SFPP and UPRR are also engaged in multiple disputes over the circumstances under which SFPP must pay for a relocation of its pipeline within the UPRR right-of-way and the safety standards that govern relocations. In July 2006, a trial before a judge regarding the circumstances under which SFPP must pay for relocations concluded, and the judge determined that SFPP must pay for any relocations resulting from any legitimate business purpose of the UPRR. SFPP has appealed this decision, and in December 2008, the appellate court affirmed the decision. In addition, UPRR contends that SFPP must comply with the more expensive American Railway Engineering and Maintenance-of-Way standards in determining when relocations are necessary and in completing relocations. Each party is seeking declaratory relief with respect to its positions regarding the application of these standards with respect to relocations.
It is difficult to quantify the effects of the outcome of these cases on SFPP, because SFPP does not know UPRR’s plans for projects or other activities that would cause pipeline relocations. Even if SFPP is successful in advancing its positions, significant relocations for which SFPP must nonetheless bear the expense (i.e., for railroad purposes, with the standards in the federal Pipeline Safety Act applying) would have an adverse effect on our financial position and results of operations. These effects would be even greater in the event SFPP is unsuccessful in one or more of these litigations.
United States of America, ex rel., Jack J. Grynberg v. K N Energy (Civil Action No. 97-D-1233, filed in the U.S. District Court, District of Colorado).
This multi-district litigation proceeding involves four lawsuits filed in 1997 against numerous Kinder Morgan companies. These suits were filed pursuant to the federal False Claims Act and allege underpayment of royalties due to mismeasurement of natural gas produced from federal and Indian lands. The complaints are part of a larger series of similar complaints filed by Mr. Grynberg against 77 natural gas pipelines (approximately 330 other defendants) in various courts throughout the country which were consolidated and transferred to the District of Wyoming.
In May 2005, a Special Master appointed in this litigation found that because there was a prior public disclosure of the allegations and that Grynberg was not an original source, the Court lacked subject matter jurisdiction. As a result, the Special Master recommended that the Court dismiss all the Kinder Morgan defendants. In October 2006, the United States District Court for the District of Wyoming upheld the dismissal of each case against the Kinder Morgan defendants on jurisdictional grounds. Grynberg appealed this Order to the Tenth Circuit Court of Appeals. Briefing was completed and oral argument was held on September 25, 2008. A decision by the Tenth Circuit Court of Appeals affirming the dismissal of the Kinder Morgan Defendants was issued on March 17, 2009. Grynberg’s petition for rehearing was denied on May 4, 2009 and the Tenth Circuit issued its Mandate on May 18, 2009. A Petition for Writ of Certiorari, if filed, would be due August 3, 2009.
Prior to the dismissal order on jurisdictional grounds, the Kinder Morgan defendants filed Motions to Dismiss and for Sanctions alleging that Grynberg filed his Complaint without evidentiary support and for an improper purpose. On January 8, 2007, after the dismissal order, the Kinder Morgan defendants also filed a Motion for Attorney Fees under the False Claim Act. A decision is still pending on the Motions to Dismiss and for Sanctions and the Requests for Attorney Fees.
Severstal Sparrows Point Crane Collapse
On June 4, 2008, a bridge crane owned by Severstal Sparrows Point, LLC in Sparrows Point Maryland collapsed while being operated by Kinder Morgan Bulk Terminals, Inc. According to our investigation, the collapse was caused by unexpected, sudden and extreme winds. On June 24, 2009, Severstal filed suit against Kinder Morgan Bulk Terminals in the United States District Court for the District of Maryland, cause no. WMN 09CV1668, alleging that we were contractually obligated to replace the collapsed crane and that our employees were negligent in failing to properly secure the crane prior to the collapse. Severstal seeks unspecified damages for value of the crane and lost profits. Kinder Morgan Bulk Terminals denies each of Severstal’s allegations.
Leukemia Cluster Litigation
Richard Jernee, et al v. Kinder Morgan Energy Partners, et al, No. CV03-03482 (Second Judicial District Court, State of Nevada, County of Washoe) (“Jernee”).
Floyd Sands, et al v. Kinder Morgan Energy Partners, et al, No. CV03-05326 (Second Judicial District Court, State of Nevada, County of Washoe) (“Sands”).
On May 30, 2003, plaintiffs, individually and on behalf of Adam Jernee, filed a civil action in the Nevada State trial court against us and several Kinder Morgan related entities and individuals and additional unrelated defendants. Plaintiffs in the Jernee matter claim that defendants negligently and intentionally failed to inspect, repair and replace unidentified segments of their pipeline and facilities, allowing “harmful substances and emissions and gases” to
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damage “the environment and health of human beings.” Plaintiffs claim that “Adam Jernee’s death was caused by leukemia that, in turn, is believed to be due to exposure to industrial chemicals and toxins.” Plaintiffs purport to assert claims for wrongful death, premises liability, negligence, negligence per se, intentional infliction of emotional distress, negligent infliction of emotional distress, assault and battery, nuisance, fraud, strict liability (ultra hazardous acts), and aiding and abetting, and seek unspecified special, general and punitive damages.
On August 28, 2003, a separate group of plaintiffs, represented by the counsel for the plaintiffs in the Jernee matter, individually and on behalf of Stephanie Suzanne Sands, filed a civil action in the Nevada State trial court against the same defendants and alleging the same claims as in the Jernee case with respect to Stephanie Suzanne Sands. The Jernee case has been consolidated for pretrial purposes with the Sands case.
In July, 2009, plaintiffs in both the Sands and Jernee cases agreed to dismiss all claims against the Kinder Morgan related defendants with prejudice in exchange for the Kinder Morgan defendants’ agreement that they would not seek to recover their defense costs against the plaintiffs. The Kinder Morgan defendants have filed a Motion for Approval of Good Faith Settlement with the trial court, which is currently pending. If granted, this matter will be concluded with respect to all Kinder Morgan related entities and individuals.
Pipeline Integrity and Releases
From time to time, despite our best efforts, our pipelines experience leaks and ruptures. These leaks and ruptures may cause explosions, fire, damage to the environment, damage to property and/or personal injury or death. In connection with these incidents, we may be sued for damages caused by an alleged failure to properly mark the locations of our pipelines and/or to properly maintain our pipelines. Depending upon the facts and circumstances of a particular incident, state and federal regulatory authorities may seek civil and/or criminal fines and penalties.
Midcontinent Express Pipeline LLC Construction Incident
On July 15, 2009, a Midcontinent Express Pipeline LLC contractor and subcontractor were conducting a nitrogen pressure test on facilities at a Midcontinent Express delivery meter station that was under construction in Smith County, Mississippi. An unexpected release occurred during testing, resulting in one fatality and injuries to four other employees of the contractor or subcontractor. The United States Occupational Safety and Health Administration is investigating the cause of the incident with assistance from the United States Department of Transportation Pipeline and Hazardous Materials Safety Administration, referred to in this note as the PHMSA. All construction work at other Midcontinent Express meter sites was allowed to continue after safety and construction reviews confirmed that the work could resume safely.
Pasadena Terminal Fire
On September 23, 2008, a fire occurred in the pit 3 manifold area of our Pasadena, Texas terminal facility. One of our employees was injured and subsequently died. In addition, the pit 3 manifold was severely damaged.
On July 13, 2009, a civil lawsuit was filed by and on behalf of the family of the deceased employee entitledBrandy Williams et. al. v. KMGP Services Company, Inc. in the 133rd District Court of Harris County, Texas, case no. 2009-44321. The suit alleges one count of gross negligence against defendant and seeks unspecified compensatory and punitive damages. We have filed an Answer denying the allegations in the Complaint, and the parties are currently engaged in discovery.
Rockies Express Pipeline LLC Wyoming Construction Incident
On November 11, 2006, a bulldozer operated by an employee of Associated Pipeline Contractors, Inc., a third-party contractor to Rockies Express Pipeline LLC, struck an existing subsurface natural gas pipeline owned by Wyoming Interstate Company, a subsidiary of El Paso Pipeline Group. The pipeline was ruptured, resulting in an explosion and fire. The incident occurred in a rural area approximately nine miles southwest of Cheyenne, Wyoming. The incident resulted in one fatality (the operator of the bulldozer) and there were no other reported injuries. The cause of the incident was investigated by the PHMSA. In March 2008, the PHMSA issued a Notice of Probable Violation, Proposed Civil Penalty and Proposed Compliance Order, referred to in this note as a NOPV, to El Paso Corporation in which it
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concluded that El Paso failed to comply with federal law and its internal policies and procedures regarding protection of its pipeline, resulting in this incident.
To date, the PHMSA has not issued any NOPV’s to Rockies Express Pipeline LLC, referred to as Rockies Express, and we do not expect that it will do so. Immediately following the incident, Rockies Express and El Paso Pipeline Group reached an agreement on a set of additional enhanced safety protocols designed to prevent the reoccurrence of such an incident.
In September 2007, the family of the deceased bulldozer operator filed a wrongful death action against us, Rockies Express and several other parties in the District Court of Harris County, Texas, 189th Judicial District, at case number 2007-57916. The plaintiffs seek unspecified compensatory and exemplary damages plus interest, attorney’s fees and costs of suit. We have asserted contractual claims for complete indemnification for any and all costs arising from this incident, including any costs related to this lawsuit, against third parties and their insurers. On March 25, 2008, we entered into a settlement agreement with one of the plaintiffs, the decedent’s daughter, resolving any and all of her claims against us, Rockies Express and its contractors. We were indemnified for the full amount of this settlement by one of Rockies Express’ contractors. On October 17, 2008, the remaining plaintiffs filed a Notice of Nonsuit, which dismissed the remaining claims against all defendants without prejudice to the plaintiffs’ ability to re-file their claims at a later date. The remaining plaintiffs re-filed their Complaint against Rockies Express, us and several other parties on November 7, 2008, Cause No. 2008-66788, currently pending in the District Court of Harris County, Texas, 189th Judicial District. The parties are currently engaged in discovery.
Charlotte, North Carolina
On November 27, 2006, the Plantation Pipeline experienced a release of approximately 95 barrels of gasoline from a Plantation Pipe Line Company block valve on a delivery line into a terminal owned by a third party company. The line was repaired and put back into service within a few days. Remediation efforts are continuing under the direction of the North Carolina Department of Environment and Natural Resources, referred to in this note as the NCDENR, which issued a Notice of Violation and Recommendation of Enforcement against Plantation on January 8, 2007. Plantation continues to cooperate fully with the NCDENR.
In April 2007, during pipeline maintenance activities near Charlotte, North Carolina, Plantation discovered the presence of historical soil contamination near the pipeline, and reported the presence of impacted soils to the NCDENR. Subsequently, Plantation contacted the owner of the property to request access to the property to investigate the potential contamination. The results of that investigation indicate that there is soil and groundwater contamination which appears to be from a historical turbine fuel release. The groundwater contamination is underneath at least two lots on which there is current construction of single family homes that are part of a new residential development. Further investigation and remediation are being conducted under the oversight of the NCDENR. Plantation reached a settlement with the builder of the two homes that were impacted. Plantation continues to negotiate with the owner of the property to address any potential claims that it may bring.
Barstow, California
The United States Department of Navy has alleged that historic releases of methyl tertiary-butyl ether, referred to in this report as MTBE, from Calnev Pipe Line Company’s Barstow terminal (i) have migrated underneath the Navy’s Marine Corps Logistics Base in Barstow; (ii) have impacted the Navy’s existing groundwater treatment system for unrelated groundwater contamination not alleged to have been caused by Calnev; and (iii) could affect the Barstow, California Marine Corps Logistic Base’s water supply system. Although Calnev believes that it has certain meritorious defenses to the Navy’s claims, it is working with the Navy to agree upon an Administrative Settlement Agreement and Order on Consent for federal Comprehensive Environmental Response, Compensation and Liability Act (referred to as CERCLA) Removal Action to reimburse the Navy for $0.5 million in past response actions, plus potentially perform other work, if the parties determine it to be necessary, to ensure protection of the Navy’s existing treatment system and water supply.
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Oil Spill Near Westridge Terminal, Burnaby, British Columbia
On July 24, 2007, a third-party contractor installing a sewer line for the City of Burnaby struck a crude oil pipeline segment included within our Trans Mountain pipeline system near its Westridge terminal in Burnaby, BC, resulting in a release of approximately 1,400 barrels of crude oil. The release impacted the surrounding neighborhood, several homes and nearby Burrard Inlet. No injuries were reported. To address the release, we initiated a comprehensive emergency response in collaboration with, among others, the City of Burnaby, the British Columbia Ministry of Environment, the National Energy Board, and the National Transportation Safety Board. Cleanup and environmental remediation is near completion.
The National Transportation Safety Board released its investigation report on the incident on March 18, 2009. The report confirmed that an absence of pipeline location marking in advance of excavation and inadequate communication between the contractor and our subsidiary Kinder Morgan Canada Inc., the operator of the line, were the primary causes of the accident. No directives, penalties or actions of Kinder Morgan Canada Inc. were required as a result of the report.
On July, 22, 2009, the British Columbia Ministry of Environment issued regulatory charges against the third-party contractor, the engineering consultant to the sewer line project, Kinder Morgan Canada Inc., and Trans Mountain L.P. (the last two of which are subsidiaries of ours). The charges claim that the parties charged caused the release of crude oil, and in doing so were in violation of various sections of the Environmental, Fisheries and Migratory Bird Acts. We are of the view that the charges have been improperly laid against us, and we intend to vigorously defend against them.
General
Although no assurance can be given, we believe that we have meritorious defenses to the actions set forth in this note and, to the extent an assessment of the matter is possible, if it is probable that a liability has been incurred and the amount of loss can be reasonably estimated, we believe that we have established an adequate reserve to cover potential liability.
Additionally, although it is not possible to predict the ultimate outcomes, we also believe, based on our experiences to date, that the ultimate resolution of these matters will not have a material adverse impact on our business, financial position, results of operations or cash flows. As of June 30, 2009 and December 31, 2008, we have recorded a total reserve for legal fees, transportation rate cases and other litigation liabilities in the amount of $207.9 million and $234.8 million, respectively. The reserve is primarily related to various claims from lawsuits arising from our West Coast products pipeline transportation rates, 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.
Environmental Matters
The City of Los Angeles v. Kinder Morgan Liquids Terminals, LLC, Shell Oil Company, Equilon Enterprises LLC; California Superior Court, County of Los Angeles, Case No. NC041463.
Kinder Morgan Liquids Terminals LLC is a defendant in a lawsuit filed in 2005 alleging claims for environmental cleanup costs at the former Los Angeles Marine Terminal in the Port of Los Angeles. The lawsuit was stayed for the first half of 2009 in order to allow the parties to work with the regulatory agency concerning the scope of the required cleanup. The regulatory agency has not yet made any final decisions concerning cleanup of the former terminal, although the agency is expected to issue final cleanup orders in 2009.
The lawsuit stay has now been lifted, and two new defendants have been added to the lawsuit by plaintiff in a Third Amended Complaint. Plaintiff's Third Amended Complaint alleges that future environmental cleanup costs at
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the former terminal will exceed $10 million, and that Plaintiff's past damages exceed $2 million. No trial date has yet been set.
Exxon Mobil Corporation v. GATX Corporation, Kinder Morgan Liquids Terminals, LLC and ST Services, Inc.
On April 23, 2003, Exxon Mobil Corporation filed a complaint in the Superior Court of New Jersey, Gloucester County. The lawsuit relates to environmental remediation obligations at a Paulsboro, New Jersey liquids terminal owned by ExxonMobil from the mid-1950s through November 1989, by GATX Terminals Corp. from 1989 through September 2000, later owned by Support Terminals. The terminal is now owned by Pacific Atlantic Terminals, LLC, and it too is a party to the lawsuit.
The complaint seeks any and all damages related to remediating all environmental contamination at the terminal, and, according to the New Jersey Spill Compensation and Control Act, treble damages may be available for actual dollars incorrectly spent by the successful party in the lawsuit. The parties are currently involved in mandatory mediation and met in June and October 2008. No progress was made at any of the mediations. The mediation judge has referred the case back to the litigation court room.
On June 25, 2007, the New Jersey Department of Environmental Protection, the Commissioner of the New Jersey Department of Environmental Protection and the Administrator of the New Jersey Spill Compensation Fund, referred to collectively as the plaintiffs, filed a complaint against ExxonMobil Corporation and Kinder Morgan Liquids Terminals LLC, f/k/a GATX Terminals Corporation. The complaint was filed in Gloucester County, New Jersey. Both ExxonMobil and KMLT filed third party complaints against Support Terminals seeking to bring Support Terminals into the case. Support Terminals filed motions to dismiss the third party complaints, which were denied. Support Terminals is now joined in the case and it filed an Answer denying all claims.
The plaintiffs seek the costs and damages that the plaintiffs allegedly have incurred or will incur as a result of the discharge of pollutants and hazardous substances at the Paulsboro, New Jersey facility. The costs and damages that the plaintiffs seek include cleanup costs and damages to natural resources. In addition, the plaintiffs seek an order compelling the defendants to perform or fund the assessment and restoration of those natural resource damages that are the result of the defendants’ actions. As in the case brought by ExxonMobil against GATX Terminals, the issue is whether the plaintiffs’ claims are within the scope of the indemnity obligations between GATX Terminals (and therefore, Kinder Morgan Liquids Terminals) and Support Terminals. The court may consolidate the two cases. The parties are now conducting discovery.
State of Texas v. Kinder Morgan Petcoke, L.P.
Harris County, Texas Criminal Court No. 11, Cause No. 1571148 On February 24, 2009, our subsidiary Kinder Morgan Petcoke, L.P. was served with a misdemeanor summons alleging the unintentional discharge of petroleum coke into the Houston Ship Channel during maintenance activities. On May 27, 2009, we settled the matter by entering a plea of nolo contendere to one count of unintentional discharge to water and paying a fine of $30,000.
Mission Valley Terminal Lawsuit
In August 2007, the City of San Diego, on its own behalf and purporting to act on behalf of the People of the state of California, filed a lawsuit against us and several affiliates seeking injunctive relief and unspecified damages allegedly resulting from hydrocarbon and MTBE impacted soils and groundwater beneath the city’s stadium property in San Diego arising from historic operations at the Mission Valley terminal facility. The case was filed in the Superior Court of California, San Diego County, case number 37-2007-00073033-CU-OR-CTL. On September 26, 2007, we removed the case to the United States District Court, Southern District of California, case number 07CV1883WCAB. On October 3, 2007, we filed a Motion to Dismiss all counts of the Complaint. The court denied in part and granted in part the Motion to Dismiss and gave the City leave to amend their complaint. The City submitted its Amended Complaint and we filed an Answer. The parties have commenced with discovery. This site has been, and currently is, under the regulatory oversight and order of the California Regional Water Quality Control Board.
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Kinder Morgan Port Manatee Terminal, LLC, Palmetto, Florida
On June 18, 2009, Kinder Morgan Port Manatee Terminal received a Revised Warning Letter from the Florida Department of Environmental Protection, referred to in this note as the Florida DEP, advising us of possible regulatory and air permit violations regarding operations at the Port Manatee Terminal. We previously conducted a voluntary internal audit at this facility in March 2008 and identified various environmental compliance and permitting issues primarily related to air quality compliance. We reported our findings from this audit in a self-disclosure letter to the Florida DEP in March, 2008. Following the submittal of our self-disclosure letter, the agency conducted numerous inspections of the air pollution control devices at the Terminal and issued this Revised Warning Letter. We have scheduled a meeting with the Florida DEP to attempt to resolve these issues.
In addition, we have received a subpoena from the U.S. Department of Justice for production of documents related to the service and operation of the Kinder Morgan Port Manatee Terminal. We are fully cooperating with the investigation of this matter.
Other Environmental
We are subject to environmental cleanup and enforcement actions from time to time. In particular, the CERCLA generally imposes joint and several liability for cleanup and enforcement costs on current and predecessor owners and operators of a site, among others, without regard to fault or the legality of the original conduct. Our operations are also subject to federal, state and local laws and regulations relating to protection of the environment. Although we believe our operations are in substantial compliance with applicable environmental law and regulations, risks of additional costs and liabilities are inherent in pipeline, terminal and carbon dioxide field and oil field operations, and there can be no assurance that we will not incur significant costs and liabilities. Moreover, it is possible that other developments, such as increasingly stringent environmental laws, regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from our operations, could result in substantial costs and liabilities to us.
We are currently involved in several governmental proceedings involving alleged air, water and waste violations issued by various governmental authorities related to compliance with environmental regulations. As we receive notices of non-compliance, we negotiate and settle these matters. We do not believe that these alleged violations will have a material adverse effect on our business.
We are also currently involved in several governmental proceedings involving groundwater and soil remediation efforts under administrative orders or related state remediation programs issued by various regulatory authorities related to compliance with environmental regulations associated with our assets. We have established a reserve to address the costs associated with the cleanup.
In addition, we are involved with and have been identified as a potentially responsible party in several federal and state superfund sites. Environmental reserves have been established for those sites where our contribution is probable and reasonably estimable. In addition, we are from time to time involved in civil proceedings relating to damages alleged to have occurred as a result of accidental leaks or spills of refined petroleum products, natural gas liquids, natural gas and carbon dioxide. See “—Pipeline Integrity and Releases” above for additional information with respect to ruptures and leaks from our pipelines.
General
Although it is not possible to predict the ultimate outcomes, we believe that the resolution of the environmental matters set forth in this note will not have a material adverse effect on our business, financial position, results of operations or cash flows. However, we are not able to reasonably estimate when the eventual settlements of these claims will occur and changing circumstances could cause these matters to have a material adverse impact. As of June 30, 2009, we have accrued an environmental reserve of$78.1 million, and we believe the establishment of this environmental reserve is adequate such that the resolution of pending environmental matters will not have a material adverse impact on our business, cash flows, financial position or results of operations. In addition, we have recorded a receivable of $18.6 million for expected cost recoveries that have been deemed probable. As of December 31, 2008, our environmental reserve totaled $78.9 million and our estimated receivable for environmental cost recoveries totaled $20.7 million, respectively. Additionally, many factors may change in the future affecting our reserve estimates, such as (i) regulatory changes; (ii) groundwater and land use near our sites; and (iii) changes in cleanup technology.
Other
We are a defendant in various lawsuits arising from the day-to-day operations of our businesses. Although no assurance can be given, we believe, based on our experiences to date, that the ultimate resolution of such items will not have a material adverse impact on our business, financial position, results of operations or cash flows.
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11. Regulatory Matters
The following updates the disclosure in Note 17 to our audited financial statements that were filed with our 2008 Form 10-K, with respect to developments that occurred during the six months ended June 30, 2009.
Notice of Proposed Rulemaking – Natural Gas Price Transparency
On November 20, 2008, the FERC issued Order 720, which established new reporting requirements for interstate and major non-interstate natural gas pipelines. Interstate pipelines are required to post no-notice activity at each receipt and delivery point three days after the day of gas flow. Major non-interstate pipelines are required to post design capacity, scheduled volumes and available capacity at each receipt or delivery point with a design capacity of 15,000 MMBtus of natural gas per day or greater. The final rule became effective January 27, 2009 for interstate pipelines. On January 15, 2009, the FERC issued an order granting an extension of time for major non-interstate pipelines to comply until 150 days following the issuance of an order addressing the pending requests for rehearing. On January 16, 2009, the FERC granted rehearing of Order 720. On July 16, 2009, the FERC issued a request for supplemental comments on revisions to the posting requirements. Comments are due on October 31, 2009. We do not expect this Order to have a material impact on our consolidated financial statements.
Notice of Proposed Rulemaking - Contract Reporting Requirements of Intrastate Natural Gas Companies, Docket No. RM09-2-000.
On November 20, 2008, the FERC issued a Notice of Inquiry seeking comments on whether the FERC should require intrastate and Hinshaw pipelines to publicly report the details of their transactions in interstate commerce. Comments were filed on February 13, 2009. In response to such comments, on July 16, 2009, the FERC issued a Notice of Proposed Rulemaking in this proceeding, proposing to revise the existing annual transactional reporting requirements for intrastate and Hinshaw pipelines to be filed on a quarterly basis and to include more information than was required under the annual reports. Comments are due on October 27, 2009.
Natural Gas Pipeline Expansion Filings
Rockies Express Meeker to Cheyenne Expansion Project
Pursuant to certain rights exercised by EnCana Gas Marketing USA as a result of its foundation shipper status on the former Entrega Gas Pipeline LLC facilities (now part of the Rockies Express Pipeline), Rockies Express Pipeline LLC is requesting authorization to construct and operate certain facilities that will comprise its Meeker, Colorado to Cheyenne, Wyoming Rockies Express Pipeline expansion project. The proposed expansion will add natural gas compression at its Big Hole compressor station located in Moffat County, Colorado, and its Arlington compressor station located in Carbon County, Wyoming. Upon completion, the additional compression will permit the transportation of an additional 200 million cubic feet per day of natural gas from (i) the Meeker Hub located in Rio Blanco County, Colorado northward to the Wamsutter Hub located in Sweetwater County, Wyoming; and (ii) the Wamsutter Hub eastward to the Cheyenne Hub located in Weld County, Colorado.
The expansion is fully contracted and is expected to be operational in April 2010. The total estimated cost for the proposed project is approximately $78 million. By Commission order issued July 16, 2009 Rockies Express was granted authorization to construct and operate this project.
Rockies Express Pipeline-East Project
Construction continued during the second quarter of 2009 on the previously announced Rockies Express Pipeline-East Pipeline project. The Rockies Express-East project includes the construction of an additional natural gas pipeline segment, comprising 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. Current market conditions for consumables, labor and construction equipment along with certain provisions in the final regulatory orders have resulted in increased costs for the project and have impacted certain projected completion dates. On October 31, 2008, Rockies Express filed an amendment to its certificate application, seeking
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authorization to revise its tariff-based recourse rates for transportation service on the Rockies Express-East pipeline segment to reflect updated construction costs for the project. By order issued March 16, 2009, the FERC authorized the revised rates as filed by Rockies Express. Including expansions, our current estimate of total construction costs on the entire Rockies Express Pipeline is now approximately $6.7 billion (consistent with our July 15, 2009 second quarter earnings press release).
On June 29, 2009, Rockies Express-East commenced service on the portion of the pipeline from Audrain County, Missouri to the Lebanon Hub in Warren County, Ohio. This section of the line provides capacity of approximately 1.6 billion cubic feet per day of natural gas, and includes interconnects to Natural Gas Pipeline Company of America LLC, Ameren, Trunkline, Midwestern Gas Transmission, Panhandle Eastern, Texas Eastern, Dominion Transmission and Columbia Gas, with future interconnects to Texas Gas Transmission, ANR, Citizens and Vectren. The remainder of Rockies Express-East, consisting of approximately 195-miles of 42-inch diameter pipe extending to Clarington, Ohio, is expected to be in service by November 1, 2009. When completed, the entire 1,679-mile Rockies Express Pipeline will have a capacity of approximately 1.8 billion cubic feet per day of natural gas, virtually all of which has been contracted under long-term firm commitments from creditworthy shippers.
Kinder Morgan Interstate Gas Transmission Pipeline - Huntsman 2009 Expansion Project
Our Kinder Morgan Interstate Gas Transmission natural gas pipeline system, referred to as KMIGT, has filed an application with the FERC for authorization to construct and operate certain storage facilities necessary to increase the storage capability of the existing Huntsman Storage Facility, located near Sidney, Nebraska. KMIGT also requested approval of new incremental rates for the project facilities under its currently effective Cheyenne Market Center Service Rate Schedule CMC-2. When fully constructed, the proposed facilities will create incremental firm storage capacity for up to one million dekatherms of natural gas, with an associated injection capability of approximately 6,400 dekatherms per day and an associated deliverability of approximately 10,400 dekatherms per day. As a result of an open season, KMIGT and one shipper have executed a firm precedent agreement for 100% of the capacity to be created by the project facilities over a five-year term.
Kinder Morgan Louisiana Pipeline
On December 30, 2008, we filed a second amendment to our certificate application, seeking authorization to revise our initial rates for transportation service on our previously announced Kinder Morgan Louisiana natural gas pipeline system to reflect additional increases in estimated construction costs for the project (a first amendment revising our initial rates was filed in July 2008 and accepted by the FERC in August 2008). The filing was approved by the FERC on February 27, 2009. On April 16, 2009, we received authorization from the FERC to begin service on Leg 2 of the approximately 133-mile, 42-inch diameter pipeline, and service on Leg 2 commenced April 18, 2009. On June 21, 2009, we completed pipeline construction and placed the pipeline system’s remaining portion into service. The Kinder Morgan Louisiana Pipeline project cost approximately $1 billion to complete (consistent with our July 15, 2009 second quarter earnings press release).
The Kinder Morgan Louisiana Pipeline provides approximately 3.2 billion cubic feet per day of take-away natural gas capacity from the Cheniere Sabine Pass liquefied natural gas terminal, located in Cameron Parish, Louisiana, to various delivery points in Louisiana. The pipeline interconnects with multiple third-party pipelines and all of the capacity on the pipeline system has been fully subscribed by Chevron and Total under 20-year take-or-pay customer commitments. One transportation contract became effective on June 21, 2009, and the second will become effective in the third quarter of 2009.
Midcontinent Express Pipeline
Construction continued during the second quarter of 2009 on the previously announced Midcontinent Express Pipeline project. The Midcontinent Express Pipeline is owned by Midcontinent Express Pipeline LLC, a 50/50 joint venture between us and Energy Transfer Partners, L.P. The pipeline will extend from southeast Oklahoma, across northeast Texas, northern Louisiana and central Mississippi, and terminate at an interconnection with the Transco Pipeline near Butler, Alabama. The entire estimated project cost for the approximately 500-mile natural gas pipeline system is expected to be approximately $2.3 billion (consistent with our July 15, 2009 second quarter earnings press release).
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On January 9, 2009, Midcontinent Express filed an amendment to its original certificate application requesting authorization to revise its initial rates for transportation service on the pipeline system to reflect an increase in projected construction costs for the project. The filing was approved by the FERC on March 25, 2009. Interim service commenced for Zone 1 on April 10, 2009 with deliveries to Natural Gas Pipeline Company of America LLC. Service to all Zone 1 delivery points occurred by May 21, 2009. Zone 2 is anticipated to be placed in service on or about August 1, 2009.
Fayetteville Express Pipeline
Pipeline system development work continued during the second quarter of 2009 on the previously announced Fayetteville Express Pipeline project. The Fayetteville Express Pipeline is owned by Fayetteville Express Pipeline LLC, another 50/50 joint venture between us and Energy Transfer Partners, L.P. The Fayetteville Express Pipeline is a 187-mile, 42-inch diameter natural gas pipeline that will begin in Conway County, Arkansas, and end in Panola County, Mississippi. The pipeline will have an initial capacity of two billion cubic feet per day, and has currently secured ten year binding commitments totaling 1.85 billion cubic feet per day of capacity. On June 15, 2009, Fayetteville Express filed its certificate application with the FERC. Pending regulatory approvals, the pipeline is expected to be in service by late 2010 or early 2011. Our estimate of the total costs of this pipeline project is approximately $1.2 billion (consistent with our July 15, 2009 second quarter earnings press release).
12. Recent Accounting Pronouncements
SFAS No. 141(R) and FASB Staff Position No. 141(R)-1
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. 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 was adopted by us effective January 1, 2009, and the adoption of this Statement did not have a material impact on our consolidated financial statements.
On April 1, 2009, the FASB issued FASB Staff Position No. FAS 141(R)-1, “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies.” This Staff Position amends the provisions related to the initial recognition and measurement, subsequent measurement and disclosure of assets and liabilities arising from contingencies in a business combination under SFAS No. 141R. This Staff Position carries forward the requirements in SFAS No. 141, “Business Combinations,” for acquired contingencies, which would require that such contingencies be recognized at fair value on the acquisition date if fair value can be reasonably estimated during the allocation period. Otherwise, companies would typically account for the acquired contingencies in accordance with SFAS No. 5, “Accounting for Contingencies.” This Staff Position has the same effective date as SFAS No. 141R, and did not have a material impact on our consolidated financial statements.
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, sometimes referred to as minority interests, in consolidated financial statements. A
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noncontrolling interest is the portion of equity in a subsidiary not attributable, directly or indirectly, to a parent. We adopted SFAS No. 160 effective January 1, 2009.
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 consolidated balance sheet within equity, but separate from the parent’s equity; and (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. Accordingly, our consolidated net income and comprehensive income are now determined without deducting amounts attributable to our noncontrolling interests, but our earnings-per-unit information continues to be calculated on the basis of the net income attributable to our limited partners. The provisions of this Statement apply prospectively; however, the presentation and disclosure requirements are applied retrospectively for all periods presented.
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 provides for enhanced disclosure requirements that 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 was adopted by us effective January 1, 2009, and the adoption of this Statement did not have a material impact on our consolidated financial statements.
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. For us, this Issue was effective January 1, 2009. The guidance in this Issue is to be applied retrospectively for all financial statements presented; however, the adoption of this Issue did not have any impact on our consolidated financial statements.
FASB Staff Position No. FAS 142-3
On April 25, 2008, the FASB issued FASB Staff Position No. 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.” For us, this Staff Position was effective January 1, 2009, and the adoption of this Staff Position did not have any impact on our consolidated financial statements.
FASB Staff Position No. EITF 03-6-1
On June 16, 2008, the FASB issued FASB Staff Position No. EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities.” This Staff Position clarifies that share-based payment awards that entitle their holders to receive nonforfeitable dividends before vesting should be considered participating securities. As participating securities, these instruments should be included in the calculation of basic earnings per share. For us, this Staff Position was effective January 1, 2009, and the adoption of this Staff Position did not have any impact on our consolidated financial statements.
FASB Staff Position No. FAS 157-3
On October 10, 2008, the FASB issued FASB Staff Position No. FAS 157-3 “Determining the Fair Value of a Financial Asset When the Market for that Asset is Not Active.” This Staff Position provides guidance clarifying how SFAS No. 157, “Fair Value Measurements,” should be applied when valuing securities in markets that are not
41
active. This Staff Position applies the objectives and framework of SFAS No. 157 to determine the fair value of a financial asset in a market that is not active, and it reaffirms the notion of fair value as an exit price as of the measurement date. Among other things, the guidance also states that significant judgment is required in valuing financial assets. This Staff Position became effective upon issuance, and did not have any material effect on our consolidated financial statements.
EITF 08-6
On November 24, 2008, the FASB ratified the consensus reached by the Emerging Issues Task Force on Issue No. 08-6, or EITF 08-6, “Equity Method Investment Accounting Considerations.” EITF 08-6 clarifies certain accounting and impairment considerations involving equity method investments. For us, this Issue was effective January 1, 2009, and the adoption of this Issue did not have any impact on our consolidated financial statements.
FASB Staff Position No. FAS 132(R)-1
On December 30, 2008, the FASB issued FASB Staff Position No. FAS 132(R)-1, “Employer’s Disclosures About Postretirement Benefit Plan Assets.” This Staff Position is effective for financial statements ending after December 15, 2009 (December 31, 2009 for us) and requires additional disclosure of pension and post retirement benefit plan assets regarding (i) investment asset classes; (ii) fair value measurement of assets; (iii) investment strategies; (iv) asset risk; and (v) rate-of-return assumptions. We do not expect this Staff Position to have a material impact on our consolidated financial statements.
Securities and Exchange Commission’s Final Rule on Oil and Gas Disclosure Requirements
On December 31, 2008, the Securities and Exchange Commission issued its final rule “Modernization of Oil and Gas Reporting,” which revises the disclosures required by oil and gas companies. The SEC disclosure requirements for oil and gas companies have been updated to include expanded disclosure for oil and gas activities, and certain definitions have also been changed that will impact the determination of oil and gas reserve quantities. The provisions of this final rule are effective for registration statements filed on or after January 1, 2010, and for annual reports for fiscal years ending on or after December 31, 2009. We are currently reviewing the effects of this final rule.
FASB Staff Position No. FAS 157-4
FASB Staff Position No. FAS 107-1 and APB 28-1
FASB Staff Position No. FAS 115-2 and FAS 124-2
On April 9, 2009, the FASB issued three separate Staff Positions intended to provide additional application guidance and enhance disclosures regarding fair value measurements and impairments of securities. FAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly,” provides guidelines for making fair value measurements more consistent with the principles presented in SFAS No. 157, “Fair Value Measurements.” This Staff Position provides additional guidance to highlight and expand on the factors that should be considered in estimating fair value when there has been a significant decrease in market activity for a financial asset.
FAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments,” enhances consistency in financial reporting by increasing the frequency of fair value disclosures from annual only to quarterly, in order to provide financial statement users with more timely information about the effects of current market conditions on their financial instruments. This Staff Position requires us to disclose in our interim financial statements the fair value of all financial instruments within the scope of SFAS No. 107, “Disclosures about Fair Value of Financial Instruments,” as well as the method(s) and significant assumptions we use to estimate the fair value of those financial instruments.
FAS 115-2 and FAS 124-2, “Recognition and Presentation of Other-Than-Temporary Impairments,” provides additional guidance designed to create greater clarity and consistency in accounting for and presenting impairment losses on securities. This Staff Position changes (i) the method for determining whether an other-than-temporary impairment exists for debt securities; and (ii) the amount of an impairment charge to be recorded in earnings.
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For us, each of these three Staff Positions became effective June 30, 2009; however, the adoption of these Staff Positions did not have a material impact on our consolidated financial statements.
SFAS No. 165
On May 28, 2009, the FASB issued SFAS No. 165, “Subsequent Events.” This Statement establishes general standards of accounting for and disclosure of subsequent events—events or transactions that occur after the balance sheet date but before financial statements are issued or are available to be issued. It requires the disclosure of the date through which an entity has evaluated subsequent events and the basis for that date. This Statement was effective for interim and annual periods ending after June 15, 2009. For us, this Statement became effective June 30, 2009, and the adoption of this Statement did not have a material impact on our consolidated financial statements. For more information on our disclosure of subsequent events, see Note 1.
SFAS Nos. 166 and 167
On June 12, 2009, the FASB published SFAS No. 166, “Accounting for Transfers of Financial Assets—an amendment of FASB Statement No. 140,” and SFAS No. 167, “Amendments to FASB Interpretation No. 46(R)." The Statements change the way entities account for securitizations and special-purpose entities. SFAS No. 166 is a revision of SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities,” and will require more information about transfers of financial assets, including securitization transactions, and where companies have continuing exposure to the risks related to transferred financial assets. SFAS No. 167 is a revision to FASB Interpretation No. 46(R), “Consolidation of Variable Interest Entities,” and changes how a company determines when an entity that is insufficiently capitalized or is not controlled through voting (or similar rights) should be consolidated.
Both Statement Nos. 166 and 167 will be effective at the start of an entity’s first fiscal year beginning after November 15, 2009 (January 1, 2010 for us). We do not expect the adoption of these Statements to have a material impact on our consolidated financial statements.
SFAS No. 168 and the Financial Accounting Standards Board’s Accounting Standards Codification
On June 3, 2009, the FASB voted to approve its Accounting Standards Codification as the single source of authoritative nongovernmental U.S. generally accepted accounting principles, commonly referred to as GAAP, effective July 1, 2009. The move was officially effected by the June 29, 2009 issuance of SFAS No. 168, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles—a replacement of SFAS No. 162.” On the effective date of this Statement, the Codification will supersede all then-existing non-Securities and Exchange Commission accounting and reporting standards. All other nongrandfathered non-Securities and Exchange Commission accounting literature not included in the Codification will become nonauthoritative. In other words, the GAAP hierarchy will be modified to include only two levels of GAAP: authoritative and nonauthoritative.
While the Codification does not change U.S. GAAP, it introduces a new structure—reorganizing the thousands of pre-Codification U.S. GAAP pronouncements into approximately 90 accounting topics and displaying all topics consistently. Rules and interpretive releases of the U.S. Securities and Exchange Commission under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants, and the Codification includes relevant SEC guidance that follows the same topical structure in separate sections. All guidance contained in the Codification carries an equal level of authority.
The Codification will be effective for interim and annual periods ending after September 15, 2009 (September 30, 2009 for us). The adoption of the Accounting Standards Codification will affect the way we reference U.S. GAAP in our financial statements and in our accounting policies; however, we do not expect the adoption to have any direct effect on our consolidated financial statements.
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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
General and Basis of Presentation
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 2008 Form 10-K.
In addition, our financial statements and the financial information contained in this Management’s Discussion and Analysis of Financial Condition and Results of Operations reflect the August 28, 2008 transfer of both the 33 1/3% interest in the Express and Platte crude oil pipeline system net assets (collectively referred to in this report as the Express pipeline system) and the Jet Fuel pipeline system net assets from KMI as of the date of transfer. Accordingly, we have included the financial results of the Express and Jet Fuel pipeline systems within our Kinder Morgan Canada business segment disclosures presented in this report for all periods subsequent to August 28, 2008.
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 our 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 2008 Form 10-K. There have not been any significant changes in these policies and estimates during the three months ended June 30, 2009.
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Results of Operations
Consolidated
| | | | | | | | | | | | | |
| | Three Months Ended
June 30, | | Earnings
Increase/(decrease) |
| | | | |
| | 2009 | | 2008 | | |
| | | | | | |
| | (In millions, except percentages) | |
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments(a) | | | | | | | | | | | | | |
Products Pipelines(b) | | $ | 155.0 | | $ | 137.6 | | $ | 17.4 | | | 13 | % |
Natural Gas Pipelines(c) | | | 162.1 | | | 182.5 | | | (20.4 | ) | | (11 | )% |
CO2 | | | 202.7 | | | 216.6 | | | (13.9 | ) | | (6 | )% |
Terminals(d) | | | 142.9 | | | 140.4 | | | 2.5 | | | 2 | % |
Kinder Morgan Canada(e) | | | 46.7 | | | 33.4 | | | 13.3 | | | 40 | % |
| | | | | | | | | | | | | |
Segment earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments | | | 709.4 | | | 710.5 | | | (1.1 | ) | | — | |
| | | | | | | | | | | | | |
Depreciation, depletion and amortization expense | | | (203.1 | ) | | (165.6 | ) | | (37.5 | ) | | (23 | )% |
Amortization of excess cost of equity investments | | | (1.5 | ) | | (1.5 | ) | | — | | | — | |
General and administrative expense(f) | | | (72.6 | ) | | (72.8 | ) | | 0.2 | | | — | |
Unallocable interest expense, net of interest income(g) | | | (101.3 | ) | | (99.9 | ) | | (1.4 | ) | | (1 | )% |
Unallocable income tax expense | | | (2.3 | ) | | (4.4 | ) | | 2.1 | | | 48 | % |
| | | | | | | | | | | | | |
Net income | | | 328.6 | | | 366.3 | | | (37.7 | ) | | (10 | )% |
Net income attributable to noncontrolling interests | | | (4.8 | ) | | (4.1 | ) | | (0.7 | ) | | (17 | )% |
| | | | | | | | | | | | | |
Net income attributable to Kinder Morgan Energy Partners, L.P. | | $ | 323.8 | | $ | 362.2 | | $ | (38.4 | ) | | (11 | )% |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| |
| | | | | | | | | | | | | |
| | Six Months Ended
June 30, | | Earnings
Increase/(decrease) |
| | | | |
| | 2009 | | 2008 | | |
| | | | | | |
| | (In millions, except percentages) | |
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments(a) | | | | | | | | | | | | | |
Products Pipelines(h) | | $ | 300.4 | | $ | 278.3 | | $ | 22.1 | | | 8 | % |
Natural Gas Pipelines(i) | | | 362.9 | | | 370.7 | | | (7.8 | ) | | (2 | )% |
CO2 | | | 370.1 | | | 416.4 | | | (46.3 | ) | | (11 | )% |
Terminals(j) | | | 277.6 | | | 266.2 | | | 11.4 | | | 4 | % |
Kinder Morgan Canada(k) | | | 66.2 | | | 63.6 | | | 2.6 | | | 4 | % |
| | | | | | | | | | | | | |
Segment earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments | | | 1,377.2 | | | 1,395.2 | | | (18.0 | ) | | (1 | )% |
| | | | | | | | | | | | | |
Depreciation, depletion and amortization expense | | | (413.3 | ) | | (323.7 | ) | | (89.6 | ) | | (28 | )% |
Amortization of excess cost of equity investments | | | (2.9 | ) | | (2.9 | ) | | — | | | — | |
General and administrative expense(l) | | | (155.1 | ) | | (149.6 | ) | | (5.5 | ) | | (4 | )% |
Unallocable interest expense, net of interest income(m) | | | (205.9 | ) | | (197.6 | ) | | (8.3 | ) | | (4 | )% |
Unallocable income tax expense | | | (4.6 | ) | | (4.4 | ) | | (0.2 | ) | | (5 | )% |
| | | | | | | | | | | | | |
Net income | | | 595.4 | | | 717.0 | | | (121.6 | ) | | (17 | )% |
Net income attributable to noncontrolling interests(n) | | | (7.7 | ) | | (8.1 | ) | | 0.4 | | | 5 | % |
| | | | | | | | | | | | | |
Net income attributable to Kinder Morgan Energy Partners, L.P. | | $ | 587.7 | | $ | 708.9 | | $ | (121.2 | ) | | (17 | )% |
| | | | | | | | | | | | | |
| | |
| | |
| |
(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. |
(b) | 2009 and 2008 amounts include increases in income of $1.0 million and $0.1 million, respectively, resulting from unrealized foreign currency gains on long-term debt transactions. 2009 amount also includes a $3.8 million increase in expense associated with environmental liability adjustments. 2008 amount also includes a $0.8 million gain from the 2007 sale of our North System. |
(c) | 2009 and 2008 amounts include decreases in income of $2.5 million and $13.1 million, respectively, resulting from unrealized mark to market gains and losses due to the discontinuance of hedge accounting at Casper Douglas. 2008 amount also includes 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) | 2009 amount includes a $0.5 million decrease in expense associated with legal liability adjustments related to a litigation matter involving our Staten Island liquids terminal, and a $0.1 million increase in expense associated with environmental liability adjustments. |
(e) | 2009 amount includes a $3.7 million decrease in expense due to a certain non-cash accounting change related to book tax accruals and foreign exchange fluctuations. |
(f) | Includes unallocated litigation and environmental expenses. 2009 and 2008 amounts include increases of $1.4 million in non-cash compensation expense allocated to us from KMI (we do not have any obligation, nor do we expect to pay any amounts related to these expenses). 2009 amount also includes a $0.9 million decrease in expense related to capitalized overhead costs associated with the 2008 hurricane season. |
(g) | 2009 and 2008 amounts include increases in imputed interest expense of $0.3 million and $0.5 million, respectively, related to our January 1, 2007 Cochin Pipeline acquisition. |
(h) | 2009 and 2008 amounts include a $0.4 million increase in income and a $0.7 million decrease in income, respectively, resulting from unrealized foreign currency gains and losses on long-term debt transactions. 2009 amount also includes a $3.8 million increase in expense associated with environmental liability adjustments. 2008 amount also includes a $1.3 million gain from the 2007 sale of our North System. |
(i) | 2009 and 2008 amounts include decreases in income of $3.8 million and $13.1 million, respectively, resulting from unrealized mark to market gains and losses due to the discontinuance of hedge accounting at Casper Douglas. 2008 amount also includes a $13.0 million gain from the sale of our 25% equity ownership interest in Thunder Creek Gas Services, LLC. |
(j) | 2009 amount includes a $0.5 million decrease in expense associated with legal liability adjustments related to a litigation matter involving our Staten Island liquids terminal, and a $0.1 million increase in expense associated with environmental liability adjustments. |
(k) | 2009 amount includes a $3.7 million decrease in expense due to a certain non-cash accounting change related to book tax accruals and foreign exchange fluctuations, and a $14.9 million increase in expense primarily due to certain non-cash regulatory accounting adjustments to the carrying amount of the previously established deferred tax liability. |
(l) | 2009 and 2008 amounts include increases of $2.8 million in non-cash compensation expense allocated to us from KMI (we do not have any obligation, nor do we expect to pay any amounts related to these expenses). 2009 amount also includes a $0.1 million increase in expense for certain Express pipeline system acquisition costs, and a $1.5 million decrease in expense related to capitalized overhead costs associated with the 2008 hurricane season. |
(m) | 2009 and 2008 amounts include increases in imputed interest expense of $0.8 million and $1.0 million, respectively, related to our January 1, 2007 Cochin Pipeline acquisition. |
(n) | 2009 amount includes a $0.2 million decrease in net income attributable to noncontrolling (minority) interests, related to all of the six month 2009 items previously disclosed in these footnotes. |
For the quarterly period ended June 30, 2009, net income attributable to our partners, which includes all of our limited partner unitholders and our general partner, totaled $323.8 million in the second quarter of 2009, compared to $362.2 million for the quarterly period ended June 30, 2008. Our total revenues for the comparative second quarter periods were $1,645.3 million in 2009 and $3,495.7 million in 2008. For the six months ended June 30, 2009 and 2008, net income attributable to our partners totaled $587.7 million and $708.9 million, respectively, on revenues of $3,431.8 million and $6,216.0 million, respectively.
Because our partnership agreement requires us to distribute 100% of our available cash to our partners on a quarterly basis (available cash as defined in our partnership agreement generally consists 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.
Total segment earnings before depreciation, depletion and amortization for the three months ended June 30, 2009 was essentially flat versus the same quarter last year. Combined, the certain items described in the footnotes to the tables above decreased total segment EBDA by $2.0 million (combining to decrease total segment EBDA by $1.2 million in 2009 and to increase total segment EBDA by $0.8 million in 2008). The remaining $0.9 million increase in total segment EBDA included higher earnings in 2009 from our Products Pipelines, Kinder Morgan Canada and Terminals business segments, and lower earnings from our Natural Gas Pipelines and CO2 business segments.
For the comparable six month periods, the certain items described in the footnotes to the tables decreased segment EBDA by $18.5 million in 2009, when compared to the first half of last year (combining to decrease total segment EBDA by $18.0 million in 2009 and to increase total segment EBDA by $0.5 million in 2008). The remaining $0.5 million increase in total segment EBDA was driven by better performance from our Products
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Pipelines, Kinder Morgan Canada and Terminals business segments, and offset by lower year-over-year earnings from our CO2 and Natural Gas Pipelines business segments.
Products Pipelines
| | | | | | | | | | | | | |
| | Three Months Ended
June 30, | | Six Months Ended
June 30, | |
| | 2009 | | 2008 | | 2009 | | 2008 | |
| | | | | |
| | (In millions, except operating statistics) | |
Revenues | | $ | 206.7 | | $ | 198.6 | | $ | 394.9 | | $ | 396.9 | |
Operating expenses(a) | | | (60.0 | ) | | (68.5 | ) | | (109.0 | ) | | (130.9 | ) |
Other income (expense)(b) | | | — | | | 0.6 | | | — | | | 1.0 | |
Earnings from equity investments | | | 8.0 | | | 8.7 | | | 13.4 | | | 16.2 | |
Interest income and Other, net-income (expense)(c) | | | 3.5 | | | 1.3 | | | 6.3 | | | 1.8 | |
Income tax benefit (expense) | | | (3.2 | ) | | (3.1 | ) | | (5.2 | ) | | (6.7 | ) |
| | | | | | | | | | | | | |
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments | | $ | 155.0 | | $ | 137.6 | | $ | 300.4 | | $ | 278.3 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Gasoline (MMBbl) | | | 104.2 | | | 100.5 | | | 199.8 | | | 198.4 | |
Diesel fuel (MMBbl) | | | 36.5 | | | 41.6 | | | 72.0 | | | 80.2 | |
Jet fuel (MMBbl) | | | 28.1 | | | 29.9 | | | 54.9 | | | 59.6 | |
| | | | | | | | | | | | | |
Total refined product volumes (MMBbl) | | | 168.8 | | | 172.0 | | | 326.7 | | | 338.2 | |
Natural gas liquids (MMBbl) | | | 7.3 | | | 6.1 | | | 12.2 | | | 13.0 | |
| | | | | | | | | | | | | |
Total delivery volumes (MMBbl)(d) | | | 176.1 | | | 178.1 | | | 338.9 | | | 351.2 | |
| | | | | | | | | | | | | |
| | |
| | |
| | |
(a) | 2009 amounts include a $3.8 million increase in expense associated with environmental liability adjustments. 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 legal liability adjustments. |
(b) | Three and six month 2008 amounts include gains of $0.8 million and $1.3 million, respectively, from the 2007 sale of our North System. We accounted for the North System business as a discontinued operation; however, because the sale does not change the structure of our internal organization in a manner that causes a change to our reportable business segments, we included the 2008 gain adjustments within our Products Pipelines business segment disclosures. Except for these gain adjustments on disposal of the North System, we recorded no other financial results from the operations of the North System during the first six months of 2008. |
(c) | Three and six month 2009 amounts include increases in income of $1.0 million and $0.4 million, respectively, resulting from unrealized foreign currency gains on long-term debt transactions. 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 gains and losses on long-term debt transactions. |
(d) | Includes Pacific, Plantation, Calnev, Central Florida, Cochin and Cypress pipeline volumes. |
Combined, the certain items described in the footnotes to the table above decreased our Product Pipelines’ earnings before depreciation, depletion and amortization expenses by $3.7 million in the second quarter of 2009, and decreased earnings before depreciation, depletion and amortization expenses by $4.0 million in the first six months of 2009, when compared to same periods in 2008. For each of the comparable three and six month periods, following is information related to (i) the remaining increases and decreases in segment earnings before depreciation, depletion and amortization expenses (EBDA); and (ii) the increases and decreases in operating revenues:
| | |
| Three months ended June 30, 2009 versus Three months ended June 30, 2008 | |
| | |
| | | | | | | | | | | | | |
| | EBDA
increase/(decrease) | | Revenues
increase/(decrease) |
| | | | |
| | (In millions, except percentages) | |
Cochin Pipeline System | | $ | 7.8 | | | 128 | % | $ | 6.2 | | | 58 | % |
Pacific operations | | | 4.8 | | | 8 | % | | 1.4 | | | 2 | % |
West Coast Terminals | | | 3.6 | | | 29 | % | | 4.0 | | | 22 | % |
Central Florida Pipeline | | | 2.6 | | | 24 | % | | 3.0 | | | 22 | % |
Plantation Pipeline | | | (0.1 | ) | | (1 | )% | | (6.1 | ) | | (56 | )% |
All others (including eliminations) | | | 2.4 | | | 7 | % | | (0.4 | ) | | (1 | )% |
| | | | | | | | | | | | | |
Total Products Pipelines | | $ | 21.1 | | | 15 | % | $ | 8.1 | | | 4 | % |
| | | | | | | | | | | | | |
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| | |
| Six months ended June 30, 2009 versus Six months ended June 30, 2008 | |
| | |
| | | | | | | | | | | | | |
| | EBDA
increase/(decrease) | | Revenues
increase/(decrease) |
| | | | |
| | (In millions, except percentages) | |
West Coast Terminals | | $ | 9.2 | | | 39 | % | $ | 8.6 | | | 24 | % |
Cochin Pipeline System | | | 8.9 | | | 54 | % | | 2.5 | | | 10 | % |
Central Florida Pipeline | | | 5.1 | | | 24 | % | | 6.1 | | | 24 | % |
Pacific operations | | | 3.7 | | | 3 | % | | (3.5 | ) | | (2 | )% |
Plantation Pipeline | | | (2.1 | ) | | (9 | )% | | (12.2 | ) | | (55 | )% |
All others (including eliminations) | | | 1.3 | | | 2 | % | | (3.5 | ) | | (4 | )% |
| | | | | | | | | | | | | |
Total Products Pipelines | | $ | 26.1 | | | 9 | % | $ | (2.0 | ) | | (1 | )% |
| | | | | | | | | | | | | |
Overall, our Products Pipelines business segment reported strong operating results in the second quarter of 2009 as earnings before depreciation, depletion and amortization expenses increased $21.1 million (15%), when compared to the second quarter of 2008. Although ongoing weak economic conditions continued to dampen demand for refined petroleum products at many of our assets in this segment, resulting in lower volumes versus the second quarter of 2008, earnings were positively impacted by higher operating revenues, due to increased natural gas liquids throughput volumes on the Cochin pipeline system, by higher ethanol revenues on our Central Florida Pipeline, and by improved warehousing margins at existing and expanded West Coast terminal facilities. In addition, the segment benefited from a $12.3 million (18%) reduction in combined operating expenses in the second quarter of 2009, primarily due to lower outside services and other discretionary operating expenses, lower fuel and power expenses, and due to new service contracts or bidding work at lower prices compared to a year earlier.
The primary increase in segment earnings for the comparable three month periods was attributable to the $7.8 million (128%) increase from our Cochin Pipeline. The increase in earnings from Cochin was largely related to the $6.2 million (58%) increase in operating revenues compared to the same quarter a year earlier. The increase in revenues was driven by a 42% increase in liquids throughput volumes, reflecting increased pipeline utilization that was mainly due to significantly higher throughput volumes on the pipelines’ East Leg (which services Windsor, Ontario, Canada, and extends to Sarnia, Ontario).
The period-to-period earnings increases from our West Coast terminal operations were largely revenue related, driven by higher revenues from our combined Carson/Los Angeles Harbor terminal system and by incremental returns from the completion of a number of capital expansion projects that modified and upgraded terminal infrastructure since the end of the second quarter of 2008. Revenues at our Carson/Los Angeles terminal complex increased $3.0 million and $6.5 million in the second quarter and first six months of 2009, respectively, when compared to the same periods a year earlier. The increases were mainly due to both increased warehouse charges (escalated warehousing contract rates resulting from customer contract revisions made since the second quarter a year ago) and to new customers (including incremental terminalling for U.S. defense fuel services). Revenues from our remaining West Coast facilities increased $1.0 million and $2.1 million in the second quarter and first six months of 2009, respectively, due mostly to additional throughput and storage services associated with renewable fuels (both ethanol and biodiesel).
Earnings before depreciation, depletion and amortization from our Pacific operations increased $4.8 million (8%) in the second quarter of 2009, when compared to the second quarter last year. The increase in earnings was due mainly to a $3.2 million (10%) decrease in combined operating expenses and a $1.4 million (2%) increase in total revenues. The decrease in expenses, relative to 2008, was due to both higher product gains and lower right-of-way and environmental expenses. The increase in revenues included a $1.1 million (2%) increase in mainline delivery revenues, driven by a nearly 4% increase in average tariff rates.
The earnings increases from our Central Florida Pipeline were mainly due to both incremental ethanol revenues, resulting from capital expansion projects that provided ethanol storage and terminal service beginning in mid-April 2008 at our Tampa and Orlando terminals, and from higher overall revenues driven by higher average transportation rates, due to a mid-year tariff rate increase that became effective July 1, 2008.
48
Earnings from our approximate 51% equity investment in the Plantation Pipe Line Company were essentially flat across both second quarter periods, but decreased $2.1 million (9%) in the first half of 2009, when compared to the same period last year. The six month decrease in earnings from our investment in Plantation was chiefly attributable to lower oil loss allowance revenues in 2009. The drop in oil loss allowance revenues, relative to last year, reflects the decline in refined product market prices since the end of the second quarter of 2008. The overall decreases in revenues earned from our investment in Plantation in both the comparable three and six month periods were mainly due to changes made to the Plantation operating agreement by ExxonMobil and us. On January 1, 2009, both parties agreed to reduce the fixed operating fees we earn from operating the pipeline; however, the reductions in our fee revenues were largely offset by corresponding decreases in the labor and non-labor expenses we incurred from operating the pipeline—resulting in minimal impact on our net operating income in the first six months of 2009.
Also, on June 30, 2009, Plantation successfully completed the first U.S. transmarket commercial shipment of blended 5% biodiesel on a mainline segment of its pipeline. In addition to the June 2009 deliveries to marketing terminals located in Athens, Georgia and Roanoke, Virginia, Plantation is optimistically moving forward to delivering biodiesel to multiple markets along its pipeline system in response to customers’ needs for blending and transporting biodiesel to meet federal regulatory requirements.
Combining all of the segment’s operations, total revenues from refined petroleum products deliveries increased 0.4% in the second quarter of 2009, when compared to the second quarter of 2008; however, total products delivery volumes decreased 1.9% as ongoing weak economic conditions resulted in lower demand for diesel and jet fuel. Total gasoline delivery volumes increased 3.7% (including ethanol), diesel volumes decreased 12.3%, and jet fuel volumes decreased 6.0%, respectively, in the second quarter of 2009 compared to the second quarter of 2008. Excluding Plantation—which is impacted by a competing pipeline—total refined products delivery revenues were up 3.5% and total refined product delivery volumes were down 2.2%, when compared to the second quarter last year.
Gasoline delivery volumes (including ethanol) increased 0.7% in the first half of 2009, when compared to the first half of 2008, due to higher second quarter 2009 volumes. Year-over-year percentage changes in jet fuel volumes showed some improvement in the second quarter of 2009, when compared to the prior quarter (first quarter of 2009), while year-over-year percentage changes in diesel volumes further declined in the second quarter of 2009 versus the prior quarter. Natural gas liquids delivery volumes on our Cochin and Cypress pipelines increased by 20% in the second quarter of 2009 compared to the second quarter last year, chiefly due to the 42% increase in liquids deliveries on the Cochin Pipeline (discussed above).
Natural Gas Pipelines
| | | | | | | | | | | | | |
| | Three Months Ended
June 30, | | Six Months Ended
June 30, | |
| | 2009 | | 2008 | | 2009 | | 2008 | |
| | | | | |
| | (In millions, except operating statistics) | |
| | | | | | | | | | | | | |
Revenues | | $ | 860.7 | | $ | 2,644.7 | | $ | 1,912.4 | | $ | 4,557.2 | |
Operating expenses(a) | | | (739.3 | ) | | (2,515.6 | ) | | (1,629.8 | ) | | (4,260.7 | ) |
Other income | | | — | | | 2.7 | | | — | | | 2.7 | |
Earnings from equity investments | | | 29.4 | | | 31.3 | | | 56.0 | | | 54.8 | |
Interest income and Other, net-income (expense)(b) | | | 12.6 | | | 17.7 | | | 27.3 | | | 17.9 | |
Income tax benefit (expense) | | | (1.3 | ) | | 1.7 | | | (3.0 | ) | | (1.2 | ) |
| | | | | | | | | | | | | |
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments | | $ | 162.1 | | $ | 182.5 | | $ | 362.9 | | $ | 370.7 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Natural gas transport volumes (Trillion Btus)(c) | | | 541.8 | | | 502.3 | | | 1,050.2 | | | 983.2 | |
| | | | | | | | | | | | | |
Natural gas sales volumes (Trillion Btus)(d) | | | 198.1 | | | 224.9 | | | 401.8 | | | 440.0 | |
| | | | | | | | | | | | | |
| | |
| | |
| |
(a) | Three and six month 2009 amounts include decreases in income of $2.5 million and $3.8 million, respectively, and 2008 amounts include decreases in income of $13.1 million, all resulting from unrealized mark to market gains and losses due to the discontinuance of hedge accounting at Casper Douglas. |
(b) | 2008 amounts include a $13.0 million gain from the sale of our 25% equity ownership interest in Thunder Creek Gas Services, LLC. |
49
| |
(c) | Includes Kinder Morgan Interstate Gas Transmission LLC, Trailblazer Pipeline Company LLC, TransColorado Gas Transmission Company LLC, Rockies Express Pipeline LLC, Midcontinent Express Pipeline LLC, Kinder Morgan Louisiana Pipeline and Texas intrastate natural gas pipeline group pipeline volumes. |
(d) | Represents Texas intrastate natural gas pipeline group volumes. |
For the three and six months ended June 30, 2009, the certain items related to our Natural Gas Pipelines business segment and described in the footnotes to the table above decreased the change in earnings before depreciation, depletion and amortization expenses by $2.4 million and $3.7 million, respectively. For each of the comparable three and six month periods of 2009 and 2008, following is information related to (i) the remaining changes in segment earnings before depreciation, depletion and amortization expenses (EBDA); and (ii) the changes in operating revenues:
| | |
| Three months ended June 30, 2009 versus Three months ended June 30, 2008 | |
| | |
| | | | | | | | | | | | | |
| | EBDA
increase/(decrease) | | Revenues
increase/(decrease) | |
| | | | |
| | (In millions, except percentages) | |
Texas Intrastate Natural Gas Pipeline Group | | $ | (26.4 | ) | | (29 | )% | $ | (1,751.4 | ) | | (69 | )% |
Rockies Express Pipeline | | | (2.5 | ) | | (10 | )% | | — | | | — | |
Kinder Morgan Louisiana Pipeline | | | 7.3 | | | 242 | % | | — | | | — | |
Kinder Morgan Interstate Gas Transmission | | | 5.2 | | | 19 | % | | (5.9 | ) | | (12 | )% |
All others (including eliminations) | | | (1.6 | ) | | (5 | )% | | (26.7 | ) | | (37 | )% |
| | | | | | | | | | | | | |
Total Natural Gas Pipelines | | $ | (18.0 | ) | | (10 | )% | $ | (1,784.0 | ) | | (67 | )% |
| | | | | | | | | | | | | |
| | |
| Six months ended June 30, 2009 versus Six months ended June 30, 2008 | |
| | |
| | | | | | | | | | | | | |
| | EBDA
increase/(decrease) | | Revenues
increase/(decrease) | |
| | | | |
| | (In millions, except percentages) | |
Texas Intrastate Natural Gas Pipeline Group | | $ | (28.3 | ) | | (14 | )% | $ | (2,592.6 | ) | | (60 | )% |
Kinder Morgan Louisiana Pipeline | | | 15.9 | | | 525 | % | | — | | | — | |
Kinder Morgan Interstate Gas Transmission | | | 9.5 | | | 17 | % | | (4.5 | ) | | (5 | )% |
Rockies Express Pipeline | | | 2.3 | | | 6 | % | | — | | | — | |
All others (including eliminations) | | | (3.5 | ) | | (5 | )% | | (47.7 | ) | | (35 | )% |
| | | | | | | | | | | | | |
Total Natural Gas Pipelines | | $ | (4.1 | ) | | (1 | )% | $ | (2,644.8 | ) | | (58 | )% |
| | | | | | | | | | | | | |
The overall decreases in segment earnings before depreciation, depletion and amortization expenses in 2009 for the comparable three and six month periods were driven primarily by lower earnings from our Texas intrastate natural gas pipeline group. The decreases in earnings from the intrastate group were mainly attributable to lower margins from natural gas sales, timing differences that negatively affected both natural gas storage margins and operational expenses, relative to last year, and lower natural gas processing margins, due to unfavorable gross processing spreads as a result of significantly lower average natural gas liquids prices in 2009.
Combined, the decreases in natural gas sales margins on our two largest intrastate pipeline systems—Kinder Morgan Tejas (including Kinder Morgan Border Pipeline) and Kinder Morgan Texas Pipeline—totaled $14.8 million and $21.4 million, respectively, in the three and six month periods of 2009, when compared to the same periods last year. The decreases in sales margins were primarily due to lower average natural gas prices and partly due to lower pipeline spreads and lower sales volumes, relative to 2008. Compared to the same periods in 2008, total natural gas sales volumes for our intrastate group decreased 12% and 9% in the three and six month periods of 2009, respectively, primarily due to the economic slow-down and to natural gas production declines.
The incremental earnings before depreciation, depletion and amortization expenses from our Kinder Morgan Louisiana Pipeline, which began full service on June 21, 2009, primarily relates to other non-operating income realized in the second quarter and first six months of 2009 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. In addition to the start of service on our Kinder Morgan Louisiana Pipeline, interim service on our 50% owned Midcontinent Express Pipeline commenced on April
50
10, 2009, with deliveries to Natural Gas Pipeline Company of America LLC. Service to all Zone 1 delivery points occurred by May 21, 2009.
The increases in earnings from our Kinder Morgan Interstate Gas Transmission pipeline system reflect higher period-to-period operating margins, driven mainly by higher firm transportation demand fees, higher earnings from natural gas park and loan services, and higher pipeline fuel recoveries, relative to the same comparable periods a year ago. The increase in demand fees was mainly due to the completion of (i) our previously announced Colorado Lateral expansion project in November 2008; and (ii) additional system expansions completed since the end of the second quarter of 2008 that provide for delivery service to multiple ethanol-producing industrial plants.
The increases and decreases in earnings from our equity investment in the Rockies Express joint venture pipeline relate to changes in net income earned by Rockies Express Pipeline LLC. Lower equity earnings in the second quarter of 2009, relative to last year, was chiefly due to Rockies Express’ higher interest expenses, due to higher year-over-year average borrowings, and partly due to higher depreciation and property tax expenses, as a result of more assets in service during the first half of 2009. Higher equity earnings for the full six months of 2009 were primarily due to incremental earnings attributable to the Rockies Express-West natural gas pipeline segment, which began full operations in May 2008. Overall transport volumes for the entire Rockies Express Pipeline increased 7% in the second quarter of 2009, and 26% in the first half of 2009, when compared to the same periods last year, and these volume increases were mainly due to the full operations of Rockies Express-West. Additionally, initial pipeline service on the Rockies Express-East pipeline segment began on June 29, 2009. The Rockies Express-East line extends from Audrain County, Missouri to the Lebanon Hub in Warren County, Ohio and currently has a total capacity of up to 1.6 billion cubic feet per day.
CO2
| | | | | | | | | | | | | |
| | Three Months Ended
June 30, | | Six Months Ended
June 30, | |
| | 2009 | | 2008 | | 2009 | | 2008 | |
| | | | | |
| | (In millions, except operating statistics) | |
Revenues | | $ | 258.2 | | $ | 308.6 | | $ | 487.1 | | $ | 595.0 | |
Operating expenses | | | (59.3 | ) | | (96.6 | ) | | (125.9 | ) | | (187.3 | ) |
Earnings from equity investments | | | 5.1 | | | 5.5 | | | 10.9 | | | 11.1 | |
Other, net-income (expense) | | | — | | | — | | | — | | | (0.2 | ) |
Income tax benefit (expense) | | | (1.3 | ) | | (0.9 | ) | | (2.0 | ) | | (2.2 | ) |
| | | | | | | | | | | | | |
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments | | $ | 202.7 | | $ | 216.6 | | $ | 370.1 | | $ | 416.4 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Carbon dioxide delivery volumes (Bcf)(a) | | | 188.7 | | | 178.6 | | | 401.4 | | | 358.8 | |
SACROC oil production (gross)(MBbl/d)(b) | | | 31.1 | | | 27.5 | | | 30.6 | | | 27.4 | |
SACROC oil production (net)(MBbl/d)(c) | | | 25.9 | | | 22.9 | | | 25.5 | | | 22.8 | |
Yates oil production (gross)(MBbl/d)(b) | | | 26.8 | | | 28.1 | | | 26.6 | | | 28.3 | |
Yates oil production (net)(MBbl/d)(c) | | | 11.9 | | | 12.5 | | | 11.8 | | | 12.6 | |
Natural gas liquids sales volumes (net)(MBbl/d)(c) | | | 9.6 | | | 9.1 | | | 9.2 | | | 9.3 | |
Realized weighted average oil price per Bbl(d)(e) | | $ | 49.47 | | $ | 53.01 | | $ | 46.71 | | $ | 51.52 | |
Realized weighted average natural gas liquids price per Bbl(e)(f) | | $ | 34.02 | | $ | 77.28 | | $ | 31.20 | | $ | 71.48 | |
| |
|
|
(a) | Includes Cortez, Central Basin, Canyon Reef Carriers, Centerline and Pecos pipeline volumes. |
(b) | Represents 100% of the production from the field. We own an approximately 97% working interest in the SACROC unit and an approximately 50% working interest in the Yates unit. |
(c) | Net to Kinder Morgan, after royalties and outside working interests. |
(d) | Includes all Kinder Morgan crude oil production properties. |
(e) | Hedge gains/losses for crude oil and natural gas liquids are included with crude oil. |
(f) | Includes production attributable to leasehold ownership and production attributable to our ownership in processing plants and third party processing agreements. |
51
Our CO2 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 2009 and 2008, of the segment’s (i) earnings before depreciation, depletion and amortization (EBDA); and (ii) operating revenues:
| | | | | | | | | | | |
Three months ended June 30, 2009 versus Three months ended June 30, 2008 |
| | EBDA
increase/(decrease) | | Revenues
increase/(decrease) |
| | | | |
| | (In millions, except percentages) |
Sales and Transportation Activities | | $ | (23.1 | ) | (32 | )% | $ | (19.8 | ) | (25 | )% |
Oil and Gas Producing Activities | | | 9.2 | | 6 | % | | (41.6 | ) | (17 | )% |
Intrasegment Eliminations | | | — | | — | | | 11.0 | | 55 | % |
| | | | | | | | | | | |
Total CO2 | | $ | (13.9 | ) | (6 | )% | $ | (50.4 | ) | (16 | )% |
| | | | | | | | | | | |
| | | | | | | | | | | |
Six months ended June 30, 2009 versus Six months ended June 30, 2008 |
| | EBDA
increase/(decrease) | | Revenues
increase/(decrease) |
| | | | |
| | (In millions, except percentages) |
Sales and Transportation Activities | | $ | (29.9 | ) | (21 | )% | $ | (25.8 | ) | (17 | )% |
Oil and Gas Producing Activities | | | (16.4 | ) | (6 | )% | | (96.7 | ) | (20 | )% |
Intrasegment Eliminations | | | — | | — | | | 14.6 | | 39 | % |
| | | | | | | | | | | |
Total CO2 | | $ | (46.3 | ) | (11 | )% | $ | (107.9 | ) | (18 | )% |
| | | | | | | | | | | |
The segment’s overall decreases in earnings before depreciation, depletion and amortization expenses in the comparable three and six month periods of 2009 versus 2008 were primarily due to lower earnings from the segment’s sales and transportation activities. The period-to-period decreases in earnings from sales and transportation activities were primarily due to decreases in carbon dioxide sales revenues, and partly due to decreases in pipeline transportation revenues.
Overall revenues from carbon dioxide sales to third parties decreased $16.0 million (30%) and $17.0 million (17%), respectively, in the second quarter and first half of 2009, when compared to the same prior year periods, and the decreases were entirely price related, as the segment’s average price received for all carbon dioxide sales decreased 39% and 31%, respectively, in the three and six month periods ended June 30, 2009, when compared to last year. The decreases in average sales prices in 2009 were due primarily to a portion of our carbon dioxide sales contracts being tied to lower crude oil prices, when compared to prior year periods.
The period-to-period decreases in sales revenues due to the drop in prices were partially offset, however, by increases in carbon dioxide sales volumes in the comparable three and six month periods of 2009 versus 2008. Primarily due to expansion projects completed since the end of the second quarter last year, and also to a continued strong demand for carbon dioxide use in and around the Permian Basin, our carbon dioxide sales volumes increased 16% and 21%, respectively, in the three and six month periods of 2009, when compared to the same periods a year ago. For both comparable periods, carbon dioxide delivery volumes also increased 6% and 12%, respectively, due largely to completed expansion projects that increased carbon dioxide production in southwest Colorado. We do not recognize profits on carbon dioxide sales to ourselves.
Earnings from 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, increased $9.2 million (6%) in the second quarter of 2009, but decreased $16.4 million (6%) in the first half of 2009, when compared to the same periods last year. Generally, earnings from the segment’s oil and gas producing activities are closely aligned with the revenues earned from both crude oil and natural gas plant products sales, and although oil and gas related revenues decreased $41.6 million (17%) in the second quarter of 2009, relative to the second quarter last year, oil and gas related operating expenses decreased by $50.8 million (48%). The decrease in revenues was due to lower average sales prices in the second quarter of 2009 for both crude oil and natural gas liquids (although the decrease from lower prices was somewhat offset by increased volumes), and the decrease in combined operating expenses
52
was due in part to overall cost reduction efforts (discussed below) and in part to a $15.4 million favorable adjustment to our accrued severance tax liabilities due to prior year overpayments.
The decrease in earnings from oil and gas producing activities in the comparable six month periods was driven by lower sales revenues from both crude oil and natural gas liquids, due largely to lower crude oil and natural gas liquids realizations in the first half of 2009, compared to last year (although average industry price levels for crude oil have increased since the beginning of 2009). Compared to the first half of 2008, revenues from crude oil sales decreased $17.6 million (5%) and revenues from natural gas liquids sales decreased $68.5 million (57%), respectively. The overall decrease in oil and gas related earnings in the comparable six month periods was partially offset by an $80.3 million (39%) decrease in combined operating expenses in the first half of 2009. The decrease in expenses was mostly related to lower severance and property tax expenses (including the June 2009 severance tax adjustment discussed above), lower operating, maintenance and fuel and power expenses (due in part to lower prices charged by the industry’s material and service providers), and to the successful renewal of lower priced service and supply contracts negotiated by our CO2 segment since the beginning of 2009.
Because price levels of crude oil and natural gas liquids are subject to external factors over which we have no control, and because future price changes may be volatile, our CO2 segment is exposed to commodity price risk related to the price volatility of crude oil and natural gas liquids. To some extent, we are able to mitigate this commodity price risk through a long-term hedging strategy that is intended to generate more stable realized prices by using derivative contracts to hedge the majority of our long-term production. The derivatives hedge our exposure to fluctuating future cash flows produced by changes in commodity sales prices; nonetheless, decreases in the prices of crude oil and natural gas liquids will have a negative impact on the result of our CO2 business segment, and even though we hedge the majority of our crude oil production, we do have exposure to unhedged volumes, the majority of which are natural gas liquids volumes.
With respect to crude oil, our realized weighted average price per barrel decreased 7% and 9% in the second quarter and first six months of 2009, respectively, when compared to the same periods a year ago. The decreases in revenues due to unfavorable pricing were partially offset by increases of 7% and 5%, respectively, in crude oil sales volumes. Average gross oil production for the second quarter of 2009 was 31.1 thousand barrels per day at the SACROC unit, 13% higher compared to the second quarter of 2008. At Yates, average gross oil production for the second quarter of 2009 was 26.8 thousand barrels per day, a decline of almost 5% versus the same quarter last year, but up slightly (1%) compared to the first quarter of 2009.
With respect to natural gas liquids, for the three and six month periods of 2009, our realized weighted average price per barrel decreased 56% in both comparable periods, and sales volumes increased 6% in the second quarter of 2009, but remained flat in the first half of 2009 versus the first half of 2008. All of our hedge gains and losses for crude oil and natural gas liquids are included in our realized average price for oil, and had we not used energy derivative contracts to transfer commodity price risk, our crude oil sales prices would have averaged $56.98 per barrel in the second quarter of 2009, and $123.03 per barrel in the second quarter of 2008. For more information on our hedging activities, see Note 6 to our consolidated financial statements included elsewhere in this report.
53
Terminals
| | | | | | | | | | | | | |
| | Three Months Ended
June 30, | | Six Months Ended
June 30, |
| | 2009 | | 2008 | | 2009 | | 2008 |
| | | | |
| | (In millions, except operating statistics) |
Revenues | | $ | 264.0 | | $ | 300.7 | | $ | 531.9 | | $ | 580.9 | |
Operating expenses(a) | | | (123.9 | ) | | (156.0 | ) | | (257.5 | ) | | (308.8 | ) |
Other income (expense) | | | 2.7 | | | (0.2 | ) | | 3.6 | | | 0.4 | |
Earnings from equity investments | | | — | | | 0.7 | | | 0.1 | | | 1.7 | |
Interest income and Other, net-income (expense) | | | 1.2 | | | 1.4 | | | 1.1 | | | 2.7 | |
Income tax expense | | | (1.1 | ) | | (6.2 | ) | | (1.6 | ) | | (10.7 | ) |
| | | | | | | | | | | | | |
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments | | $ | 142.9 | | $ | 140.4 | | $ | 277.6 | | $ | 266.2 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Bulk transload tonnage (MMtons)(b) | | | 18.2 | | | 27.7 | | | 36.9 | | | 51.6 | |
| | | | | | | | | | | | | |
Liquids leaseable capacity (MMBbl) | | | 55.1 | | | 52.4 | | | 55.1 | | | 52.4 | |
| | | | | | | | | | | | | |
Liquids utilization % | | | 96.9 | % | | 98.1 | % | | 96.9 | % | | 98.1 | % |
| | | | | | | | | | | | | |
| |
|
|
(a) | 2009 amounts include a $0.5 million decrease in expense associated with legal liability adjustments related to a litigation matter involving our Staten Island liquids terminal, and a $0.1 million increase in expense associated with environmental liability adjustments. |
(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. We group our bulk and liquids terminal operations into regions based on geographic location and/or primary operating function. This structure allows our management to organize and evaluate segment performance and to help make operating decisions and allocate resources.
The segment’s operating results in the first six months of 2009 include incremental contributions from strategic terminal acquisitions. Beginning with our June 16, 2008 acquisition of a steel terminal located in Cincinnati, Ohio, we have invested approximately $38.1 million in cash to acquire various terminal assets and operations, and combined, our acquired terminal operations accounted for incremental amounts of earnings before depreciation, depletion and amortization of $1.5 million, revenues of $4.9 million, and operating expenses of $3.4 million in the second quarter of 2009. For the six month period of 2009, acquired assets contributed incremental earnings before depreciation, depletion and amortization of $2.4 million, revenues of $7.3 million, and operating expenses of $4.9 million. All of the incremental amounts listed above represent the earnings, revenues and expenses from acquired terminals’ operations during the additional months of ownership in 2009, and do not include increases or decreases during the same months we owned the assets in 2008.
For all other terminal operations (those owned during identical periods in both 2009 and 2008), the certain items described in footnote (a) to the table above increased earnings before depreciation, depletion and amortization expenses for the three and six months ended June 30, 2009 by $0.4 million, when compared to the same two periods last year. Following is information for these terminal operations, for each of the comparable three and six month periods and by terminal operating region, related to (i) the remaining $0.6 million (0%) and $8.6 million (3%) increases in earnings before depreciation, depletion and amortization; and (ii) the $41.6 million (14%) and $56.3 million (10%) decreases in operating revenues:
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| | | | | | | | | | | |
Three months ended June 30, 2009 versus Three months ended June 30, 2008 |
| | EBDA
Increase/(decrease) | | Revenues
Increase/(decrease) |
| | | | |
| | (In millions, except percentages) |
Lower River (Louisiana) | | $ | 8.2 | | 149 | % | $ | (3.9 | ) | (14 | )% |
Gulf Coast | | | 1.8 | | 5 | % | | (0.4 | ) | (1 | )% |
West | | | 1.2 | | 12 | % | | (2.1 | ) | (10 | )% |
Mid River | | | (5.0 | ) | (57 | )% | | (13.1 | ) | (53 | )% |
Ohio Valley | | | (3.7 | ) | (53 | )% | | (6.9 | ) | (38 | )% |
Mid-Atlantic | | | (2.5 | ) | (21 | )% | | (8.2 | ) | (28 | )% |
All others (including eliminations) | | | 0.6 | | 1 | % | | (7.0 | ) | (5 | )% |
| | | | | | | | | | | |
Total Terminals | | $ | 0.6 | | — | | $ | (41.6 | ) | (14 | )% |
| | | | | | | | | | | |
| | | | | | | | | | | |
Six months ended June 30, 2009 versus Six months ended June 30, 2008 |
| | EBDA
Increase/(decrease) | | Revenues
increase/(decrease) |
| | | | |
| | (In millions, except percentages) |
Lower River (Louisiana) | | $ | 11.5 | | 85 | % | $ | (6.8 | ) | (13 | )% |
Northeast | | | 3.6 | | 10 | % | | 4.7 | | 8 | % |
Texas Petcoke | | | 3.1 | | 10 | % | | (2.3 | ) | (4 | )% |
Gulf Coast | | | 3.0 | | 4 | % | | 2.2 | | 2 | % |
Mid River | | | (7.9 | ) | (52 | )% | | (22.1 | ) | (47 | )% |
Ohio Valley | | | (4.6 | ) | (43 | )% | | (9.9 | ) | (32 | )% |
All others (including eliminations) | | | (0.1 | ) | — | | | (22.1 | ) | (9 | )% |
| | | | | | | | | | | |
Total Terminals | | | 8.6 | | 3 | % | $ | (56.3 | ) | (10 | )% |
| | | | | | | | | | | |
Earnings before depreciation, depletion and amortization from terminals owned in both comparable periods was flat for the second quarter of 2009 and up 3% in the first six months of the year, versus the same periods of 2008. The increases in earnings before depreciation, depletion and amortization expenses from our Lower River (Louisiana) terminals were mainly due to the higher earnings realized in the second quarter of 2009, relative to the second quarter last year. The increase was driven by both a $4.4 million increase in earnings from our International Marine Terminals facility, a Louisiana partnership located in Port Sulphur, Louisiana and owned 66 2/3% by us, and a $3.6 million decrease in income tax expense due to lower taxable income in our tax paying terminal subsidiaries. Although quarterly revenues at IMT declined by $3.0 million in the second quarter of 2009, due to less tonnage and lower revenues from fleeting and barge services, the terminal benefited from both a $4.2 million decrease in operating expenses, due to lower fuel and power expenses and lower crane rental and ship demurrage fees, and from a $3.2 million property casualty gain (on a vessel dock that was damaged in June 2009).
The increases in earnings from our Gulf Coast terminals were driven by favorable results from our Pasadena and Galena Park, Texas liquids facilities located along the Houston Ship Channel. The increases were driven by higher liquids warehousing revenues, mainly due to new and incremental customer agreements (at higher rates) and to additional ancillary terminal services. For our Terminals segment combined, expansion projects completed since the second quarter of 2008 increased our liquids terminals’ leasable capacity to 55.1 million barrels, up 5% from a capacity of 52.4 million barrels at the end of the second quarter of 2008. At the same time, our overall liquids utilization capacity rate (the ratio of our actual leased capacity to our estimated potential capacity) decreased a slight 1% since the end of the second quarter of 2008.
The increase in earnings in the second quarter of 2009 from our West region terminals was driven by an incremental contribution of $1.4 million from our Kinder Morgan North 40 terminal, the crude oil tank farm we constructed near Edmonton, Alberta, Canada, and which was placed into service in the second quarter of 2008. Earnings from our Northeast terminals, which include the combined operations of our three New York Harbor liquids terminals, and our Texas Petcoke terminals, which primarily handle petroleum coke tonnage in and around the Texas Gulf Coast, were flat for the second quarter of 2009, but higher in 2009 on a year-to-date basis (as discussed below).
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The increase in earnings in the first half of 2009 versus the first half of 2008 from our New York Harbor terminals, which include our Perth Amboy, New Jersey terminal, our Carteret, New Jersey terminal, and our Staten Island, New York terminal, was driven by a 7% increase in combined liquids throughput volumes, resulting from both terminal expansions completed since the second quarter of 2008 and continued strong demand for petroleum distillates. The increase in earnings through the first six months of 2009 from our petroleum coke operations was driven by higher petroleum coke throughput volumes and higher handling rates, relative to the first half of 2008, at our Port of Houston and Port Arthur, Texas terminal locations.
The overall increases in segment earnings before depreciation, depletion and amortization in the comparable three and six month periods of 2009 versus 2008 were partly offset by lower earnings from our Mid River and Ohio Valley terminals, and in the comparable second quarter periods only, by lower earnings from our Mid-Atlantic terminals. The decreases from these facilities were due primarily to decreased import/export activity, and to lower business activity at various owned and/or operated rail and terminal sites that are primarily involved in the handling and storage of steel and alloy products.
The economic downturn that began last year has negatively affected the worldwide steel industry and has led to a general decrease in U.S. port activity relative to the first half of last year. As a result, for our Terminals segment combined, bulk traffic tonnage decreased by 9.5 million tons (34%) in the second quarter of 2009, and decreased 14.7 million tons (28%) in the first six months of 2009, when compared to the same prior year periods. The economic downturn and drops in tonnage resulted in lower period-to-period revenues and earnings at various terminal facilities that handle steel and iron ore, dock barges and deep sea vessels for bulk cargo operations, and perform stevedoring and wharfage services.
Kinder Morgan Canada
| | | | | | | | | | | | | |
| | Three Months Ended
June 30, | | Six Months Ended
June 30, |
| | 2009 | | 2008 | | 2009 | | 2008 |
| | | | |
| | (In millions, except operating statistics) |
Revenues | | $ | 56.0 | | $ | 43.4 | | $ | 106.0 | | $ | 86.5 | |
Operating expenses | | | (18.1 | ) | | (17.0 | ) | | (33.3 | ) | | (32.7 | ) |
Earnings from equity investments | | | (0.6 | ) | | — | | | (0.3 | ) | | 0.1 | |
Interest income and Other, net-income (expense) | | | 8.2 | | | 4.0 | | | 8.9 | | | 6.1 | |
Income tax benefit (expense)(a) | | | 1.2 | | | 3.0 | | | (15.1 | ) | | 3.6 | |
| | | | | | | | | | | | | |
Earnings (loss) before depreciation, depletion and amortization expense and amortization of excess cost of equity investments | | $ | 46.7 | | $ | 33.4 | | $ | 66.2 | | $ | 63.6 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Transport volumes (MMBbl)(b) | | | 24.3 | | | 21.5 | | | 46.9 | | | 40.9 | |
| | | | | | | | | | | | | |
| |
|
|
(a) | 2009 amounts include a $3.7 million decrease in expense due to a certain non-cash accounting change related to book tax accruals and foreign exchange fluctuations related to the Express pipeline system. Six month 2009 amount also includes a $14.9 million increase in expense primarily due to certain non-cash regulatory accounting adjustments to Trans Mountain’s carrying amount of the previously established deferred tax liability. |
(b) | Represents Trans Mountain pipeline system volumes. |
Our Kinder Morgan Canada business segment includes the operations of the Trans Mountain, Express, and Jet Fuel pipeline systems. We acquired both our one-third equity ownership interest in the approximate 1,700-mile Express pipeline system and our full ownership of the approximate 25-mile Jet Fuel pipeline system from KMI effective August 28, 2008. After taking into account the certain item related to the Express pipeline system described in footnote (a) to the table above, these combined businesses accounted for incremental amounts of earnings before depreciation, depletion and amortization of $2.6 million and $6.6 million in the second quarter and first half of 2009, respectively. The incremental earnings primarily related to interest earned on our long-term investment in a debt security issued by the Express pipeline.
After taking into effect the residual non-cash certain items described in footnote (a) to the table above and the Express acquisition described above, the segment’s remaining business—the Trans Mountain crude oil and refined products pipeline system—contributed incremental earnings before depreciation, depletion and amortization
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expenses of $7.0 million (21%) and $7.2 million (11%) in the second quarter and first six months of 2009, respectively. The increases in earnings were driven by higher pipeline transportation revenues, due to increases in pipeline throughput volumes and to higher tariff rates that became effective in May 2009.
In the second quarter and first half of 2009, Trans Mountain’s operating revenues increased $11.8 million (27%) and $18.0 million (21%), respectively, when compared to the same periods last year. The increases in revenues were driven by corresponding increases in mainline delivery volumes—13% in the comparable three month periods and 15% in the comparable six month periods—resulting primarily from expansion projects completed since the second quarter of 2008, and from increases in ship traffic during 2009 at the Port of Metro Vancouver. On both April 28 and October 30 of 2008, we completed separate portions of the Trans Mountain Pipeline’s Anchor Loop expansion project and combined, this project boosted pipeline transportation capacity by 15% (from 260,000 barrels per day to 300,000 barrels per day) and resulted in higher period-to-period average toll rates.
Other
| | | | | | | | | | | | | |
| | Three Months Ended June 30, | | Earnings
increase/(decrease) | |
| | | | |
| | 2009 | | 2008 | | |
| | | | | | | |
| | (In millions-income (expense), except percentages) | |
General and administrative expenses(a) | | $ | (72.6 | ) | $ | (72.8 | ) | $ | 0.2 | | | — | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Unallocable interest expense, net of interest income(b) | | $ | (101.3 | ) | $ | (99.9 | ) | $ | (1.4 | ) | | (1 | )% |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Unallocable income tax expense | | $ | (2.3 | ) | $ | (4.4 | ) | $ | 2.1 | | | 48 | % |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Net income attributable to noncontrolling interests | | $ | (4.8 | ) | $ | (4.1 | ) | $ | (0.7 | ) | | (17 | )% |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | Six Months Ended June 30, | | Earnings
increase/(decrease) | |
| | | | |
| | 2009 | | 2008 | | |
| | | | | | | |
| | (In millions-income (expense), except percentages) | |
General and administrative expenses(c) | | $ | (155.1 | ) | $ | (149.6 | ) | $ | (5.5 | ) | | (4 | )% |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Interest expense, net of unallocable interest income(d) | | $ | (205.9 | ) | $ | (197.6 | ) | $ | (8.3 | ) | | (4 | )% |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Unallocable income tax expense | | $ | (4.6 | ) | $ | (4.4 | ) | $ | (0.2 | ) | | (5 | )% |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Net income attributable to noncontrolling interests(e) | | $ | (7.7 | ) | $ | (8.1 | ) | $ | 0.4 | | | 5 | % |
| | | | | | | | | | | | | |
|
| |
(a) | 2009 and 2008 amounts include increases of $1.4 million in non-cash compensation expense allocated to us from KMI. We do not have any obligation, nor do we expect, to pay any amounts related to these expenses. 2009 amount also includes a $0.9 million decrease in expense related to capitalized overhead costs associated with the 2008 hurricane season. |
(b) | 2009 and 2008 amounts include increases in imputed interest expense of $0.3 million and $0.5 million, respectively, related to our 2007 Cochin Pipeline acquisition. |
(c) | 2009 and 2008 amounts include increases of $2.8 million in non-cash compensation expense allocated to us from KMI. We do not have any obligation, nor do we expect, to pay any amounts related to these expenses. 2009 amount also includes a $0.1 million increase in expense for certain Express pipeline system acquisition costs, and a $1.5 million decrease in expense related to capitalized overhead costs associated with the 2008 hurricane season. |
(d) | 2009 and 2008 amounts include increases in imputed interest expense of $0.8 million and $1.0 million, respectively, related to our 2007 Cochin Pipeline acquisition. |
(e) | 2009 amount includes a $0.2 million decrease in net income attributable to noncontrolling interests related to all of the six month 2009 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 and income tax expense, interest expense, and net income attributable to noncontrolling interests. 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. We report our interest expense as “net,” meaning that we have subtracted unallocated interest income from our total interest expense to arrive at one interest amount.
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For the three and six months ended June 30, 2009, the certain items described in footnotes (a) and (c) to the tables above decreased our general and administrative expenses by $0.9 million and $1.4 million, respectively, when compared to the same 2008 periods. The remaining general and administrative expenses for the three months ended June 30, 2009 were essentially flat versus the same period last year, but the remaining expenses for the six month period of 2009 exceeded last year’s expenses by $6.9 million (5%). The overall increase included a $5.5 million increase from higher employee benefit and payroll tax expenses in the first half of 2009, due mainly to cost inflation increases on work-based health and insurance benefits and to a larger year-over-year labor force.
We continue to manage aggressively our general and administrative expenses, and in light of the current economic uncertainties, we have taken additional measures to reduce our expenses since the start of the year. Specifically, we are reducing our travel and compensation costs where possible, decreasing our use of outside consultants, reducing overtime where possible, and reviewing our capital and operating budgets to identify costs we can reduce without compromising operating efficiency, maintenance or safety.
After taking into effect the certain items described in footnotes (b) and (d) to the tables above, our unallocable interest expense, net of interest income, increased $1.6 million (2%) in the second quarter of 2009 and $8.5 million (4%) in the first half of 2009, versus the same periods last year. The increases in interest expense were attributable to higher average debt balances—average borrowings increased 15% and 19%, respectively, in the comparable three and six month periods of 2009—but were partly offset by decreases of 15% and 13%, respectively, in the weighted average interest rate on all of our borrowings.
The increases in our average borrowings were largely due to the capital expenditures and joint venture contributions we have made since the end of the second quarter of 2008, driven primarily by continued investment in our Natural Gas Pipelines and CO2 business segments. Generally, we initially fund our discretionary capital spending, the contributions we pay for our proportionate share of pipeline project construction costs, and our acquisition outlays from borrowings under our bank credit facility (or under our commercial paper program when we have access to the commercial paper market). From time to time, we issue senior notes and equity in order to refinance our commercial paper and credit facility borrowings.
The period-to-period decreases in our average borrowing rates reflect a general drop in variable interest rates since the end of the second quarter of 2008. We use interest rate swap agreements to transform a portion of the underlying cash flows related to our long-term fixed rate debt securities (senior notes) into variable rate debt in order to achieve our desired mix of fixed and variable rate debt. In periods of falling interest rates, these swaps will result in period-to-period decreases in our interest expense. As of June 30, 2009, approximately 52% of our $9,399.8 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. For more information on our interest rate swaps, see Note 6 to our consolidated financial statements included elsewhere in this report.
The period-to-period fluctuations in both unallocable income tax expenses and net income attributable to noncontrolling interests were not significant in either the three or six month comparable periods of 2009 and 2008. Unallocable income tax expense relates to corporate-level income tax expense accruals (accrued by the Partnership) for the Texas margin tax, an entity-level tax imposed on the amount of our total revenue that is apportioned to the state of Texas. Income allocated to our noncontrolling interests represents the allocation of our consolidated net income attributable to all outstanding ownership interests in our five operating limited partnerships and their consolidated subsidiaries that are not held by us.
Financial Condition
General
As of June 30, 2009, we believe our balance sheet and liquidity position remained strong. Our short term debt, net of cash, was approximately $42.9 million. In addition, we demonstrated substantial flexibility in the term debt market by issuing an additional $1 billion in principal amount of senior notes in the second quarter of 2009 (receiving proceeds, after underwriting discounts and commissions, of $993.3 million).
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Similarly, we demonstrated continued access to the equity market by raising approximately $712.5 million in net proceeds from equity offerings year to date, including $286.9 million from the public offering of 5,750,000 common units on June 12, 2009 (we received additional net cash proceeds of $43.0 million from the issuance of an additional 862,500 common units pursuant to the underwriters’ exercise of an over-allotment option in July 2009). We have consistently generated strong cash flow from operations—generating $936.8 million in cash from operations in the first half of 2009—and we continue to have access to additional sources of liquidity though our $1.85 billion bank credit facility and our equity distribution agreement with UBS Securities LLC.
As of June 30, 2009, we had approximately $1.4 billion of borrowing capacity available under our credit facility (discussed below in “—Short-term Liquidity”). Furthermore, at KMI’s third quarter 2008 board meeting held on October 15, 2008, KMI’s board indicated its willingness to contribute up to $750 million of equity to us over the subsequent 18 months, if necessary, in order to support our capital raising efforts.
We believe that our cash generating business model provides us with the financial flexibility needed to operate our assets and make targeted investments in the business segments that present our best long-term opportunities, and as we continue to operate in the current challenging economic environment, we will also continue to focus on cost and expense reduction and improved efficiency.
Our primary cash requirements, in addition to normal operating expenses, are debt service, sustaining capital expenditures (defined as capital expenditures which do not increase the capacity of an asset), expansion capital expenditures and quarterly distributions to our common unitholders, Class B unitholder 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 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.
In general, we expect to fund:
| |
| ▪ cash distributions and sustaining capital expenditures with existing cash and cash flows from operating activities; |
| |
| ▪ expansion capital expenditures and working capital deficits with retained cash (resulting from including i-units in the determination of cash distributions per unit but paying quarterly distributions on i-units in additional i-units rather than cash), additional borrowings, the issuance of additional common units or the proceeds from purchases of additional i-units by KMR; |
| |
| ▪ interest payments with cash flows from operating activities; and |
| |
| ▪ debt principal payments with additional borrowings, as such debt principal payments become due, or by the issuance of additional common units or the proceeds from purchases of additional i-units by KMR. |
In addition to our results of operations, our debt and capital balances are affected by our financing activities, as discussed below in “—Financing Activities.”
Credit Ratings and Capital Market Liquidity
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 expansion activities in order to maintain acceptable financial ratios. Currently, our long-term corporate debt credit rating is BBB, Baa2 and BBB, respectively, at S&P, Moody’s and Fitch. As a publicly traded limited partnership, our common units are attractive primarily to individual investors, although such investors represent a small segment of the total equity capital market. We believe that some institutional investors prefer shares of KMR over our common units due to tax and other regulatory considerations, and we are able to access this segment of the capital market through KMR’s purchases of i-units issued by us with the proceeds from the sale of KMR shares to institutional investors.
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On September 15, 2008, Lehman Brothers Holdings Inc. filed for bankruptcy protection under the provisions of Chapter 11 of the U.S. Bankruptcy Code. Lehman Brothers Commercial Bank was a lending institution that provided $63.3 million of the commitments under our credit facility. During the first quarter of 2009, we amended our facility to remove Lehman Brothers Commercial Bank as a lender, thus reducing the facility by $63.3 million. The commitments of the other banks remain unchanged, and the facility is not defaulted.
On October 13, 2008, S&P revised its outlook on our long-term credit rating to negative from stable (but affirmed our long-term credit rating at BBB), due to our previously announced expected delay and cost increases associated with the completion of the Rockies Express Pipeline project. At the same time, S&P lowered our short-term credit rating to A-3 from A-2. As a result of this revision to our short-term credit rating and the current commercial paper market conditions, we are unable to access commercial paper borrowings.
On May 6, 2009, Moody’s downgraded our commercial paper rating to Prime-3 from Prime-2 and assigned a negative outlook to our long-term credit rating. The downgrade was primarily related to the increases, since the beginning of 2009, in our outstanding debt balance. However, we continue to maintain an investment grade credit rating, and all of our long-term credit ratings remain unchanged since December 31, 2008. Furthermore, we expect that our financing and our short-term liquidity needs will continue to be met through borrowings made under our bank credit facility. Nevertheless, our ability to satisfy our financing requirements or fund our planned capital expenditures will depend upon our future operating performance, which will be affected by prevailing economic conditions in the energy and terminals industries and other financial and business factors, some of which are beyond our control.
Additionally, 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. These financial problems may arise from the current financial crises, changes in commodity prices or otherwise. We have and 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 current or future 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.
Short-term Liquidity
Our principal sources of short-term liquidity are our (i) $1.85 billion senior unsecured revolving bank credit facility that matures August 18, 2010; and (ii) cash from operations (discussed below in “—Operating Activities”). Borrowings under our bank 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 $2.04 billion (after reductions by the Lehman commitment). As of June 30, 2009, the outstanding balance under our bank credit facility was $100.0 million, and there were no borrowings under our commercial paper program. As of December 31, 2008, we had no outstanding borrowings under our credit facility or our commercial paper program.
As of June 30, 2009, our outstanding short-term debt was $145.4 million, primarily consisting of the $100.0 million of outstanding borrowings under our bank credit facility. We provide for additional liquidity by maintaining a sizable amount of excess borrowing capacity related to our bank credit facility. After reduction for (i) our letters of credit; (ii) our outstanding borrowings under our credit facility; and (iii) the lending commitments made by Lehman Brothers Commercial Bank, which was canceled in connection with the Lehman Brothers bankruptcy (see Note 4 “Debt” to our consolidated financial statements included elsewhere in this report), the remaining available borrowing capacity under our bank credit facility was $1,377.9 million as of June 30, 2009. Currently, we believe our liquidity to be adequate.
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.
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We are subject, however, to conditions 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 debt financing alternatives, some of which could involve higher costs or negatively affect our credit ratings. Furthermore, our ability to access the public and private debt markets is affected by our credit ratings. See “—Credit Ratings and Capital Market Liquidity” above for a discussion of our credit ratings.
As of June 30, 2009 and December 31, 2008, the total liability balance due on the various series of our senior notes was $9,130.1 million and $8,381.5 million, respectively, and the total liability balance due on the various borrowings of our operating partnerships and subsidiaries was $169.7 million and $182.1 million, respectively. For more information on our 2009 debt related transactions, including our issuances of senior notes, see Note 4 “Debt” to our consolidated financial statements included elsewhere in this report, and for additional information regarding our debt securities and credit facility, see Note 9 to our consolidated financial statements included in our 2008 Form 10-K. For information on our equity issuances in the first half of 2009, including cash proceeds received from public offerings of common units and from our equity distribution agreement, see Note 5 “Partners’ Capital—Equity Issuances” to our consolidated financial statements included elsewhere in this report
Capital Structure
We attempt to maintain a relatively conservative overall capital structure, financing our expansion capital expenditures and acquisitions with approximately 50% equity and 50% debt. In the short-term, we fund these expenditures from borrowings under our credit facility until the amount borrowed is of a sufficient size to cost effectively do either a debt or equity offering, or both.
With respect to our debt, we target a debt mixture of approximately 50% fixed and 50% variable interest rates. We achieve our variable rate exposure primarily by issuing long-term fixed rate debt and then swapping the fixed rate interest payments for variable rate payments.
Capital Expenditures
Including both sustaining and discretionary spending, our capital expenditures were $796.6 million in the first six months of 2009, versus $1,262.6 million in the same year-ago period. Our sustaining capital expenditures, defined as capital expenditures which do not increase the capacity of an asset, totaled $70.7 million, compared to $76.8 million for 2008. These sustaining expenditure amounts include our proportionate share of Rockies Express’ sustaining capital expenditures—approximately $0.1 million in the first six months of 2009 and less than $0.1 million in the first six months of 2008. Additionally, our forecasted expenditures for the remaining six months of 2009 for sustaining capital expenditures are approximately$111.7 million—including our proportionate shares of Rockies Express and Midcontinent Express. Generally, we fund our sustaining capital expenditures with existing cash or from cash flows from operations. In addition to utilizing cash generated from its operations, Rockies Express can fund its cash requirements for capital expenditures through borrowings under its own credit facility, issuing its own long-term notes, or with proceeds from contributions received from its equity owners.
All of our capital expenditures, with the exception of sustaining capital expenditures, are classified as discretionary. The discretionary capital expenditures reflected in our consolidated statement of cash flows for the first half of 2009 and 2008 were $725.9 million and $1,185.8 million, respectively. Generally, we fund our discretionary capital expenditures (and our investment contributions) through borrowings under our bank credit facility. To the extent this source of funding is not sufficient, we generally fund additional amounts through the issuance of long-term notes or common units for cash. During the first half of 2009, we used sales of common units and the issuance of senior notes to refinance portions of our short-term borrowings under our bank credit facility.
Operating Activities
Net cash provided by operating activities was $936.8 million for the six months ended June 30, 2009, versus $974.7 million for the comparable period of 2008. The period-to-period decrease of $37.9 million (4%) in cash provided by operating activities primarily consisted of:
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| ▪ a $165.4 million decrease in cash inflows relative to net changes in working capital items, primarily driven by reductions in customer deposits, lower net cash inflows from the collection and payment of trade and related party receivables and payables (including collections and payments on natural gas transportation and exchange imbalance receivables and payables), and higher payments in 2009 to settle certain refined product imbalance liabilities owed to U.S. military customers of our Products Pipelines business segment; |
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| ▪ a $35.0 million decrease in cash from overall lower partnership income—after adjusting for the following four non-cash items: depreciation, depletion and amortization expenses; undistributed earnings from equity investees; income from the allowance for equity funds used during construction; and income from the sales of property, plant and equipment. The year-to-year decrease in partnership income from our five reportable business segments in the first six months of 2009 and 2008 is discussed above in “—Results of Operations” (including all of the certain items disclosed in the associated table footnotes); |
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| ▪ a $25.7 million decrease in cash relative to changes in other non-current assets and liabilities, and other non-cash expenses, primarily driven by reductions in our Trans Mountain Pipeline’s deferred revenue obligations and by higher payments for natural gas storage on our Kinder Morgan Interstate Gas Transmission system; |
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| ▪ a $144.4 million increase in cash from an interest rate swap termination payment we received in January 2009, when we terminated a fixed-to-variable interest rate swap agreement having a notional principal amount of $300 million and a maturity date of March 15, 2031; and |
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| ▪ a $36.0 million increase in cash related to higher distributions received from equity investments—chiefly due to incremental distributions of $43.1 million received from West2East Pipeline LLC, the sole owner of Rockies Express Pipeline LLC. We began receiving distributions on our 51% equity interest in West2East Pipeline LLC in the second quarter of 2008. 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. |
Investing Activities
Net cash used in investing activities was $1,537.9 million for the six month period ended June 30, 2009, compared to $1,654.9 million for the comparable 2008 period. The $117.0 million (7%) decrease in cash used in investing activities was primarily attributable to:
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| ▪ a $466.0 million decrease in cash used for capital expenditures—largely due to the higher investment undertaken in the first half of 2008 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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| ▪ a $182.2 million decrease in cash used for margin and restricted deposits in 2009 compared to 2008, associated largely with our utilization of derivative contracts to hedge (offset) against the volatility of energy commodity price risks; |
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| ▪ a $109.6 million decrease in cash used due to the full repayment received during the first six months of 2009 from a $109.6 million loan we made in December 2008 to a single customer of our Texas intrastate natural gas pipeline group; |
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| ▪ a $464.1 million increase in cash used due to higher contributions to equity investees in the first half of 2009, relative to the first six months a year ago. The increase was primarily driven by incremental contributions to West2East Pipeline LLC, Midcontinent Express Pipeline LLC, and Fayetteville Pipeline LLC to partially fund their respective Rockies Express, Midcontinent Express, and Fayetteville Express Pipeline construction and/or pre-construction costs. As discussed in Note 2 to our consolidated financial statements included elsewhere in this report, in the first half of 2009 we contributed a combined $797.7 million for these three pipeline projects, versus contributions of $333.5 million in the first half of 2008; |
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| §an $89.1 million increase in cash used related to a return of capital received from Midcontinent Express Pipeline LLC in February 2008. During that month, 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; |
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| § a $52.6 million increase in cash used, relative to 2008, due to lower net proceeds received from the sales of investments, property, plant and equipment, and other net assets (net of salvage and removal costs). The decrease in cash sales proceeds was driven by the approximately $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; and |
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| § a $23.4 million increase in cash used related to a contribution received from KMI in April 2008, as a result of certain true-up provisions in our Trans Mountain acquisition agreement. |
Financing Activities
Net cash provided by financing activities amounted to $638.6 million for the first half of 2009. For the first six months a year ago, our financing activities provided net cash of $701.0 million. The $62.4 million (9%) cash decrease from the comparable 2008 period was mainly due to:
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| § a $152.5 million decrease in cash from higher partnership distributions in the first six months of 2009, when compared to the same period last year. Distributions to all partners, including our common and Class B unitholders, our general partner and our noncontrolling interests, totaled $858.9 million in the first half of 2009, compared to $706.4 million in the same period last year; |
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| § a $148.7 million decrease in cash from overall debt financing activities—which include our issuances and payments of debt and our debt issuance costs. The period-to-period decrease in cash from overall financing activities was primarily due to (i) a $838.5 million decrease in cash due to lower net issuances and repayments of senior notes in the first half of 2009; (ii) a $589.1 million increase in cash due to net commercial paper repayments in the first half of 2008; and (iii) a $100.0 million increase in cash from incremental borrowings under our bank credit facility in the first half of 2009; |
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| | The decrease in cash inflows from changes in senior notes outstanding reflects the combined $743.3 million we received from both issuing and repaying senior notes in 2009 (discussed in Note 4 to our consolidated financial statements included elsewhere in this report), versus the combined $1,581.8 million we received from our February and June 2008 public offerings of senior notes. Our 2008 debt offerings consisted of four separate series of senior notes, having an aggregate principal amount of $1.6 billion. We used the proceeds from each of these offerings to reduce the borrowings under our commercial paper program; |
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| § a $48.7 million decrease in cash inflows from net changes in cash book overdrafts—resulting from timing differences on checks issued but not yet presented for payment; and |
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| § a $285.2 million increase in cash from higher partnership equity issuances. The increase relates to the combined $669.5 million we received, after commissions and underwriting expenses, from the sales of additional common units in the first half of 2009 (discussed in Note 5 to our consolidated financial statements included elsewhere in this report), versus the combined $384.3 million we received from two separate offerings of common units in the first half of 2008. The $384.3 million in proceeds received in 2008 included $60.1 million from the issuance of 1,080,000 common units in a privately negotiated transaction completed in February 2008, and $324.2 million from the issuance of 5,750,000 additional common units pursuant to a public offering completed in March 2008. We used the proceeds from each of these two offerings to reduce the borrowings under our commercial paper program. |
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
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respective percentage interests. Our 2008 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 our noncontrolling interests.
On May 15, 2009, we paid a quarterly distribution of $1.05 per unit for the first quarter of 2009. This distribution was 9% greater than the $0.96 distribution per unit we paid in May 2008 for the first quarter of 2008. 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 $1.05 cash distribution per common unit. On July 15, 2009, we declared a cash distribution of $1.05 per unit for the second quarter of 2009 (an annualized rate of $4.20 per unit). This distribution was 6% higher than the $0.99 per unit distribution we made for the second quarter of 2008.
The incentive distribution that we paid on May 15, 2009 to our general partner (for the first quarter of 2009) was $223.2 million. Our general partner’s incentive distribution that we paid in May 2008 (for the first quarter of 2008) was $185.8 million. Our general partner’s incentive distribution for the distribution that we declared for the second quarter of 2009 is $231.8 million, and our general partner’s incentive distribution for the distribution that we paid for the second quarter of 2008 was $194.2 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.
Additionally, in November 2008, we announced that we expected to declare cash distributions of $4.20 per unit for 2009, almost a 4.5% increase over our cash distribution of $4.02 per unit for 2008. Although the majority of the cash generated by our assets is fee based and is not sensitive to commodity prices, our CO2 business segment is exposed to commodity price risk related to the price volatility of crude oil and natural gas liquids. While we hedge the majority of our crude oil production, we do have exposure on our unhedged volumes, the majority of which are natural gas liquids. Our 2009 distribution expectation assumes an average West Texas Intermediate crude oil price of $68 per barrel (with some minor adjustments for timing, quality and location differences). Based on the actual prices we have received through the date of this report and the forward price curve for WTI (adjusted for the same factors used in our 2009 budget), we currently expect to realize an average WTI crude oil price of approximately $58 per barrel in 2009. For 2009, we expect that every $1 change in the average WTI crude oil price per barrel will impact our CO2 segment’s cash flows by approximately $6 million (or approximately 0.2% of our combined business segments’ distributable cash flow).
To offset the lower crude prices, as well as other headwinds we face from ongoing weak market conditions, we have identified a number of areas across our company to minimize costs and maximize revenues without compromising operational safety or efficiency. Since the start of 2009, (i) we have continued to focus on reducing our general and administrative expenses across our business portfolio wherever possible; (ii) our CO2 business segment has negotiated lower contract prices with various oil and gas material and service suppliers, thereby lowering its operating and maintenance expenses; (iii) our Terminals segment has entered into various term supply contracts to lower its costs of diesel fuel; and (iv) average interest rates have been lower than originally anticipated for 2009, resulting in lower interest expense on our outstanding debt. We expect these items to further benefit us throughout the year, and as a result of these cost reductions and other opportunities that we have identified, we continue to expect that we will achieve our budget target of $4.20 per unit in cash distributions for 2009.
Recent Accounting Pronouncements
Please refer to Note 12 to our consolidated financial statements included elsewhere in this report for information concerning recent accounting pronouncements.
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,
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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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| § changes in 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 oil sands; |
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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 and credit 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 10 to our consolidated financial statements included elsewhere in this report. |
The foregoing list should not be construed to be exhaustive. We believe the forward-looking statements in this report are reasonable. However, 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 2008 Form 10-K 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 our 2008 Form 10-K. 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, 2008, in Item 7A of our 2008 Form 10-K. For more information on our risk management activities, see Note 6 to our consolidated financial statements included elsewhere in this report.
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Item 4. | Controls and Procedures. |
As of June 30, 2009, 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,
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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, 2009 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
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Item 1. | Legal Proceedings. |
See Part I, Item 1, Note 10 to our consolidated financial statements entitled “Litigation, Environmental and Other Contingencies,” which is incorporated in this item by reference.
There have been no material changes in or additions to the risk factors disclosed in Part I, Item 1A “Risk Factors” in our 2008 Form 10-K.
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Item 2. | Unregistered Sales of Equity Securities and Use of Proceeds. |
Effective April 24, 2009, we issued 105,752 common units as the purchase price for ownership interests in certain oil and gas properties. The units were valued at $5.0 million, based on the average of the closing prices of our common units on the New York Stock Exchange for the five trading day period ended April 23, 2009, and were issued to the two sellers of the properties in a transaction not involving a public offering, exempt from registration pursuant to Section 4(2) of the Securities Act of 1933.
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Item 3. | Defaults Upon Senior Securities. |
None.
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Item 4. | Submission of Matters to a Vote of Security Holders. |
None.
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Item 5. | Other Information. |
None.
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4.1 | — | 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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4.2 | — | Certificate of the Vice President and Chief Financial Officer and the Vice President and Treasurer 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 5.625% Senior Notes due 2015, and the 6.85% Senior Notes due 2020. |
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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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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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101 | — | Interactive Data File. |
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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. |
| | Registrant (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: July 31, 2009 |
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