectively for all periods presented. We are currently reviewing the effects of this Statement.
SFAS No. 161
On March 19, 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and hedging Activities.” This Statement amends SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” and is intended to help investors better understand how derivative instruments and hedging activities affect an entity’s financial position, financial performance and cash flows through enhanced disclosure requirements. The enhanced disclosures include, among other things, (i) a tabular summary of the fair value of derivative instruments and their gains and losses; (ii) disclosure of derivative features that are credit-risk–related to provide more information regarding an entity’s liquidity; and (iii) cross-referencing within footnotes to make it easier for financial statement users to locate important information about derivative instruments.
This Statement is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008 (January 1, 2009 for us). Early application is encouraged. We are currently reviewing the effects of this Statement.
EITF 07-4
In March 2008, the Emerging Issues Task Force reached a consensus on Issue No. 07-4, or EITF 07-4, “Application of the Two-Class Method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships.” EITF 07-4 provides guidance for how current period earnings should be allocated between limited partners and a general partner when the partnership agreement contains incentive distribution rights.
This Issue is effective for fiscal years beginning after December 15, 2008 (January 1, 2009 for us), and interim periods within those fiscal years. Earlier application is not permitted, and the guidance in this Issue is to be applied retrospectively for all financial statements presented. We are currently reviewing the effects of this Issue.
FASB Staff Position No. FAS 142-3
On April 25, 2008, the FASB issued FASB Staff Position FAS 142-3 “ Determination of the Useful Life of Intangible Assets.” This Staff Position amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142, “Goodwill and Other Intangible Assets”. This Staff Position is effective for financial statements issued for fiscal years beginning after December 15, 2008 (January 1, 2009 for us), and interim periods within those fiscal years. Early adoption is prohibited. We are currently reviewing the effects of this Staff Position.
SFAS No. 162
On May 9, 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles.” This Statement is intended to improve financial reporting by identifying a consistent framework, or hierarchy, for selecting accounting principles to be used in preparing financial statements that are presented in conformity with U.S. generally accepted accounting principles, referred to in this note as GAAP, for nongovernmental entities.
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Statement No. 162 establishes that the GAAP hierarchy should be directed to entities because it is the entity (not its auditor) that is responsible for selecting accounting principles for financial statements that are presented in conformity with GAAP. Statement No. 162 is effective 60 days following the U.S. Securities and Exchange Commission’s approval of the Public Company Accounting Oversight Board Auditing amendments to AU Section 411, “The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles,” and is only effective for nongovernmental entities. We do not expect the adoption of this Statement to have any effect on our consolidated financial statements.
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
The following information should be read in conjunction with (i) our accompanying interim consolidated financial statements and related notes (included elsewhere in this report); and (ii) our consolidated financial statements, related notes and management’s discussion and analysis of financial condition and results of operations included in our 2007 Form 10-K.
In addition, as discussed in Note 2 to our consolidated financial statements included elsewhere in this report, our financial statements reflect:
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| ▪ the April 30, 2007 transfer of Trans Mountain as if such transfer had taken place on January 1, 2006, the effective date of common control pursuant to generally accepted accounting principles. The financial information contained in this Management’s Discussion and Analysis of Financial Condition and Results of Operations includes the financial results of Trans Mountain for all periods subsequent to January 1, 2006; and |
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| ▪ the reclassifications necessary to reflect the results of our North System as discontinued operations. However, due to the fact that the sale of our North System does not change the structure of our internal organization in a manner that causes a change to our reportable business segments pursuant to the provisions of SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information,” we have included the North System’s financial results within our Products Pipelines business segment disclosures presented in this report for the three and six months ended June 30, 2007. |
Critical Accounting Policies and Estimates
Accounting standards require information in financial statements about the risks and uncertainties inherent in significant estimates, and the application of generally accepted accounting principles involves the exercise of varying degrees of judgment. Certain amounts included in or affecting our consolidated financial statements and related disclosures must be estimated, requiring us to make certain assumptions with respect to values or conditions that cannot be known with certainty at the time the financial statements are prepared. These estimates and assumptions affect the amounts we report for our assets and liabilities, our revenues and expenses during the reporting period, and our disclosure of contingent assets and liabilities at the date of our financial statements. We routinely evaluate these estimates, utilizing historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our estimates.
Further information about us and information regarding our accounting policies and estimates that we consider to be “critical” can be found in our 2007 Form 10-K. There have not been any significant changes in these policies and estimates during the six months ended June 30, 2008; however, during the second quarter of 2008, we changed the date of our annual goodwill impairment test date to May 31 of each year. This change constitutes a change in the method of applying an accounting principle, as discussed in paragraph 4 of SFAS No. 154, “Accounting Changes and Error Corrections.” For more information on this change, see Note 6 to our consolidated financial statements included elsewhere in this report.
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Results of Operations
Consolidated
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June 30, | | Earnings
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Earnings before depreciation, depletion and amortization
expense and amortization of excess cost of equity investments(a) | | | |
Products Pipelines(b) | | $ | 137.6 | | $ | 147.6 | | $ | (10.0 | ) | | (7 | )% |
Natural Gas Pipelines(c) | | | 182.5 | | | 144.6 | | | 37.9 | | | 26 | % |
CO2 | | | 216.6 | | | 128.9 | | | 87.7 | | | 68 | % |
Terminals | | | 140.4 | | | 110.1 | | | 30.3 | | | 28 | % |
Trans Mountain(d) | | | 33.4 | | | 29.6 | | | 3.8 | | | 13 | % |
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Segment earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments | | | 710.5 | | | 560.8 | | | 149.7 | | | 27 | % |
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Depreciation, depletion and amortization expense(e) | | | (165.6 | ) | | (135.8 | ) | | (29.8 | ) | | (22 | )% |
Amortization of excess cost of equity investments | | | (1.5 | ) | | (1.5 | ) | | — | | | — | |
Interest and corporate administrative expenses(f) | | | (181.2 | ) | | (190.8 | ) | | 9.6 | | | 5 | % |
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Net income | | $ | 362.2 | | $ | 232.7 | | $ | 129.5 | | | 56 | % |
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June 30, | | | |
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Increase/(decrease) | |
| | 2008 | | 2007 | | |
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Earnings before depreciation, depletion and amortization
expense and amortization of excess cost of equity investments(a) | | | |
Products Pipelines(g) | | $ | 278.3 | | $ | 290.8 | | $ | (12.5 | ) | | (4 | )% |
Natural Gas Pipelines(h) | | | 370.7 | | | 279.3 | | | 91.4 | | | 33 | % |
CO2 | | | 416.4 | | | 254.3 | | | 162.1 | | | 64 | % |
Terminals(i) | | | 266.2 | | | 210.6 | | | 55.6 | | | 26 | % |
Trans Mountain(j) | | | 63.6 | | | (328.6 | ) | | 392.2 | | | 119 | % |
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Segment earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments | | | 1,395.2 | | | 706.4 | | | 688.8 | | | 98 | % |
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Depreciation, depletion and amortization expense(k) | | | (323.7 | ) | | (268.5 | ) | | (55.2 | ) | | (21 | )% |
Amortization of excess cost of equity investments | | | (2.9 | ) | | (2.9 | ) | | — | | | — | |
Interest and corporate administrative expenses(l) | | | (359.7 | ) | | (351.8 | ) | | (7.9 | ) | | (2 | )% |
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Net income | | $ | 708.9 | | $ | 83.2 | | $ | 625.7 | | | 752 | % |
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(a) | Includes revenues, earnings from equity investments, allocable interest income and other, net, less operating expenses, allocable income taxes, and other expense (income). Operating expenses include natural gas purchases and other costs of sales, operations and maintenance expenses, fuel and power expenses, and taxes, other than income taxes. |
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(b) | 2008 amount includes a $0.8 million gain from the 2007 sale of our North System, and a $0.1 million increase in income resulting from unrealized foreign currency gains on long-term debt transactions. 2007 amount includes a $2.2 million increase in expense associated with environmental liability adjustments, and a $0.8 million increase in income resulting from unrealized foreign currency gains on long-term debt transactions. |
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(c) | 2008 amount includes a $13.1 million increase in expense resulting from unrealized mark to market losses due to the discontinuance of hedge accounting at Casper Douglas, and a $13.0 million gain from the sale of our 25% equity ownership interest in Thunder Creek Gas Services, LLC. |
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(d) | 2007 amount includes earnings of $9.0 million for a period prior to our acquisition date of April 30, 2007. |
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(e) | 2007 amount includes Trans Mountain expenses of $1.6 million for a period prior to our acquisition date of April 30, 2007. |
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(f) | Includes unallocated interest income and income tax expense, interest and debt expense, general and administrative expenses (including unallocated litigation and environmental expenses) and minority interest expense. 2008 amount includes (i) a $1.4 million increase in non-cash compensation expense, allocated to us from Knight. We do not have any obligation, nor do we expect to pay any amounts related to this expense; and (ii) a $0.5 million increase in imputed interest expense related to our January 1, 2007 Cochin Pipeline acquisition. 2007 amount includes (i) a $21.2 million increase in non-cash compensation expense, allocated to us from Knight. Knight was responsible for the payment of this expense; (ii) a |
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| combined $1.4 million increase in expense, related to Trans Mountain interest and general and administrative expenses for a period prior to our acquisition date of April 30, 2007; (iii) a $1.1 million increase in expense for certain Trans Mountain acquisition costs; (iv) a $0.6 million increase in imputed interest expense related to our January 1, 2007 Cochin Pipeline acquisition; and (v) a total $0.2 million decrease in minority interest expense, related to the minority interest effect from all of the three month 2007 items previously listed in these footnotes. |
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(g) | 2008 amount includes a $1.3 million gain from the 2007 sale of our North System, and a $0.7 million decrease in income resulting from unrealized foreign currency losses on long-term debt transactions. 2007 amount includes a $2.2 million increase in expense associated with environmental liability adjustments, and a $0.8 million increase in income resulting from unrealized foreign currency gains on long-term debt transactions. |
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(h) | 2008 amount includes a $13.1 million increase in expense resulting from unrealized mark to market losses due to the discontinuance of hedge accounting at Casper Douglas, and a $13.0 million gain from the sale of our 25% equity ownership interest in Thunder Creek Gas Services, LLC. Beginning in the second quarter of 2008, our Casper and Douglas gas processing operations discontinued hedge accounting. 2007 amount includes an expense of $1.0 million reflecting our portion of a loss from the early extinguishment of debt by Red Cedar Gathering Company. |
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(i) | 2007 amount includes an increase in income of $1.8 million from property casualty gains associated with the 2005 hurricane season. |
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(j) | 2007 amount includes losses of $349.2 million for periods prior to our acquisition date of April 30, 2007. This amount includes a $377.1 million impairment expense, associated with a non-cash reduction in the carrying value of Trans Mountain’s goodwill. |
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(k) | 2007 amount includes Trans Mountain expenses of $6.3 million for periods prior to our acquisition date of April 30, 2007. |
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(l) | 2008 amount includes (i) a $2.8 million increase in non-cash compensation expense, allocated to us from Knight. We do not have any obligation, nor do we expect to pay any amounts related to this expense; and (ii) a $1.0 million increase in imputed interest expense related to our January 1, 2007 Cochin Pipeline acquisition. 2007 amount includes (i) a $23.4 million increase in non-cash compensation expense, allocated to us from Knight. We do not have any obligation, nor did we pay any amounts related to this expense; (ii) a combined $6.7 million increase in expense related to Trans Mountain interest and general and administrative expenses for periods prior to our acquisition date of April 30, 2007; (iii) a $1.7 million increase in insurance expense associated with the 2005 hurricane season; (iv) a $1.2 million increase in imputed interest expense related to our January 1, 2007 Cochin Pipeline acquisition; (v) a $1.1 million expense for certain Trans Mountain acquisition costs; and (vi) a total $3.5 million decrease in minority interest expense related to the minority interest effect from all of the six month 2007 items previously listed in these footnotes. |
Benefitting from higher revenues from crude oil, carbon dioxide, and natural gas plant products sales, improved margins from our Texas intrastate pipeline, the start-up of REX West, and incremental earnings from expanded bulk and liquids terminal operations, our consolidated net income for the quarterly period ended June 30, 2008 was $362.2 million ($0.65 per diluted limited partner unit), compared to $232.7 million ($0.36 per diluted limited partner unit) for the quarterly period ending June 30, 2007. The increase in quarterly net income in 2008 was tempered by such factors as lower gasoline demand, due to higher prices and a sluggish economy, and increases in fuel costs.
For the six months ended June 30, 2008 and 2007, we earned net income of $708.9 million and $83.2 million, respectively; however, our 2007 year-to-date net income included an impairment expense of $377.1 million associated with a non-cash reduction in the carrying value of Trans Mountain’s goodwill. The goodwill impairment charge was recognized by Knight in March 2007, and following our purchase of Trans Mountain from Knight on April 30, 2007, the financial results of Trans Mountain since January 1, 2006, including the impact of the goodwill impairment, are reflected in our results. For more information on this acquisition and the goodwill impairment, see Notes 2 and 6 to our consolidated financial statements included elsewhere in this report.
Because our partnership agreement requires us to distribute 100% of our available cash to our partners on a quarterly basis (available cash consists primarily of all our cash receipts, less cash disbursements and changes in reserves), we consider each period’s earnings before all non-cash depreciation, depletion and amortization expenses, including amortization of excess cost of equity investments, to be an important measure of our success in maximizing returns to our partners. We also use segment earnings before depreciation, depletion and amortization expenses (defined in the table above and sometimes referred to in this report as EBDA) internally as a measure of profit and loss used for evaluating segment performance and for deciding how to allocate resources to our five reportable business segments.
For the second quarter of 2008, total segment earnings before depreciation, depletion and amortization increased $149.7 million (27%), when compared to the second quarter of 2007. Combined, the certain items described in the footnotes to the tables above decreased total segment earnings before depreciation, depletion and amortization by $6.8 million, when compared to the second quarter last year. The remaining $156.5 million (28%) quarter-to-quarter
59
increase was driven by better performance from our CO2, Natural Gas Pipelines, Terminals and Trans Mountain business segments.
For the comparable six month periods, our total segment earnings before depreciation, depletion and amortization increased $688.8 million (98%) in 2008. The certain items described in the footnotes to the table above (including the goodwill impairment expense) accounted for $350.3 million of the increase. The remaining $338.5 million (32%) increase in period-to-period segment earnings before depreciation, depletion and amortization resulted from incremental earnings from our CO2, Natural Gas Pipelines, Terminals and Trans Mountain business segments.
Products Pipelines
| | | | | | | | | | | | | |
| | Three Months Ended
June 30, | | Six Months Ended
June 30, | |
| | 2008 | | 2007 | | 2008 | | 2007 | |
| |
| |
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| | (In millions, except operating statistics) | |
Revenues | | $ | 198.6 | | $ | 215.1 | | $ | 396.9 | | $ | 425.4 | |
Operating expenses(a) | | | (68.5 | ) | | (77.8 | ) | | (130.9 | ) | | (150.2 | ) |
Other income(b) | | | 0.6 | | | 2.8 | | | 1.0 | | | 2.3 | |
Earnings from equity investments | | | 8.7 | | | 9.0 | | | 16.2 | | | 16.4 | |
Interest income and Other, net-income (expense)(c) | | | 1.3 | | | 4.1 | | | 1.8 | | | 5.3 | |
Income tax benefit (expense) | | | (3.1 | ) | | (5.6 | ) | | (6.7 | ) | | (8.4 | ) |
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Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments | | $ | 137.6 | | $ | 147.6 | | $ | 278.3 | | $ | 290.8 | |
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Gasoline (MMBbl) | | | 100.5 | | | 113.6 | | | 198.4 | | | 220.8 | |
Diesel fuel (MMBbl) | | | 41.6 | | | 42.0 | | | 80.2 | | | 80.1 | |
Jet fuel (MMBbl) | | | 29.9 | | | 31.9 | | | 59.6 | | | 62.1 | |
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Total refined product volumes (MMBbl) | | | 172.0 | | | 187.5 | | | 338.2 | | | 363.0 | |
Natural gas liquids (MMBbl) | | | 6.1 | | | 5.9 | | | 13.0 | | | 15.5 | |
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Total delivery volumes (MMBbl)(d) | | | 178.1 | | | 193.4 | | | 351.2 | | | 378.5 | |
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(a) | 2008 amounts include a $3.0 million decrease in expense to our Pacific operations and a $3.0 million increase in expense to our Calnev Pipeline associated with offsetting legal liability adjustments. 2007 amounts include an increase in expense of $2.2 million associated with environmental liability adjustments. |
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(b) | Three and six month 2008 amounts include gains of $0.8 and $1.3 million, respectively, from the 2007 sale of our North System. |
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(c) | Three and six month 2008 amounts include an increase in income of $0.1 million and a decrease in income of $0.7 million, respectively, resulting from unrealized foreign currency losses on long-term debt transactions. 2007 amounts include an increase in income of $0.8 million resulting from unrealized foreign currency gains on long-term debt transactions. |
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(d) | Includes Pacific, Plantation, Calnev, Central Florida, Cochin and Cypress pipeline volumes. |
Combined, the certain items described in the footnotes to the table above increased our Products Pipelines’ segment earnings before depreciation, depletion and amortization expenses by $2.3 million and $2.0 million, respectively, when compared to the second quarter and first six months of last year. Following is information related to the increases and decreases, in the second quarter and first six months of 2008 compared to the same periods of 2007, of the segment’s remaining changes in earnings before depreciation, depletion and amortization expense (EBDA); and changes in operating revenues:
60
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Three months ended June 30, 2008 versus Three months ended June 30, 2007 |
|
| | EBDA
increase/(decrease) | | Revenues
increase/(decrease) | |
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| | (In millions, except percentages) | |
North System | | $ | (7.7 | ) | | (100 | )% | $ | (13.5 | ) | | (100 | )% |
Pacific operations | | | (4.6 | ) | | (7 | )% | | (0.4 | ) | | — | |
West Coast Terminals | | | (2.4 | ) | | (17 | )% | | (0.2 | ) | | (1 | )% |
Cochin Pipeline System | | | (1.3 | ) | | (18 | )% | | (5.7 | ) | | (34 | )% |
Central Florida Pipeline | | | 2.1 | | | 23 | % | | 2.0 | | | 18 | % |
Southeast Terminals | | | 1.0 | | | 9 | % | | 0.4 | | | 2 | % |
All other (including eliminations) | | | 0.6 | | | 2 | % | | 0.9 | | | 2 | % |
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| | | | |
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| | | | |
Total Products Pipelines | | $ | (12.3 | ) | | (8 | )% | $ | (16.5 | ) | | (8 | )% |
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| | | | | | | | | | | | | |
Six months ended June 30, 2008 versus Six months ended June 30, 2007 |
|
| | EBDA
increase/(decrease) | | Revenues
increase/(decrease) | |
| |
| |
| |
| | (In millions, except percentages) | |
North System | | $ | (17.1 | ) | | (100 | )% | $ | (26.7 | ) | | (100 | )% |
Pacific operations | | | (1.4 | ) | | (1 | )% | | 2.6 | | | 1 | % |
West Coast Terminals | | | (2.3 | ) | | (9 | )% | | 1.0 | | | 3 | % |
Cochin Pipeline System | | | (1.8 | ) | | (10 | )% | | (12.5 | ) | | (33 | )% |
Central Florida Pipeline | | | 2.9 | | | 16 | % | | 2.4 | | | 11 | % |
Southeast Terminals | | | 3.4 | | | 17 | % | | 2.0 | | | 5 | % |
All other (including eliminations) | | | 1.8 | | | 3 | % | | 2.7 | | | 3 | % |
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Total Products Pipelines | | $ | (14.5 | ) | | (5 | )% | $ | (28.5 | ) | | (7 | )% |
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The period-to-period decreases in both segment earnings before depreciation, depletion and amortization expenses and segment revenues attributable to our North System were due to our October 2007 divestiture of the approximate 1,600-mile interstate common carrier liquids pipeline system and our 50% ownership interest in the Heartland Pipeline Company (collectively referred to in this report as our North System) to ONEOK Partners, L.P. Following purchase price adjustments, we received approximately $295.7 million in cash for the sale of our North System. We accounted for our North System business as a discontinued operation pursuant to generally accepted accounting principals which require that our income statement be formatted to separate the divested business from our continuing operations; however, as discussed above, due to the fact that the sale of our North System does not change the structure of our internal organization in a manner that causes a change to our reportable business segments, we have included the North System’s operating results within our Products Pipelines business segment disclosures presented in this report for all periods presented in this discussion and analysis. This decision was based on the way our management organizes segments internally to make operating decisions and assess performance.
We earned net income from our North System (discontinued operations) of $5.4 million and $12.5 million, respectively, for the three and six months ended June 30, 2007, and we recognized a $152.8 million gain on disposal of the North System in the fourth quarter of 2007. We also recorded incremental gain adjustments of $0.8 million and $1.3 million, respectively, in the second quarter and first six months of 2008. For more information regarding this transaction, see Note 2 to our consolidated financial statements included elsewhere in this report. For information on our reconciliation of segment information with our consolidated general-purpose financial statements, see Note 11 to our consolidated financial statements included elsewhere in this report.
Both period-to-period decreases in earnings before depreciation, depletion and amortization from our Pacific operations were driven by a $6.6 million (48%) increase in operating and maintenance expenses in the second quarter of 2008, relative to the second quarter last year. The increase was primarily due to increased major maintenance and pipeline integrity expenses (resulting mainly from project timing), lower capitalized overhead credits, and incremental expenses resulting from environmental liability adjustments.
61
The higher operating expenses were partially offset by lower fuel and power expenses, due largely to decreases of 8% and 5%, respectively, in total mainline delivery volumes (primarily gasoline volumes). For the comparable quarters, our Pacific operations’ revenues were essentially flat, as the drop in mainline delivery volumes were offset by higher average tariff rates; for the comparable six month periods, total operating revenues increased a slight 1% ($2.6 million), driven by higher average tariff rates in 2008 on refined petroleum products deliveries to Arizona and to various West Coast military bases, due to a more favorable mix of higher-rate East Line volumes versus lower-rate West Line volumes.
The decreases in earnings before depreciation, depletion and amortization expenses and in revenues from our Cochin Pipeline were largely attributable to lower deliveries of propane volumes in 2008; however, we believe the issue was partly mitigated through the implementation of a shipper provided line-fill program that began April 1, 2008. Going forward, we expect the line-fill program, along with increased shipper sales, exchange and marketing activities, to help increase propane volumes.
The decreases in earnings from our West Coast terminal operations were mainly due to incremental gains from asset sales in the second quarter of 2007. In June 2007, we recognized a $3.6 million gain on the sale of our interest in the Black Oil pipeline system in Los Angeles, California. Although total revenues from our West Coast terminals dropped a slight $0.2 million (1%) in the second quarter of 2008, when compared to the second quarter a year ago, revenues increased $1.0 million (3%) in the first half of 2008, driven by higher petroleum throughput revenues from our combined Carson, California/Los Angeles Harbor terminal system, largely due to the completion of storage expansion projects since the middle of 2007.
All of the of the remaining assets in our Products Pipelines business segment produced higher earnings before depreciation, depletion and amortization expenses in the second quarter and first six months of 2008, when compared to the same periods last year, and the primary increases were related to our Central Florida Pipeline and our Southeast liquids terminal operations. These two operations benefitted from increased demand for ethanol and from our completion of a number of capital expansion projects that modified and upgraded infrastructure, enabling us to provide additional ethanol related services to our customers.
In addition, the increases in earnings from our Central Florida Pipeline were also related to higher product delivery revenues, driven by an increase in the average tariff per barrel moved as a result of a mid-year 2007 tariff rate increase on product deliveries. The period-to-period earnings increases from our Southeast terminal operations were also driven by improved margins on liquids inventory sales.
Although combined segment revenues from refined petroleum products deliveries increased approximately 2% in the second quarter of 2008, when compared to the second quarter last year, the segment’s volumes were clearly impacted by reductions in demand driven by higher crude oil and product prices and by weaker economic conditions. Total refined products delivery volumes decreased 8.3% when compared to the second quarter of 2007, reflecting an 11.5% drop in gasoline volumes, a 6.3% drop in jet fuel volumes, and a slight 1% decline in diesel fuel volumes. The segment’s deliveries of natural gas liquids increased 3.4% in the second quarter of 2008, primarily due to a strong performance from our Cypress Pipeline. For the first six months of 2008, total refined products revenues were up 2.7%, compared to the first half of 2007, but total refined product delivery volumes were down 6.8%. Excluding Plantation, total refined products delivery volumes decreased 5.0% in the first half of 2008 versus the first half of 2007.
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Natural Gas Pipelines
| | | | | | | | | | | | | |
| | Three Months Ended
June 30, | | Six Months Ended
June 30, | |
| | 2008 | | 2007 | | 2008 | | 2007 | |
| |
| |
| |
| | (In millions, except operating statistics) | |
Revenues | | $ | 2,644.7 | | $ | 1,693.1 | | $ | 4,557.2 | | $ | 3,228.5 | |
Operating expenses(a) | | | (2,515.6 | ) | | (1,555.4 | ) | | (4,260.7 | ) | | (2,961.1 | ) |
Other income | | | 2.7 | | | 2.7 | | | 2.7 | | | 2.7 | |
Earnings from equity investments(b) | | | 31.3 | | | 3.8 | | | 54.8 | | | 10.2 | |
Interest income and Other, net-income (expense)(c) | | | 17.7 | | | 0.2 | | | 17.9 | | | 0.2 | |
Income tax benefit (expense) | | | 1.7 | | | 0.2 | | | (1.2 | ) | | (1.2 | ) |
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Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments | | $ | 182.5 | | $ | 144.6 | | $ | 370.7 | | $ | 279.3 | |
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Natural gas transport volumes (Trillion Btus)(d) | | | 545.1 | | | 429.5 | | | 1,040.5 | | | 834.5 | |
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Natural gas sales volumes (Trillion Btus)(e) | | | 224.9 | | | 207.6 | | | 440.0 | | | 416.6 | |
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(a) | Three and six month 2008 amounts include a $13.1 million increase in expense resulting from unrealized mark to market losses due to the discontinuance of hedge accounting. Beginning in the second quarter of 2008, our Casper and Douglas gas processing operations discontinued hedge accounting. |
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(b) | Six month 2007 amount includes an expense of $1.0 million reflecting our portion of a loss from the early extinguishment of debt by Red Cedar Gathering Company. |
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(c) | Three and six month 2008 amounts include a $13.0 million gain from the sale of our 25% equity ownership interest in Thunder Creek Gas Services, LLC. |
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(d) | Includes Kinder Morgan Interstate Gas Transmission LLC, Trailblazer Pipeline Company LLC, TransColorado Gas Transmission Company LLC, Rockies Express Pipeline LLC, and Texas intrastate natural gas pipeline group pipeline volumes. |
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(e) | Represents Texas intrastate natural gas pipeline group volumes. |
For the three and six months ended June 30, 2008, the certain items related to our Natural Gas Pipelines business segment described in the footnotes to the table above decreased earnings before depreciation, depletion and amortization expenses by $0.1 million and increased earnings before depreciation, depletion and amortization by $0.9 million, respectively, when compared to the same periods last year.
The largest of these items includes (i) a comparable increase in earnings of $13.0 million in the second quarter of 2008 due to the sale of our 25% ownership interest in Thunder Creek Gas Services, LLC; and (ii) a decrease in earnings in the second quarter of 2008 of $13.1 million due to an unrealized mark to market loss resulting from the removal of hedge designation on certain derivative contracts used to mitigate the price risk associated with future sales of natural gas liquids by our Casper and Douglas natural gas processing operations. Effective April 1, 2008, we sold our equity ownership interest in Thunder Creek to a third party and we received cash proceeds, net of closing costs and settlements, of approximately $50.7 million for our investment. We recognized a gain of $13.0 million with respect to this transaction. For more information on this gain, see Note 2 to our consolidated financial statements included elsewhere in this report; for more information on our expense from the discontinuance of hedge accounting, see Note 10 to our consolidated financial statements included elsewhere in this report.
Following is information related to the increases and decreases, in the second quarter and first six months of 2008 compared to the same periods of 2007, of the segment’s remaining changes in earnings before depreciation, depletion and amortization expense (EBDA); and changes in operating revenues:
63
| | | | | | | | | | | | | |
Three months ended June 30, 2008 versus Three months ended June 30, 2007 |
|
| | EBDA
increase/(decrease) | | Revenues
increase/(decrease) | |
| |
| |
| |
| | (In millions, except percentages) | |
Rockies Express Pipeline | | $ | 28.5 | | | 724 | % | $ | — | | | — | |
Texas Intrastate Natural Gas Pipeline Group | | | 4.5 | | | 5 | % | | 928.3 | | | 58 | % |
TransColorado Pipeline | | | 3.0 | | | 28 | % | | 3.1 | | | 25 | % |
Kinder Morgan Louisiana Pipeline | | | 3.0 | | | n/a | | | — | | | — | |
Casper and Douglas gas processing | | | (2.1 | ) | | (42 | )% | | 17.8 | | | 77 | % |
All others | | | 1.1 | | | 2 | % | | 2.4 | | | 4 | % |
Intrasegment Eliminations | | | — | | | — | | | — | | | — | |
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| | | | |
Total Natural Gas Pipelines | | $ | 38.0 | | | 26 | % | $ | 951.6 | | | 56 | % |
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| | | | | | | | | | | | | |
Six months ended June 30, 2008 versus Six months ended June 30, 2007 |
|
| | EBDA
increase/(decrease) | | Revenues
increase/(decrease) | |
| |
| |
| |
| | (In millions, except percentages) | |
Rockies Express Pipeline | | $ | 45.3 | | | 808 | % | $ | — | | | — | |
Texas Intrastate Natural Gas Pipeline Group | | | 36.5 | | | 22 | % | | 1,284.2 | | | 25 | % |
TransColorado Pipeline | | | 6.1 | | | 29 | % | | 6.8 | | | 27 | % |
Kinder Morgan Louisiana Pipeline | | | 3.0 | | | n/a | | | — | | | — | |
Casper and Douglas gas processing | | | (2.8 | ) | | (32 | )% | | 36.9 | | | 87 | % |
All others | | | 2.4 | | | 3 | % | | 3.2 | | | 3 | % |
Intrasegment Eliminations | | | — | | | — | | | (2.4 | ) | | (385 | )% |
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Total Natural Gas Pipelines | | $ | 90.5 | | | 32 | % | $ | 1,328.7 | | | 41 | % |
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The overall increases in segment earnings before depreciation, depletion and amortization expenses in the three and six months ended June 30, 2008, when compared to the same periods last year, were driven primarily by incremental contributions from our 51% equity ownership interest in the Rockies Express Pipeline, higher earnings from our Texas intrastate natural gas pipeline group, and improved performance from our TransColorado Pipeline and Louisiana Pipeline.
The incremental earnings from our investment in Rockies Express relates to higher net income earned by Rockies Express Pipeline LLC, primarily due to the start-up of service on the Rockies Express-West pipeline segment in January and May 2008. The Rockies Express-West segment is a 713-mile, 42-inch diameter pipeline that extends from the Cheyenne Hub in Weld County, Colorado to an interconnect with Panhandle Eastern Pipeline Company in Audrain County, Missouri. Rockies Express-West began interim service for up to 1.4 billion cubic feet per day of natural gas on the segment’s first 503 miles of pipe on January 12, 2008, and service on the remaining 210 miles (to Audrain County) began on May 20, 2008.
Now fully operational, Rockies Express-West has the capacity to transport up to 1.5 billion cubic feet per day and can make deliveries to interconnects with our Kinder Morgan Interstate Gas Transmission Pipeline, Northern Natural Gas Company, Natural Gas Pipeline Company of America LLC, ANR and Panhandle Eastern Pipeline Company. Rockies Express expects to conduct further hydrostatic testing of portions of its system during September 2008 to satisfy U.S. Department of Transportation testing requirements to operate at its targeted higher operating pressure. This hydrostatic test will result in the temporary outage of pipeline delivery points and an overall reduction of firm capacity available to firm shippers. By the terms of the Rockies Express FERC Gas Tariff, firm shippers are entitled to daily reservation revenue credits for non-force majeure and planned maintenance outages; however, we believe any revenue credits resulting from the temporary pipeline outage will not have a material adverse impact on our business, cash flows, financial position or results of operations.
Our Texas intrastate natural gas pipeline group includes the operations of our (i) Kinder Morgan Tejas (including Kinder Morgan Border Pipeline); (ii) Kinder Morgan Texas Pipeline; (iii) Kinder Morgan North Texas Pipeline; and (iv) Mier-Monterrey Mexico Pipeline, and combined, the group’s quarter-to-quarter increase in earnings in 2008 versus 2007 was mainly attributable to higher natural gas sales margins and greater natural gas processing volumes and margins. For the comparable six month periods, the group also benefitted, in 2008, from incremental natural gas transport and storage revenues due to a long-term contract with one of its largest customers that became effective April 1, 2007.
The quarter-to-quarter increase in natural gas sales margin was driven by increases in the average unit margin and natural gas sales volumes of 9% and 8%, respectively; for the comparable six month periods, the higher margin in 2008 was primarily related to an over 5% increase in sales volumes. Since the second quarter of 2007, our Texas intrastate pipeline group has also benefitted from increases in gas processing margins.
64
Because our Texas intrastate group buys and sells significant quantities of natural gas, the variances from period to period in both segment revenues and segment operating expenses (which include natural gas costs of sales) are due to changes in our intrastate groups’ average prices and volumes for natural gas purchased and sold. To the extent possible, we balance the pricing and timing of our natural gas purchases to our natural gas sales, and these contracts are frequently settled in terms of an index price for both purchases and sales. In order to minimize commodity price risk, we attempt to balance sales with purchases at the index price on the date of settlement.
The increases in earnings from our TransColorado Pipeline reflect contract improvements and expansions completed since the end of the second quarter of 2007, caused by an increase in natural gas production in the Piceance and San Juan basins of New Mexico and Colorado. In December 2007, we completed an approximate $50 million expansion project on our TransColorado Pipeline. The Blanco-Meeker project was placed into service January 1, 2008, and boosted natural gas transportation capacity on the pipeline by approximately 250 million cubic feet per day from the Blanco Hub area in San Juan County, New Mexico through TransColorado’s existing pipeline for deliveries to the Rockies Express Pipeline at an existing point of interconnection located at the Meeker Hub in Rio Blanco County, Colorado. All of the incremental capacity is subscribed under a long-term contract with ConocoPhillips.
The $3.0 million incremental earnings contribution from our Kinder Morgan Louisiana Pipeline reflects other non-operating income realized in the second quarter of 2008 pursuant to FERC regulations governing allowances for capital funds that are used for pipeline construction costs (an equity cost of capital allowance). The equity cost of capital allowance provides for a reasonable return on construction costs that are funded by equity contributions, similar to the allowance for capital costs funded by borrowings.
The decreases in period-to-period earnings before depreciation, depletion and amortization from our Casper Douglas gas processing operations was largely due to lower prices on our product sales due to unfavorable hedge settlements and to increased natural gas purchase costs. The lower prices primarily resulted from the settlements of higher priced crude oil hedges that we used to hedge our heavy natural gas products sales, and the increased gas purchase costs were due to increases in both prices and volumes, relative to last year.
CO2
| | | | | | | | | | | | | |
| | Three Months Ended
June 30, | | Six Months Ended
June 30, | |
| | 2008 | | 2007 | | 2008 | | 2007 | |
| |
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|
| | (In millions, except operating statistics) | |
Revenues | | $ | 308.6 | | $ | 199.5 | | $ | 595.0 | | $ | 391.1 | |
Operating expenses | | | (96.6 | ) | | (76.2 | ) | | (187.3 | ) | | (146.8 | ) |
Other expense | | | — | | | — | | | — | | | — | |
Earnings from equity investments | | | 5.5 | | | 5.0 | | | 11.1 | | | 10.2 | |
Other, net-income (expense) | | | — | | | — | | | (0.2 | ) | | — | |
Income tax benefit (expense) | | | (0.9 | ) | | 0.6 | | | (2.2 | ) | | (0.2 | ) |
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Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments | | $ | 216.6 | | $ | 128.9 | | $ | 416.4 | | $ | 254.3 | |
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Carbon dioxide delivery volumes (Bcf)(a) | | | 178.6 | | | 156.6 | | | 358.8 | | | 322.2 | |
SACROC oil production (gross)(MBbl/d)(b) | | | 27.5 | | | 28.0 | | | 27.4 | | | 28.9 | |
SACROC oil production (net)(MBbl/d)(c) | | | 22.9 | | | 23.3 | | | 22.8 | | | 24.1 | |
Yates oil production (gross)(MBbl/d)(b) | | | 28.1 | | | 27.0 | | | 28.3 | | | 26.6 | |
Yates oil production (net)(MBbl/d)(c) | | | 12.5 | | | 12.0 | | | 12.6 | | | 11.8 | |
Natural gas liquids sales volumes (net)(MBbl/d)(c) | | | 9.1 | | | 9.7 | | | 9.3 | | | 9.7 | |
Realized weighted average oil price per Bbl(d)(e) | | $ | 53.01 | | $ | 34.76 | | $ | 51.52 | | $ | 34.97 | |
Realized weighted average natural gas liquids price per Bbl(e)(f) | | $ | 77.28 | | $ | 50.35 | | $ | 71.48 | | $ | 46.05 | |
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(a) | Includes Cortez, Central Basin, Canyon Reef Carriers, Centerline and Pecos pipeline volumes. |
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(b) | Represents 100% of the production from the field. We own an approximate 97% working interest in the SACROC unit and an approximate 50% working interest in the Yates unit. |
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(c) | Net to Kinder Morgan, after royalties and outside working interests. |
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(d) | Includes all Kinder Morgan crude oil production properties. |
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(e) | Hedge gains/losses for crude oil and natural gas liquids are included with crude oil. |
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(f) | Includes production attributable to leasehold ownership and production attributable to our ownership in processing plants and third party processing agreements. |
Our CO2 segment consists of Kinder Morgan CO2 Company, L.P. and its consolidated affiliates. The segment’s primary businesses involve the production, marketing and transportation of both carbon dioxide (commonly called CO2) and crude oil, and the production and marketing of natural gas and natural gas liquids. For each of the segment’s two primary businesses, following is information related to the increases and decreases, in the comparable three and six month periods of 2008 and 2007, of the segment’s (i) earnings before depreciation, depletion and amortization (EBDA); and (ii) operating revenues:
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Three months ended June 30, 2008 versus Three months ended June 30, 2007 |
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increase/(decrease) | | Revenues
increase/(decrease) | |
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Sales and Transportation Activities | | $ | 28.1 | | | 64 | % | $ | 34.2 | | | 77 | % |
Oil and Gas Producing Activities | | | 59.6 | | | 70 | % | | 84.5 | | | 51 | % |
Intrasegment Eliminations | | | — | | | — | | | (9.6 | ) | | (91 | )% |
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Total CO2 | | $ | 87.7 | | | 68 | % | $ | 109.1 | | | 55 | % |
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Six months ended June 30, 2008 versus Six months ended June 30, 2007 |
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increase/(decrease) | | Revenues
increase/(decrease) | |
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Sales and Transportation Activities | | $ | 57.1 | | | 69 | % | $ | 65.4 | | | 75 | % |
Oil and Gas Producing Activities | | | 105.0 | | | 61 | % | | 154.2 | | | 47 | % |
Intrasegment Eliminations | | | — | | | — | | | (15.7 | ) | | (71 | )% |
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Total CO2 | | $ | 162.1 | | | 64 | % | $ | 203.9 | | | 52 | % |
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The overall period-to-period increases in segment earnings before depreciation, depletion and amortization expenses resulted from higher earnings from both oil and gas producing activities and carbon dioxide sales and transportation activities. Highlights for the second quarter of 2008 compared to the second quarter of 2007 included an increase in oil production at the Yates field unit, and higher earnings from increased carbon dioxide, crude oil, and natural gas liquids sales revenues, due largely to continuing increases in average crude oil (which also impacts the price of carbon dioxide) and natural gas plant product prices since the second quarter of 2007.
Revenues from crude oil sales and natural gas plant products sales increased $59.8 million (53%) and $19.1 million (43%), respectively, in the second quarter of 2008 compared to the second quarter of 2007, and increased $106.7 million (46%) and $39.4 million (49%), respectively, in the first six months of 2008 compared to the first six months of 2007. With respect to crude oil, overall sales volumes were essentially flat across both three and six month comparable periods, but we benefitted from increases of 53% and 47%, respectively, in our realized weighted average price per barrel; with respect to natural gas liquids, decreases in sales volumes of 6% and 4%, respectively, were more than offset by increases of 53% and 55%, respectively, in our realized weighted average price per barrel. The period-to-period decreases in natural gas liquids volumes were primarily attributable to operational issues on a third party owned pipeline, which resulted in pro-rationing.
Average gross oil production for the second quarter of 2008 was 28.1 thousand barrels per day at the Yates unit, over 4% higher compared to the second quarter of 2007. At SACROC, average gross oil production for the second quarter of 2008 was 27.5 thousand barrels per day, a decline of almost 2% versus the same quarter last year, but up slightly (almost 1%) compared to the previous quarter (first quarter of 2008).
Generally, earnings for the segment’s oil and gas producing activities, which include the operations associated with its ownership interests in oil-producing fields and natural gas processing plants, are closely aligned with industry price levels for crude oil and natural gas liquids products. Because such price levels are subject to external factors over which we have no control, and because future price changes may be volatile, our CO2 segment is
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exposed to commodity price risk related to the price volatility of crude oil and natural gas liquids. We mitigate this risk through a long-term hedging strategy that is intended to generate more stable realized prices by using derivative contracts as hedges to the exposure of fluctuating expected future cash flows produced by changes in commodity sales prices. All of our hedge gains and losses for crude oil and natural gas liquids are included in our realized average price for oil. Had we not used energy derivative contracts to transfer commodity price risk, our crude oil sales prices would have averaged $123.03 per barrel in the second quarter of 2008, and $61.39 per barrel in the second quarter of 2007. For more information on our hedging activities, see Note 10 to our consolidated financial statements included elsewhere in this report.
The period-to-period increases in earnings before depreciation, depletion and amortization from the segment’s sales and transportation activities were largely revenue related, reflecting both higher carbon dioxide sales revenues and higher carbon dioxide and crude oil pipeline transportation revenues. Overall, our CO2 segment reported increases of $18.1 million (118%) and $34.0 million (121%), respectively, in carbon dioxide sales revenues in the second quarter and first half of 2008, relative to the same periods a year ago. The increases in sales revenues were primarily driven by increases of 84% and 81%, respectively, in average sales prices in 2008, and partially driven by increases in sales volumes of 12% and 11%, respectively. The increases in average sales prices reflect continued customer demand for carbon dioxide for use in oil recovery projects throughout the Permian Basin area and, in addition, a portion of our carbon dioxide contracts are tied to crude oil prices, which as discussed above, have increased since the second quarter of 2007. We do not recognize profits on carbon dioxide sales to ourselves.
The increases in sales volumes were largely due to the January 1, 2008 start-up of our new Doe Canyon carbon dioxide source field located in Dolores County, Colorado. Since January 2007, we have invested approximately $87 million to develop this new carbon dioxide source field (named the Doe Canyon Deep unit). In addition, investments were also made to drill additional carbon dioxide wells at the McElmo Dome unit, increase transportation capacity on the Cortez Pipeline, and extend the Cortez Pipeline to the new Doe Canyon Deep unit.
Compared to the second quarter and first half of 2007, the segment’s $20.4 million (27%) and $40.5 million (28%) increases in combined operating expenses in the three and six months ended June 30, 2008, respectively, were largely due to higher severance and property tax expenses, field operating expenses, and fuel and power expenses. The increases in severance tax expenses were related to the period-to-period increases in crude oil revenues; the increases in property tax expenses were largely due to increased asset infrastructure resulting from the capital investments we have made since the end of the second quarter of 2007. The increases in operating expenses were driven by higher well workover and repair expenses related to infrastructure expansions at the SACROC and Yates oil field units and at the McElmo Dome carbon dioxide unit. In addition to its effect on product sales revenues, rising price levels since the end of the second quarter of 2007 also contributed to the increases in the segment’s operating, maintenance, and fuel and power expenses.
Terminals
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| | Three Months Ended
June 30, | | Six Months Ended
June 30, | |
| | 2008 | | 2007 | | 2008 | | 2007 | |
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Revenues | | $ | 300.7 | | $ | 229.0 | | $ | 580.9 | | $ | 444.1 | |
Operating expenses | | | (156.0 | ) | | (117.1 | ) | | (308.8 | ) | | (232.9 | ) |
Other income (expense)(a) | | | (0.2 | ) | | 1.7 | | | 0.4 | | | 4.4 | |
Earnings from equity investments | | | 0.7 | | | — | | | 1.7 | | | — | |
Other, net-income (expense) | | | 1.4 | | | — | | | 2.7 | | | — | |
Income tax expense | | | (6.2 | ) | | (3.5 | ) | | (10.7 | ) | | (5.0 | ) |
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Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments | | $ | 140.4 | | $ | 110.1 | | $ | 266.2 | | $ | 210.6 | |
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Bulk transload tonnage (MMtons)(b) | | | 26.7 | | | 25.1 | | | 49.8 | | | 48.3 | |
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Liquids leaseable capacity (MMBbl) | | | 52.4 | | | 43.7 | | | 52.4 | | | 43.7 | |
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Liquids utilization % | | | 98.1 | % | | 97.1 | % | | 98.1 | % | | 97.1 | % |
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(a) | Six month 2007 amount includes an increase in income of $1.8 million from property casualty gains associated with the 2005 hurricane season. |
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(b) | Volumes for acquired terminals are included for all periods. |
Our Terminals business segment includes the operations of our petroleum, chemical and other liquids terminal facilities (other than those included in our Products Pipelines segment), and all of our coal, petroleum coke, fertilizer, steel, ores and other dry-bulk material services facilities. As described in footnote (a) to the table above, the segment recognized a $1.8 million gain in the first quarter of 2007, based upon our final determination of the book value of fixed assets damaged or destroyed during Hurricanes Katrina and Rita in 2005.
The segment’s $30.3 million (28%) increase in earnings before depreciation, depletion and amortization in the second quarter of 2008 versus the second quarter of 2007, and its remaining $57.4 million (27%) increase in earnings in the first half of 2008 versus the first half of 2007 were due to a combination of internal expansions and strategic acquisitions completed since the second quarter of 2007. Since May 30, 2007, we have invested approximately $163.1 million in cash to acquire both terminal assets and equity interests in terminal operations and combined, these acquired operations accounted for incremental amounts of earnings before depreciation, depletion and amortization of $12.6 million, revenues of $32.6 million, equity earnings of $0.7 million, and operating expenses of $20.7 million, respectively, in the second quarter of 2008, and incremental earnings before depreciation, depletion and amortization of $24.9 million, revenues of $65.5 million, equity earnings of $1.7 million, and operating expenses of $42.3 million, respectively, in the first six months of 2008.
All of the incremental amounts listed above represent the earnings, revenues and expenses from acquired terminals’ operations during the additional months of ownership in 2008, and do not include increases or decreases during the same months we owned the assets in 2007. Our significant terminal acquisitions since the beginning of the second quarter of 2007 included the following:
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| § the Vancouver Wharves bulk marine terminal, which includes five deep-sea vessel berths and terminal assets located on the north shore of the Port of Vancouver’s main harbor. The assets include significant rail infrastructure, dry bulk and liquid storage, and material handling systems, and were acquired May 30, 2007; and |
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| § the terminal assets and operations acquired from Marine Terminals, Inc., which are primarily involved in the handling and storage of steel and alloys and consist of two separate facilities located in Blytheville, Arkansas, and individual terminal facilities located in Decatur, Alabama; Hertford, North Carolina; and Berkley, South Carolina. The assets were acquired September 1, 2007. |
For all other terminal operations (those owned during identical periods in both 2008 and 2007), earnings before depreciation, depletion and amortization expenses increased $17.7 million (16%) in the second quarter of 2008, and $32.5 million (16%) in the first six months of 2008, when compared to the same prior year periods.
The overall increases in earnings from terminals owned during identical periods in both years included (i) incremental earnings before depreciation, depletion and amortization of $7.2 million (28%) from our two large Gulf Coast liquids terminal facilities located along the Houston Ship Channel in Pasadena and Galena Park, Texas, primarily due to record liquids throughput volumes as a result of expansions completed since the second quarter of 2007; (ii) incremental earnings of $4.6 million (179%) from our Pier IX terminal located in Newport News, Virginia, due to higher quarter-over-quarter coal transfer volumes (including record coal throughput volumes in June 2008 of 1.1 million tons); and incremental earnings of $1.2 million (47%) from our Perth Amboy, New Jersey liquids terminal, located in the New York Harbor area, driven by higher liquids throughput volumes as a result of an expansion completed at the end of the first quarter of 2008.
For the Terminals segment combined, expansion projects completed since the end of the second quarter of 2007 have increased our liquids terminals’ leaseable capacity to 52.4 million barrels, up 20% from a capacity of 43.7 million barrels in the second quarter of 2007. At the same time, we increased our overall liquids utilization capacity rate (the ratio of our actual leased capacity to our estimated potential capacity) to 98.1%, up 1% since the second quarter last year. For all terminals combined, total liquids throughput totaled 160.6 million barrels, up 15% over
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second quarter 2007 volumes, due primarily to the addition of the new liquids capacity and partly to continued strong demand for imported fuel. With regard to our bulk terminals, we benefitted by incremental earnings from many of our coal handling terminals, as coal transfer volumes totaled 8.8 million tons in the second quarter of 2008, representing an increase of 22% over coal handling volumes in the second quarter of 2007.
Trans Mountain
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| | Three Months Ended
June 30, | | Six Months Ended
June 30, | |
| | 2008 | | 2007 | | 2008 | | 2007 | |
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| | (In millions, except operating statistics) | |
Revenues | | $ | 43.4 | | $ | 43.3 | | $ | 86.5 | | $ | 76.1 | |
Operating expenses | | | (17.0 | ) | | (16.0 | ) | | (32.7 | ) | | (27.9 | ) |
Other income (expense)(a) | | | — | | | — | | | — | | | (377.1 | ) |
Earnings from equity investments | | | — | | | — | | | 0.1 | | | — | |
Other, net-income (expense) | | | 4.0 | | | 0.6 | | | 6.1 | | | 1.1 | |
Income tax benefit (expense) | | | 3.0 | | | 1.7 | | | 3.6 | | | (0.8 | ) |
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Earnings (loss) before depreciation, depletion and amortization expense and amortization of excess cost of equity investments(b) | | $ | 33.4 | | $ | 29.6 | | $ | 63.6 | | $ | (328.6 | ) |
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Transport volumes (MMBbl) | | | 21.5 | | | 25.0 | | | 40.9 | | | 44.8 | |
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(a) | Six month 2007 amount represents a goodwill impairment expense recorded by Knight in the first quarter of 2007. |
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(b) | Three and six month 2007 amounts include earnings of $9.0 million and losses of $349.2 million, respectively, for periods prior to our acquisition date of April 30, 2007. |
Our Trans Mountain segment includes the operations of the Trans Mountain Pipeline, which we acquired from Knight effective April 30, 2007. Trans Mountain transports crude oil and refined products from Edmonton, Alberta to marketing terminals and refineries in British Columbia and the state of Washington. An additional 15,000 barrel per day expansion that will increase capacity on the pipeline to approximately 300,000 barrels per day is currently under construction and is expected to be completed in the fourth quarter of 2008.
According to the provisions of generally accepted accounting principles that prescribe the standards used to account for business combinations, due to the fact that our acquisition of Trans Mountain from Knight represented a transfer of assets between entities under common control, we initially recorded the assets and liabilities of Trans Mountain transferred to us from Knight at their carrying amounts in the accounts of Knight. Furthermore, our accompanying financial statements included in this report, and the information in the table above, reflect the results of operations for the first six months of 2007 as though the transfer of Trans Mountain from Knight had occurred at the date when both Trans Mountain and we met the accounting requirements for entities under common control (January 1, 2006).
After taking into effect the items described in footnote (b) to the table above, the remaining increases in earnings before depreciation, depletion and amortization for the three and six months ended June 30, 2008 totaled $12.8 million (62%) and $43.0 million (209%), respectively, when compared to the same prior year periods. These period-to-period increases consisted of (i) higher earnings of $2.8 million (14%) from the two second quarter months (May and June) we owned the assets in both years; and (ii) incremental earnings of $10.0 million and $40.2 million, respectively, from periods we owned the assets in 2008 only. The increase in earnings in the second quarter of 2008 was driven primarily by higher toll rates, which more than offset a 14% decline in transport volumes due to lower demand for water-borne exports out of Vancouver, British Columbia.
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Other
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| | | Three Months Ended June 30, | | Earnings | |
| | | | 2008 | | | 2007 | | increase/(decrease) | |
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| General and administrative expenses(a) | | $ | (72.8 | ) | $ | (89.4 | ) | $ | 16.6 | | | 19 | % |
| Unallocable interest expense, net of interest income(b) | | | (99.9 | ) | | (98.2 | ) | | (1.7 | ) | | (2 | %) |
| Unallocable income tax benefit (expense) | | | (4.4 | ) | | — | | | (4.4 | ) | | n/a | |
| Minority interest(c) | | | (4.1 | ) | | (3.2 | ) | | (0.9 | ) | | (28 | %) |
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| Total interest and corporate administrative expenses | | $ | (181.2 | ) | $ | (190.8 | ) | $ | 9.6 | | | 5 | % |
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| | | Six Months Ended June 30, | | Earnings | |
| | | 2008 | | 2007 | | increase/(decrease) | |
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| General and administrative expenses(d) | | $ | (149.6 | ) | $ | (159.7 | ) | $ | 10.1 | | | 6 | % |
| Unallocable interest expense, net of interest income(e) | | | (197.6 | ) | | (190.1 | ) | | (7.5 | ) | | (4 | %) |
| Unallocable income tax benefit (expense) | | | (4.4 | ) | | — | | | (4.4 | ) | | n/a | |
| Minority interest(f) | | | (8.1 | ) | | (2.0 | ) | | (6.1 | ) | | (305 | %) |
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| Total interest and corporate administrative expenses | | $ | (359.7 | ) | $ | (351.8 | ) | $ | (7.9 | ) | | (2 | %) |
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(a) | 2008 amount includes a $1.4 million increase in non-cash compensation expense, allocated to us from Knight. We do not have any obligation, nor do we expect to pay any amounts related to this expense. 2007 amount includes (i) a $21.2 million increase in non-cash compensation expense, allocated to us from Knight. We do not have any obligation, nor did we pay any amounts related to this expense; (ii) a $1.1 million increase in expense for certain Trans Mountain acquisition costs; and (iii) a $1.0 million increase in expense from the inclusion of Trans Mountain for a period prior to our acquisition date of April 30, 2007. |
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(b) | 2008 and 2007 amounts include increases in imputed interest expense of $0.5 million and $0.6 million, respectively, related to our January 1, 2007 Cochin Pipeline acquisition. 2007 amount also includes a $0.4 million increase in interest expense from the inclusion of Trans Mountain for a period prior to our acquisition date of April 30, 2007. |
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(c) | 2007 amount includes a $0.2 million decrease in expense related to the minority interest effect from all of the three month 2007 items previously disclosed in the footnotes to the tables included in “—Results of Operations.” |
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(d) | 2008 amount includes a $2.8 million increase in non-cash compensation expense, allocated to us from Knight. We do not have any obligation, nor do we expect to pay any amounts related to this expense. 2007 amount includes (i) a $23.4 million increase in non-cash compensation expense, allocated to us from Knight. We do not have any obligation, nor did we pay any amounts related to this expense; (ii) a $5.5 million increase in expense from the inclusion of Trans Mountain for periods prior to our acquisition date of April 30, 2007; (iii) a $1.7 million increase in expense related to an additional insurance premium charge, associated with the 2005 hurricane season; and (iv) a $1.1 million increase in expense for certain Trans Mountain acquisition costs. |
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(e) | 2008 and 2007 amounts include increases in imputed interest expense of $1.0 million and $1.2 million, respectively, related to our January 1, 2007 Cochin Pipeline acquisition. 2007 amount also includes a $1.2 million increase in interest expense from the inclusion of Trans Mountain for periods prior to our acquisition date of April 30, 2007. |
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(f) | 2007 amount includes a $3.5 million decrease in expense related to the minority interest effect from all of the six month 2007 items previously disclosed in the footnotes to the tables included in “—Results of Operations.” |
Items not attributable to any segment include general and administrative expenses, unallocable interest income, unallocable income tax expense, interest expense, and minority interest. Our general and administrative expenses include such items as salaries and employee-related expenses, payroll taxes, insurance, office supplies and rentals, unallocated litigation and environmental expenses, and shared corporate services—including accounting, information technology, human resources and legal services.
The total change in general and administrative expenses is an increase of $16.6 million and $10.1 for the quarter and six months ended June 30, 2008, respectively. The certain items described in footnotes (a) and (d) to the tables above accounted for decreases in general and administrative expenses of $21.9 million and $28.9 million respectively. The decreases were largely due to the $21.2 million second quarter 2007 non-cash compensation expense allocated to us from Knight and associated with the activities required to complete the May 2007 going-private transaction of KMI (now Knight). We were required to recognize the amount related to this transaction allocated to us from Knight as expense on our income statements; however, we were not responsible for paying these expenses, and accordingly, recognized the unpaid amount as a contribution to equity—primarily as an increase in “Partners’ Capital” on our balance sheet.
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The remaining $5.3 million (8%) and $18.8 million (15%) increases in general and administrative expenses in the comparable three and six month periods, respectively, were primarily driven by (i) acquisition-related spending, associated with the businesses we acquired since the second quarter of 2007—our Trans Mountain business segment and our recently acquired bulk terminal operations described above in “—Terminals;” and (ii) higher spending in support of growth initiatives, mainly reflecting higher compensation-related expenses—including salary and benefit expenses, payroll taxes and other employee and contractor related expenses.
Compared to the second quarter and first half of 2007, net interest expense decreased $0.5 million and $1.4 million, respectively, in 2008 due to the items described in footnotes (b) and (e) to the table above. The remaining $2.2 million (2%) quarter-to-quarter increase in expense in 2008 was chiefly attributable to a 24% increase in our average debt balances, partially offset by a 17% decrease in the weighted average interest rate on all of our borrowings. For the comparable six month periods, the remaining $8.9 million (5%) increase in interest expense in 2008 versus 2007 was driven by a 22% increase in average borrowings, partially offset by a 14% drop in weighted average interest rates.
The increase in our average borrowings since the second quarter of 2007 is largely due to the capital spending (for asset expansion and improvement projects, including additional pipeline construction costs) and the external business acquisitions we have made since June 2007. The decrease in our average borrowing rates reflects a general decrease in variable interest rates since the second quarter last year. As of June 30, 2008, approximately 45% of our $8,056.5 million consolidated debt balance (excluding the value of interest rate swap agreements) was subject to variable interest rates—either as short-term or long-term variable rate debt obligations or as fixed-rate debt converted to variable rates through the use of interest rate swaps. The same percentage (45%) of our total $6,629.0 million consolidated debt balance (excluding the value of interest rate swap agreements) as of June 30, 2007, was subject to variable interest rates.
The incremental unallocable income tax expense, in both the second quarter and first six months of 2008, relates to higher corporate income tax accruals for the Texas margin tax, an entity-level tax initiated January 1, 2007 and imposed on the portion of our total revenue that is apportioned to the state of Texas. The decreases in earnings from incremental minority interest expense relates to the higher overall partnership income in 2008 versus 2007.
Financial Condition
Capital Structure
We attempt to maintain a relatively conservative overall capital structure, with a long-term target mix of approximately 50% equity and 50% debt. In addition to our results of operations, our debt and capital balances are affected by our financing activities, as discussed below in “—Financing Activities.”
The following table illustrates the sources of our invested capital (dollars in millions):
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| | June 30,
2008 | | December 31,
2007 | |
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Long-term debt, excluding value of interest rate swaps | | $ | 7,785.6 | | $ | 6,455.9 | |
Minority interest | | | 42.5 | | | 54.2 | |
Partners’ capital, excluding accumulated other comprehensive loss | | | 6,131.2 | | | 5,712.3 | |
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Total capitalization | | | 13,959.3 | | | 12,222.4 | |
Short-term debt, less cash and cash equivalents | | | 192.2 | | | 551.3 | |
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Total invested capital | | $ | 14,151.5 | | $ | 12,773.7 | |
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Capitalization: | | | | | | | |
Long-term debt, excluding value of interest rate swaps | | | 55.8 | % | | 52.8 | % |
Minority interest | | | 0.3 | % | | 0.5 | % |
Partners’ capital, excluding accumulated other comprehensive loss | | | 43.9 | % | | 46.7 | % |
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| | June 30,
2008 | | December 31,
2007 | |
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Invested Capital: | | | | | | | |
Total debt, less cash and cash equivalents and excluding value of interest rate swaps | | | 56.4 | % | | 54.9 | % |
Partners’ capital and minority interest, excluding accumulated other comprehensive loss | | | 43.6 | % | | 45.1 | % |
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| | | 100.0 | % | | 100.0 | % |
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Our primary cash requirements, in addition to normal operating expenses, are debt service, sustaining capital expenditures, expansion capital expenditures and quarterly distributions to our common unitholders, Class B unitholders and general partner. In addition to utilizing cash generated from operations, we could meet our cash requirements for expansion capital expenditures through borrowings under our credit facility, issuing short-term commercial paper, long-term notes or additional common units or the proceeds from purchases of additional i-units by KMR with the proceeds from issuances of additional KMR shares. Further information on our financing strategies and activities can be found in our Annual Report on Form 10-K for the year ended December 31, 2007.
As part of our financial strategy, we try to maintain an investment-grade credit rating, which involves, among other things, the issuance of additional limited partner units in connection with our acquisitions and internal growth activities in order to maintain acceptable financial ratios.
On May 30, 2006, Standard & Poor’s Rating Services and Moody’s Investors Service each placed our ratings on credit watch pending the resolution of KMI’s going-private transaction. On January 5, 2007, in anticipation of the buyout closing, S&P downgraded us one level to BBB and removed our rating from credit watch with negative implications. As previously noted by Moody’s in its credit opinion dated November 15, 2006, it downgraded our credit rating from Baa1 to Baa2 on May 30, 2007, following the closing of the going-private transaction. Additionally, our rating was downgraded by Fitch Ratings from BBB+ to BBB on April 11, 2007. Currently, our corporate debt credit rating is BBB, Baa2 and BBB, respectively, at S&P, Moody’s and Fitch.
Short-term Liquidity
Our principal sources of short-term liquidity are (i) our $1.85 billion five-year senior unsecured revolving credit facility that matures August 18, 2010; (ii) our $1.85 billion short-term commercial paper program (which is supported by our bank credit facility, with the amount available for borrowing under our credit facility being reduced by our outstanding commercial paper borrowings); and (iii) cash from operations (discussed following).
Borrowings under our five-year credit facility can be used for general partnership purposes and as a backup for our commercial paper program. The facility can be amended to allow for borrowings up to $2.1 billion. As of June 30, 2008, there were no borrowings under our credit facility or our commercial paper program. As of December 31, 2007, there were no borrowings under our credit facility, and we had $589.1 million of commercial paper outstanding.
As of June 30, 2008, our outstanding short-term debt was $270.9 million primarily associated with long term debt which matures in 2009. We provide for additional liquidity by maintaining a sizable amount of excess borrowing capacity related to our commercial paper program and long-term revolving credit facility. After reduction for our letters of credit and commercial paper outstanding (none at June 30, 2008), the remaining available borrowing capacity under our bank credit facility was $920.8 million as of June 30, 2008. Currently, we believe our liquidity to be adequate.
Some of our customers are experiencing, or may experience in the future, severe financial problems that have had or may have a significant impact on their creditworthiness. We are working to implement, to the extent allowable under applicable contracts, tariffs and regulations, prepayments and other security requirements, such as letters of credit, to enhance our credit position relating to amounts owed from these customers. We cannot provide assurance that one or more of our financially distressed customers will not default on their obligations to us or that such a default or defaults will not have a material adverse effect on our business, financial position, future results of operations, or future cash flows; however, we believe we have provided adequate allowance for such customers.
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Long-term Financing
In addition to our principal sources of short-term liquidity listed above, we could meet our cash requirements (other than distributions to our common unitholders, Class B unitholders and general partner) through issuing long-term notes or additional common units, or by utilizing the proceeds from purchases of additional i-units by KMR with the proceeds from issuances of KMR shares.
On February 12, 2008, we completed both a public offering of senior notes and an additional privately negotiated offering of 1,080,000 of our common units. We issued a total of $900 million in principal amount of senior notes, consisting of $600 million of 5.95% notes due February 15, 2018, and $300 million of 6.95% notes due January 15, 2038. We received proceeds from the issuance of the notes, after underwriting discounts and commissions, of approximately $894.1 million, and we used the proceeds to reduce the borrowings under our commercial paper program. We issued the 1,080,000 common units on February 12, 2008 at a price of $55.65 per unit in a privately negotiated transaction with two investors. We received net proceeds of $60.1 million for the issuance of these common units, and we used the proceeds to reduce the borrowings under our commercial paper program.
On March 3, 2008, we issued 5,000,000 of our common units in a public offering at a price of $57.70, less commissions and underwriting expenses. At the time of the offering, we granted the underwriters a 30-day option to purchase up to an additional 750,000 common units from us on the same terms and conditions, and pursuant to this option, we issued an additional 750,000 common units on March 10, 2008 upon exercise of this option. After commissions and underwriting expenses, we received net proceeds of $324.2 million for the issuance of these 5,750,000 common units, and we used the proceeds to reduce the borrowings under our commercial paper program.
On June 6, 2008, we completed an additional public offering of senior notes. We issued a total of $700 million in principal amount of senior notes, consisting of $375 million of 5.95% notes due February 15, 2018, and $325 million of 6.95% notes due January 15, 2038. We received proceeds from the issuance of the notes, after underwriting discounts and commissions, of approximately $687.7 million, and we used the proceeds to reduce the borrowings under our commercial paper program. As of June 30, 2008, our total liability balance due on the various series of our senior notes was $7,880.4 million, and the total liability balance due on the various borrowings of our operating partnerships and subsidiaries was $176.1 million.
We are subject to changes in the equity and debt markets for our limited partner units and long-term notes, and there can be no assurance we will be able or willing to access the public or private markets for our limited partner units and/or long-term notes in the future. If we were unable or unwilling to issue additional limited partner units, we would be required to either restrict potential future acquisitions or pursue other debt financing alternatives, some of which could involve higher costs or negatively affect our credit ratings. Our ability to access the public and private debt markets is affected by our credit ratings. See “—Capital Structure” above for a discussion of our credit ratings. For additional information regarding our debt securities and credit facility, see Note 9 to our consolidated financial statements included in our 2007 Form 10-K.
Operating Activities
Net cash provided by operating activities was $974.7 million for the six months ended June 30, 2008, versus $785.3 million in the comparable period of 2007. The period-to-period increase of $189.4 million (24%) in cash provided by operating activities primarily consisted of:
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| ▪ a $249.3 million increase in cash from overall higher partnership income—after adding back non-cash items including, among others, depreciation and amortization expense and a $377.1 million goodwill impairment charge recognized in the first quarter of 2007. The higher partnership income reflects the increase in cash earnings from our five reportable business segments in the first half of 2008, as discussed above in “—Results of Operations;” |
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| ▪ a $26.0 million decrease in cash inflows relative to net changes in working capital items, mainly due to timing differences that resulted in lower net cash inflows in 2008 from the collection and payment of trade and related party receivables and payables; |
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| ▪ a $23.3 million decrease in cash from FERC-mandated reparation payments made in March 2008. Pursuant to FERC orders, we made reparation payments to certain shippers on our Pacific operations’ pipelines and we reduced our rate case liability. The payment primarily related to a FERC ruling in February 2008 that resolved certain challenges by complainants with regard to delivery tariffs and gathering enhancement fees at our Pacific operations’ Watson Station, located in Carson, California; and |
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| ▪ a $15.0 million decrease in cash from an interest rate swap termination payment we received in March 2007, when we terminated a fixed-to-floating interest rate swap agreement having a notional principal amount of $100 million and a maturity date of March 15, 2032. |
Investing Activities
Net cash used in investing activities was $1,654.9 million for the six month period ended June 30, 2008, compared to $1,310.9 million in the comparable 2007 period. The $344.0 million (26%) increase in cash used in investing activities was primarily attributable to:
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| ▪ a $572.2 million increase from higher capital expenditures—largely due to increased investment undertaken to construct our Kinder Morgan Louisiana Pipeline, and to expand our Trans Mountain crude oil and refined petroleum products pipeline system. |
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| Since the middle of 2007, rising construction costs continue to create a challenging business environment, and our total forecasted capital expenditures on our major projects have increased by almost 10% from the projection we made at the beginning of 2008. Most of this increase has been on our natural gas pipeline major projects—for example, market conditions for consumables, labor and construction equipment along with certain provisions in the final environmental impact statement have resulted in increased construction costs for the Rockies Express Pipeline. We continue to be extremely focused on managing these cost increases, and identifying ancillary opportunities to offset them where possible, in order to complete our expansion projects as close to on time and on budget as possible. |
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| Our sustaining capital expenditures, defined as capital expenditures which do not increase the capacity of an asset, were $76.8 million for the first half of 2008, compared to $63.2 million for the first half of 2007. The above amounts include our proportionate share of Rockies Express’ sustaining capital expenditures but do not include the sustaining capital expenditures of our Trans Mountain business segment for periods prior to our acquisition date of April 30, 2007. Additionally, our forecasted expenditures for the remaining six months of 2008 for sustaining capital expenditures are approximately $120 million. All of our capital expenditures, with the exception of sustaining capital expenditures, are discretionary; |
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| ▪ a $294.9 million increase from incremental contributions to equity investments in the first half of 2008, largely driven by a $306.0 million equity investment paid in February 2008 to West2East Pipeline LLC, the sole owner of Rockies Express Pipeline LLC. Currently, we own a 51% equity interest in West2East Pipeline LLC, and when construction of the Rockies Express Pipeline is completed, our ownership interest will be reduced to 50% and the capital accounts of West2East Pipeline LLC will be trued-up to reflect our 50% economic interest in the project; |
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| ▪ a $201.6 million increase due to higher period-to-period payments for margin and restricted deposits in 2008 compared to 2007, associated largely with our utilization of derivative contracts to hedge (offset) against the volatility of energy commodity price risks; |
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| ▪ a $572.4 million decrease in cash used related to our acquisition of Trans Mountain from Knight. On April 30, 2007, we paid $549.0 million to Knight to acquire the net assets of Trans Mountain, and in April 2008, we received a cash contribution of $23.4 million from Knight as a result of certain true-up provisions in our acquisition agreement. For more information on our acquisition of Trans Mountain from Knight, see Note 2 to our consolidated financial statements included elsewhere in this report; |
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| ▪ an $89.1 million decrease related to a return of capital received from Midcontinent Express Pipeline LLC in the first quarter of 2008. In February 2008, Midcontinent entered into and then made borrowings under a new $1.4 billion three-year, unsecured revolving credit facility due February 28, 2011. Midcontinent then made distributions (in excess of cumulative earnings) to its two member owners to reimburse them for prior contributions made to fund its pipeline construction costs. We own a 50% equity interest in the joint venture pipeline; |
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| ▪ a $43.6 million decrease due to lower expenditures made for strategic business acquisitions. In the first half of 2008, our acquisition outlays totaled $4.2 million, which primarily consisted of the purchase of a Cincinnati, Ohio steel terminal. Located on approximately 17 acres along the Ohio River, the port facility primarily handles and stores break-bulk steel, and in 2007, the facility handled approximately 150,000 tons of steel products. In the first half of 2007, our acquisition outlays totaled $47.8 million, including $38.3 million paid for our purchase of the Vancouver Wharves bulk marine terminal from British Columbia Railway Company; and |
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| ▪ a $40.2 million decrease in cash used, relative to 2007, due to higher net proceeds received from the sales of investments, property, plant and equipment, and other net assets (net of salvage and removal costs). The increase in cash sales proceeds was driven by the approximate $50.7 million we received in the second quarter of 2008 for the sale of our 25% equity ownership interest in Thunder Creek Gas Services, LLC (discussed in Note 2 to our consolidated financial statements included elsewhere in this report). |
Financing Activities
Net cash provided by financing activities amounted to $701.0 million for the first six months of 2008. For the same six month period last year, our financing activities provided net cash of $579.9 million. The $121.1 million (21%) cash increase from the comparable 2007 period was primarily due to:
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| ▪ a $158.6 million increase from overall debt financing activities—which include our issuances and payments of debt and our debt issuance costs. The period-to-period increase in cash from financing activities was primarily due to (i) a $113.6 million increase in cash inflows from higher overall net commercial paper borrowings in the first half of 2008; and (ii) a $45.1 million net increase in cash inflows from higher issuances of senior notes in the first half of 2008. |
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| The increase from issuances of senior notes reflects the combined $1,581.8 million we received from our February and June 2008 public offerings of senior notes (discussed in Note 7 to our consolidated financial statements included elsewhere in this report), versus the combined $1,536.7 million we received from our public offerings of senior notes in the first half of 2007. On January 30, 2007 and June 21, 2007, we completed offerings of $1.0 billion and $550 million, respectively, in principal amount of senior notes in three separate series: $600 million of 6.00% notes due February 1, 2017, $400 million of 6.50% notes due February 1, 2037, and $550 million of 6.95% notes due January 15, 2038. We used the proceeds from each of our 2008 and 2007 debt offerings to reduce the borrowings under our commercial paper program; |
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| ▪ an $86.4 million increase in cash inflows from partnership equity issuances. The increase relates to the combined $384.3 million we received from the two separate offerings of additional common units in the first half of 2008 (discussed above in “—Long-term Financing”), versus the $297.9 million we received, after commissions and underwriting expenses, in May 2007 for our issuance of an additional 5,700,000 i-units; |
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| ▪ a $32.6 million increase in cash inflows from net changes in cash book overdrafts—resulting from timing differences on checks issued but not yet endorsed; and |
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| ▪ a $158.4 million decrease from higher partnership distributions in the first six months of 2008, when compared to the first six months of 2007. Distributions to all partners, consisting of our common and Class B unitholders, our general partner and minority interests, totaled $706.4 million in the first half of 2008, compared to $548.0 million in the same period a year ago. |
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Partnership Distributions
Our partnership agreement requires that we distribute 100% of “Available Cash,” as defined in our partnership agreement, to our partners within 45 days following the end of each calendar quarter in accordance with their respective percentage interests. Our 2007 Form 10-K contains additional information concerning our partnership distributions, including the definition of “Available Cash,” the manner in which our total distributions are divided between our general partner and our limited partners, and the form of distributions to all of our partners, including minority interests.
As discussed in Note 2 to our consolidated financial statements included elsewhere in this report, the transactions, balances and results of operations of our Trans Mountain pipeline system were included in our consolidated financial information as if it had been transferred to us on January 1, 2006; however, the effective date of this acquisition was April 30, 2007, and the acquisition had no impact on the distributions we made (including incentive distributions paid to our general partner) prior to this date.
On May 15, 2008, we paid a quarterly distribution of $0.96 per unit for the first quarter of 2008. This distribution was 16% greater than the $0.83 distribution per unit we paid in May 2007 for the first quarter of 2007. We paid this distribution in cash to our general partner and to our common and Class B unitholders. KMR, our sole i-unitholder, received additional i-units based on the $0.96 cash distribution per common unit. We believe that future operating results will continue to support similar levels of quarterly cash and i-unit distributions; however, no assurance can be given that future distributions will continue at such levels.
Additionally, on July 16, 2008, we declared a cash distribution of $0.99 per unit for the second quarter of 2008 (an annualized rate of $3.96 per unit). This distribution was 16% higher than the $0.85 per unit distribution we made for the second quarter of 2007. In November 2007, we announced that we expected to declare cash distributions of $4.02 per unit for 2008, an almost 16% increase over our cash distributions of $3.48 per unit for 2007. We now expect to exceed this distribution target for 2008; however, no assurance can be given that we will be able to exceed this level of distribution, and our expectation does not take into account any capital costs associated with financing the payment of reparations sought by shippers on our Pacific operations’ interstate pipelines.
The incentive distribution that we paid on May 15, 2008 to our general partner (for the first quarter of 2008) was $185.8 million. Our general partner’s incentive distribution that we paid in May 2007 (for the first quarter of 2007) was $138.8 million. Our general partner’s incentive distribution for the distribution that we declared for the second quarter of 2008 will be $194.2 million, and our general partner’s incentive distribution for the distribution that we paid for the second quarter of 2007 was $147.6 million. The period-to-period increases in our general partner incentive distributions resulted from both increased cash distributions per unit and increases in the number of common units and i-units outstanding.
Litigation and Environmental
As of June 30, 2008, we have recorded a total reserve for environmental claims, without discounting and without regard to anticipated insurance recoveries, in the amount of $88.1 million. In addition, we have recorded a receivable of $30.2 million for expected cost recoveries that have been deemed probable. As of December 31, 2007, our environmental reserve totaled $92.0 million and our estimated receivable for environmental cost recoveries totaled $37.8 million, respectively. The reserve is primarily established to address and clean up soil and ground water impacts from former releases to the environment at facilities we have acquired or accidental spills or releases at facilities that we own. Reserves for each project are generally established by reviewing existing documents, conducting interviews and performing site inspections to determine the overall size and impact to the environment. Reviews are made on a quarterly basis to determine the status of the cleanup and the costs associated with the effort. In assessing environmental risks in conjunction with proposed acquisitions, we review records relating to environmental issues, conduct site inspections, interview employees, and, if appropriate, collect soil and groundwater samples.
Additionally, as of June 30, 2008, and December 31, 2007, we have recorded a total reserve for legal fees, transportation rate cases and other litigation liabilities in the amount of $219.4 million and $247.9 million, respectively. The reserve is primarily related to various claims from lawsuits arising from our Pacific operations,
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and the contingent amount is based on both the circumstances of probability and reasonability of dollar estimates. We regularly assess the likelihood of adverse outcomes resulting from these claims in order to determine the adequacy of our liability provision.
Though no assurance can be given, we believe we have established adequate environmental and legal reserves such that the resolution of pending environmental matters and litigation will not have a material adverse impact on our business, cash flows, financial position or results of operations. However, changing circumstances could cause these matters to have a material adverse impact.
Pursuant to our continuing commitment to operational excellence and our focus on safe, reliable operations, we have implemented, and intend to implement in the future, enhancements to certain of our operational practices in order to strengthen our environmental and asset integrity performance. These enhancements have resulted and may result in higher operating costs and sustaining capital expenditures; however, we believe these enhancements will provide us the greater long term benefits of improved environmental and asset integrity performance.
Please refer to Note 3 to our consolidated financial statements included elsewhere in this report for additional information regarding pending litigation, environmental and asset integrity matters.
Certain Contractual Obligations
Except as set forth under “—Midcontinent Express Pipeline LLC Debt” and under “—Senior Notes” in Note 7 to our consolidated financial statements included elsewhere in this report, there have been no material changes in our contractual obligations that would affect the disclosures presented as of December 31, 2007 in our 2007 Form 10-K.
Off Balance Sheet Arrangements
Except as set forth under “—Midcontinent Express Pipeline LLC Debt” in Note 7 to our consolidated financial statements included elsewhere in this report, there have been no material changes in our obligations with respect to other entities that are not consolidated in our financial statements that would affect the disclosures presented as of December 31, 2007 in our 2007 Form 10-K.
Fair Value Measurements
On September 15, 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” In general, fair value measurements and disclosures are made in accordance with the provisions of this Statement and, while not requiring material new fair value measurements, SFAS No. 157 established a single definition of fair value in generally accepted accounting principles and expanded disclosures about fair value measurements. For more information on our fair value measurements, see Note 10 to our consolidated financial statements included elsewhere in this report.
Information Regarding Forward-Looking Statements
This filing includes forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. They use words such as “anticipate,” “believe,” “intend,” “plan,” “projection,” “forecast,” “strategy,” “position,” “continue,” “estimate,” “expect,” “may,” or the negative of those terms or other variations of them or comparable terminology. In particular, statements, express or implied, concerning future actions, conditions or events, future operating results or the ability to generate sales, income or cash flow or to make distributions are forward-looking statements. Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. Future actions, conditions or events and future results of operations may differ materially from those expressed in these forward-looking statements. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors which could cause actual results to differ from those in the forward-looking statements include:
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| ▪ price trends and overall demand for natural gas liquids, refined petroleum products, oil, carbon dioxide, natural gas, electricity, coal and other bulk materials and chemicals in North America; |
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| ▪ economic activity, weather, alternative energy sources, conservation and technological advances that may affect price trends and demand; |
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| ▪ changes in our tariff rates implemented by the Federal Energy Regulatory Commission or the California Public Utilities Commission; |
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| ▪ our ability to acquire new businesses and assets and integrate those operations into our existing operations, as well as our ability to expand our facilities; |
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| ▪ difficulties or delays experienced by railroads, barges, trucks, ships or pipelines in delivering products to or from our terminals or pipelines; |
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| ▪ our ability to successfully identify and close acquisitions and make cost-saving changes in operations; |
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| ▪ shut-downs or cutbacks at major refineries, petrochemical or chemical plants, ports, utilities, military bases or other businesses that use our services or provide services or products to us; |
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| ▪ crude oil and natural gas production from exploration and production areas that we serve, such as the Permian Basin area of West Texas, the U.S. Rocky Mountains and the Alberta oilsands; |
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| ▪ changes in laws or regulations, third-party relations and approvals, and decisions of courts, regulators and governmental bodies that may adversely affect our business or our ability to compete; |
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| ▪ changes in accounting pronouncements that impact the measurement of our results of operations, the timing of when such measurements are to be made and recorded, and the disclosures surrounding these activities; |
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| ▪ our ability to offer and sell equity securities and debt securities or obtain debt financing in sufficient amounts to implement that portion of our business plan that contemplates growth through acquisitions of operating businesses and assets and expansions of our facilities; |
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| ▪ our indebtedness, which could make us vulnerable to general adverse economic and industry conditions, limit our ability to borrow additional funds, and/or place us at competitive disadvantages compared to our competitors that have less debt or have other adverse consequences; |
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| ▪ interruptions of electric power supply to our facilities due to natural disasters, power shortages, strikes, riots, terrorism, war or other causes; |
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| ▪ our ability to obtain insurance coverage without significant levels of self-retention of risk; |
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| ▪ acts of nature, sabotage, terrorism or other similar acts causing damage greater than our insurance coverage limits; |
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| ▪ capital markets conditions, inflation and interest rates; |
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| ▪ the political and economic stability of the oil producing nations of the world; |
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| ▪ national, international, regional and local economic, competitive and regulatory conditions and developments; |
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| ▪ our ability to achieve cost savings and revenue growth; |
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| ▪ foreign exchange fluctuations; |
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| ▪ the timing and extent of changes in commodity prices for oil, natural gas, electricity and certain agricultural products; |
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| ▪ the extent of our success in discovering, developing and producing oil and gas reserves, including the risks inherent in exploration and development drilling, well completion and other development activities; |
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| ▪ engineering and mechanical or technological difficulties that we may experience with operational equipment, in well completions and workovers, and in drilling new wells; |
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| ▪ the uncertainty inherent in estimating future oil and natural gas production or reserves; |
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| ▪ the ability to complete expansion projects on time and on budget; |
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| ▪ the timing and success of our business development efforts; and |
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| ▪ unfavorable results of litigation and the fruition of contingencies referred to in Note 3 to our consolidated financial statements included elsewhere in this report. |
There is no assurance that any of the actions, events or results of the forward-looking statements will occur, or if any of them do, what impact they will have on our results of operations or financial condition. Because of these uncertainties, you should not put undue reliance on any forward-looking statements.
See Item 1A “Risk Factors” of our 2007 Form 10-K, and Part II, Item 1A “Risk Factors” of this report for a more detailed description of these and other factors that may affect the forward-looking statements. When considering forward-looking statements, one should keep in mind the risk factors described in both our 2007 Form 10-K and this report. The risk factors could cause our actual results to differ materially from those contained in any forward-looking statement. We disclaim any obligation, other than as required by applicable law, to update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments.
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Item 3. Quantitative and Qualitative Disclosures About Market Risk. |
There have been no material changes in market risk exposures that would affect the quantitative and qualitative disclosures presented as of December 31, 2007, in Item 7A of our 2007 Form 10-K. For more information on our risk management activities, see Note 10 to our consolidated financial statements included elsewhere in this report.
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Item 4. Controls and Procedures. |
As of June 30, 2008, our management, including our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon and as of the date of the evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the design and operation of our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in the reports we file and submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported as and when required, and is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. There has been no change in our internal control over financial reporting during the quarter ended June 30, 2008 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
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PART II. OTHER INFORMATION
Item 1. Legal Proceedings.
See Part I, Item 1, Note 3 to our consolidated financial statements entitled “Litigation, Environmental and Other Contingencies,” which is incorporated in this item by reference.
Item 1A. Risk Factors.
Except as set forth below, there have been no material changes in or additions to the risk factors disclosed in Item 1A “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2007.
Our business is subject to extensive regulation that affects our operations and costs.
Our assets and operations are subject to regulation by federal, state, provincial and local authorities, including regulation by the Federal Energy Regulatory Commission, and by various authorities under federal, state and local environmental, human health and safety and pipeline safety laws. Regulation affects almost every aspect of our business, including, among other things, our ability to determine terms and rates for our interstate pipeline services, to make acquisitions or to build extensions of existing facilities. The costs of complying with such laws and regulations are already significant, and additional or more stringent regulation could have a material adverse impact on our business, financial condition and results of operations.
In addition, regulators have taken actions designed to enhance market forces in the gas pipeline industry, which have led to increased competition. In a number of U.S. markets, natural gas interstate pipelines face competitive pressure from a number of new industry participants, such as alternative suppliers, as well as traditional pipeline competitors. Increased competition driven by regulatory changes could have a material impact on business in our markets and therefore adversely affect our financial condition and results of operations.
Environmental regulation and liabilities could result in increased operating and capital costs.
Our business operations are subject to federal, state, provincial and local laws and regulations relating to environmental protection, pollution and human health and safety in the United States and Canada. For example, if an accidental leak, release or spill of liquid petroleum products, chemicals or other hazardous substances occurs at or from our pipelines or at or from our storage or other facilities, we may experience significant operational disruptions and we may have to pay a significant amount to clean up the leak, release or spill, pay for government penalties, address natural resource damage, compensate for human exposure or property damage, install costly pollution control equipment or a combination of these and other measures. The resulting costs and liabilities could materially and negatively affect our level of earnings and cash flows. In addition, emission controls required under federal, state and provincial environmental laws could require significant capital expenditures at our facilities. The costs of complying with such environmental laws and regulations are already significant, and additional or more stringent regulation could increase these costs or otherwise negatively affect our business.
We own and/or operate numerous properties that have been used for many years in connection with our business activities. While we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other hazardous substances may have been released at or from properties owned, operated or used by us or our predecessors, or at or from properties where our or our predecessors’ wastes have been taken for disposal. In addition, many of these properties have been owned and/or operated by third parties whose management, handling and disposal of hydrocarbons or other hazardous substances were not under our control. These properties and the hazardous substances released and wastes disposed thereon may be subject to laws in the United States such as the Comprehensive Environmental Response, Compensation, and Liability Act, also known as CERCLA or the Superfund law, which impose joint and several liability without regard to fault or the legality of the original conduct. Under the regulatory schemes of the various provinces, Canada has similar laws with respect to properties owned, operated or used by us or our predecessors. Under such laws and implementing regulations, we
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could be required to remove or remediate previously disposed wastes or property contamination, including contamination caused by prior owners or operators. Imposition of such liability schemes could have a material adverse impact on our operations and financial position.
In addition, our oil and gas development and production activities are subject to numerous federal, state and local laws and regulations relating to environmental quality and pollution control. These laws and regulations increase the costs of these activities and may prevent or delay the commencement or continuance of a given operation. Specifically, these activities are subject to laws and regulations regarding the acquisition of permits before drilling, restrictions on drilling activities in restricted areas, emissions into the environment, water discharges, and storage and disposition of wastes. In addition, legislation has been enacted that requires well and facility sites to be abandoned and reclaimed to the satisfaction of state authorities. The costs of complying with such laws and regulations are already significant and additional or more stringent laws and regulations could increase these costs or could otherwise negatively affect our business.
We are aware of the increasing focus of national and international regulatory bodies on greenhouse gas emissions and climate change issues. We are also aware of legislation, recently proposed by the Canadian legislature, to reduce greenhouse gas emissions. Additionally, proposed United States policy, legislation or regulatory actions may also address greenhouse gas emissions. We expect to continue to monitor and assess significant new policies, legislation or regulation in the areas where we operate, but we cannot currently estimate the potential impact of the proposals on our operations.
Our substantial debt could adversely affect our financial health and make us more vulnerable to adverse economic conditions.
As of June 30, 2008, we had outstanding $8,056.5 million of consolidated debt (excluding the value of interest rate swaps). This level of debt could have important consequences, such as:
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| ▪ limiting our ability to obtain additional financing to fund our working capital, capital expenditures, debt service requirements or potential growth or for other purposes; |
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| ▪ limiting our ability to use operating cash flow in other areas of our business because we must dedicate a substantial portion of these funds to make payments on our debt; |
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| ▪ placing us at a competitive disadvantage compared to competitors with less debt; and |
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| ▪ increasing our vulnerability to adverse economic and industry conditions. |
Each of these factors is to a large extent dependent on economic, financial, competitive and other factors beyond our control.
Our large amount of variable rate debt makes us vulnerable to increases in interest rates.
As of June 30, 2008, approximately 44.6% of our $8,056.5 million of consolidated debt was subject to variable interest rates, either as short-term or long-term variable rate debt obligations or as long-term fixed-rate debt converted to variable rates through the use of interest rate swaps. Should interest rates increase significantly, the amount of cash required to service this debt would increase. For information on our interest rate risk, see Item 7A “Quantitative and Qualitative Disclosures About Market Risk—Interest Rate Risk” in our Annual Report on Form 10-K for the year ended December 31, 2007.
Terrorist attacks, or the threat of them, may adversely affect our business.
The U.S. government has issued public warnings that indicate that pipelines and other energy assets might be specific targets of terrorist organizations. These potential targets might include our pipeline systems. Our operations could become subject to increased governmental scrutiny that would require increased security measures. Recent federal legislation provides an insurance framework that should cause current insurers to continue to provide sabotage and terrorism coverage under standard property insurance policies. Nonetheless, there is no assurance that
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adequate sabotage and terrorism insurance will be available at rates we believe are reasonable in the near future. These developments may subject our operations to increased risks, as well as increased costs, and, depending on their ultimate magnitude, could have a material adverse effect on our business, results of operations and financial condition.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.
None.
Item 3. Defaults Upon Senior Securities.
None.
Item 4. Submission of Matters to a Vote of Security Holders.
None.
Item 5. Other Information.
None.
Item 6. Exhibits.
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*3.1 — | Third Amended and Restated Agreement of Limited Partnership of Kinder Morgan Energy Partners, L.P. (filed as Exhibit 3.1 to Kinder Morgan Energy Partners, L.P. Form 10-Q (File No. 1-11234) for the quarter ended June 30, 2001, filed on August 9, 2001). |
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*3.2 — | Amendment No. 1 dated November 19, 2004 to Third Amended and Restated Agreement of Limited Partnership of Kinder Morgan Energy Partners, L.P. (filed as Exhibit 99.1 to Kinder Morgan Energy Partners, L.P. Form 8-K, filed November 22, 2004). |
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*3.3 — | Amendment No. 2 to Third Amended and Restated Agreement of Limited Partnership of Kinder Morgan Energy Partners, L.P. (filed as Exhibit 99.1 to Kinder Morgan Energy Partners, L.P. Form 8-K, filed May 5, 2005). |
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*3.4 — | Amendment No. 3 to Third Amended and Restated Agreement of Limited Partnership of Kinder Morgan Energy Partners, L.P. (filed as Exhibit 3.1 to Kinder Morgan Energy Partners, L.P. Form 8-K, filed April 21, 2008). |
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*4.1 — | Certificate of the Vice President and Treasurer and the Vice President and Chief Financial Officer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 6.95% Senior Notes due 2038 (filed as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P. Form 10-Q for the quarter ended June 30, 2007 filed August 8, 2007). |
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*4.2 — | Certificate of the Vice President and Treasurer and the Vice President and Chief Financial Officer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 5.95% Senior Notes due 2018 (filed as Exhibit 4.28 to Kinder Morgan Energy Partners, L.P. Form 10-K for the year ended December 31, 2007 filed February 26, 2008). |
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4.3 — | Certain instruments with respect to long-term debt of Kinder Morgan Energy Partners, L.P. and its consolidated subsidiaries which relate to debt that does not exceed 10% of the total assets of Kinder Morgan Energy Partners, L.P. and its consolidated subsidiaries are omitted pursuant to Item 601(b) (4) (iii) (A) of Regulation S-K, 17 C.F.R. sec.229.601. Kinder Morgan Energy Partners, L.P. hereby agrees to furnish supplementally to the Securities and Exchange Commission a copy of each such instrument upon request. |
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*10. 1 – | First Amendment to Retention and Relocation Agreement, dated as of July 16, 2008, between Knight Inc. and Scott E. Parker (filed as Exhibit 10.1 to Kinder Morgan Energy Partners, L.P. Form 8-K, filed July 25, 2008). |
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11 | — Statement re: computation of per share earnings. |
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12 | — Statement re: computation of ratio of earnings to fixed charges. |
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18 | — Letter re: change in accounting principle. |
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31.1 — | Certification by CEO pursuant to Rule 13a-14 or 15d-14 of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
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31.2 — | Certification by CFO pursuant to Rule 13a-14 or 15d-14 of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
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32.1 — | Certification by CEO pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
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32.2 — | Certification by CFO pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
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* Asterisk indicates exhibits incorporated by reference as indicated; all other exhibits are filed herewith, except as noted otherwise. |
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SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
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| KINDER MORGAN ENERGY PARTNERS, L.P. |
| (A Delaware limited partnership) |
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| By: | KINDER MORGAN G.P., INC., |
| | its sole General Partner |
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| By: | KINDER MORGAN MANAGEMENT, LLC, |
| | the Delegate of Kinder Morgan G.P., Inc. |
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| | /s/ Kimberly A. Dang |
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| | Kimberly A. Dang |
| | Vice President and Chief Financial Officer |
| | (principal financial and accounting officer) |
| | Date: August 6, 2008 |
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