UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
| x | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the period ended August 31, 2005
OR
| ¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the Transition Period from to
Commission file number 333-125036-09
HPL Consolidation LP
(Exact name of registrant as specified in its charter)
| | |
| Delaware | | 20-2218693 |
(State or other jurisdiction of incorporation or organization) | | (I.R.S. Employer Identification No.) |
2838 Woodside Street, Dallas, Texas 75204
(Address of principal executive offices and zip code)
(214) 981-0700
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ¨ No x
THE REGISTRANT MEETS THE CONDITIONS SET FORTH IN GENERAL INSTRUCTIONS (I) (1) (a) AND (b) OF FORM 10-K AND IS THEREFORE FILING THIS FORM WITH THE REDUCED DISCLOSURE FORMAT.
Documents Incorporated by Reference: None
HPL CONSOLIDATION LP
2005 FORM 10-K ANNUAL REPORT
TABLE OF CONTENTS
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* We have not included a response to this item in this document since no response is required pursuant to the reduced disclosure format permitted by General Instructions I to Form 10-K.
The following is a list of certain acronyms and terms generally used in the energy industry and throughout this document:
| | |
/d | | per day |
Bbls | | barrels |
Btu | | British thermal unit, an energy measurement |
Mcf | | thousand cubic feet |
MMBtu | | million British thermal unit |
MMcf | | million cubic feet |
Bcf | | billion cubic feet |
NGL | | natural gas liquid, such as propane, butane and natural gasoline |
Tcf | | trillion cubic feet |
LIBOR | | London Interbank Offered Rate |
NYMEX | | New York Mercantile Exchange |
Reservoir | | A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs. |
When we refer to “us”, “we”, “our”, “ours” or “HPL”, we are describing HPL Consolidation LP and/or our subsidiaries.
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PART I
Forward-Looking Statements
Certain matters discussed in this report, excluding historical information, as well as some statements by us in periodic press releases and some oral statements of our officials during presentations about the Partnership, include certain “forward-looking” statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. Statements using words such as “anticipate,” “believe,” “intend,” “project,” “plan,” “expect”, “continue,” “estimate,” “goal,” “forecast,” “may,” “will,” or similar expressions help identify forward-looking statements. Although we and our General Partner believe such forward-looking statements are based on reasonable assumptions and current expectations and projections about future events, neither we or our General Partner can give assurances that such expectations will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. When considering forward-looking statements, please read the section titled “Risk Factors” included under Item 7 of this annual report.
ITEM 1. BUSINESS.
Overview
We are a limited partnership that is primarily engaged in the natural gas transportation and storage business and are a wholly-owned subsidiary of La Grange Acquisition, L.P. (“ETC OLP”). ETC OLP is a wholly-owned subsidiary of Energy Transfer Partners, L.P. (“ETP”), a registrant subject to the information requirements of the Securities Exchange Act of 1934, as amended. Prior to January 26, 2005, we were owned by American Electric Power, Inc. (“AEP”). On January 26, 2005, ETP, through ETC OLP, purchased a 98% controlling interest in us. AEP retained a 2% limited partner interest in us. ETC OLP purchased AEP’s 2% limited partnership interest on November 10, 2005 for $16.6 million in cash, making us a wholly-owned subsidiary of ETP.
We are a fully integrated natural gas gathering, processing, storage, and transportation operation located in the state of Texas. Our assets are comprised of approximately 4,200 miles of intrastate natural gas pipeline with an aggregate capacity of 2.4 Bcf/d and the underground Bammel storage reservoir and related transportation assets. Our pipeline system has access to multiple sources of historically significant natural gas supply reserves from south Texas, the Gulf Coast, east Texas and the western Gulf of Mexico, and is directly connected to major gas distribution, electric and industrial load centers in Houston, Corpus Christi, Texas City and other cities located along the Gulf Coast of Texas. We are well situated to gather gas in many of the major gas producing areas in Texas. Our assets have a particularly strong presence in the key Houston Ship Channel and Katy Hub markets, which significantly contribute to our overall ability to play an important role in the Texas natural gas markets. We also are well positioned to capitalize upon off-system opportunities due to our numerous interconnections with other pipeline systems, our direct access to multiple market hubs at Katy, the Houston Ship Channel and Agua Dulce, and our operation of the Bammel storage facility. The Bammel storage facility has a total working gas capacity of approximately 65 Bcf. The field has a peak withdrawal rate of 1.3 Bcf/d. The field also has considerable flexibility during injection periods in that we have engineered an injection well configuration that provides a 0.6 Bcf/d peak injection rate. The Bammel storage facility is strategically located near the Houston Ship Channel market area and the Katy Hub and is ideally suited to provide a physical backup for on-system and off-system customers.
Midstream Natural Gas Industry Overview
The midstream natural gas industry is the link between the exploration and production of natural gas and the delivery of its components to end-use markets. The midstream industry consists of natural gas gathering, compression, treating, processing and transportation and NGL fractionation and transportation, and is generally characterized by regional competition based on the proximity of gathering systems and processing plants to natural gas producing wells.
Natural gas has a widely varying quality and composition, depending on the field, the formation, or the reservoir from which it is produced. The principal constituents of natural gas are methane and ethane, though most natural gas also contains varying amounts of heavier components, such as propane, butane and natural gasoline that may be removed by a
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number of processing methods. Most raw materials produced at the wellhead are not suitable for long-haul pipeline transportation or commercial use and must be compressed and transported via pipelines to a central processing facility, where it is processed to remove the heavier hydrocarbon components and other contaminants that would interfere with pipeline transportation or the end use of the gas.
Demand for natural gas.Natural gas continues to be a critical component of energy consumption in the United States. According to the Energy Information Administration, or the EIA, total domestic consumption of natural gas is expected to increase by over 2.2% per annum, on average, to 27.1 Tcf by 2010, from an estimated 22.2 Tcf consumed in 2001, representing approximately 25% of all total end-user energy requirements by 2010. During the last five years, the United States has on average consumed approximately 22.6 Tcf per year, with average domestic production of approximately 19.1 Tcf per year during the same period. The industrial and electricity generation sectors currently account for the largest usage of natural gas in the United States.
Natural gas gathering.The natural gas gathering process begins with the drilling of wells into gas bearing rock formations. Once a well has been completed, the well is connected to a gathering system. Gathering systems generally consist of a network of small diameter pipelines and, if necessary, compression systems that collect natural gas from points near producing wells and transport it to larger pipelines for further transportation.
Natural gas compression.Gathering systems are operated at design pressures that will maximize the total throughput from all connected wells. Specifically, lower pressure gathering systems allow wells, which produce at progressively lower field pressures as they age, to remain connected to gathering systems and to continue to produce for longer periods of time. As the pressure of a well declines, it becomes increasingly more difficult to deliver the remaining production in the ground against a higher pressure that exists in the connecting gathering system. Field compression is typically used to lower the pressure of a gathering system. If field compression is not installed, then the remaining production in the ground will not be produced because it cannot overcome the higher gathering system pressure. In contrast, if field compression is installed, then a well can continue delivering production that otherwise would not be produced.
Natural gas treating.Natural gas has a varied composition depending on the field, the formation and the reservoir from which it is produced. Natural gas from certain formations is high in carbon dioxide, hydrogen sulfide or certain other contaminants. Treating plants remove carbon dioxide and hydrogen sulfide from natural gas to ensure that it meets pipeline quality specifications.
Natural gas processing.Some natural gas produced by a well does not meet the pipeline quality specifications established by downstream pipelines or is not suitable for commercial use and must be processed to remove the mixed NGL stream. In addition, some natural gas produced by a well, while not required to be processed, can be processed to take advantage of favorable processing margins. Natural gas processing involves the separation of natural gas into pipeline quality natural gas, or residue gas, and a mixed NGL stream.
Natural gas transportation. Natural gas transportation pipelines receive natural gas from other mainline transportation pipelines and gathering systems and deliver the natural gas to industrial end-users, utilities and other pipelines.
Competition
The business of providing natural gas gathering, transmission, treating, transporting, storing and marketing services is highly competitive. Since pipelines are generally the only practical mode of transportation for natural gas over land, the most significant competitors of our transportation and storage segment are other pipelines. Pipelines typically compete with each other based on location, capacity, price and reliability.
We face competition with respect to retaining and obtaining significant natural gas supplies under terms favorable to us for the gathering, treating and marketing portions of our business. Our competitors include major integrated oil companies, interstate and intrastate pipelines and companies that gather, compress, treat, process, transport and market natural gas. Many of our competitors, such as major oil and gas and pipeline companies, have capital resources and control supplies of natural gas substantially greater than ours.
In marketing natural gas, we have numerous competitors, including marketing affiliates of interstate pipelines, major integrated oil companies, and local and national natural gas gatherers, brokers and marketers of widely various sizes, financial resources and experience. Local utilities and distributors of natural gas are, in some cases, engaged directly, and through affiliates, in marketing activities that compete with our marketing operations.
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Credit Risk and Customers
We have a concentration of customers in natural gas transmission, distribution and marketing as well as industrial end-users and customers in the refining and petrochemical industries. We are diligent in attempting to ensure that we issue credit to credit-worthy customers. However, our purchase and resale of gas exposes us to significant credit risk, as the margin on any sale is generally a very small percentage of the total sale price. Therefore, a credit loss can be very large relative to our overall profitability.
During the period from January 26, 2005 to August 31, 2005, we had two customers, Exxon Mobil and Centerpoint Energy, that individually accounted for more than 10% of revenues. The loss of these customers, individually or in the aggregate, could have a material impact on our results of operations.
Regulation
Regulation by FERC of Interstate Natural Gas Pipelines.Under the Natural Gas Act (“NGA��), the Federal Energy Regulatory Commission (“FERC”) generally regulates the transportation of natural gas in interstate commerce. For FERC regulatory purposes, “transportation” service includes storage service. We do not own any interstate natural gas transportation facilities, so FERC does not directly regulate any of our pipeline operations pursuant to its jurisdiction under the NGA. However, FERC’s regulation influences certain aspects of our business and the market for our products. In general, FERC has authority over natural gas companies that provide natural gas pipeline transportation services in interstate commerce and its authority to regulate those services includes:
| | • | | the certification and construction of new facilities; |
| | • | | the extension or abandonment of services and facilities; |
| | • | | the maintenance of accounts and records; |
| | • | | the acquisition and disposition of facilities; |
| | • | | the initiation and discontinuation of services; and |
Failure to comply with the NGA can result in the imposition of administrative, civil and criminal remedies.
In recent years, FERC has pursued pro-competitive policies in its regulation of interstate natural gas pipelines. However, we cannot assure you that FERC will continue this approach as it considers matters such as pipelines’ rates and rules and policies that may affect rights of access to natural gas transportation capacity.
Intrastate Pipeline Regulation.Our intrastate natural gas pipeline operations generally are not subject to rate regulation by FERC, but they are subject to regulation by various agencies in Texas, principally the Texas Railroad Commission (“TRRC”), where they are located. However, to the extent that our intrastate pipeline systems transport natural gas in interstate commerce, the rates, terms and conditions of such transportation service are subject to FERC jurisdiction under Section 311 of the Natural Gas Policy Act (“NGPA”), which regulates, among other things, the provision of transportation services by an intrastate natural gas pipeline on behalf of a local distribution company or an interstate natural gas pipeline. Under Section 311, rates charged for transportation must be fair and equitable, and amounts collected in excess of fair and equitable rates are subject to refund with interest, and the terms and conditions of service set forth in the pipeline’s statement of operating conditions are subject to FERC review and approval. Failure to observe the service limitations applicable to transportation and storage services under Section 311, failure to comply with the rates approved by FERC for Section 311 service, and failure to comply with the terms and conditions of service established in the pipeline’s FERC approved Statement of Operating Conditions could result in an alteration of jurisdictional status, and/or the imposition of administrative, civil and criminal remedies.
Our intrastate pipeline and storage operations in Texas are subject to the Texas Utilities Code, as implemented by the TRRC. Generally, the TRRC is vested with authority to ensure that rates, operations and services of gas utilities, including intrastate pipelines, are just and reasonable and not discriminatory. The rates we charge for transportation services are deemed just and reasonable under Texas law unless challenged in a complaint. We cannot predict whether such a complaint will be filed against us or whether the TRRC will change its regulation of these rates. Failure to comply with the Texas Utilities Code can result in the imposition of administrative, civil and criminal remedies.
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Gathering Pipeline Regulation.Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of FERC under the NGA. We believe our natural gas pipelines in Texas meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to FERC jurisdiction. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of substantial, on-going litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC and the courts. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and in some instances complaint-based rate regulation. In Texas, our gathering facilities are subject to regulation by the TRRC under the Texas Utilities Code in the same manner as described above for our intrastate pipeline facilities.
We are subject to state ratable take and common purchaser statutes in all of the states in which we operate. The ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. These statutes have the effect of restricting our right as an owner of gathering facilities to decide with whom it contracts to purchase or transport natural gas.
Natural gas gathering may receive greater regulatory scrutiny at both the state and Federal levels now that FERC has taken a more light-handed approach to regulation of the gathering activities of interstate pipeline transmission companies and a number of such companies have transferred gathering facilities to unregulated affiliates. For example, the TRRC has approved changes to its regulations governing transportation and gathering services performed by intrastate pipelines and gatherers, which prohibit such entities from unduly discriminating in favor of their affiliates. Many of the producing states have adopted some form of complaint-based regulation that generally allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering access and rate discrimination. Our gathering operations could be adversely affected should they be subject in the future to the application of state or federal regulation of rates and services. Our gathering operations also may be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.
Sales of Natural Gas.Sales for resale of natural gas in interstate commerce made by intrastate pipelines or their affiliates are subject to FERC regulation unless the gas is produced by the pipeline or affiliate. Under current federal rules, however, the price at which we sell natural gas currently is not regulated, insofar as the interstate market is concerned and, for the most part, is not subject to state regulation. Effective as of January 12, 2004, the FERC’s rules require pipelines (including intrastate pipelines) and their affiliates who sell gas in interstate commerce subject to FERC’s jurisdiction to adhere to a code of conduct prohibiting market manipulation and transactions that have no legitimate business purpose or result in prices not reflective of legitimate forces of supply and demand. Those who violate such code of conduct may be subject to suspension or loss of authorization to perform such sales, disgorgement of unjust profits, or other appropriate non-monetary remedies imposed by FERC. FERC denied rehearing of these rules on May 19, 2004, but the rules are still subject to possible court appeals. We cannot predict the outcome of these further proceedings, but do not believe we will be affected materially differently from other intrastate gas pipelines and their affiliates. In addition, our sales of natural gas are affected by the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation are subject to extensive federal and state regulation. FERC is continually proposing and implementing new rules and regulations affecting those segments of the natural gas industry, most notably interstate natural gas transmission companies that remain subject to FERC’s jurisdiction. These initiatives also may affect the intrastate transportation of natural gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry and these initiatives generally reflect more light-handed regulation. We cannot predict the ultimate impact of these regulatory changes to our natural gas marketing operations, and we note that some of FERC’s more recent proposals may adversely affect the availability and reliability of interruptible transportation service on interstate pipelines. We do not believe that it will be affected by any such FERC action materially differently than other natural gas marketers with whom it competes.
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Pipeline Safety.The states in which we conduct operations administer federal pipeline safety standards under the Natural Gas Pipeline Safety Act of 1968, as amended, (the “NGPSA”), which requires certain pipelines to comply with safety standards in constructing and operating the pipelines and subjects the pipelines to regular inspections. Failure to comply with the NGPSA may result in the imposition of administrative, civil and criminal remedies. The “rural gathering exemption” under the presently exempts substantial portions of our gathering facilities from jurisdiction under that statute. The portions of our facilities that are exempt include those portions located outside of cities, towns or any area designated as residential or commercial, such as a subdivision or shopping center. The “rural gathering exemption,” however, may be restricted in the future, and it does not apply to our intrastate natural gas pipelines.
Government Regulation and Environmental Matters
The operation of pipelines, plants and other facilities for gathering, compressing, treating, processing, or transporting natural gas, natural gas liquids and other products is subject to stringent and complex federal, state, and local laws and regulations governing the discharge of materials into the environment or otherwise relating to the protection of the environment. These laws and regulations can impair our business activities that affect the environment in many ways, such as:
| | • | | restricting the way we can release materials or waste products into the air, water, or soils; |
| | • | | limiting or prohibiting construction activities in sensitive areas such as wetlands or areas of endangered species habitat, or otherwise constraining how or when construction is conducted; |
| | • | | requiring remedial action to mitigate pollution from former operations, or requiring plans and activities to prevent pollution from ongoing operations; and |
| | • | | imposing substantial liabilities on us for pollution resulting from our operations, including, for example, potentially enjoining the operations of facilities if it were determined that they were not in compliance with permit terms. |
Costs of planning, designing, constructing and operating pipelines, plants and other facilities must incorporate compliance with environmental laws and regulations and safety standards. We have implemented environmental programs and policies designed to avoid potential liability and cost under applicable environmental laws and regulations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, the issuance of injunctions and the filing of federally authorized citizen suits.
The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus, any changes in environmental laws and regulations that result in more stringent and costly waste handling, storage, transport, disposal, or remediation requirements could have a material adverse effect on our operations and financial position. Moreover, risks of process upsets, accidental releases or spills are associated with our operations, and we cannot assure you that we will not incur significant costs and liabilities as a result of such upsets, releases, or spills, including those relating to claims for damage to property and persons. In the event of future increases in costs, we may be unable to pass on those increases to our customers. While we believe that we are in substantial compliance with existing environmental laws and regulations and that continued compliance with current requirements would not have a material adverse effect on us, there is no assurance that this trend will continue in the future.
The Comprehensive Environmental Response, Compensation and Liability Act, as amended, also known as “CERCLA” or “Superfund,” and comparable state laws impose liability without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a hazardous substance into the environment, including those arising out of historical operations conducted by predecessors. Under CERCLA, these “responsible persons” may be subject to joint and several, strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances into the environment. Although “petroleum” is excluded from the definition of hazardous substance under CERCLA, we will generate materials in the course of our operations that may be regulated as hazardous substances. We also may incur liability under the Resource Conservation and Recovery Act, also known as “RCRA,” which imposes requirements related to the management and disposal of solid and hazardous wastes. While there exists an exclusion from the definition of hazardous wastes for “drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil, natural gas or geothermal
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energy,” in the course of our operations, we may generate unrecovered petroleum product wastes as well as ordinary industrial wastes such as paint wastes, waste solvents, and waste compressor oils that may be regulated as hazardous or solid wastes.
We currently own or lease, and have in the past owned or leased, numerous properties that for many years have been used for the measurement, gathering, field compression and processing of natural gas and NGLs. Although we used operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons or wastes may have been disposed of or released on or under the properties owned or leased by us, or on or under other locations where such wastes have been taken for disposal. In addition, some of these properties have been operated by third parties whose treatment and disposal or release of petroleum hydrocarbons and wastes was not under our control. These properties and the materials disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove or remediate previously disposed wastes or property contamination, or to perform remedial activities to prevent future contamination. In addition, we are currently involved in several remediation projects that have cleanup costs and related liabilities. As of August 31, 2005 an accrual of $0.9 million was recorded in our consolidated balance sheet to cover estimated environmental liabilities.
The Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act, and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into state and federal waters. The discharge of pollutants into regulated waters is prohibited, except in accord with the terms of a permit issued by EPA or the state. Any unpermitted release of pollutants, including NGLs or condensates, from our systems or facilities could result in fines or penalties, as well as significant remedial obligations. We believe that we are in substantial compliance with the Clean Water Act. We currently expect to incur costs of approximately $0.1 million over the next year to upgrade or modify certain facilities as required under our spill prevention, control and countermeasures, or “SPCC,” plans.
The Clean Air Act, as amended, and comparable state laws restrict the emission of air pollutants from many sources, including processing plants and compressor stations. These laws and any implementing regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions, impose stringent air permit requirements, or utilize specific equipment or technologies to control emissions. Failure to comply with these laws and regulations could expose us to civil and criminal enforcement actions.
Our operations are subject to regulation by the U.S. Department of Transportation or “DOT” under the Hazardous Liquid Pipeline Safety Act, or “HLPSA,” pursuant to which the DOT has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. HLPSA requires any entity which owns or operates pipeline facilities to permit access to and allow copying of records and to make certain reports and provide information as required by DOT. While we believe that our pipeline operations are in substantial compliance with applicable HLPSA requirements, there can be no assurance that future compliance with the HLPSA will not have a material adverse effect on our operations or financial position. Moreover, the DOT, through the Office of Pipeline Safety, has promulgated rules requiring pipeline operators to develop integrity management programs for gas transmission pipelines that, in the event of a failure, could impact “high consequence areas,” including areas with specified population densities. Activities under these integrity management programs involve the performance of internal pipeline inspections, pressure testing, or other effective means to assess the integrity of these regulated pipeline segments, and the regulations require prompt action to address integrity issues raised by the assessment and analysis. We estimate that the cost of implementing these integrity management plans is $7 million to $9 million per year, over the fiscal years 2006 to 2008.
We are subject to the requirements of the federal Occupational Safety and Health Act, also known as OSHA, and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA’s hazard communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in substantial compliance with the OSHA requirements, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances.
As of October 31, 2005, 551 people provided services to conduct our operations, all of which were employees of our parent, ETC OLP or its parent, ETP.
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ITEM 2. PROPERTIES.
Substantially all of our pipelines, which are located in Texas, are constructed on rights-of-way granted by the apparent record owners of the property. Lands over which pipeline rights-of-way have been obtained may be subject to prior liens that have not been subordinated to the right-of-way grants. We have obtained, where necessary, easement agreements from public authorities and railroad companies to cross over or under, or to lay facilities in or along, watercourses, county roads, municipal streets, railroad properties and state highways, as applicable. In some cases, properties on which our pipelines were built were purchased in fee.
Some of the leases, easements, rights-of-way, permits, licenses and franchise ordinances that will be transferred to us will require the consent of the current landowner to transfer these rights, which in some instances is a governmental entity. We believe that we have obtained or will obtain sufficient third-party consents, permits and authorizations for the transfer of the assets necessary for us to operate our business in all material respects. With respect to any consents, permits or authorizations that have not been obtained, we believe that these consents, permits or authorizations will be obtained, or that the failure to obtain these consents, permits or authorizations will have no material adverse effect on the operation of our business.
We also lease office facilities in Houston, Texas. While we may require additional office space as our business expands, we believe that our existing facilities are adequate to meet our needs for the immediate future, and that additional facilities will be available on commercially reasonable terms as needed.
We believe that we have satisfactory title to or valid rights to use all of our material properties. Although some of our properties are subject to liabilities and leases, liens for taxes not yet due and payable, encumbrances securing payment obligations under non-competition agreements and immaterial encumbrances, easements and restrictions, we do not believe that any such burdens will materially interfere with our continued use of such properties in our business, taken as a whole. In addition, we believe that we have, or are in the process of obtaining, all required material approvals, authorizations, orders, licenses, permits, franchises and consents of, and have obtained or made all required material registrations, qualifications and filings with, the various state and local government and regulatory authorities which relate to ownership of our properties or the operations of our business.
ITEM 3. LEGAL PROCEEDINGS.
A description of our legal proceedings is included in Note 9 to the financial statements as of and for the period ended August 31, 2005, and in Note 3 to the financial statements as of December 31, 2004 and 2003 and for the period ended January 25, 2005 and for the three year period ended December 31, 2004, incorporated herein by reference
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
Item 4, Submission of Matters to a Vote of Security Holders, has been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.
PART II
ITEM 5. MARKET FOR THE REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND
ISSUER PURCHASES OF EQUITY SECURITIES.
The Partnership is a wholly-owned subsidiary of ETP. Accordingly, there is no established public trading market for the Partnership’s partnership interests, and no dividends have been, or are currently intended to be, declared on the Partnership’s partnership interests.
ITEM 6. SELECTED FINANCIAL DATA
Item 6, Selected Financial Data, has been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.
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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS.
The information required by this Item is presented in a reduced disclosure format pursuant to General Instructions I to Form 10-K. The notes to our consolidated financial statements contain information that is pertinent to the following analysis, including a discussion of our significant accounting policies.
Overview
The following is a discussion of our results of operations, and should be read in conjunction with our historical consolidated financial statements and accompanying notes thereto included elsewhere in this Form 10-K.
Our assets are comprised of approximately 4,200 miles of intrastate natural gas pipeline, the 65 Bcf of working gas underground Bammel storage reservoir and related transportation assets. We have access to multiple sources of historically significant natural gas supply reserves from south Texas, the Gulf Coast, east Texas and the western Gulf of Mexico and are directly connected to major gas distribution, electric and industrial load centers in Houston, Corpus Christi, Texas City, Baytown, Beaumont and Port Arthur. Our assets consist of six main transportation pipelines and three market area loops. We have direct access to multiple market hubs at Katy, the Houston Ship Channel, and Agua Dulce through these pipelines and through our operations of the Bammel storage facility.
In January 2005, ETC OLP acquired the controlling interests in us from AEP for approximately $825.0 million subject to working capital adjustments. The acquisition was financed by ETP, ETC OLP’s parent company, through a combination of borrowings under its credit facilities and a private placement of $350.0 million of ETP’s common units with institutional investors. In addition, ETC OLP acquired the working inventory of natural gas stored in the Bammel storage facility and financed it through a short-term borrowing from an affiliate. The total purchase price of $1,350.2 million which included $1,039.5 million of cash paid, net of cash acquired and liabilities assumed of $329.5 million, including $0.8 million in estimated acquisition costs, was allocated to the assets acquired and liabilities assumed. Under the terms of the transaction, ETC OLP acquired all but a 2% limited partner interest in HPL. On November 10, 2005 ETC OLP purchased the 2% limited partner interest in us that it did not already own, from AEP, for $16.6 million in cash. As a result, we became a wholly owned subsidiary of ETC OLP. ETC OLP also reached a settlement agreement with AEP related to inventory and working capital matters associated with the acquisition. The terms of the settlement agreement were not material in relation to our financial position, results of operations or cash flows.
The transaction was accounted for as a business combination using the purchase method of accounting in accordance with the provisions of Statement of Financial Accounting Standards No. 141, “Business Combinations” (SFAS 141), which requires the purchase price to be allocated based on the estimated fair value of the individual assets acquired and the liabilities assumed at the date of the respective acquisition. The purchase price has been assigned primarily to depreciable fixed assets or amortizable intangible assets as opposed to goodwill. We have engaged an appraisal firm to perform the asset appraisal in order to develop a definitive allocation of the purchase price. As a result, the final purchase price allocation may differ from the preliminary allocation. To the extent that the final allocation will result in goodwill, this amount would not be subject to amortization, but would be subject to an annual impairment test and if necessary, written down to a lower fair value should circumstances warrant.
As noted above, the purchase method of accounting was used to record assets acquired and liabilities assumed. Such accounting generally results in increased depreciation and amortization reported in future periods. Accordingly, the accompanying financial statements for the period subsequent to the acquisition and for the periods prior to the acquisition incorporated herein by reference are not comparable in all material respects since the financial statements for the period from January 26, 2005 to August 31, 2005 reflect a new basis of accounting.
We generate our revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users, and other marketing companies. Generally, we purchase our natural gas from either the market, including purchases from affiliates at market rates, and from producers at the wellhead. To the extent the natural gas comes from producers, it is purchased at a discount to a specified price and resold to customers at the index price.
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We engage in natural gas storage transactions in which we seek to find and profit from pricing differences that occur over time utilizing the Bammel storage reservoir. The Bammel storage reservoir is one of the largest storage facilities in North America with a total working gas capacity of approximately 65 Bcf. The reservoir has a peak withdrawal rate of 1.3 Bcf/d and also has considerable flexibility during injection periods due to an injection well configuration that provides for a 0.6 Bcf/d peak injection rate. Therefore, we purchase physical natural gas and then sell financial contracts at a price sufficient to cover our carrying costs and provide for a gross profit margin. See further discussion regarding our risk management policies in Item 7a. “Quantitative and Qualitative Disclosures about Market Risk” found elsewhere in this report. Since ETC OLP’s acquisition of us, we have continually managed our positions to enhance the future profitability of our storage position. We may, from time to time, change our scheduled injection and withdrawal plans based on market conditions and adjust the level of working natural gas stored in the Bammel reservoir. We expect our margins to be higher during the periods from November to March of each year and lower during the period from April through October of each year due to the increased demand for natural gas during colder weather. As of August 31, 2005, we had approximately 28 Bcf of working natural gas stored in the Bammel storage facility. We intend to continue to purchase and store natural gas in our first quarter of 2006 in order to meet anticipated demand during the periods from November to March. However, we can not assure that management’s expectations will be fully realized in the future and in what time period, due to various factors including weather, availability of natural gas in regions in which we operate, competitive factors in the energy industry, and other issues.
Results from our operations are also determined primarily by the amount of capacity our customers reserve as well as the actual volume of natural gas that flows through our transportation pipelines. Under transportation contracts, we charge our customers (1) a demand fee, which is a fixed fee for the reservation of an agreed amount of capacity on the transportation pipeline for a specified period of time and which obligates the customer to pay us even if the customer does not transport natural gas on the respective pipeline, (2) a transportation fee, which is based on the actual throughput of natural gas by the customer, or (3) a fuel retention based on a percentage of gas transported on the pipeline, or a combination of the three, generally payable monthly. We also generate revenue from fees charged for storing customers’ working natural gas in our storage facilities
None of our operations suffered any material damage or interruption from either Hurricane Katrina or Hurricane Rita, which landed in Louisiana and Texas, respectively, during September 2005.
Trends and Outlook
We expect our business to continue to be affected by the following key trends. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our actual results may vary materially from our expected results.
We believe that current natural gas prices will continue to cause relatively high levels of natural gas-related drilling in the United States as producers seek to increase their level of natural gas production. Although the number of natural gas wells drilled in the United States has increased overall in recent years, a corresponding increase in average annual production has not been realized, primarily as a result of smaller average discoveries and the decline in production from existing wells. We believe that an increase in United States drilling activity and imports of natural gas and liquefied natural gas will be required for the natural gas industry to meet the expected increased demand for, and to compensate for the declining production of, natural gas in the United States. A number of the areas in which we operate are experiencing significant drilling activity as a result of recent high natural gas prices, new increased drilling for deeper natural gas formations and the implementation of new exploration and production techniques.
While we anticipate continued high levels of exploration and production activities in a number of the areas in which we operate, fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new natural gas reserves. Drilling activity generally decreases as natural gas prices decrease. We have no control over the level of drilling activity in the areas of our operations.
The midstream natural gas industry is cyclical, with the operating results of companies in the industry significantly affected by the prevailing price of NGLs, which in turn has been generally correlated to the price of crude oil. Although the prevailing price of natural gas has less short term significance to our operating results than the price of NGLs, in the long term, the growth and sustainability of our business depends on natural gas prices being at levels sufficient to provide incentives and capital for producers to increase natural gas exploration and production. In the past, the prices of NGLs, crude oil and natural gas have been extremely volatile.
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Based on historical trends, we generally expect NGL prices to follow changes in crude oil prices over the long term, which we believe will in large part be determined by the level of production from major crude oil exporting countries and the demand generated by growth in the world economy. We believe that future natural gas prices will be influenced by supply deliverability, the severity of winter and summer weather and the level of worldwide economic growth. The average number of active oil and gas rigs drilling in the United States were 223 and 1,219, respectively at August 31, 2005, compared to 166 and 1,082, respectively, at August 31, 2004 as reported by Baker Hughes Incorporated. The increase in natural gas rigs is primarily attributable to recent significant increases in natural gas prices, which could result in continued sustained drilling activity for the remainder of 2005.
Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the periods presented. It may in the future, however, increase the cost to acquire or replace property, plant and equipment and may increase the costs of labor and supplies. To the extent permitted by competition, regulation and our existing agreements, we have and will continue to pass along increased costs to our customers in the form of higher fees.
Other Recent Transactions
On November 10, 2005 ETC OLP purchased the remaining 2% limited partner interest in us from AEP for $16.6 million in cash. As a result ETC OLP now owns 100% of our general and limited partner interests.
Results of Operations
Below are our results of operations for the years ended December 31, 2004 and 2003, respectively. Such results were under the direction and management of AEP. Results of operations for the period from January 26, 2005 to August 31, 2005 are under the direction and management of ETP. A discussion of the results for the period ended August 31, 2005 compared to the results for the comparable preceding period would not be meaningful for the following reasons:
| | • | | Prior to the acquisition by ETP, we were owned by AEP, a utility company. During the fourth quarter of 2003, AEP recorded an impairment charge of $300 million pre-tax reflecting management’s decision not to operate as a major trading hub. Furthermore, we entered into a long-term asset management agreement with AEP for the exclusive rights to manage injections of natural gas into, and withdrawals of natural gas from, the natural gas storage facility, and to make use of natural gas injection, withdrawal and storage capacity not otherwise contractually committed by us that may not be available from the storage facility. In exchange for these rights, AEP agreed to pay us a fixed, annual fee of $25 million. In addition, AEP agreed to pay us a market-based rate for storage services on the available space that was not contractually committed to third parties. For the years ended December 31, 2004 and 2003, we had revenues of $28.5 million and $29.8 million attributable to this agreement. The agreement was terminated in December 2004. |
| | • | | Prior to the termination of the asset management agreement, AEP maintained title of working natural gas inventory. As a result any storage-related activity (natural gas sales, purchases, derivative and trading activity, etc.) was accounted for separately from our operating results. Subsequent to the termination of the asset management agreement in December 2004, the working natural gas inventory was transferred to us. |
| | • | | As a result of the acquisition of the controlling interests in us by ETP, the operations are viewed by the new management substantially different than that under previous management. The working natural gas is owned and operated by us, and the results thereof are included in the statement of operations from the acquisition date. In addition, any derivative activity associated with the working natural gas is also included in the statement of operations from the acquisition date. |
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Fiscal Year Ended December 31, 2004 Compared to Fiscal Year Ended December 31, 2003
| | | | | | | | |
| | | Year Ended
| |
| | | (in thousands) | |
| | | December 31,
2004
| | | December 31,
2003
| |
Revenues | | $ | 3,931,437 | | | $ | 3,905,677 | |
Cost of sales | | | 3,764,295 | | | | 3,805,119 | |
| | |
|
|
| |
|
|
|
Gross margin | | | 167,142 | | | | 100,558 | |
| | |
Operating expenses | | | 72,235 | | | | 65,346 | |
Administrative and general | | | 22,741 | | | | 20,246 | |
Depreciation and amortization | | | 10,655 | | | | 15,149 | |
| | |
|
|
| |
|
|
|
Asset impairment | | | — | | | | 300,000 | |
| | |
|
|
| |
|
|
|
Operating income (loss) | | | 61,511 | | | | (300,183 | ) |
| | |
Equity in losses of affiliates | | | (683 | ) | | | (668 | ) |
Other, net | | | 5,892 | | | | 2,685 | |
Income tax expense (benefit) | | | 22,694 | | | | (81,595 | ) |
| | |
|
|
| |
|
|
|
Net income (loss) | | $ | 44,026 | | | $ | (216,571 | ) |
| | |
|
|
| |
|
|
|
Gross margin. Gross margin increased $66.6 million from $100.6 million for the year ended December 31, 2003 to $167.1 million for the year ended December 31, 2004. The increase was principally due to an increase in the average natural gas sales price in 2004 compared to the same average in 2003 offset by a reduction in sales volumes in 2004 compared to 2003. Our average natural gas sales price was $5.77 for the year ended December 31, 2004 compared to $5.22 for the year ended December 31, 2003, a difference of $0.55 or 11%. The average natural gas sales volumes decreased 8.8% or 180,124 MMBtu/d from 2,038,380 MMBtu/d in 2003 compared to 1,858,256 MMBtu/d in 2004. Our gas costs also decreased from $3,805.1 million for the year ended December 31, 2003 to $3,764.3 million for the year ended December 31, 2004.
Operating expenses. Operating expenses were $65.3 million for the year ended December 31, 2003 compared to $72.2 million for the year ended December 31, 2004, an increase of $6.9 million or 11%. The increase was attributable to a $3.2 million production tax credit refund received in 2003, an increase of $1.1 million in property taxes, $5.4 million increase in maintenance expenses, $0.8 million in other operating expenses, net, offset by a decrease of $3.6 million in fuel compressor costs.
Administrative and general. Administrative and general expenses were $22.7 million and $20.2 million for the years ended December 31, 2004 and 2003, respectively. The increase of $2.5 million was principally due to increased salaries and wages and related benefits.
Depreciation and amortization. Depreciation and amortization expense decreased $4.5 million from $15.1 million for the year ended December 31, 2004 to $10.7 million for the year ended December 31, 2003 principally due to the $300.0 million asset impairment charge recorded during the fourth quarter of the year ended December 31, 2003 resulting in a lower depreciable asset base in 2004.
Asset impairment. During the fourth quarter of 2003, based on a probability-weighted after-tax cash flow analysis of our fair value, we recorded an impairment of $300.0 million pre-tax ($218 million after-tax), with $150 million pre-tax related to the entire balance of goodwill, reflecting management’s decision not to operate as a major trading hub. The cash flow analysis, among other things, used management’s estimate of the alternative likely outcomes of the uncertainties surrounding the continued use of the Bammel facility and other matters.
Other, net. Other, net, of $5.9 million for the year ended December 31, 2004 principally consists of $2.3 million of affiliated interest income, $3.5 million of non-operating gains net of $0.2 of affiliated interest expense. Other, net, of $2.7 million for the year ended December 31, 2003 principally consists of $2.5 million of affiliated interest income, $0.2 million of non-operating gains net of $0.1 million of non-affiliated interest expense. The $3.3 million increase in non-operating gains principally consisted of a $2.4 million gain on a disputed claim recorded in December 2004 and $0.9 million in miscellaneous reimbursements and refunds received in 2004.
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Income tax expense (benefit). The effective income tax rate of 34.0% for the year ended December 31, 2004 differed from the effective tax rate of 27.4% for the year ended December 31, 2003 principally due to the non-deductible portion of goodwill write-off associated with the asset impairment charge noted above.
Net income. The change from a net loss of $216.6 million for the year ended December 31, 2003 to net income of $44.0 million for the year ended December 31, 2004 was principally due to the $300.0 million pre-tax asset impairment charge noted above.
Liquidity
For our primary sources of liquidity, we rely on cash generated from our internal operations and advances from our parent company. As of December 31, 2004, we participated in AEP’s cash management program referred to a money pool. Under AEP’s money pool program, depending on whether we had short-term cash surpluses or requirements, we either provided cash to AEP or AEP provided cash to us. We reflect these advances as financing activities in our statement of cash flows. At December 31, 2004, we had advances from affiliates of $210.0 million.
Subsequent to our acquisition by ETP, our primary sources of liquidity are cash generated from our internal operations and advances from our parent company. We engage in natural gas storage storage transactions in which we seek to find and profit from pricing differences that occur over time. Natural gas is typically purchased and held in storage during the summer months and sold during the winter months. Although we intend to fund natural gas purchases with cash generated from operations from time to time, we may require cash advances from our parent company to fund the purchase of natural gas to be held in storage. We intend to repay these advances with cash generated from operations when the gas is sold.
Critical Accounting Policies and Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to establish accounting policies and make estimates and assumptions that affect reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting rules have developed. Accounting rules generally do not involve a selection among alternatives, but involve an implementation and interpretation of existing rules, and the use of judgment applied to the specific set of circumstances existing in our business. We make every effort to properly comply with all applicable rules on or before their adoption, and we believe the proper implementation and consistent application of the accounting rules are critical. Our critical accounting policies are discussed below. For further details on our accounting policies and a discussion of new accounting pronouncements, see Note 3 —“Summary of Significant Accounting Policies and Balance Sheet Detail” to the Consolidated Financial Statements beginning on page F-1 of this report. We believe the following are critical accounting policies:
Revenue Recognition.
Revenues are recognized from domestic gas pipeline and storage services when gas is delivered to contractual meter points or when services are provided, with the exception of certain physical forward gas purchase and sale contracts that are derivatives and that are accounted for using fair value accounting. We also engage in wholesale natural gas marketing and risk management activities. These activities were focused on wholesale markets where we own assets. Our activities include the purchase and sale of gas under forward contracts at fixed and variable prices and the buying and selling of financial gas contracts, which include exchange traded futures and options, and over-the-counter options and swaps.
Impairment of Long-Lived Assets and Goodwill. Long-lived assets are required to be tested for recoverability whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recoverable. Goodwill must be tested for impairment annually or more frequently if events or changes in circumstances indicate that the related asset might be impaired. An impairment loss should be recognized only if the carrying amount of the asset/goodwill is not recoverable and exceeds its fair value.
In order to test for recoverability, we must make estimates of projected cash flows related to the asset which include, but are not limited to, assumptions about the use or disposition of the asset, estimated remaining life of the asset,
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and future expenditures necessary to maintain the asset’s existing service potential. In order to determine fair value, we make certain estimates and assumptions, including, among other things, changes in general economic conditions in regions in which our markets are located, the availability and prices of natural gas and propane supply, our ability to negotiate favorable sales agreements, the risks that natural gas exploration and production activities will not occur or be successful, our dependence on certain significant customers and producers of natural gas, and competition from other midstream companies, including major energy producers. Due to the subjectivity of the assumptions used to test for recoverability and to determine fair value, significant impairment charges could result in the future, thus affecting our future reported net income.
Property, Plant, and Equipment. Maintenance capital expenditures are capital expenditures made to replace partially or fully depreciated assets in order to maintain the existing operating capacity of our assets and to extend their useful lives. Maintenance capital expenditures also include capital expenditures made to connect additional wells to our systems in order to maintain or increase throughput on our existing assets. Growth or expansion capital expenditures are capital expenditures made to expand the existing operating capacity of our assets, whether through construction or acquisition. We treat repair and maintenance expenditures that do not extend the useful life of existing assets as operating expenses as we incur them. Upon disposition or retirement of pipeline components or gas plant components, any gain or loss is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in operations. Depreciation of property, plant and equipment is provided using the straight-line method based on their estimated useful lives ranging from 5 to 65 years. Changes in the estimated useful lives of the assets could have a material effect on our results of operation. We do not anticipate future changes in the estimated useful lives of our property, plant, and equipment.
Fair Value of Derivative Commodity Contracts. Through ETC OLP’s marketing activities, we utilize various exchange-traded and over-the-counter commodity financial instrument contracts to limit our exposure to margin fluctuations in natural gas, NGL and propane prices and in our trading activities. These contracts consist primarily of commodity forwards, futures, swaps, options and certain basis contracts as cash flow hedging instruments. Certain contracts, which, in accordance with SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities”, are not accounted for as hedges, but are marked to fair value on the income statement. On our contracts that are designated as cash flow hedging instruments in accordance with SFAS No. 133, the effective portion of the hedged gain or loss is initially reported as a component of other comprehensive income and is subsequently reclassified into earnings when the physical transaction settles. The ineffective portion of the gain or loss is reported in earnings immediately. We utilize published settlement prices for exchange-traded contracts, quotes provided by brokers, and estimates of market prices based on daily contract activity to estimate the fair value of these contracts. We also use the Black Scholes valuation model to estimate the value of certain embedded derivatives. Changes in the methods used to determine the fair value of these contracts could have a material effect on our results of operations. We do not anticipate future changes in the methods used to determine the fair value of these derivative contracts.
Natural Gas Exchanges.We record exchange receivables and payables when a customer delivers more or less gas into our pipelines than they take out. We primarily estimate the value of our exchanges at prices representing the value of the commodity at the end of the accounting reporting period. Changes in natural gas prices may impact our valuation.
Volume Measurement. We record amounts for natural gas gathering and transportation revenue, liquid transportation and handling revenue, natural gas sales and natural gas purchases, and the sale of production based on volumetric calculations. Variances resulting from such calculations are inherent in our business.
Asset Retirement Obligation. An entity is required to recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. If a reasonable estimate cannot be made in the period the asset retirement obligation is incurred, the liability should be recognized when a reasonable estimate of fair value can be made.
In order to determine fair value, management must make certain estimates and assumptions including, among other things, projected cash flows, a credit-adjusted risk-free rate, and an assessment of market conditions that could significantly impact the estimated fair value of the asset retirement obligation. These estimates and assumptions are very subjective. We have determined that we are obligated by contractual or regulatory requirements to remove assets or perform other remediation upon retirement of certain assets. However, the fair value of the asset retirement obligation cannot currently be reasonably estimated because the settlement dates are indeterminate. We will record an asset retirement obligation in the periods in which it can reasonably determine the settlement dates.
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ITEM 7a. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
Market risk includes the risk of loss arising from adverse changes in market rates and prices. We face market risk from commodity variations, risks related to interest rate variations, and to a lesser extent, credit risks. From time to time, we may utilize derivative financial instruments as described below to manage our exposure to such risks.
We utilize the formal risk management policies established by ETC OLP and ETP in which derivative financial instruments are employed in connection with an underlying asset, liability and/or anticipated transaction. At inception of a hedge, we formally document the relationship between the hedging instrument and the hedged item, the risk management objectives, and the methods used for assessing and testing effectiveness. We also assess, both at the inception of the hedge and on a quarterly basis, whether the derivatives that are used in our hedging transactions are highly effective in offsetting changes in cash flows. Furthermore, management meets on a weekly basis to assess the creditworthiness of the derivative counterparties to manage against the risk of default. If we determine that a derivative is no longer highly effective as a hedge, we discontinue hedge accounting prospectively by including changes in the fair value of the derivative in current earnings.
The derivative activities associated with our operations are maintained by ETC OLP. ETC OLP enters into the hedging instrument with the counterparty and enters into an offsetting position with the Partnership to properly reflect those transactions on our books and records. The offsetting positions are reflected as Receivables from and Payables to Affiliated Companies equal to the fair value of the associated price risk management assets and liabilities in the Consolidated Balance Sheet as of August 31, 2005 until the hedged item is settled. The fair value of price risk management assets and liabilities entered into by ETC OLP that are designated and documented as cash flow hedges and determined to be effective are recorded through Other Comprehensive Income (Loss). For those instruments that do not qualify for hedge accounting, the change in market value is recorded as cost of products sold in the Consolidated Income Statement. The effective portion of the hedge gain or loss is initially reported as a component of Other Comprehensive Income and when the physical transaction settles, any gain or loss previously recorded in Other Comprehensive Income (Loss) on the derivative is recognized in earnings in the Consolidated Income Statement. The ineffective portion of the gain or loss is reported immediately in cost of products sold in the Consolidated Income Statement.
In the course of normal operations, we routinely enter into contracts such as forward physical contracts for the purchase and sale of natural gas, propane, and other NGLs that qualify for and are designated as a normal purchase and sales contracts. Such contracts are exempted from the fair value accounting requirements of SFAS 133 and are accounted for using traditional accrual accounting. Certain physical forward contracts contain embedded options and have not been designated as normal purchases and sales contracts. Therefore they are marked to market in addition to the financial options that offset them. The Black Scholes valuation model was used to estimate the value of these embedded derivatives.
The market prices used to value the financial derivative transactions reflect management’s estimates considering various factors including closing exchange and over-the-counter quotations, and the time value of the underlying commitments.
We also attempt to maintain balanced positions to protect us from the volatility in the energy commodities markets. To the extent open commodity positions exist, fluctuating commodity prices can impact our financial results either favorably or unfavorably.
A description of our derivative activities is included in Notes 3 and 10 to the financial statements as of and for the period ended August 31, 2005 and in Notes 1 and 7 to the financial statements as of December 31, 2004 and 2003 and for the period ended January 25, 2005 and for the three year period ended December 31, 2004 incorporated herein by reference.
Credit Risk
We maintain credit policies with regard to our counterparties that we believe significantly minimize overall credit risk. These policies include an evaluation of potential counterparties’ financial condition (including credit ratings), collateral requirements under certain circumstances and the use of standardized agreements which allow for netting of positive and negative exposure associated with a single counterparty.
14
Our counterparties consist primarily of financial institutions, major energy companies and local distribution companies (LDCs). This concentration of counterparties may impact our overall exposure to credit risk, either positively or negatively in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions. Based on our policies, exposures, credit and other reserves, we do not anticipate a material adverse effect on financial position or results of operations as a result of counterparty performance.
Sensitivity analysis
The table below summarizes our positions and values as of August 31, 2005. It also assumes a hypothetical 10% change in the underlying price of the commodity and its effect.
| | | | | | | | |
| | | Notional Volume MMBTU
| | | Fair
Value
| | | Effect of Hypothetical 10% Change
|
Nymex Futures/ Fixed Price | | (38,457,500 | ) | | (143,343 | ) | | 45,813 |
Basis Swaps | | (51,751,124 | ) | | 16,368 | | | 4,207 |
Fixed Price Index Swaps | | 5,910,000 | | | 36,455 | | | 6,472 |
Options | | (1,776,000 | ) | | 78,942 | | | 16,034 |
Swing Swaps | | (25,811,504 | ) | | (5,645 | ) | | 585 |
Forward Contracts | | (19,316,000 | ) | | (78,942 | ) | | 16,034 |
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
The financial statements set forth starting on page F-1 of this report are incorporated herein by reference.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE.
None.
ITEM 9A. CONTROLS AND PROCEDURES.
We maintain controls and procedures designed to ensure that information required to be disclosed in the reports that are filed or submitted under the Securities Exchange Act of 1934 (the “Exchange Act”) is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. An evaluation was performed under the supervision and with the participation of management, including the Co-Chief Executive Officers and Chief Financial Officer of ETP’s General Partner, of the effectiveness of the design and operation of our disclosure controls and procedures (as such terms are defined in Rule 13a–15(e) and 15d–15(e) of the Exchange Act). Based upon that evaluation, management, including the Co-Chief Executive Officers and Chief Financial Officer of ETP’s General Partner, concluded that our disclosure controls and procedures were adequate and effective as of August 31, 2005 to provide reasonable assurance that information required to be disclosed in the reports that are filed or submitted under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms.
Our management does not expect that our disclosure controls and procedures will prevent all errors and all fraud. The design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Based on the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the Company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple errors or mistakes. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the controls. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events. Therefore, a control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Our disclosure controls and procedures are designed to provide such reasonable assurances of achieving our desired control objectives and the Co-Chief Executive Officers of ETP’s General Partner and the Chief Financial Officer of ETP’s General Partner have concluded, as of August 31, 2005, that our disclosure controls and procedures are effective in achieving that level of reasonable assurance.
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Changes in Internal Control Over Financial Reporting
On January 26, 2005, ETP completed the HPL acquisition. In recording the HPL acquisition, ETP followed its normal accounting procedures and internal controls. ETP’s management also reviewed the operations of the HPL System from the date of the acquisition that are included in ETP’s earnings for the fiscal year ended August 31, 2005. In addition, ETP solicited disclosure information from former AEP (now ETC OLP) employees and reviewed the historical audited financial statements and notes accompanying the financial statements. As disclosed in the filings and reports submitted by ETP, our business was excluded from Management’s Report on Internal Control Over Financial Reporting of ETP as of August 31, 2005. ETP is continuing to integrate its internal controls into our operations, and it is expected that this effort will continue into future fiscal quarters of 2006.
Significant changes in internal control over financial reporting subsequent to the acquisition of HPL have included changes in the cash management and treasury function, risk management and accounting for derivative activities, and the preparation and review of financial statements and related disclosures by ETP management.
ITEM 9B. OTHER INFORMATION
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
Item 10, Directors and Executive Officers of the Registrant, has been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.
ITEM 11. EXECUTIVE COMPENSATION.
Item 11, Executive Compensation, has been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED
STOCKHOLDER MATTERS.
Item 12, Security Ownership of Certain Beneficial Owners and Management, has been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
Item 13, Certain Relationships and Related Transactions, has been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES.
The following sets forth fees billed by Grant Thornton LLP for the audits of our financial statements and other services rendered for the period ended August 31, 2005:
| | | |
Audit fees (1) | | $ | 374,517 |
Audit related fees | | $ | — |
Tax fees | | $ | — |
All other fees | | $ | — |
| | |
|
|
Total | | $ | 374,517 |
| | |
|
|
16
| (1) | Includes fees for audits of our annual financial statements, reviews of the related quarterly financial statements, and services that are normally provided by the independent accountants in connection with statutory and regulatory filings or engagements, including reviews of documents filed with the Securities and Exchange Commission. |
Pursuant to the charter of the Audit Committee of the General Partner of ETP, our reporting parent (the “Audit Committee”), the Audit Committee is responsible for the oversight of our accounting, reporting and financial practices. The Audit Committee has the responsibility to select, appoint, engage, oversee, retain, evaluate and terminate our external auditors; pre-approve all audit and non-audit services to be provided, consistent with all applicable laws, to us by our external auditors; and establish the fees and other compensation to be paid to our external auditors. The Audit Committee also oversees and directs our internal auditing program and reviews our internal controls.
The Audit Committee has adopted a policy for the pre-approval of audit and permitted non-audit services provided by our principal independent accountants. The policy requires that all services provided by Grant Thornton LLP including audit services, audit-related services, tax services and other services, must be pre-approved by the Committee.
The Audit Committee reviews the external auditors’ proposed scope and approach as well as the performance of the external auditors. It also has direct responsibility for and sole authority to resolve any disagreements between our management and our external auditors regarding financial reporting, regularly reviews with the external auditors any problems or difficulties the auditors encountered in the course of their audit work, and, at least annually, uses its reasonable efforts to obtain and review a report from the external auditors addressing the following (among other items):
| | • | | the auditors’ internal quality-control procedures; |
| | • | | any material issues raised by the most recent internal quality-control review, or peer review, of the external auditors; |
| | • | | the independence of the external auditors; |
| | • | | the aggregate fees billed by our external auditors for each of the previous two fiscal years; and |
| | • | | the rotation of the lead partner. |
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.
| (a) | 1. Financial Statements. |
See “Index to Financial Statements” set forth on page F-1.
| | 2. Financial Statement Schedules. |
None.
See “Index to Exhibits” set forth on page E-1.
17
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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.
| | |
HPL CONSOLIDATION LP |
| |
By: | | HPL Holdings GP, L.L.C., its General Partner |
| | |
| |
By: | | /s/ Ray C. Davis
|
| | | Ray C. Davis |
| | | Co-Chief Executive Officer and officer duly authorized to sign on behalf of the registrant |
| |
By: | | /s/ Kelcy L. Warren
|
| | | Kelcy L. Warren |
| | | Co-Chief Executive Officer and officer duly authorized to sign on behalf of the registrant |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons in the capacities and on the dates indicated:
| | | | |
Signature
| | Title
| | Date
|
| | |
/s/ Ray C. Davis
Ray C. Davis | | Co-Chief Executive Officer and Manager (Principal Executive Officer) | | December 13, 2005 |
| | |
/s/ Kelcy L. Warren
Kelcy L. Warren | | Co-Chief Executive Officer and Manager (Principal Executive Officer) | | December 13, 2005 |
| | |
/s/ H. Michael Krimbill
H. Michael Krimbill | | President, Chief Financial Officer (Principal Financial and Accounting Officer) | | December 13, 2005 |
18
INDEX TO EXHIBITS
The exhibits listed on the following Exhibit Index are filed as part of this report. Exhibits required by Item 601 of Regulation S-K, but which are not listed below, are not applicable.
| | | | |
| | | Exhibit
Number
| | Description
|
| | |
| | |
| (*) | | 21.1 | | List of Subsidiaries. |
| | |
| (*) | | 31.1 | | Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
| | |
| (*) | | 31.2 | | Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
| | |
| (*) | | 32.1 | | Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
| | |
| (*) | | 32.2 | | Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
E-1
INDEX TO FINANCIAL STATEMENTS
HPL Consolidation LP
| | |
| | | Page
|
| |
Report of Independent Registered Public Accounting Firm | | F-1 |
| |
Consolidated Balance Sheet – August 31, 2005 | |
F-2 |
| |
Consolidated Income Statement – Period from January 26, 2005 to August 31, 2005 | |
F-3 |
| |
Consolidated Statements of Comprehensive Loss – Period from January 26, 2005 to August 31, 2005 | |
F-4 |
| |
Consolidated Statements of Partners’ Capital – Period from January 26, 2005 to August 31, 2005 | |
F-5 |
| |
Consolidated Statements of Cash Flows – Period from January 26, 2005 to August 31, 2005 | |
F-6 |
| |
Notes to Consolidated Financial Statements | | F-7 |
| |
Reports of Independent Registered Public Accounting Firms | | F-18 |
| |
Consolidated Statements of Operations – Period from January 1, 2005 to January 25, 2005 and for the years ended December 31, 2004, 2003, and 2002 | |
F-20 |
| |
Consolidated Balance Sheets – December 31, 2004 and 2003 | |
F-21 |
| |
Consolidated Statements of Cash Flows – Period from January 1, 2005 to January 25, 2005 and for the years ended December 31, 2004, 2003, and 2002 | |
F-23 |
| |
Consolidated Statements of Partners’ Capital – Period from January 1, 2005 to January 25, 2005 and for the years ended December 31, 2004, 2003, and 2002 | |
F-24 |
| |
Notes to Consolidated Financial Statements | | F-26 |
Report of Independent Registered Public Accounting Firm
To the Partners
HPL Consolidation LP
We have audited the consolidated balance sheet of HPL Consolidation LP and subsidiaries as of August 31, 2005, and the related consolidated statements of income, comprehensive loss, partners’ capital, and cash flows for the period from acquisition (January 26, 2005) to August 31, 2005. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of HPL Consolidation LP and subsidiaries as of August 31, 2005, and the results of their operations and their cash flows for the period from acquisition (January 26, 2005) to August 31, 2005, in conformity with accounting principles generally accepted in the United States of America.
|
/s/ GRANT THORNTON LLP |
|
Houston, Texas |
December 6, 2005 |
F-1
HPL CONSOLIDATION LP
CONSOLIDATED BALANCE SHEET
(In Thousands)
| | | | |
| | | August 31, 2005
| |
| ASSETS | | | | |
CURRENT ASSETS: | | | | |
Cash and cash equivalents | | $ | 38 | |
Receivables: | | | | |
Trade receivables | | | 295,158 | |
Affiliated companies, net | | | 69,291 | |
Exchanges | | | 17,626 | |
Materials and supplies | | | 1,504 | |
Inventories | | | 215,612 | |
Price risk management assets | | | 111 | |
Other current assets | | | 1,076 | |
| | |
|
|
|
Total current assets | | | 600,416 | |
| |
Property, plant and equipment | | | 826,315 | |
Accumulated depreciation | | | (12,448 | ) |
| | |
|
|
|
Property, plant and equipment, net | | | 813,867 | |
| |
Investments in affiliates | | | 32,205 | |
| |
Long-term price risk management assets | | | 2,245 | |
| |
Other noncurrent assets | | | 2,876 | |
| | |
|
|
|
Total assets | | $ | 1,451,609 | |
| | |
|
|
|
| LIABILITIES AND PARTNERS’ CAPITAL | | | | |
CURRENT LIABILITIES: | | | | |
Payables: | | | | |
Trade payables | | $ | 280,771 | |
Exchanges | | | 19,920 | |
Deposits from customers | | | 84,513 | |
Accrued expenses | | | 25,921 | |
Price risk management liabilities | | | 52,944 | |
| | |
|
|
|
Total current liabilities | | | 464,069 | |
| |
Long-term price risk management liabilities | | | 28,354 | |
Other non-current liabilities | | | 12,492 | |
| |
COMMITMENTS AND CONTINGENCIES | | | | |
| |
PARTNERS’ CAPITAL: | | | | |
General partner’s capital | | | 10,297 | |
Limited partners’ capital | | | 1,019,455 | |
Accumulated other comprehensive loss | | | (83,058 | ) |
| | |
|
|
|
Total partners’ capital | | | 946,694 | |
| | |
|
|
|
Total liabilities and partners’ capital | | $ | 1,451,609 | |
| | |
|
|
|
The accompanying notes are an integral part of these consolidated financial statements.
F-2
HPL CONSOLIDATION LP
CONSOLIDATED INCOME STATEMENT
(In Thousands)
| | | | |
| | | Period from January 26, 2005 to August 31, 2005
| |
OPERATING REVENUES | | | | |
Third party | | $ | 1,943,531 | |
Affiliated | | | 371,250 | |
| | |
|
|
|
Total revenue | | | 2,314,781 | |
| |
COSTS AND EXPENSES: | | | | |
Cost of products sold: | | | | |
Third party | | | 1,797,992 | |
Affiliated | | | 444,001 | |
Operating expense | | | 38,669 | |
General and administrative | | | 12,071 | |
Depreciation and amortization | | | 12,555 | |
| | |
|
|
|
Total costs and expenses | | | 2,305,288 | |
| | |
|
|
|
OPERATING INCOME | | | 9,493 | |
| |
OTHER INCOME (EXPENSE): | | | | |
Interest expense | | | (160 | ) |
Equity in losses of affiliates | | | (735 | ) |
Other, net | | | 475 | |
| | |
|
|
|
NET INCOME | | $ | 9,073 | |
| | |
|
|
|
The accompanying notes are an integral part of these consolidated financial statements.
F-3
HPL CONSOLIDATION LP
CONSOLIDATED STATEMENT OF COMPREHENSIVE LOSS
(In Thousands)
| | | | |
| | | Period from January 26, 2005 to August 31, 2005
| |
Net income | | $ | 9,073 | |
| |
Other comprehensive loss: | | | | |
Reclassification adjustment for gains or losses on derivative instruments included in net income | | | 12,785 | |
Change in value of derivative instruments accounted for as hedges | | | (95,843 | ) |
| | |
|
|
|
Comprehensive loss | | $ | (73,985 | ) |
| | |
|
|
|
RECONCILIATION OF ACCUMULATED OTHER COMPREHENSIVE LOSS | | | | |
| |
Balance, beginning of period | | $ | — | |
| |
Current period reclassification to earnings | | | 12,785 | |
Current period change | | | (95,843 | ) |
| | |
|
|
|
Balance, end of period | | $ | (83,058 | ) |
| | |
|
|
|
The accompanying notes are an integral part of these consolidated financial statements.
F-4
HPL CONSOLIDATION LP
CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL
Period from January 26, 2005 to August 31, 2005
(In Thousands)
| | | | | | | | | | | | | | |
| | | General Partner’s Capital
| | Limited Partners’ Capital
| | Accumulated Other Comprehensive Loss
| | | Total Partners’ Capital
| |
Balance, January 26, 2005 | | $ | 10,206 | | $ | 1,010,473 | | | — | | | $ | 1,020,679 | |
Net change in accumulated other comprehensive loss per accompanying statement | | | — | | | — | | | (83,058 | ) | | | (83,058 | ) |
Net income | | | 91 | | | 8,982 | | | — | | | | 9,073 | |
| | |
|
| |
|
| |
|
|
| |
|
|
|
Balance, August 31, 2005 | | $ | 10,297 | | $ | 1,019,455 | | $ | (83,058 | ) | | $ | 946,694 | |
| | |
|
| |
|
| |
|
|
| |
|
|
|
The accompanying notes are an integral part of these consolidated financial statements.
F-5
HPL CONSOLIDATION LP
CONSOLIDATED STATEMENT OF CASH FLOW
(In Thousands)
| | | | |
| | | Period from January 26, 2005 to August 31, 2005
| |
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | |
Net income | | $ | 9,073 | |
Adjustments to reconcile net income to net cash provided by operating activities: | | | | |
Depreciation and amortization expense | | | 12,555 | |
Equity in losses of affiliates | | | 735 | |
Changes in operating assets and liabilities: | | | | |
Trade receivables | | | 26,056 | |
Receivables - Affiliated Companies | | | (69,291 | ) |
Materials and supplies | | | 282 | |
Inventories | | | (85,303 | ) |
Exchange gas receivable | | | (9,003 | ) |
Price risk management assets and liabilities | | | (4,116 | ) |
Other current assets | | | (980 | ) |
Other noncurrent assets | | | (1,715 | ) |
Trade payables | | | 27,012 | |
Exchange gas payable | | | 8,409 | |
Deposits from customers | | | 83,817 | |
Accrued expenses | | | 7,453 | |
Other long-term liabilities | | | (2,355 | ) |
| | |
|
|
|
Net cash provided by operating activities | | | 2,629 | |
| |
CASH FLOWS FROM INVESTING ACTIVITIES - Capital expenditures | | | (2,782 | ) |
CASH FLOWS FROM FINANCING ACTIVITIES | | | — | |
| | |
|
|
|
NET DECREASE IN CASH AND CASH EQUIVALENTS | | | (153 | ) |
CASH AND CASH EQUIVALENTS, beginning of period | | | 191 | |
| | |
|
|
|
CASH AND CASH EQUIVALENTS, end of period | | $ | 38 | |
| | |
|
|
|
The accompanying notes are an integral part of these consolidated financial statements.
F-6
HPL Consolidation LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
August 31, 2005
(in thousands)
1. Organization
Business Operations – HPL Consolidation LP (the “Partnership” or “HPL”) is owned by La Grange Acquisition, LP (ETC OLP), which owns a 98% controlling interest, and American Electric Power Inc. (“AEP”), which owns a 2% limited partner interest. HPL was formed in November 2004 in connection with the acquisition of the Bammel storage field leased assets. HPL wholly owns HPL Storage GP, LLC (“HPL GP”), which owns the Bammel storage field assets and Houston Pipe Line Company LP (“HPC”). AEP acquired HPC from Enron Corporation on June 1, 2001. ETC purchased the 98% controlling interest of HPL from AEP on January 26, 2005 (see note 5). The transaction is accounted for as if it had occurred on January 31, 2005.
HPL is a fully integrated natural gas gathering, processing, storage, and transportation operation located in the state of Texas. HPL’s gathering and transportation assets include 4,200 miles of gas pipeline and the Bammel gas storage facility with approximately 130 billion cubic feet of capacity and is accounted for as one segment: transportation and storage. In addition to the pipelines and storage assets, HPL owns a 50% interest in Mid Texas Pipeline Company (“Mid Texas”). Mid Texas’ sole asset is a 139-mile pipeline in South Texas of which HPL is also the operator. Mid Texas is accounted for under the equity method of accounting. HPL is subject to certain regulations with regard to rates and other matters by the Texas Railroad Commission.
Consolidation Policy – The consolidated financial statements include the accounts of HPL and its wholly-owned and majority owned subsidiaries. All significant intercompany transactions are eliminated in preparing the accompanying consolidated financial statements. HPL also owns varying undivided interests in certain pipelines. Ownership of these pipelines has been structured as an ownership of an undivided interest in assets, not as an ownership interest in a partnership, limited liability company, joint venture or other forms of entities. Each owner controls marketing and invoices separately, and each owner is responsible for any loss, damage or injury that may occur to their own customers. As a result, the Partnership applies proportionate consolidation for its interests in these accounts.
2. Basis of Presentation
The accompanying audited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America. The consolidated financial statements reflect a new basis of accounting which results from the purchase method of accounting discussed in Note 5.
HPL was accounted for on a calendar year basis when owned by AEP and was changed to a fiscal year end of August 31 when purchased by ETC OLP.
The results of operations for the period from January 26, 2005 to August 31, 2005 should not be taken as indicative of the results to be expected for the full year, due to seasonality of portions of the natural gas business and maintenance activities. HPL expects margin to be higher during the periods from November through March of each year and lower during the periods from April through October of each year due to the increased demand for natural gas during cold weather. However, HPL can not assure that management’s expectations will be fully realized in the future and in what time period due to various factors including, weather, availability of natural gas in regions in which the Partnership operates, competitive factors in the energy industry, and other issues.
3. Summary of Significant Accounting Policies and Balance Sheet Detail
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The natural gas industry conducts its business by processing actual transactions at the end of the month
following the month of delivery. Consequently, the most current month’s financial results are estimated using volume estimates and market prices. Any differences between estimated results and actual results are recognized in the following month’s financial statements. Management believes that the operating results estimated for the period from January 26, 2005 to August 31, 2005 represent the actual results in all material respects.
Some of the other more significant estimates made by management include, but are not limited to, allowances for doubtful accounts, the fair value of derivative instruments, useful lives for depreciation and amortization, purchase accounting allocations, commitments and contingencies. Actual results could differ from those estimates.
F-7
Cash and Cash Equivalents
Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. The Partnership considers cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and which are subject to an insignificant risk of changes in value.
Accounts Receivable
The Partnership deals with counterparties that are typically either investment grade or are otherwise secured with a letter of credit or other form of security (corporate guaranty prepayment or master set off agreement). Management reviews accounts receivable balances each week. Credit limits are assigned and monitored for all counterparties. Management believes that the occurrence of bad debt is not significant; therefore, an allowance for doubtful accounts was not deemed necessary at August 31, 2005. Bad debt expense related to these receivables is recognized at the time an account is deemed uncollectible. There was no bad debt expense recorded during the period from January 26, 2005 to August 31, 2005.
The Partnership enters into netting arrangements with counterparties of derivative contracts to mitigate credit risk. Transactions are confirmed with each counterparty covered by a netting agreement and the net amount is settled when due. Amounts outstanding under these netting arrangements are presented on a net basis in the consolidated balance sheets.
Inventories
HPL’s inventories consist principally of natural gas held in storage, which is valued at the lower of cost or market utilizing the weighted-average cost method.
Exchanges
Exchanges consist of natural gas and NGL delivery imbalances with others. These amounts, which are valued at market prices, turn over regularly and are recorded as exchanges receivable or exchanges payable on the Partnership’s consolidated balance sheet. Management believes market value approximates cost.
Investments in Affiliates
The Partnership owns a 50% ownership interest in Mid Texas Pipeline Company (MidTexas) which owns a 129-mile transportation pipeline that connects various receipt points in south Texas to delivery points in the Katy Hub. This pipeline has a throughput capacity of 500 MMcf/d. The investment is accounted for using the equity method of accounting. The Partnership does not exercise management control over MidTexas, and, therefore the Partnership is precluded from consolidating the MidTexas financial statements with those of its own.
Property, Plant and Equipment
Property, plant and equipment is stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful lives of the assets. Expenditures for maintenance and repairs that do not add capacity or extend the useful life are expensed as incurred. Expenditures to refurbish assets that either extend the useful lives of the asset or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset. Additionally, the Partnership capitalizes certain costs directly related to the construction of assets including internal labor costs, interest and engineering costs. Upon disposition or retirement of pipeline components or natural gas plant components, any gain or loss is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in operations.
The Partnership reviews long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of long-lived assets is not recoverable, the Partnership reduces the carrying amount of such assets to fair value. No impairment of long-lived assets was recorded during the period presented.
F-8
Components and useful lives of property, plant and equipment were as follows:
| | | | |
| | | August 31, 2005
| |
Land and improvements | | $ | 7,573 | |
Buildings and improvements (10 to 30 years) | | | 8,864 | |
Pipelines and equipment (10 to 65 years) | | | 687,910 | |
Natural gas storage (40 years) | | | 15,618 | |
Vehicles (5 to 10 years) | | | 1,235 | |
Right of way (20 to 65 years) | | | 4,806 | |
Furniture and fixtures (3 to 10 years) | | | 1,225 | |
Linepack | | | 12,299 | |
Pad Gas | | | 58,811 | |
Other (5 to 10 years) | | | 9,990 | |
| | |
|
|
|
| | | | 808,331 | |
Less – Accumulated depreciation | | | (12,448 | ) |
| | |
|
|
|
| | | | 795,883 | |
Plus – Construction work-in-process | | | 17,984 | |
| | |
|
|
|
Property, plant and equipment, net | | $ | 813,867 | |
| | |
|
|
|
Asset Retirement Obligation
The Partnership accounts for its asset retirement obligations in accordance with Statement of Financial Accounting Standards No. 143,Accounting for Asset Retirement Obligations,(“SFAS 143”). SFAS No. 143 requires the Partnership to record the fair value of an asset retirement obligation as a liability in the period a legal obligation for the retirement of tangible long-lived assets is incurred, typically at the time the assets are placed into service. A corresponding asset is also recorded and depreciated over the life of the asset. After the initial measurement, an entity would recognize changes in the amount of the liability resulting from the passage of time and revisions to either the timing or amount of estimated cash flows.
The Partnership’s management has completed the assessment of SFAS 143, and has determined that the Partnership is obligated by contractual requirements to remove facilities or perform other remediation upon retirement of certain assets. Determination of the amounts to be recognized is based upon numerous estimates and assumptions, including expected settlement dates, future retirement costs, future inflation rates, and the credit-adjusted risk-free interest rates. However, management is not able to reasonably determine the fair value of the asset retirement obligations as of August 31, 2005 because the settlement dates are indeterminable. An asset retirement obligation will be recorded in the periods management can reasonably determine the settlement dates.
Non-current Assets
Included in non-current assets are intangibles consisting of customer relationships which are accounted for at fair value in connection with the acquisition of the Partnership by ETC OLP. Intangibles of $1,440, net of $280 in amortization, are being amortized on a straight-line basis over three years. Amortization expense of intangible assets was $280 for the period from January 26, 2005 to August 31, 2005. The estimated amortization expense is $480 for 2006; $480 for 2007; and $200 for 2008.
The Partnership reviews intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of intangible assets is not recoverable, the Partnership reduces the carrying amount of such assets to fair value. No impairment of intangible assets has been recorded as of August 31, 2005.
Non-current assets also include the non-current portion of receivables not expected to be collected within a year.
F-9
Accrued Expenses
Accrued expenses consisted of the following:
| | | |
| | | August 31, 2005
|
Operating expenses | | $ | 7,316 |
Wages, payroll taxes and employee benefits | | | 1,606 |
Taxes other than income | | | 11,860 |
Pipeline integrity | | | 2,316 |
Accrued capital costs | | | 1,327 |
Other | | | 1,496 |
| | |
|
|
Accrued expenses | | $ | 25,921 |
| | |
|
|
Fair Value
The carrying value of cash and cash equivalents, trade accounts receivable and accounts payable approximate their respective fair values due to their short maturities.
The derivative financial instruments are carried as fair value, which reflects the Partnership’s best estimate and is based upon exchange-traded prices, published market prices or over-the-counter market prices quotations.
Revenue Recognition
Revenues are recognized from domestic gas pipeline and storage services when gas is delivered to contractual meter points or when services are provided, with the exception of certain physical forward gas purchase and sale contracts that are derivatives which are accounted for using fair value accounting.
HPL engages in wholesale natural gas marketing and risk management activities. Our activities include the purchase and sale of gas under forward contracts at fixed and variable prices and the buying and selling of financial gas contracts, which include exchange traded futures and options, and over-the-counter options and swaps.
Allocation of Income (Loss)
For purposes of maintaining partner capital accounts, the Partnership Agreement of HPL specifies that items of income and loss shall generally be allocated among the partners in accordance with their percentage interests (see Note 11).
Income Taxes
HPL Consolidation LP is a limited partnership. As a result, the Partnership’s earnings or losses for federal and state income tax purposes are included in the tax returns of the individual partners. Net earnings for financial statement purposes may differ significantly from taxable income reportable to partners as a result of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under the Partnership Agreement.
F-10
Accounting for Derivative Instruments and Hedging Activities
The Partnership applies Statement of Financial Accounting Standards No. 133,Accounting for Derivative Instruments and Hedging Activities(SFAS 133) as amended. This statement requires that all derivatives be recognized in the balance sheet as either an asset or liability measured at fair value. Special accounting for qualifying hedges allows a derivative’s gains and losses to offset related results on the hedged item in the income statement and requires that a company must formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment.
The Partnership utilizes the formal risk management policy established by ETC OLP in which derivative financial instruments are employed in connection with an underlying asset, liability and/or anticipated transaction. At inception of a hedge, the Partnership formally documents the relationship between the hedging instrument and the hedged item, the risk management objectives, and the methods used for assessing and testing effectiveness. The Partnership also assesses, both at the inception of the hedge and on a quarterly basis, whether the derivatives that are used in its hedging transactions are highly effective in offsetting changes in cash flows. Furthermore, management meets on a weekly basis to assess the creditworthiness of the derivative counterparties to manage against the risk of default. If the Partnership determines that a derivative is no longer highly effective as a hedge, it discontinues hedge accounting prospectively by including changes in the fair value of the derivative in current earnings.
The Partnership’s derivative activities associated with its operations are maintained by ETC OLP. ETC OLP enters into the hedging instrument with the counterparty and enters into an offsetting position with the Partnership to properly reflect those transactions on the books and records of HPL. The offsetting positions are reflected as Receivables from Affiliated Companies equal to the fair value of the associated price risk management assets and liabilities in the Consolidated Balance Sheet as of August 31, 2005 until the hedged item is settled. The fair value of price risk management assets and liabilities entered into by ETC OLP that are designated and documented as cash flow hedges and determined to be effective are recorded through other comprehensive income (loss). For those instruments that do not qualify for hedge accounting, the change in market value is recorded as cost of products sold in the consolidated income statement. The effective portion of the hedge gain or loss is initially reported as a component of Other Comprehensive Income and when the hedged physical transaction settles, any gain or loss previously recorded in other comprehensive income (loss) on the derivative is recognized in earnings in the consolidated income statement. The ineffective portion of the gain or loss is reported immediately in cost of products sold in the consolidated income statement. As of August 31, 2005, these hedging instruments had a net fair value of $(100,164), which was included in Receivables from Affiliated Companies on the Consolidated Balance Sheet. See the table in Note 10 for a detail of these hedging instruments. The Partnership reclassified into cost of sales losses of $12,785 for the period ended August 31, 2005, related to the commodity financial instruments, that were previously reported in accumulated other comprehensive income (loss). The amount of hedge ineffectiveness recognized in income by HPL was a loss of $17,105. The Partnership expects losses of $83,288 to be reclassified into earnings over the next twelve months related to losses currently reported in Other Comprehensive Income. The majority of the Partnership’s derivatives are expected to settle within the next three years.
In the course of normal operations, the Partnership routinely enters into contracts such as forward physical contracts for the purchase and sale of natural gas, propane, and other NGLs that qualify for and are
F-11
designated as a normal purchase and sales contracts. Such contracts are exempted from the fair value accounting requirements of SFAS 133 and are accounted for using traditional accrual accounting. In connection with the HPL acquisition, the Partnership acquired certain physical forward contracts that contain embedded options. These contracts have not been designated as normal purchases and sales contracts, and therefore, are marked to market in addition to the financial options that offset them. The net fair value of the embedded derivatives as of August 31, 2005 was a liability of $78,941, and the Black Scholes valuation model was used to estimate the value of these embedded derivatives.
The market prices used to value the financial derivative transactions reflect management’s estimates considering various factors including closing exchange and over-the-counter quotations, and the time value of the underlying commitments.
4. New Accounting Pronouncements
FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations (“FIN 47”).In March 2005, the Financial Accounting Standards Board (FASB) published FIN 47, which requires companies to record a liability for those asset retirement obligations in which the timing or amount of settlement of the obligation are uncertain. These conditional obligationswere notaddressed by SFAS 143. FIN 47 will require the Partnership to accrue a liability when a range of scenarios can be determined. Management intends to adopt FIN 47 no later than the end of the fiscal year ending August 31, 2006, and has not yet determined the impact, if any, that this pronouncement will have on the Partnership’s financial statements.
SFAS No. 153, Exchanges of Nonmonetary Assets-an amendment of APB Opinion No. 29 (“SFAS 153”).In December 2004, the FASB issued SFAS 153, which amends APB Opinion No. 29 by eliminating the exception to the fair-value principle for exchanges of similar productive assets, which were accounted for under APB Opinion No. 29 based on the book value of the asset surrendered with no gain or loss recognition. SFAS 153 also eliminates APB 29’s concept of culmination of an earnings process. SFAS 153 is effective for nonmonetary transactions occurring in fiscal periods beginning after June 15, 2005. Management has determined that the adoption of SFAS 153, on September 1, 2005, will not have a material impact on the Partnership’s consolidated results of operations, cash flows or financial position.
EITF Issue No.04-1 Accounting for Preexisting Relationships between the Parties to a Business Combination (“EITF 04-1”). EITF 04-1 requires that pre-existing contractual relationships between two parties involved in a business combination be evaluated to determine if a settlement of the pre-existing contracts is required separately from the accounting for the business combination. This consensus is effective for business combinations consummated and goodwill impairment tests performed in reporting periods beginning after October 13, 2004. The Partnership adopted EITF 04-1 during the quarter ended February 28, 2005, without a material effect on its financial position, results of operations and cash flows.
5. Change in Ownership
In January 2005, ETC OLP acquired the controlling interests in HPL from American Electric Power Corporation (“AEP”) for approximately $825,000 subject to working capital adjustments. The acquisition was financed by Energy Transfer Partners, LP (ETP), ETC OLP’s parent company, through a combination of borrowings under its current credit facilities and a private placement of $350,000 of ETP’s Common Units with institutional investors. In addition, the Partnership acquired working inventory of natural gas stored in the Bammel storage facility and financed it through a short-term borrowing from an affiliate. The total purchase price of $1,350,212 which included $1,039,521 of cash paid, net of cash acquired and liabilities assumed of $329,533, including $800 in estimated acquisition costs, was allocated to the assets acquired and liabilities assumed. Under the terms of the transaction, the Partnership acquired all but a 2% limited partner interest in HPL.
F-12
The transaction was accounted for as a business combination using the purchase method of accounting in accordance with the provisions of SFAS 141, which requires the purchase price to be allocated based on the estimated fair value of the individual assets acquired and the liabilities assumed at the date of the respective acquisition. The results of operations are included in the Consolidated Income Statement from the date of the acquisition. The purchase price allocation related to the assets acquired and liabilities assumed was as follows (excludes the minority interest related to the 2% limited partner interest retained by AEP):
| | | | |
Cash and equivalents | | $ | 191 | |
Accounts receivable | | | 321,214 | |
Inventory | | | 132,095 | |
Other current assets | | | 8,672 | |
Investments in unconsolidated affiliate | | | 32,940 | |
Price risk management assets | | | 30,300 | |
Property, plant, and equipment | | | 823,360 | |
Intangibles | | | 1,440 | |
| | |
|
|
|
Total assets acquired | | | 1,350,212 | |
| | |
|
|
|
Accounts payable | | | (253,784 | ) |
Accrued expenses | | | (18,344 | ) |
Other current liabilities | | | (11,829 | ) |
Other liabilities | | | (15,276 | ) |
Price risk management liabilities | | | (30,300 | ) |
| | |
|
|
|
Total liabilities assumed | | | (329,533 | ) |
| | |
|
|
|
Net assets acquired | | $ | 1,020,679 | |
| | |
|
|
|
The purchase price of HPL has been allocated using the acquisition methodology used by ETC OLP when evaluating potential acquisitions. The purchase price will be assigned primarily to depreciable fixed assets or amortizable intangible assets as opposed to goodwill. The Partnership has engaged an appraisal firm to perform the asset appraisal in order to develop a definitive allocation of the purchase price. As a result, the final purchase price allocation may differ from the preliminary allocation. To the extent that the final allocation will result in goodwill, this amount would not be subject to amortization, but would be subject to an annual impairment test and if necessary, written down to a lower fair value should circumstances warrant.
During the 2005 period the Partnership completed a verification of the working gas inventory contained in the storage facilities of HPL and has adjusted the preliminary allocations of the purchase prices to reflect the verified amounts. The Partnership has also adjusted the preliminary allocations to reflect working capital settlement with AEP occurring in the fourth fiscal quarter of 2005. On November 10, 2005, ETP reached a settlement agreement with AEP related to the inventory and working capital matters, and the terms of the agreement were not material in relation to the Partnership’s financial position, results of operations or cash flows. Further adjustments may be necessary to reflect the final purchase price allocation which will be based in part, on the independent appraisal.
6. Retirement Benefits
The Partnership participates in the ETC OLP sponsored defined contribution profit sharing and 401(k) savings plan, which covers virtually all employees subject to service period requirements. Profit sharing contributions are made to the plan at the discretion of the Board of Directors of ETP’s General Partner and are allocated to eligible employees as of the last day of the plan year. Employer matching contributions are calculated using a discretionary formula based on employee contributions. The Partnership made matching contributions of $252 to the 401(k) savings plan for the period from January 26, 2005 to August 31, 2005.
7. Related Party Transactions
ETC OLP provides certain managerial, treasury, general and administrative services to HPL. The costs of
F-13
these services are billed to HPL based on management’s estimate of HPL’s usage of the services. For the period from January 26, 2005 to August 31, 2005, HPL recognized costs of $3,105 for these services which are included in general and administrative expenses in the Consolidated Income Statement.
HPL purchases and sells gas and enters into financial hedge transactions with ETC OLP. These transactions are conducted at market prices and settlements are handled according to standard industry practices.
8. Major Customers and Suppliers
The Partnership had gross sales as a percentage of total revenues to nonaffiliated major customers as follows:
| | | |
| | | From January 26, 2005 to August 31, 2005
| |
Exxon Mobil | | 12.77 | % |
Centerpoint Energy | | 12.06 | % |
The Partnership’s natural gas operations have a concentration of customers in natural gas transmission, distribution and marketing, as well as industrial end-users while its NGL operations have a concentration of customers in the refining and petrochemical industries. These concentrations of customers may impact the Partnership’s overall exposure to credit risk, either positively or negatively.
These concentrations of suppliers may impact the Partnership’s overall operations, either positively or negatively. However, management believes that the diversification of suppliers is sufficient to enable the Partnership to purchase all of its supply needs at market prices without a material disruption of operations if supplies are interrupted from any of our existing sources. Although no assurances can be given that supplies of natural gas will be readily available in the future, we expect a sufficient supply to continue to be available.
9. Commitments and Contingencies
Commitments
Certain property and equipment is leased under noncancelable leases, which require fixed monthly rental payments and expire at various dates through 2020. Rental expense under these leases totaled approximately $938 from January 26, 2005 to August 31, 2005, and has been included in operating expenses in the accompanying statements of operations. Fiscal year future minimum lease commitments for such leases are $996 in 2006; $375 in 2007; $13 in 2008; $13 in 2009; $2 in 2010 and $41 thereafter.
The Partnership has forward commodity contracts, which will be settled by physical delivery. Short-term contracts, which expire in less than one year, require delivery of up to 8.0 MMBtu/d. Long-term contracts require delivery of up to 10.30 MMBtu/d. The long-term contracts run through October 2012.
In connection with the HPL ownership change in January 2005, the Partnership acquired a sales agreement whereby the Partnership is committed to sell minimum amounts of gas ranging from 20 MMBtu/d to 50 MMBtu/d to a single customer. Future annual minimum sale volumes remaining under the agreement are approximately 9.9 billion Btu and 6.9 billion Btu for the years ended August 31, 2006, and 2007, respectively. The Partnership also assumed a contract with a service provider which obligates HPL to obtain certain compressor, measurement and other services through 2007 with monthly payments of approximately $1,700.
The Partnership in the normal course of business, purchases, processes and sells natural gas pursuant to
F-14
long-term contracts. Such contracts contain terms that are customary in the industry. The Partnership believes that such terms are commercially reasonable and will not have a material adverse effect on the Partnership’s financial position or results of operations.
ETC OLP and its designated subsidiaries, which includes HPL, act as the guarantor of the debt obligations for the ETP 2015 Registered Notes issued on January 18, 2005, the 2012 Registered Notes issued on July 29, 2005 and the ETP Revolver. If ETP were to default, ETC OLP and the other guarantors, including HPL, would be responsible for full repayment of those obligations. The ETP Senior Notes have equal rights to holders of our other current and future unsecured debt. The outstanding debt covered by this guaranty as of August 31, 2005 was $1,359,732.
Litigation
The Partnership may, from time to time, be involved in litigation and claims arising out of its operations in the normal course of business. In addition, management is not aware of any material legal or governmental proceedings currently existing or contemplated to be brought, under the various environmental protection statutes to which it is subject.
At the time of the HPL acquisition, the HPL Entities, their parent companies and AEP, were engaged in ongoing litigation with Bank of America (“B of A”) that related to AEP’s acquisition of HPL in the Enron bankruptcy and B of A’s financing of cushion gas stored in the Bammel Storage facility (Cushion Gas). This litigation is referred to as the “Cushion Gas Litigation”. Under the terms of the Purchase and Sale Agreement and the related Cushion Gas Litigation Agreement, AEP and its subsidiaries that were the sellers of the HPL Entities retained control of the Cushion Gas Litigation and have agreed to indemnify ETC OLP and the HPL Entities for any damages arising from the Cushion Gas Litigation and the loss of use of the Cushion Gas, up to a maximum of the amount paid by ETC OLP for the HPL Entities and the working gas inventory. The Cushion Gas Litigation Agreement terminates upon final resolution of the Cushion Gas Litigation. In addition, under the terms of the Purchase and Sale Agreement, AEP retained control of additional matters relating to ongoing litigation and environmental remediation and agreed to bear the costs of or indemnify ETC OLP and the HPL Entities for the costs related to such matters.
The Partnership or its subsidiaries is a party to various legal proceedings and/or regulatory proceedings incidental to its business. Certain claims, suits and complaints arising in the ordinary course of business have been filed or are pending against ETP. In the opinion of management, all such matters are either covered by insurance, are without merit or involve amounts, which, if resolved unfavorably, would not have a significant effect on the financial position or results of operations of the Partnership. Once management determines that information pertaining to a legal proceeding indicates that it is probable that a liability has been incurred, an accrual is established equal to management’s estimate of the likely exposure. For matters that are covered by insurance, HPL accrues the related deductible. As of August 31, 2005, no accrual related to insurance was recorded as accrued and other current liabilities on the Partnership’s consolidated balance sheet.
Environmental
The Partnership’s operations are subject to extensive federal, state and local environmental laws and regulations that require expenditures for remediation at operating facilities and waste disposal sites. Although HPL believes its operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in the natural gas pipeline and processing business, and there can be no assurance that significant costs and liabilities will not be incurred. 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 the operations, could result in substantial costs and liabilities. Accordingly, the Partnership has adopted policies, practices, and procedures in the areas of pollution control, product safety, occupational health, and the handling, storage, use, and disposal of hazardous materials to prevent material environmental or other damage, and to limit the financial liability, which could result from such events. However, some risk of environmental or other damage is inherent in the natural gas pipeline and processing business, as it is with other entities engaged in similar businesses.
F-15
HPL has eleven sites under environmental remediation as of August 31, 2005. Environmental exposures and liabilities are difficult to assess and estimate due to unknown factors such as the magnitude of possible contamination, the timing and extent of remediation, the determination of the Partnership’s liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future. Although environmental costs may have a significant impact on the results of operations for any single period, the Partnership believes that such costs will not have a material adverse effect on its financial position. The Partnership has accounted for the environmental liabilities in accordance with Statement of Position 96-1, Environmental Remediation Liabilities. As of August 31, 2005, an accrual of $870, was recorded in the Partnership’s balance sheets to cover material environmental liabilities, including certain matters assumed in connection with the HPL acquisition.
10. Price Risk Management Assets and Liabilities
Commodity Price Risk
The following table details the outstanding derivatives as of August 31, 2005 entered into by ETC OLP which are related to the Partnership’s operations and are accounted for Receivables from Affiliated Companies:
| | | | | | | | | | |
August 31, 2005
| | Commodity
| | Notional Volume MMBTU
| | | Maturity
| | Fair Value
| |
| | | | | |
Mark to Market Derivatives | | | | | | | | | | |
Basis Swaps | | Gas | | (20,130,777 | ) | | 2005 | | 5,829 | |
Basis Swaps | | Gas | | (23,842,347 | ) | | 2006 | | 7,392 | |
Basis Swaps | | Gas | | (2,043,000 | ) | | 2007 | | 584 | |
| | | | | | | | | |
|
|
| | | | | | | | | | 13,805 | |
| | | | |
Swing Swaps | | Gas | | (13,141,504 | ) | | 2005 | | (5,838 | ) |
Swing Swaps | | Gas | | (12,670,000 | ) | | 2006 | | 193 | |
| | | | | | | | | |
|
|
| | | | | | | | | | (5,645 | ) |
| | | | |
Fixed Swaps/Futures | | Gas | | 2,577,500 | | | 2005 | | (5,331 | ) |
Fixed Swaps/Futures | | Gas | | 190,000 | | | 2006 | | 1,170 | |
| | | | | | | | | |
|
|
| | | | | | | | | | (4,161 | ) |
| | | | |
Options | | Gas | | 416,000 | | | 2005 | | 17,552 | |
Options | | Gas | | (730,000 | ) | | 2006 | | 46,951 | |
Options | | Gas | | (730,000 | ) | | 2007 | | 15,772 | |
Options | | Gas | | (732,000 | ) | | 2008 | | (1,334 | ) |
| | | | | | | | | |
|
|
| | | | | | | | | | 78,941 | |
| | | | |
| Hedging Derivatives | | | | | | | | | | |
| | | | |
Basis Swaps | | Gas | | (5,735,000 | ) | | 2005 | | 2,563 | |
| | | | |
Fixed Swaps/Futures | | Gas | | (28,312,500 | ) | | 2005 | | (108,078 | ) |
Fixed Swaps/Futures | | Gas | | (12,912,500 | ) | | 2006 | | (31,104 | ) |
| | | | | | | | | |
|
|
| | | | | | | | | | (139,182 | ) |
| | | | |
Fixed Index Swaps | | Gas | | 2,640,000 | | | 2005 | | 15,628 | |
Fixed Index Swaps | | Gas | | 3,270,000 | | | 2006 | | 20,827 | |
| | | | | | | | | |
|
|
| | | | | | | | | | 36,455 | |
F-16
Estimated fair values of price risk management assets and liabilities related to the Partnership’s gas marketing activities are sensitive to uncertainty and volatility inherent in the energy commodities markets and actual results could differ from these estimates. The Partnership attempts to maintain balanced positions to protect itself from the volatility in the energy commodities markets; however, net unbalanced positions can exist. Long-term physical contracts are tied to index prices. System gas, which is also tied to index prices, will provide the gas required by our long-term physical contracts. When third-party gas is required to supply long-term contracts, a hedge is put in place to protect the margin on the contract. Financial contracts, which are not tied to physical delivery, will be offset with financial contracts to balance the Partnership’s positions.
The following represents loss on derivative activity for the periods presented:
| | | |
| | | From January 26, 2005 to August 31, 2005 |
| | |
|
|
Unrealized loss recognized in cost of products sold related to Partnership’s derivative activity | | $ | 13,107 |
| |
Realized loss included in cost of products sold | | | 7,410 |
11. Partners’ Capital
ETC OLP owns the 1% general partner and a 97% limited partner interest in HPL. AEP holds a 2% limited partner interest. Limited partner interests in the Partnership entitle the holders thereof to the rights and privileges specified in the Partnership Agreement. Income and loss is generally allocated among the partners in accordance with their percentage interests.
12. Subsequent Events (unaudited)
On November 10, 2005, ETC OLP purchased the 2% limited partner interest in HPL, which it did not already own, from AEP for $16,560 in cash. As a result, HPL became a wholly owned subsidiary of ETC OLP. ETC OLP also reached a settlement agreement with AEP related to the inventory and working capital matters associated with the HPL acquisition discussed in Note 5. The terms of the agreement were not material in relation to the Partnership’s financial position, results of operations or cash flows.
F-17
Report of Independent Registered Public Accounting Firm
To the Partners
HPL Consolidation LP
We have audited the consolidated statements of operations, partners’ capital, and cash flows of HPL Consolidation LP and subsidiaries for the period from January 1, 2005 to January 25, 2005. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the consolidated statements of operations, partners’ capital, and cash flows referred to above present fairly, in all material respects, the results of operations and cash flows of HPL Consolidation LP and subsidiaries for the period from January 1, 2005 to January 25, 2005, in conformity with accounting principles generally accepted in the United States of America.
|
/s/ GRANT THORNTON LLP |
|
Houston, Texas |
December 6, 2005 |
F-18
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Partners of
HPL Consolidation LP:
We have audited the accompanying consolidated balance sheets of HPL Consolidation LP (“the Company”) as of December 31, 2004 and 2003, and the related consolidated statements of operations, cash flows and partners’ capital for each of the three years in the period ended December 31, 2004. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of HPL Consolidation LP as of December 31, 2004, and 2003 and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America.
|
/s/ Deloitte & Touche LLP |
|
Houston, Texas |
March 15, 2005 |
F-19
HPL CONSOLIDATION LP
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands)
| | | | | | | | | | | | | | | | |
| | | Period from
January 1, 2005 to
January 25, 2005
| | | Year Ended December 31,
| |
| | | 2004
| | | 2003
| | | 2002
| |
Operating Revenues | | $ | 305,552 | | | $ | 3,069,160 | | | $ | 3,006,444 | | | $ | 2,123,180 | |
Operating Revenues - Affiliated | | | 55,155 | | | | 862,277 | | | | 899,233 | | | | 573,960 | |
| | |
|
|
| |
|
|
| |
|
|
| |
|
|
|
Total Operating Revenues | | | 360,707 | | | | 3,931,437 | | | | 3,905,677 | | | | 2,697,140 | |
| | |
|
|
| |
|
|
| |
|
|
| |
|
|
|
Operating Expenses | | | | | | | | | | | | | | | | |
Gas Purchases | | | 310,213 | | | | 3,004,001 | | | | 3,340,656 | | | | 2,149,615 | |
Gas Purchases - Affiliated | | | 20,647 | | | | 760,294 | | | | 464,463 | | | | 388,193 | |
Operation and Maintenance | | | 4,344 | | | | 58,960 | | | | 56,508 | | | | 48,868 | |
Administrative and General | | | 1,118 | | | | 17,229 | | | | 15,255 | | | | 17,520 | |
Asset Impairment | | | — | | | | — | | | | 300,000 | | | | — | |
Parent Company Managerial and Professional | | | 607 | | | | 5,512 | | | | 4,991 | | | | 5,372 | |
Depreciation and Amortization | | | 1,171 | | | | 10,655 | | | | 15,149 | | | | 13,246 | |
Taxes Other Than Income Taxes | | | 1,273 | | | | 13,275 | | | | 8,838 | | | | 11,705 | |
| | |
|
|
| |
|
|
| |
|
|
| |
|
|
|
Total Operating Expenses | | | 339,373 | | | | 3,869,926 | | | | 4,205,860 | | | | 2,634,519 | |
| | |
|
|
| |
|
|
| |
|
|
| |
|
|
|
Operating Income (Loss) | | | 21,334 | | | | 61,511 | | | | (300,183 | ) | | | 62,621 | |
| | | | |
Equity Loss of Nonconsolidated Subsidiary | | | (95 | ) | | | (683 | ) | | | (668 | ) | | | (249 | ) |
Interest Income | | | — | | | | 408 | | | | — | | | | — | |
Interest Income - Affiliated | | | 95 | | | | 2,294 | | | | 2,542 | | | | 4,874 | |
Interest Expense | | | — | | | | (36 | ) | | | (70 | ) | | | (723 | ) |
Interest Expense - Affiliated | | | (447 | ) | | | (227 | ) | | | — | | | | — | |
Nonoperating Gain | | | 111 | | | | 3,453 | | | | 213 | | | | 538 | |
| | |
|
|
| |
|
|
| |
|
|
| |
|
|
|
Income (Loss) Before Income Taxes | | | 20,998 | | | | 66,720 | | | | (298,166 | ) | | | 67,061 | |
| | | | |
Income Tax Expense (Credit) | | | 7,477 | | | | 22,694 | | | | (81,595 | ) | | | 23,604 | |
| | |
|
|
| |
|
|
| |
|
|
| |
|
|
|
Net Income (Loss) | | $ | 13,521 | | | $ | 44,026 | | | $ | (216,571 | ) | | $ | 43,457 | |
| | |
|
|
| |
|
|
| |
|
|
| |
|
|
|
See Notes to Consolidated Financial Statements.
F-20
HPL CONSOLIDATION LP
CONSOLIDATED BALANCE SHEETS
ASSETS
(in thousands)
| | | | | | | | |
| | | December 31,
| |
| | | 2004
| | | 2003
| |
CURRENT ASSETS: | | | | | | | | |
Cash and Cash Equivalents | | $ | 220 | | | $ | 2,891 | |
Advances to Affiliates | | | — | | | | 93,868 | |
Accounts Receivable: | | | | | | | | |
Trade Receivables | | | 281,338 | | | | 298,546 | |
Allowance for Uncollectible Accounts | | | (1,348 | ) | | | (1,409 | ) |
Affiliated Companies | | | 34,091 | | | | 39,450 | |
Gas Inventory | | | 221,075 | | | | 3,095 | |
Materials and Supplies | | | 1,573 | | | | 1,550 | |
Exchange Gas Receivables | | | 10,452 | | | | 9,222 | |
Price-Risk Management Assets | | | 22,777 | | | | 36,462 | |
Price-Risk Management Assets – Affiliated | | | 70,981 | | | | 7,378 | |
Other | | | 730 | | | | 824 | |
| | |
|
|
| |
|
|
|
TOTAL CURRENT ASSETS | | | 641,889 | | | | 491,877 | |
| | |
|
|
| |
|
|
|
PROPERTY, PLANT AND EQUIPMENT, net | | | 399,649 | | | | 280,989 | |
| | |
|
|
| |
|
|
|
OTHER NONCURRENT ASSETS | | | 1,846 | | | | 2,349 | |
| | |
|
|
| |
|
|
|
EQUITY INVESTMENT – NONCONSOLIDATED SUBSIDIARY | | | 33,035 | | | | 33,718 | |
| | |
|
|
| |
|
|
|
LONG-TERM – PRICE-RISK MANAGEMENT ASSETS | | | 18,009 | | | | 17,770 | |
| | |
|
|
| |
|
|
|
LONG-TERM – PRICE-RISK MANAGEMENT ASSETS - AFFILIATED | | | 6,040 | | | | 9,571 | |
| | |
|
|
| |
|
|
|
DEFERRED INCOME TAX | | | 98,400 | | | | 122,164 | |
| | |
|
|
| |
|
|
|
TOTAL ASSETS | | $ | 1,198,868 | | | $ | 958,438 | |
| | |
|
|
| |
|
|
|
See Notes to Consolidated Financial Statements.
F-21
HPL CONSOLIDATION LP
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND PARTNERS’ CAPITAL
(in thousands)
| | | | | | | | |
| | | December 31,
| |
| | | 2004
| | | 2003
| |
CURRENT LIABILITIES: | | | | | | | | |
Advances From Affiliates | | $ | 209,992 | | | $ | — | |
Accounts Payable – Trade | | | 172,948 | | | | 263,864 | |
Accounts Payable – Affiliated Companies | | | 86,636 | | | | 47,405 | |
Taxes Accrued | | | 32,017 | | | | 1,981 | |
Exchange Gas Payable | | | 12,747 | | | | 11,994 | |
Price-Risk Management Liabilities | | | 21,474 | | | | 25,715 | |
Other | | | 21,927 | | | | 18,585 | |
| | |
|
|
| |
|
|
|
TOTAL CURRENT LIABILITIES | | | 557,741 | | | | 369,544 | |
| | |
|
|
| |
|
|
|
NONCURRENT LIABILITIES | | | 12,104 | | | | 18,855 | |
| | |
|
|
| |
|
|
|
LONG-TERM PRICE-RISK MANAGEMENT LIABILITIES | | | 24,227 | | | | 12,971 | |
| | |
|
|
| |
|
|
|
PARTNERS’ CAPITAL | | | | | | | | |
Paid-in Capital | | | 740,485 | | | | 772,747 | |
Accumulated Other Comprehensive Income (Loss) | | | 35,683 | | | | (281 | ) |
Accumulated Deficit | | | (171,372 | ) | | | (215,398 | ) |
| | |
|
|
| |
|
|
|
TOTAL PARTNERS’ CAPITAL | | | 604,796 | | | | 557,068 | |
| | |
|
|
| |
|
|
|
TOTAL PARTNERS’ CAPITAL AND LIABILITIES | | $ | 1,198,868 | | | $ | 958,438 | |
| | |
|
|
| |
|
|
|
See Notes to Consolidated Financial Statements.
F-22
HPL CONSOLIDATION LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
| | | | | | | | | | | | | | | | |
| | | Period from January 1, 2005 to January 25, 2005
| | | Year Ended December 31,
| |
| | | 2004
| | | 2003
| | | 2002
| |
OPERATING ACTIVITIES: | | | | | | | | | | | | | | | | |
Net Income (Loss) | | $ | 13,521 | | | $ | 44,026 | | | $ | (216,571 | ) | | $ | 43,457 | |
Adjustments for Noncash Items: | | | | | | | | | | | | | | | | |
Impairment of Long-Lived Assets | | | — | | | | — | | | | 300,000 | | | | — | |
Depreciation and Amortization | | | 1,171 | | | | 10,655 | | | | 15,149 | | | | 13,246 | |
Deferred Income Taxes | | | 3,075 | | | | 4,398 | | | | (81,111 | ) | | | 2,319 | |
Fair Value of Price Risk Management Contracts | | | 41,325 | | | | (3,647 | ) | | | 7,093 | | | | 4,942 | |
Changes in Certain Current Items: | | | | | | | | | | | | | | | | |
Accounts Receivable | | | 30,814 | | | | 17,147 | | | | (36,087 | ) | | | (114,765 | ) |
Accounts Receivable-Affiliated Companies | | | (43,695 | ) | | | 5,359 | | | | 47,954 | | | | 304,030 | |
Gas Inventory, Materials and Supplies | | | 66,802 | | | | (218,003 | ) | | | (2,201 | ) | | | (263 | ) |
Accrued Taxes | | | (6,399 | ) | | | 30,036 | | | | (12,636 | ) | | | (1,663 | ) |
Accounts Payable | | | 7,975 | | | | (90,916 | ) | | | 29,395 | | | | 116,899 | |
Accounts Payable - Affiliated Companies | | | (65,934 | ) | | | 39,231 | | | | (89,066 | ) | | | (86,713 | ) |
Exchange Gas Payable (net) | | | (600 | ) | | | (477 | ) | | | (881 | ) | | | (7,335 | ) |
Other (net) | | | (10,569 | ) | | | 19,012 | | | | (10,015 | ) | | | 2,032 | |
| | |
|
|
| |
|
|
| |
|
|
| |
|
|
|
Net Cash Flows From (Used For) Operating Activities | | | 37,486 | | | | (143,179 | ) | | | (48,977 | ) | | | 276,186 | |
| | |
|
|
| |
|
|
| |
|
|
| |
|
|
|
| | | | |
INVESTING ACTIVITIES: | | | | | | | | | | | | | | | | |
Gross Property Additions | | | (1,516 | ) | | | (16,788 | ) | | | (25,427 | ) | | | (17,118 | ) |
Acquistion of Bammel | | | — | | | | (115,000 | ) | | | — | | | | — | |
Other | | | 99 | | | | 699 | | | | 4,138 | | | | — | |
| | |
|
|
| |
|
|
| |
|
|
| |
|
|
|
Net Cash Used For Investing Activities | | | (1,417 | ) | | | (131,089 | ) | | | (21,289 | ) | | | (17,118 | ) |
| | |
|
|
| |
|
|
| |
|
|
| |
|
|
|
FINANCING ACTIVITIES: | | | | | | | | | | | | | | | | |
Capital Contribution | | | 196,817 | | | | 115,000 | | | | 26,160 | | | | — | |
Return of Capital to Parent | | | — | | | | (147,262 | ) | | | — | | | | (100,000 | ) |
Change in Advances from/to Affiliates (net) | | | (232,896 | ) | | | 303,859 | | | | 59,697 | | | | (123,267 | ) |
Dividend Paid to Parent | | | — | | | | — | | | | (12,700 | ) | | | (38,000 | ) |
| | |
|
|
| |
|
|
| |
|
|
| |
|
|
|
Net Cash From (Used For) Financing Activities | | | (36,079 | ) | | | 271,597 | | | | 73,157 | | | | (261,267 | ) |
| | |
|
|
| |
|
|
| |
|
|
| |
|
|
|
NET INCREASE (DECREASE) IN CASH | | | (10 | ) | | | (2,671 | ) | | | 2,891 | | | | (2,199 | ) |
CASH AT BEGINNING OF PERIOD | | | 220 | | | | 2,891 | | | | — | | | | 2,199 | |
| | |
|
|
| |
|
|
| |
|
|
| |
|
|
|
CASH AT END OF PERIOD | | $ | 210 | | | $ | 220 | | | $ | 2,891 | | | $ | — | |
| | |
|
|
| |
|
|
| |
|
|
| |
|
|
|
SUPPLEMENTAL DISCLOSURE:
Cash paid for interest, net of capitalized amounts was $0 in January 2005 and in 2004 and was $70 and $788 in 2003 and 2002. Cash paid to (refunds received from) Parent for income taxes was $0 in January 2005 and was $(9,537), $12,546 and $20,342 in 2004, 2003, and 2002. See Note 9 for noncash investing activities.
See Notes to Consolidated Financial Statements.
F-23
HPL CONSOLIDATION LP
CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
(in thousands)
| | | | | | | | | | | | | | | | |
| | | Accumulated Other Comprehensive Income (Loss)
| | | Other Paid-In Capital
| | | Retained Earnings (Accumulated Deficit)
| | | Total
| |
December 31, 2001 | | $ | — | | | $ | 846,587 | | | $ | 8,416 | | | $ | 855,003 | |
| | | | |
Dividends Paid to Parent | | | | | | | | | | | (38,000 | ) | | | (38,000 | ) |
Return of Capital to Parent | | | | | | | (100,000 | ) | | | | | | | (100,000 | ) |
| | | | | | | | | | | | | | |
|
|
|
TOTAL | | | | | | | | | | | | | | | 717,003 | |
| | | | | | | | | | | | | | |
|
|
|
| | | | |
COMPREHENSIVE INCOME (LOSS) | | | | | | | | | | | | | | | | |
NET INCOME | | | | | | | | | | | 43,457 | | | | 43,457 | |
| | | | | | | | | | | | | | |
|
|
|
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | 43,457 | |
| | |
|
|
| |
|
|
| |
|
|
| |
|
|
|
December 31, 2002 | | | — | | | | 746,587 | | | | 13,873 | | | | 760,460 | |
Dividends Paid to Parent | | | | | | | | | | | (12,700 | ) | | | (12,700 | ) |
Capital Contributions from Parent | | | | | | | 26,160 | | | | | | | | 26,160 | |
| | | | | | | | | | | | | | |
|
|
|
TOTAL | | | | | | | | | | | | | | | 773,920 | |
| | | | |
COMPREHENSIVE INCOME (LOSS) | | | | | | | | | | | | | | | | |
Other Comprehensive Income (Loss), | | | | | | | | | | | | | | | | |
Cash Flow Hedges, net of $(151) Tax | | | (281 | ) | | | | | | | | | | | (281 | ) |
NET LOSS | | | | | | | | | | | (216,571 | ) | | | (216,571 | ) |
| | | | | | | | | | | | | | |
|
|
|
TOTAL COMPREHENSIVE LOSS | | | | | | | | | | | | | | | (216,852 | ) |
| | |
|
|
| |
|
|
| |
|
|
| |
|
|
|
December 31, 2003 | | | (281 | ) | | | 772,747 | | | | (215,398 | ) | | | 557,068 | |
Capital Contributions from Parent | | | | | | | 115,000 | | | | | | | | 115,000 | |
Return of Capital to Parent | | | | | | | (147,262 | ) | | | | | | | (147,262 | ) |
| | | | | | | | | | | | | | |
|
|
|
TOTAL | | | | | | | | | | | | | | | 524,806 | |
| | | | | | | | | | | | | | |
|
|
|
| | | | |
COMPREHENSIVE INCOME (LOSS) | | | | | | | | | | | | | | | | |
Other Comprehensive Income (Loss), | | | | | | | | | | | | | | | | |
Cash Flow Hedges, net of $19,365 Tax | | | 35,964 | | | | | | | | | | | | 35,964 | |
NET INCOME | | | | | | | | | | | 44,026 | | | | 44,026 | |
| | | | | | | | | | | | | | |
|
|
|
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | 79,990 | |
| | |
|
|
| |
|
|
| |
|
|
| |
|
|
|
December 31, 2004 | | | 35,683 | | | | 740,485 | | | | (171,372 | ) | | | 604,796 | |
Capital Contributions from Parent | | | | | | | 196,817 | | | | | | | | 196,817 | |
| | | | | | | | | | | | | | |
|
|
|
TOTAL | | | | | | | | | | | | | | | 801,613 | |
| | | | | | | | | | | | | | |
|
|
|
| | | | |
COMPREHENSIVE INCOME (LOSS) | | | | | | | | | | | | | | | | |
Other Comprehensive Income (Loss), | | | | | | | | | | | | | | | | |
Cash Flow Hedges | | | (18,582 | ) | | | | | | | | | | | (18,582 | ) |
NET INCOME | | | | | | | | | | | 13,521 | | | | 13,521 | |
| | | | | | | | | | | | | | |
|
|
|
TOTAL COMPREHENSIVE LOSS | | | | | | | | | | | | | | | (5,061 | ) |
| | |
|
|
| |
|
|
| |
|
|
| |
|
|
|
January 25, 2005 | | $ | 17,101 | | | $ | 937,302 | | | $ | (157,851 | ) | | $ | 796,552 | |
| | |
|
|
| |
|
|
| |
|
|
| |
|
|
|
See Notes to Consolidated Financial Statements.
F-24
HPL CONSOLIDATION LP
INDEX TO NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
| | | | |
| | | | | Page
|
1. | | Organization and Summary of Significant Accounting Policies | | F-26 |
| | |
2. | | New Accounting Pronouncements | | F-30 |
| | |
3. | | Commitments and Contingencies | | F-31 |
| | |
4. | | Equity Investment in Nonconsolidated Subsidiary | | F-41 |
| | |
5. | | Impairments | | F-42 |
| | |
6. | | Benefit Plans | | F-42 |
| | |
7. | | Derivatives, Hedging and Financial Instruments | | F-45 |
| | |
8. | | Income Taxes | | F-46 |
| | |
9. | | Leases | | F-48 |
| | |
10. | | Concentration of Credit Risks | | F-49 |
| | |
11. | | Related Party Transactions | | F-49 |
| | |
12. | | Guarantees | | F-50 |
| | |
13. | | Subsequent Events | | F-51 |
F-25
Notes to Consolidated Financial Statements
1. Organization and Summary of Significant Accounting Policies
Organization
Business Operations – HPL Consolidation LP (“We”, “Us”, or “HPL”) was a wholly owned subsidiary of American Electric Power Inc. (“AEP”). HPL was formed in November 2004 in connection with the acquisition of the Bammel storage field leased assets as further described in Note 3. HPL wholly owns the newly formed subsidiary HPL Storage GP, LLC (“HPL GP”), which owns the Bammel storage field assets and Houston Pipe Line Company LP (“HPC”). AEP acquired HPC from Enron Corporation on June 1, 2001. HPL is a fully integrated natural gas gathering, processing, storage, and transportation operation located in the state of Texas. HPL’s gathering and transportation assets include 4,200 miles of gas pipeline and the Bammel gas storage facility with approximately 130 billion cubic feet of capacity. In addition to the pipelines and storage assets, HPL owns a 50% interest in Mid Texas Pipeline Company (“Mid Texas”). Mid Texas’ sole asset is a 139-mile pipeline in South Texas of which HPL is also the operator. Mid Texas is accounted for under the equity method of accounting. HPL is subject to certain regulation with regard to rates and other matters by the Texas Railroad Commission. The formation of HPL and the transfer of ownership of HPC and HPL GP from other AEP subsidiaries to HPL were treated as a reorganization of entities under common control similar to a pooling of interest. Accordingly, the income and expense of HPC for all periods are included in the accompanying financial statements.
On January 26, 2005, AEP sold a 98% controlling interest in us to LaGrange Acquisition, LP (“ETC OLP”), approximately 30 Bcf of working gas and working capital for approximately $1 billion, subject to a working capital and an inventory true-up adjustment. AEP retained a 2% ownership interest in us and provided certain transitional administrative services to ETC OLP. AEP provided an indemnity in an amount up to the purchase price to ETC OLP for damages, if any, arising from litigation with Bank of America (“BOA” or “BofA”) and certain other litigation. (See Note 3). On November 10, 2005, AEP sold their remaining 2% ownership interest in us to ETC OLP. (See Note 13). The transaction is accounted for as if it occurred on January 31, 2005.
Consolidation Policy– The consolidated financial statements include the accounts of HPL and its subsidiaries. All intercompany transactions are eliminated.
Summary of Significant Accounting Policies
Use of Estimates – The preparation of these financial statements in conformity with accounting principles generally accepted in the United States of America necessarily includes the use of estimates and assumptions by management. Actual results could differ from those estimates.
Property, Plant and Equipment – Property, plant and equipment are stated at their fair market value at the date of acquisition plus the original cost of property acquired or constructed since acquisition, less disposals. Additions, major replacements and betterments are added to the plant accounts. Retirements from the plant accounts are deducted from accumulated depreciation, net of salvage. The costs of labor, materials and overhead incurred to operate and maintain plant and equipment are included in operating expenses. Assets are tested for impairment as required under Statement of Financial Accounting Standards (“SFAS”) No. 144 (See Note 2).
F-26
Interest Capitalization – Interest is capitalized during construction in accordance with SFAS 34, “Capitalization of Interest Costs.” The amount of interest capitalized was not material for the period from January 1, 2005 to January 25, 2005 or for the years ended December 31, 2004, 2003 and 2002.
Depreciation and Amortization – Depreciation of plant and equipment is provided on a straight-line basis over their estimated useful lives and is calculated largely through the use of annual composite rates by functional class. The components and useful lives of property, plant, and equipment were as follows (in thousands):
| | | | | | | | |
| | | December 31, 2004
| | | December 31, 2003
| |
Land and Improvements | | $ | 2,295 | | | $ | 2,267 | |
Buildings and Improvements (3 to 33 Years) | | | 6,898 | | | | 6,447 | |
Pipelines and Equipment (19 to 50 Years) | | | 264,282 | | | | 257,374 | |
Natural Gas Storage Facilities (30 to 35 Years) | | | 104,180 | | | | 2,817 | |
Tanks and Other Equipment (15 to 36 Years) | | | 8,530 | | | | 7,851 | |
Vehicles (4 Years) | | | 390 | | | | 533 | |
Right of Way (30 Years) | | | 1,778 | | | | 1,831 | |
Furniture and Fixtures (7 to 35 Years) | | | 1,128 | | | | 1,107 | |
Linepack | | | 3,690 | | | | 3,690 | |
Pad Gas | | | 20,519 | | | | 8,630 | |
Other (3 to 12 Years) | | | 6,931 | | | | 6,484 | |
| | |
|
|
| |
|
|
|
| | | | 420,621 | | | | 299,031 | |
Less – Accumulated Depreciation | | | (41,381 | ) | | | (32,491 | ) |
| | |
|
|
| |
|
|
|
| | | | 379,240 | | | | 266,540 | |
Plus – Construction work-in-process | | | 20,409 | | | | 14,449 | |
| | |
|
|
| |
|
|
|
Property, Plant and Equipment, Net | | $ | 399,649 | | | $ | 280,989 | |
| | |
|
|
| |
|
|
|
Valuation of Non-Derivative Financial Instruments –The book values of Cash and Cash Equivalents, Accounts Receivable, Short-term Debt and Accounts Payable approximate fair value because of the short-term maturity of these instruments.
Cash and Cash Equivalents – Cash and cash equivalents include temporary cash investments with original maturities of three months or less.
Inventory – Inventories consist of natural gas in storage and in pipelines. During the year ended December 31, 2004, we purchased 45.4 Bcf ($228.2 million) of gas from AEP, which was being stored in the Bammel gas storage field. The gas inventory required to maintain company owned storage facility and pipeline minimum pressures is capitalized and classified as Property, Plant and Equipment. Gas inventory quantities in excess of the minimums, and gas held in third party facilities are carried at the lower of cost or market, utilizing the weighted average cost flow method.
Accounts Receivable – Customer accounts receivable primarily includes receivables from wholesale and retail gas customers, receivables from gas contract counterparties related to our risk management activities and customer receivables primarily related to other revenue-generating activities.
F-27
Materials and Supplies – Materials and Supplies inventories are carried at weighted average cost.
Exchange Gas Receivables and Payables – Exchange imbalance receivables from customers are valued at the lower of cost or market. Exchange imbalance payables to customers are valued at the higher of cost or market.
Revenue Recognition
Domestic Gas Pipeline and Storage Activities
Revenues are recognized from domestic gas pipeline and storage services when gas is delivered to contractual meter points or when services are provided, with the exception of certain physical forward gas purchase and sale contracts that are derivatives and that are accounted for using fair value accounting.
Marketing and Risk Management Activities
We engage in wholesale natural gas marketing and risk management activities. Effective in October 2002, these activities were focused on wholesale markets where we own assets. Our activities include the purchase and sale of gas under forward contracts at fixed and variable prices and the buying and selling of financial gas contracts, which include exchange traded futures and options, and over-the-counter options and swaps.
Accounting for Derivative Instruments
We use the fair value method of accounting for derivative contracts in accordance with SFAS 133. Unrealized gains and losses prior to settlement, resulting from revaluation of these contracts to fair value during the period, are recognized currently. When the derivative contracts are settled and gains and losses are realized, the previously recorded unrealized gains and losses from mark-to-market valuations are reversed.
Certain derivative instruments are designated as a hedge of a forecasted transaction or future cash flow (cash flow hedge). For derivatives designated as cash flow hedges, the effective portion of the derivative’s gain or loss is initially reported as a component of Accumulated Other Comprehensive Income and subsequently reclassified into Revenues in the Consolidated Statement of Operations when the forecasted transaction affects earnings. The ineffective portion of the gain or loss is recognized in Revenues in the Consolidated Statement of Operations immediately. For the period from January 1, 2005 to January 25, 2005 and the year ended 2004, we classified immaterial amounts into earnings as a result of hedge ineffectiveness related to our cash flow hedging strategies.
The fair values of derivative instruments accounted for using fair value accounting or hedge accounting are based on exchange prices and broker quotes, when available. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes and supply and demand market data and assumptions. The fair values determined are reduced by the appropriate valuation adjustments for items such as discounting, liquidity and credit quality. Credit risk is the risk that the counterparty to the contract will fail to perform or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to be less than or more than what the price should be based purely on supply and demand. There are inherent risks related to the underlying assumptions in models used to fair
F-28
value open long-term risk management contracts. We have independent controls to evaluate the reasonableness of our valuation models. However, gas markets are imperfect and volatile. Unforeseen events can and will cause reasonable price curves to differ from actual prices throughout a contract’s term and at the time a contract settles. Therefore, there could be significant adverse or favorable effects on future results of operations and cash flows if market prices are not consistent with our approach at estimating current market consensus for forward prices in the current period. This is particularly true for long-term contracts.
We recognize all derivative instruments at fair value in our Consolidated Balance Sheets as either “Price Risk Management Assets” or “Price Risk Management Liabilities” unless we have elected to treat the contracts as normal purchases or normal sales in accordance with the provisions of SFAS 133. Unrealized and realized gains and losses on all derivative instruments are ultimately included in Operating Revenues in the Consolidated Statement of Operations on a net basis, with the exception of physically settled purchases of natural gas. The unrealized and realized gains and losses on these purchases are presented as Gas Purchases in the Consolidated Statements of Operations.
Material Contract Obligations not Reflected at Fair Value - HPL has entered into a number of contracts for services and gas purchase and sale contracts that are not reflected in the financial statements at fair value. The service contracts include the provision of storage, transportation, or gas processing services to customers for periods ranging from one month to three years. These transactions are recorded and reflected in revenues in the period in which the service is provided. Similarly, the subsidiaries Houston Pipe Line Company LP and AEP Gas Marketing, LP have contracts, generally with a term of one year or less, to purchase transportation services on third party pipelines. These costs are recorded and reflected in gas purchases in the period in which the service is utilized. A number of HPL’s gas purchase and sale contracts, which are generally for terms less than three years, primarily include purchases and sales of non-firm quantities of gas, which do not qualify for fair value accounting under SFAS 133, or contracts that are considered derivatives but are not fair valued as permitted by the normal purchase and sale exemption under SFAS 133. These transactions are recorded and reflected in revenues or cost of sales in the period in which the gas is delivered or received.
Maintenance Costs – Maintenance costs are expensed as incurred.
Nonoperating Gain – Nonoperating Gain includes gains on dispositions of property, and various other non-operating and miscellaneous income.
Income Taxes – For U.S. federal income tax purposes, we are considered a partnership. Therefore, we are not separately subject to U.S. federal tax on income, but are taxed in combination with AEP’s items of income and expense. Our subsidiaries are also generally partnerships not subject to U.S. federal income tax. We are party to a tax sharing agreement with AEP. The terms of the agreement require us to make payment to or receive refunds from AEP for taxes that are attributable to our operations, or any of our subsidiaries’ operations. We follow the liability method of accounting for income taxes. Under the liability method, deferred income taxes are provided for all temporary differences between the book cost and tax basis of assets and liabilities, which will result in a future tax consequence. (See Note 8).
Excise Taxes – As an agent for a state or local government, we collect from customers certain excise taxes levied by the state or local government upon the customer. We do not recognize these taxes as revenue or expense.
F-29
Goodwill and Intangible Assets– When we acquire businesses we record the fair value of any acquired goodwill and other intangible assets. Purchased goodwill and intangible assets with indefinite lives are not amortized. We test acquired goodwill and other intangible assets with indefinite lives for impairment at least annually. Intangible assets with finite lives are amortized over their respective estimated lives to their residual values.
The policies described above became effective with our adoption of a new accounting standard for goodwill (SFAS 142). For all business combinations with an acquisition date before July 1, 2001, we amortized goodwill and intangible assets with indefinite lives through December 2001, and then ceased amortization. The goodwill associated with those business combinations with an acquisition date before July 1, 2001 was amortized on a straight-line basis generally over 40 years. Intangible assets with finite lives continue to be amortized over their respective estimated lives generally over 7 years.
The balance in Goodwill was $0 December 31, 2004 and 2003. (See Note 5).
Acquired intangible assets subject to amortization include acquired miscellaneous intangibles with a gross carrying amount of $2.7 million at December 31, 2004 and $2.4 million at December 31, 2003. Accumulated Amortization was $1.2 million and $.9 million as of December 31, 2004 and 2003. Amortization Expense was $.1 million for the period from January 1, 2005 to January 25, 2005 and $.3 million in each of the years ended December 31, 2004, 2003, and 2002. Estimated annual amortization expense is $.3 million for each of the years ended December 31, 2005, 2006, 2007, 2008, and 2009.
Comprehensive Income (Loss) - Comprehensive income is defined as the change in equity (net assets) of a business enterprise during a period from transactions and other events and circumstances from non-owner sources. It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. Comprehensive income has two components, net income and other comprehensive income.
Reclassification – Certain prior year financial statement items have been reclassified to conform to current year presentation. Such reclassifications had no impact on previously reported net income.
2. New Accounting Pronouncements
SFAS 143 “Accounting for Asset Retirement Obligations”
In implementing SFAS 143, “Accounting for Asset Retirement Obligations,” effective January 1, 2003, which requires entities to record a liability at fair value for any legal obligations for asset retirements in the period incurred, we have identified, but not recognized, asset retirement obligation liabilities related to gas pipeline assets, as a result of certain easements on property on which we have assets. Generally, such easements are perpetual and require only the retirement and removal of our assets upon the cessation of the property’s use. The retirement obligation cannot be estimated for such easements since we plan to use our facilities indefinitely. The retirement obligation would only be recognized if and when we abandon or cease the use of specific easements.
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SFAS 144 “Accounting for the Impairment or Disposal of Long-lived Assets”
In August 2001, the FASB issued SFAS 144, “Accounting for the Impairment or Disposal of Long-lived Assets” which sets forth the accounting to recognize and measure an impairment loss. This standard replaced SFAS 121, “Accounting for Long-lived Assets and for Long-lived Assets to be Disposed Of.” We adopted SFAS 144 effective January 1, 2002. See Note 5 for discussion of impairments recognized in 2003.
SFAS 149 “Amendment of Statement 133 on Derivative Instruments and Hedging Activities”
On April 30, 2003, the FASB issued Statement No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities” (SFAS 149). SFAS 149 amends SFAS 133 to clarify the definition of a derivative and the requirements for contracts to qualify for the normal purchase and sale exemption. SFAS 149 also amends certain other existing pronouncements. Effective July 1, 2003, we implemented SFAS 149 and the effect was not material to our results of operations, cash flows or financial condition.
FIN 45 “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others”
In November 2002, the FASB issued FIN 45 which clarifies the accounting to recognize liabilities related to issuing a guarantee, as well as additional disclosures of guarantees. We implemented FIN 45 as of January 1, 2003, and the effect was not material to our results of operations, cash flows or financial condition. There are no guarantees which require disclosure in accordance with FIN 45.
EITF 03-11 “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not “Held for Trading Purposes” as Defined in Issue No. 02-3”
In July 2003, the EITF reached consensus on Issue No. 03-11. The consensus states that realized gains and losses on derivative contracts not “held for trading purposes” should be reported either on a net or gross basis based on the relevant facts and circumstances. Reclassification of prior year amounts was not required. The adoption of EITF 03-11 did not have a material impact on our results of operations, financial position or cash flows.
Future Accounting Changes
The FASB’s standard-setting process is ongoing. Until new standards have been finalized and issued by FASB, we cannot determine the impact on the reporting of our operations that may result from any such future changes.
3. Commitments and Contingencies
Commitments
HPL enters into contracts as part of their normal business activities. Most long-term contracts for purchase or sale of gas have pricing provisions referencing recognized market indexes. These contracts have force majeure provisions that would release HPL Companies from their obligation under certain conditions.
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HPL’s long-term contracts for transportation, exchange, and processing of natural gas have varying term provisions, with some terms extending out until the year 2013. The majority of the contracts contain evergreen provisions, and many are currently already in their evergreen period. The contracts provide for periodic price adjustments and contain various clauses that would release HPL from their obligation under certain force majeure conditions.
HPL has contracted to sell certain quantities of processed gas liquids under long-term agreements providing for market-based rates in some instances through the year 2006. HPL could be released from their obligation under certain force majeure conditions.
Enron Bankruptcy
In 2002, certain subsidiaries of AEP, including HPC, filed claims against Enron and its subsidiaries in the bankruptcy proceeding pending in the U.S. Bankruptcy Court for the Southern District of New York. At the date of Enron’s bankruptcy, certain subsidiaries of AEP had open trading contracts and trading accounts receivables and payables with Enron. In addition, on June 1, 2001, AEP purchased HPC from Enron. Various HPL-related contingencies and indemnities from Enron remained unsettled at the date of Enron’s bankruptcy.
Enron Bankruptcy – Bammel storage facility and HPL indemnification matters –In connection with the 2001 acquisition of HPC, AEP Energy Services Gas Holding Company (“AEPESGH”) entered into a prepaid arrangement under which AEP acquired exclusive rights to use and operate the underground Bammel gas storage facility and appurtenant pipeline pursuant to an agreement with BAM Lease Company. This exclusive right to use the referenced facility is for a term of 30 years, with a renewal right for another 20 years.
In January 2004, AEP filed an amended lawsuit against Enron and its subsidiaries in the U.S. Bankruptcy Court claiming that Enron did not have the right to reject the Bammel storage facility agreement or the cushion gas use agreement, described below. In April 2004, AEP and Enron entered into a settlement agreement under which AEP acquired title to the Bammel gas storage facility and related pipeline and compressor assets, plus 10.5 billion cubic feet (BCF) of natural gas currently used as cushion gas for $115 million, which increased HPL’s property, plant and equipment account, of which $11.9 million was allocated to Pad Gas and the remainder to Natural Gas Storage Facilities. AEP and Enron agreed to release each other from all claims associated with the Bammel facility, including AEPESGH’s indemnity claims. The settlement received Bankruptcy Court approval in September 2004 and closed in November 2004. The parties’ respective trading claims and BOA’s purported lien on approximately 55 BCF of natural gas in the Bammel storage reservoir (as described below) are not covered by the settlement agreement.
Enron Bankruptcy – Right to use of cushion gas agreements –In connection with the 2001 acquisition of HPC, AEPESGH also entered into an agreement with BAM Lease Company, which grants HPL the exclusive right to use approximately 65 BCF of cushion gas (including the 10.5 BCF described in the preceding paragraph) required for the normal operation of the Bammel gas storage facility. At the time of the acquisition of HPC, BOA and certain other banks (the BOA Syndicate) and Enron entered into an agreement granting HPL the exclusive use of 65 BCF of cushion gas. Also at the time of the acquisition, Enron and the BOA Syndicate also released HPL from all prior and future liabilities and obligations in connection with the financing arrangement.
After the Enron bankruptcy, HPL was informed by the BOA Syndicate of a purported default by Enron under the terms of the financing arrangement. In July 2002, the BOA Syndicate filed a
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lawsuit against HPL in state court in Texas seeking a declaratory judgment that the BOA Syndicate has a valid and enforceable security interest in gas purportedly in the Bammel storage reservoir. In December 2003, the Texas state court granted partial summary judgment in favor of the BOA Syndicate. HPL appealed this decision. In June 2004, BOA filed an amended petition in a separate lawsuit in Texas state court seeking to obtain possession of up to 55 BCF of storage gas in the Bammel storage facility or its fair value. Following an adverse decision on its motion to obtain possession of this gas, BOA voluntarily dismissed this action. In October 2004, BOA refiled this action. HPL filed a motion to have the case assigned to the judge who heard the case originally and that motion was granted. BOA has filed a motion for further relief in that case, claiming rights against gas located in the Bammel storage facility, and a hearing has been held on that motion, but HPL has opposed that motion and no action on that motion has been taken by the court. HPL intends to defend vigorously against BOA’s claims.
In October 2003, AEP filed a lawsuit against BOA in the United States District Court for the Southern District of Texas. BOA led a lending syndicate involving the 1997 gas monetization that Enron and its subsidiaries undertook and the leasing of the Bammel underground gas storage reservoir to HPL. The lawsuit asserts that BOA made misrepresentations and engaged in fraud to induce and promote the stock sale of HPC, that BOA directly benefited from the sale of HPC and that AEP undertook the stock purchase and entered into the Bammel storage facility lease arrangement with Enron and the cushion gas arrangement with Enron and BOA based on misrepresentations that BOA made about Enron’s financial condition that BOA knew or should have known were false including that the 1997 gas monetization did not contravene or constitute a default of any federal, state, or local statute, rule, regulation, code or any law. AEPESGH, joined by HPC and HPL Resources Company LP, later amended the claims in the lawsuit to include claims for declaratory relief regarding the Bammel reservoir and the right to use and cushion gas consent agreements. In February 2004, BOA filed a motion to dismiss this Texas federal lawsuit. In September 2004, the Magistrate Judge issued a Recommended Decision and Order recommending that BOA’s Motion to Dismiss be denied, that the five counts in the lawsuit seeking declaratory judgments involving the Bammel reservoir and the right to use and cushion gas consent agreements be transferred to the Southern District of New York and that the four counts alleging breach of contract, fraud and negligent misrepresentation proceed in the Southern District of Texas. BOA objected to the Magistrate Judge’s decision. The United States District Court for the Southern District of Texas affirmed the Magistrate Judge’s decision and denied BOA’s motion to dismiss the claims made in the litigation by AEPSGH, HPC, and HPL Resources Company LP. The court also transferred the declaratory judgment claims made by HPC and HPL Resources Company LP to the United States District Court for the Southern District of New York, where they remain pending. Discovery is ongoing in the proceedings in both the Southern District of Texas and the Southern District of New York.
In February 2004, in connection with BOA’s dispute, Enron filed Notices of Rejection regarding the cushion gas exclusive right to use agreement and other incidental agreements. AEP has objected to Enron’s attempted rejection of these agreements.
On January 26, 2005, AEP sold a 98% limited partner interest in HPL. AEP has indemnified the buyer of the 98% interest in HPL against any damages resulting from the BOA litigation. (See Note 1).
Litigation and Other Contingencies
We are party to various legal proceedings. For each of these matters, we evaluate the merits of the case, our exposure to the matter, and possible legal or settlement strategies and the likelihood of
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an unfavorable outcome. If we determine that an unfavorable outcome is probable and can be estimated, we make the necessary accruals. As new information becomes available, our estimates may change. Following is a discussion of several of our more significant matters.
*False Claims Act Litigation brought by Jack J. Grynberg on behalf of the United States of America, In re Natural Gas Royalties Qui Tam Litigation, MDL Docket No. 1293 (D. Wyo.) (“Grynberg II”). Generally, these complaints allege an industry-wide conspiracy to under-report the heating value as well as the volumes of natural gas produced from federal and Native American lands, which deprived the U.S. Government of royalties. Grynberg also alleges that transactions between the defendants and their affiliates have caused royalty underpayments. These matters have been consolidated for pretrial purposes. HPL is named as defendant.
In May 2001, the court denied the defendants’ motions to dismiss.
In July 2000, the U.S. government moved to dismiss some of the so-called “valuation” claims in all the consolidatedGrynberg II cases, including those against HPL. The government sought dismissal of two categories of allegations: one deals with the alleged deduction of costs in excess of the “reasonable actual costs incurred” for transportation services; the other concerns alleged sales to affiliates. In October 2002, the Court granted the government’s motion to dismiss. The Court based its ruling on the statutory authority of the United States to seek dismissal of a False Claims Act case when that dismissal would serve a legitimate government purpose. The Court essentially ruled that Grynberg’s pursuit of his valuation claims would interfere with the government’s ability to pursue royalty valuation claims in another False Claims Act case filed by a different relator. Grynberg was ordered to file amended complaints encompassing his remaining mis-measurement claims, and Grynberg did so. Grynberg’s attempt to obtain interlocutory review was unsuccessful.
On June 4, 2002, the defendants (including HPC) filed various motions to dismiss the case, arguing that the court does not have subject matter jurisdiction under the public disclosure bar and the voluntary disclosure provisions of the False Claims Act. On May 13, 2005, Special Master Pringle issued a ruling recommending the dismissal of Houston Pipe Line Company LP and others. This recommendation is set to be heard by the Court on December 9, 2005 in Wyoming.
The defendants believe the lawsuit is not meritorious, have successfully urged the U.S. not to intervene in the cases, and are contesting the claims vigorously.
*Bank of America, N.A., as Administrative Agent, and as Representative of Wilmington Trust Company, Trustee of The Bammel Gas Trust v. Houston Pipe Line Company LP;Cause No. 2002-36488 in the District Court of Harris County, Texas, 280th Judicial District. This matter was filed in July 2002. Through the lawsuit, BofA sought declaratory relief from a Texas state district court regarding its rights in “up to 55 Bcf” of “Storage Gas” allegedly stored in the Bammel Storage Facility operated by HPL. BofA claimed to seek this relief as the alleged “Administrative Agent” for a group of lenders to entities related to Enron, as well as the alleged “Representative” of the Bammel Gas Trust, the entity that BofA claims owns the “Storage Gas” at issue. BofA claims that through a financing transaction involving Enron Corp. in 1997 – which was restructured at the time AEP, through its wholly owned subsidiary AEPESGH acquired HPC
| * | AEP has indemnified the buyer of the 98% interest in HPL against any damages resulting from this litigation. |
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from Enron in 2001 – it holds, as “Administrative Agent” for a group of lenders, a security interest in “up to 55 Bcf” of “Storage Gas” located in the Bammel Storage Facility. BofA initially claimed that as “Administrative Agent” it had the right under the security interest and other financing documents to foreclose on the “Storage Gas,” both on behalf of the lender group and as “Representative” of the Bammel Gas Trust. BofA also sought its attorneys’ fees and expenses and court costs.
For its response, HPC denied BofA’s claims and also asserted various affirmative defenses to the claims for declaratory relief by BofA. HPC also filed counterclaims against BofA, on grounds that the efforts by BofA to execute on the claimed security interest breached contractual obligations entered into by BofA and the Bammel Gas Trust at the time of the 2001 acquisition. The contractual rights sought to be enforced by HPC include a contractual right, consented to by BofA, to use any gas against which BofA might assert a security interest for operation of the Bammel Storage Facility. HPC sought a recovery of actual damages, including but not limited to attorneys’ fees and expenses, on its counterclaims.
Both sides filed motions for summary judgment as to various claims. On December 9, 2003, the court entered a final judgment dismissing HPC’s counterclaims with prejudice and granting BofA’s requests for declaratory judgment in part. The trial court entered declarations that (1) HPC is estopped to deny that the Trustee of the Bammel Gas Trust is the owner of the “Storage Gas”; (2) BofA has a security interest that is, “as against HPC,” a valid and first priority security interest in the “Storage Gas”; (3) a “Guaranty Default” has occurred under the financing, through Enron-related bankruptcy filings; (4) and any rights of HPC’s to use the “Storage Gas” under various 2001 agreements is “subject to” BofA’s claimed rights in “Storage Gas.” BofA nonsuited its claims for declaratory relief relating to enforcement of its claimed interests in the “Storage Gas.” HPC believes that a significant number of issues were left unresolved by the trial court’s judgment, including but not limited to the issue of whether BofA can enforce its claimed interests in the “Storage Gas” and, if so, in what manner; and the issue of to what amount of gas presently stored in the Bammel Storage Facility, if any, those claimed interests attach. HPC has taken an appeal from the trial court’s judgment, which is pending. Briefing on the appeal has been filed, and the appeal remains pending.
During the pendency of the appeal, on January 7, 2004, BofA filed Cause No. 2004-00384 against HPC, alleging that HPC breached contractual obligations with BofA by allegedly withdrawing, or permitting the depletion of, the aggregate quantity of recoverable natural gas in the Bammel Storage Reservoir to less than 40 Bcf. BofA sought damages as well as declaratory and injunctive relief against HPC relating to these agreements.
On January 30, 2004, HPC filed an answer generally denying BofA’s claims. HPC then removed the state court action to federal court on February 2, 2004. While pending in federal court, the case was styled as C.A. No. H-04-0405;Bank of America, N.A., As Administrative Agent, and As Representative of The Bank of New York, Trustee of the Bammel Gas Trust v. Houston Pipe Line Company LP; In the United States District Court for the Southern District of Texas, Houston Division. The case was remanded back to state court on May 24, 2004. BofA then amended its petition to assert additional claims for the immediate possession of 55 Bcf of natural gas stored in the Bammel Storage Facility.
On July 27, 2004, BofA filed an application for and obtained anex parte writ of sequestration regarding natural gas allegedly stored in the Bammel Storage Facility. HPC moved to dissolve the writ. After a full-day evidentiary hearing held on August 6, 2004, the district court indicated that it intended to vacate or modify its July 27, 2004 order pending resolution of HPC’s appeal of
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the final judgment and the ongoing federal declaratory and bankruptcy litigation described below. On August 11, 2004, BofA nonsuited Cause No. 2004-00384 without prejudice. On August 13, 2004, the court entered an order of dismissal in which, in addition to dismissing the lawsuit, vacated the July 27, 2004 order and dissolved the writ of sequestration.
On October 6, 2004, BofA filed a “petition for further relief to enforce declaratory judgment” with the trial court in Cause No. 2002-36488. By this filing, BofA sought to enforce its claimed rights under the final judgment through, among other things, the sequestration of an amount of gas sufficient to protect its claimed rights under the final judgment and/or an order allowing BofA to take immediate possession of 55 Bcf of gas located in the Bammel Storage Facility. Following this filing, Cause No. 2002-36488 was administratively transferred from the 280th District Court of Harris County (where the case had been pending and the final judgment had been entered) to the 133rd District Court, in which BofA had initiated the writ of sequestration proceedings in Cause No. 2004-00384. On December 17, 2004, BofA filed an “application for further relief to enforce final judgment,” seeking much of the same relief previously sought by the earlier-filed application for writ of sequestration in Cause No. 2004-00384 and “petition for further relief” in Cause No. 2002-36488, including a request for an order authorizing BofA to take possession of 55 Bcf of “Storage Gas” allegedly located in the Bammel Storage Facility. A hearing on BofA’s application was held on March 14, 2005. HPL has opposed that motion and no action on that motion has been taken by the court.
Since the filing of the foregoing action, AEP has filed a related suit styledAEP Energy Services Gas Holding Company, Houston Pipe Line Company LP, and HPL Resources Company LP v. Bank of America, N.A., as “Administrative Agent,” as “Master Swap Counterparty,” as “Secured Party,” and as “Purchaser”; and The Bank of New York, as Trustee of the Bammel Gas Trust; Civil Action No. H-03-4973 in the United States District Court for the Southern District of Texas, Houston Division. On October 31, 2003, AEPESGH filed suit against Bank of America, N.A. (“BofA”) for breach of contract and negligent misrepresentation in connection with the acquisition by AEPESGH of HPC from Enron Corp. in 2001. AEPESGH alleged that BofA breached contractual covenants and committed negligent misrepresentation in connection with its representations to AEPESGH relating to Enron’s financial condition. On January 8, 2004, AEPESGH, along with HPC and HPL Resources Company LP (“HPLR”) (the last two of which are HPL Consolidation LP entities), amended and supplemented the complaint to include additional claims, including fraud claims by AEPESGH against BofA and requests for declaratory relief related to issues left unresolved by the trial court in Harris County, including the issues of whether BofA can enforce its claimed interests in the “Storage Gas” and, if so, in what manner; and the issue of to what amount of gas presently stored in the Bammel Storage Facility, if any, those claimed interests attach.
In addition to the declaratory relief and attorneys’ fees and costs sought by all plaintiffs, AEPESGH seeks to recover actual and exemplary damages from BofA.
BofA has filed a motion to dismiss the case for lack of subject matter jurisdiction and on grounds of collateral estoppel and res judicata. AEPESGH, along with the other Plaintiffs, filed its opposition to this motion. The motion was referred to a United States Magistrate Judge. On September 14, 2004, the Magistrate Judge issued an order recommending that BofA’s motion to dismiss be denied in its entirety. The magistrate judge also ordered that the Plaintiffs’ declaratory claims should be severed and transferred to the United States District Court for the Southern District of New York.
BofA has filed objections to the Magistrate Judge’s recommendations and order of transfer. AEPESGH, along with the other Plaintiffs, timely filed responses to these objections. The United
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States District Court for the Southern District of Texas affirmed the Magistrate Judge’s decision and denied BOA’s motion to dismiss the claims made in the litigation by AEPSGH, HPC, and HPL Resources Company LP. The court also transferred the declaratory judgment claims made by HPC and HPL Resources Company LP to the United States District Court for the Southern District of New York, where they remain pending. Discovery is ongoing in the proceedings in both the Southern District of Texas and the Southern District of New York.
*In addition to the previously described federal lawsuit, AEP has filed an adversary proceeding in the Enron Corp. bankruptcy styledHouston Pipe Line Company LP, HPL Resources Company LP, and AEP Energy Services Gas Holding Company v. Enron Corp., ENA Asset Holdings, L.P., BAM Lease Company, the Bammel Gas Trust, the Bank of New York, as Trustee of the Bammel Gas Trust, and Bank of America, N.A., Individually and as Administrative Agent; Adversary No. 03-93372, as filed in Case No. 01-16045 (AJG) in the United States Bankruptcy Court for the Southern District of New York. On November 21, 2003, HPC, HPL Resources Company LP, and AEPESGH (“Plaintiffs”) filed an adversary proceeding against Enron Corp., ENA Asset Holdings, L.P., BAM Lease Company, the Bammel Gas Trust, the Bank of New York, as Trustee of the Bammel Gas Trust, and Bank of America, N.A., individually and as Administrative Agent (“Defendants”). Plaintiffs sought a declaration of their rights with respect to the documents executed in connection with the 2001 acquisition of HPC and HPL Resources Company LP by AEPESGH.
Plaintiffs seek declarations, among others, that various agreements under which Plaintiffs use and operate the Bammel Storage Facility and its appurtenances, including pipelines and cushion gas in the facility (the “Bammel Storage Assets”), are not subject to rejection under bankruptcy law principles; and that even if these agreements could be rejected, Plaintiffs would be entitled to maintain possession of and use these assets for the contractual period provided for under these agreements.
On January 29, 2003, following the filing of the amended and supplemental complaint in the matter described above, Plaintiffs amended their complaint in the adversary proceeding to remove claims made in that proceeding against Bank of America, N.A.
Discovery in the adversary proceeding has commenced, and absent a settlement Plaintiffs intend to pursue their claims vigorously as against the Enron-related parties to the adversary proceeding.
*John and Heather Maher, et al, and all others similarly situated v. CenterPoint Energy, Inc. d/b/a Reliant Energy, Incorporated, et al.;Cause No. 38075, in the 23rd Judicial district Court of Wharton County, Texas. This lawsuit was filed in October 2002 on behalf of two residents of Wharton County, Texas against a number of entities related to CenterPoint Energy, Inc. and Kinder Morgan Inc. Plaintiffs have also named HPL Consolidation LP subsidiaries HPC, its general partner, HPL GP, LLC and AEP Gas Marketing LP (now HPL Gas Marketing LP) as defendants. Plaintiffs allege fraud, violations of the Texas Deceptive Trade Practices Act, the Texas Utility Code, and Texas antitrust laws with respect to an alleged effort to inflate the cost of natural gas used by the CenterPoint utility to provide residential service to customers throughout Texas. When the lawsuit was initiated, Plaintiffs also sought to certify a class and to be named as the representatives of the class.
The defendants, including the HPL Consolidation LP subsidiaries, filed motions to dismiss the case on grounds, among others, that primary jurisdiction over claims raised by Plaintiffs with respect to rates charged to residential consumers of natural gas resided in the Texas Railroad Commission. The parties commenced to take discovery related to threshold issues of subject matter jurisdiction, venue, and the class certification request.
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On February 4, 2005, Plaintiffs filed an amended petition in which they removed all class action allegations. Plaintiffs added AEP Energy Services, Inc. as a defendant, as well as eight additional defendants affiliated with CenterPoint or Kinder Morgan. Plaintiffs continue to allege fraud, violations of the Texas Deceptive Trade Practices Act, the Texas Utility Code, and the Texas antitrust laws with respect to an alleged effort to inflate the cost of natural gas used by the CenterPoint utility to provide residential service to customers throughout Texas.
On February 11, 2005, the CenterPoint Defendants removed the action to federal court in the United States District Court for the Southern District of Texas, Houston Division on the basis of a federal question related to Plaintiffs’ newly asserted allegations against CenterPoint Energy Gas Transmission Company, an interstate natural gas transportation and storage services company. The HPL Consolidation LP subsidiaries, AEP Energy Services, Inc. (“AEPES”), a wholly owned subsidiary of AEP, and the Kinder Morgan Defendants consented to the removal. The case was dismissed without prejudice by the Plaintiffs in March 2005.
*Weldon Johnson and Guy W. Sparks, individually and as representatives of others similarly situated v. CenterPoint Energy, Inc., et al.; Cause No. 04-327-02, in the Circuit Court of Miller County, Arkansas. On October 8, 2004, Plaintiffs filed this lawsuit on behalf of two individuals, one a resident of Arkansas and the other a resident of Texas, seeking to certify a nationwide class action against the same HPL Consolidation LP subsidiaries named in theMaher case and a number of entities related to CenterPoint Energy, Inc. (“CenterPoint”) and Kinder Morgan Inc. (“Kinder Morgan”). Plaintiffs allege fraud and civil conspiracy claims against all of the defendants and seek an unspecified amount in damages for alleged unjust enrichment, actual damages, punitive and exemplary damages, attorneys’ fees, and interest.
On November 18, 2004, the CenterPoint Defendants removed the action to the United States District Court in the Western District of Arkansas, Texarkana Division on the basis of a federal question. The HPL and Kinder Morgan Defendants consented to the removal. On January 26, 2005, Plaintiffs filed a motion to remand. On February 10, 2005, the CenterPoint Defendants filed a response to the motion to remand. The federal district court remanded the case to the Circuit Court of Miller County, Arkansas in June 2005, where it remains pending.
In August 2005, the HPL Consolidation LP subsidiaries Defendants filed a motion to dismiss asserting, among other things, that (1) the Arkansas courts lack personal jurisdiction over each of them, (2) the Arkansas courts lack subject matter jurisdiction over the matters raised by the Plaintiffs and (3) the Plaintiffs have failed to assert claims against any of the HPL subsidiaries upon which relief can be granted. Other defendants have also filed motions to dismiss.
The Plaintiffs have not filed responses to the motions to dismiss. The court has entered a scheduling order that calls for briefing on the issues of personal and subject matter jurisdiction to be completed by January 2006, and has scheduled a hearing on those issues for February 2006. The scheduling order sets, among other deadlines, a trial date in September 2007.
The HPL Consolidation LP subsidiaries will continue to vigorously contest the Plaintiffs’ claims.
*Railroad Commission of Texas Oil and Gas Docket No. 02-0231838; Enforcement Action Against HPL Resources Company (Operator No. 407240) for Violations of Statewide Rules on the Magnolia City Plant Site (No. 04-0359),Nueces County, Texas. This case involves alleged soil and groundwater contamination at the Magnolia City Plant Site (the “Mag City Site”) located
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in Nueces County, Texas. Historically, there were two plants operated at the site: the Dean Plant and the Magnolia City Plant. The Dean Plant processed gas from 1953 until 1975, when the plant was permanently shut down. The Dean Plant was operated by a number of Tenneco and Tennessee Gas-related entities whose successors in interest include El Paso Natural Gas (“El Paso”) and Tennessee Gas Pipeline (“TGP”). Based on available facts, its does not appear that HPLR ever owned, operated or had any affiliation with the Dean Plant. The Magnolia City Plant was built in 1985 and was shut down in 1996. The Railroad Commission of Texas alleges that HPLR filed Form R-3s (entitled “Monthly Report for Gas Processing Plants”) for the Magnolia City Plant and is thus liable (or presumed liable) for the Mag City Site contamination.
Citing §91.101 of the Texas Natural Resources Code, the Commission filed a complaint alleging that HPLR “caused or allowed” pollution and discharged oil and gas wastes without a permit at the Magnolia City Plant in violation of Commission Rules 8(b) and 8(d)(1). The primary constituents of concern (“COCs”) are hydrocarbons, volatile organic compounds (“VOCs”), chloroform, chromium and chlorides. There is possible offsite contamination. However, the extent of the contamination has not been fully delineated.
Under the terms of a April 2000 Settlement Agreement, Indemnity and Release (“Indemnity”), HPC indemnified TGP and El Paso for all claims related to TGP’s or El Paso’s “environmental obligations” at the Mag City Site excepting those claims defined as “Boundary Area Claims.” The term “Boundary Area Claims” is defined in the Indemnity as “subsurface contamination which has migrated from the Plant site from the general location of the former blowdown pit located near the fence line of the northeast boundary of the Plant property.” Under the terms of this agreement, HPC (or its parent company at that time) was paid $205,000.
HPC and HPLR answered the Commission’s complaint. Some limited discovery was conducted. The Commission made HPC/HPLR a settlement offer and the parties have entered into settlement negotiations. In the meantime, the Commission contacted El Paso as a potentially responsible party. El Paso and AEP have met and discussed the terms and scope of the Indemnity, the site background, and the scope of each party’s potential liability. The parties have jointly hired a consultant to prepare a work plan to evaluate current groundwater conditions at the site for submittal to the Commission. The Commission is considering joining other parties to participate in the site investigation and remediation.
*Tuleta Plant Site Investigation (former gas plant located in Bee County, Texas). This case involves alleged soil and groundwater contamination at the Tuleta Gas Plant Site (“Tuleta”). The Tuleta Plant was a natural gas liquids processing plant that was first built in the 1940s. The plant employed a lean oil liquid extraction process. Natural gas processing operations ceased on or before July 1986. However, the site was still used for separation, compression, dehydration and/or condensate storage operations into the 1990s. HPC conducted operations at the site from January 1987 until October 1990. It appears that HPC’s operations at the site consisted solely of natural gas separation, dehydration and compression. Several entities operated the plant prior to January 1987. The successors in interest to those prior plant operators that are still solvent include: H.B. Zachry; EOG Resources, Inc.; and OneOK Bushton Processing, Inc. (“Prior Plant Operators”). Other parties with operations on site include Valero and Wagner Oil. The COCs at this site include lean oil, condensate and glycol. Extensive historic site investigations suggest there were possibly multiple releases from multiple sources (both on-site and off-site). However, the site has not been fully delineated at this time. Further, it is not clear whether HPC has any historic contractual obligations to remediate environmental conditions at this site. None have been identified to date.
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There is no current litigation or enforcement action concerning environmental conditions at this site. HPC was originally contacted by the Commission and asked to assume full responsibility for the contamination alleged at the site. However, since that time, the Commission has asked the Prior Plant Operators to share in the site remediation. HPC and the Prior Plant Operators retained an environmental consultant and voluntarily conducted a Baseline Study that reviewed all prior site investigative work. This Baseline Study was submitted to the Commission on February 11, 2005. By letter dated November 1, 2005, the Commission requested that the parties undertake a site groundwater delineation, a receptor survey and remedial action plan. The Commission has sent letters to Valero and Wagner Oil requesting that they attend a future meeting with the Commission, HPC and the Prior Plant Operators. Wagner has recently begun participating in the parties’ activities and Valero is reviewing its indemnities to ascertain whether another party besides them should be participating. Additional negotiations among the various parties and the Commission are anticipated.
City of Victoria v. Houston Pipe Line Company, et al.; Cause No. 03-6-59,833-C, in the 267th Judicial District Court of Victoria County, Texas. The City of Victoria (“Victoria”) filed suit against Houston Pipe Line Company, Houston Pipe Line Company, L.L.C., and Houston Pipe Line Company, L.P. (the HPL subsidiaries) alleging that HPC owes Victoria taxes for use of its streets, alleys, rights-of-way, and/or public property in transporting and selling gas. Victoria relies on city ordinance 14-116 for its assessment of the taxes. Ordinance 14-116 was passed on July 7, 1941, and, in summary, states that any entity owning, operating, managing or controlling any gas, electric light, or electric power plant within Victoria city limits and used for local sale and distribution using streets, alleys and/or public ways must file revenue reports with Victoria and pay Victoria two percent of gross receipts from the sale of such gas, electric lights or electric power derived from consumers. Based on these factual allegations, Victoria has alleged a violation of ordinance 14-116 and negligence per se.
In response to discovery requests, Victoria has produced documents that it claims were provided to Victoria by FERC and PUC. The documents appear to be a record of all gas sales from HPC and Central Power & Light (“CPL”), a wholly owned subsidiary of AEP, in Victoria during the period of May 1976 to December 2002. The total gross sales listed is $219,607,177.83. Victoria has claimed that the amount owed in taxes is 2% of gross sales. Thus, Victoria is claiming that $4,392,143.56 in taxes is owed by HPC to Victoria. The gross sales number provided by Victoria has not yet been verified by HPC.
HPL filed a motion for summary judgment based on the construction of the ordinance, contending that a plain reading of the ordinance shows that the ordinance is not applicable to HPL. In November 2005, the court granted HPL’s motion for summary judgment.
City of Corpus Christi, Texas v. Air Liquide America, L.P., et al., Cause No. 04-06556-A, In the District Court of Nueces County. On November 17, 2004, the City of Corpus Christi (“Corpus”) filed the above-referenced lawsuit, which names approximately forty defendants, including HPC. The City primarily sought to obtain a declaration of the validity of City Ordinance No. 026023, which required that defendants obtain a license from Corpus or equivalent authorization for their continued use of Corpus’s rights-of-way and city-owned properties (the “Ordinance”). The Ordinance required, in exchange for permission to use certain affected city rights-of-way and city-owned property, that each defendant remit to Corpus “fair compensation”, as set forth in the Ordinance. Generally, that “fair compensation” included a charge of $500 per crossing and $1.25 per foot for laying alongside public rights-of-way. Additionally, Corpus alleged trespass, purpesture (an alleged encroachment upon public rights belonging to and/or controlled by Corpus) and unjust enrichment. Prior to filing suit, Corpus had by written letter revoked the revocable easement agreements held by HPC and other defendants.
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HPC, as a member of the Texas Energy Coalition (“TEC”), engaged in settlement negotiations with Corpus, and successfully settled all claims.
In Re Port of Houston Authority. This claim involves a dispute over annual permit fees assessed by the Port of Houston Authority (“PHA”). Since 1998, HPL has disputed annual permit fees to the PHA totaling approx. $275,000. HPL has joined with other pipelines in negotiations to resolve this dispute.
If settlement discussions fail and HPC is served, HPC intends to vigorously defend this lawsuit.
While the outcomes of the matters discussed above cannot be predicted with certainty, based on information known to date and considering reserves established as of December 31, 2004, we do not expect the ultimate resolution of these matters to have a material adverse effect on our financial position, operating results, or cash flow.
Environmental Regulations – HPL is subject to extensive federal, state and local laws and regulations concerning the release of materials into the environment, and which require expenditures for remediation at various sites.
HPL has 10 known environmental remediation sites. HPL has accrued liabilities of $3.3 million and $4.0 million for the costs as of December 31, 2004 and 2003, respectively. Management feels that adequate reserves have been made for any potential future costs related to these sites. Other than the identified potential clean up sites, HPL believes that its operations and facilities are in general compliance with applicable environmental regulations.
4. Equity Investment in Nonconsolidated Subsidiary
HPL owns a 50% equity interest in Mid Texas Pipeline Company.
The period from January 1, 2005 to January 25, 2005 and years ended December 31, 2004, 2003 and 2002 equity loss from the Mid Texas investment is $95 thousand, $683 thousand, $668 thousand and $249 thousand, respectively. The following amounts, which are not consolidated into our financial statements, represent summarized financial information of Mid Texas (in thousands):
| | | | | | |
| | | December 31,
|
| | | 2004
| | 2003
|
Assets | | | | | | |
Property, Plant and Equipment (Net) | | $ | 65,977 | | $ | 67,281 |
Current Assets | | | 925 | | | 959 |
| | |
|
| |
|
|
TOTAL | | $ | 66,902 | | $ | 68,240 |
| | |
|
| |
|
|
Capitalization And Liabilities | | | | | | |
Common Shareholders’ Equity | | $ | 66,070 | | $ | 67,437 |
Current Liabilities | | | 832 | | | 803 |
| | |
|
| |
|
|
TOTAL | | $ | 66,902 | | $ | 68,240 |
| | |
|
| |
|
|
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| | | | | | | | | | | | |
| | | Period from January 1, 2005 to January 25, 2005
| | Year Ended December 31,
|
| | | | 2004
| | 2003
| | 2002
|
| Operations Statement Data | | | | | | | | | | | | |
Operating Loss | | $ | 212 | | $ | 2,469 | | $ | 2,473 | | $ | 2,296 |
Net Loss | | | 191 | | | 1,366 | | | 1,336 | | | 499 |
5. Impairments
We own and operate natural gas gathering, transportation and storage operations in Texas. During the fourth quarter of 2003, based on a probability-weighted after-tax cash flow analysis of our fair value, we recorded an impairment of $300 million pre-tax ($218 million after-tax), with $150 million pre-tax related to the entire balance of goodwill, reflecting management’s decision not to operate as a major trading hub. The cash flow analysis, among other things, used management’s estimate of the alternative likely outcomes of the uncertainties surrounding the continued use of the Bammel facility and other matters (see Note 3) and an after-tax risk free discount rate of 3.3% over the remaining life of the assets.
6. Benefit Plans
We participate in AEP sponsored U.S. qualified pension plans and nonqualified pension plans. A substantial majority of employees are covered by either one qualified plan or both a qualified and a nonqualified pension plan. In addition, we participate in other postretirement benefit plans sponsored by AEP to provide medical and life insurance benefits for retired employees in the U.S. We implemented FSP FAS 106-2 in the second quarter of 2004, retroactive to the first quarter of 2004 (see “FASB Staff Position No. FAS 106-2, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug Improvement and Modernization Act of 2003” section of Note 2). The Medicare subsidy reduced the FAS 106 accumulated postretirement benefit obligation (APBO) related to benefits attributed to past service. Our reduction in the net periodic postretirement cost for 2004 was $150,000.
Pension and Other Postretirement Plans’ Assets:
The pension and other postretirement plans were not transferred to ETC OLP upon the sale of HPL. The asset allocations for AEP’s pension plans at the end of 2004 and 2003, and the target allocation for 2005, by asset category, are as follows:
| | | | | | |
| | | Target
Allocation
| | Percentage of Plan Assets at Year End
|
| | | 2005
| | 2004
| | 2003
|
| Asset Category | | (in percentages) |
Equity Securities | | 70 | | 68 | | 71 |
Debt Securities | | 28 | | 25 | | 27 |
Cash and Cash Equivalents | | 2 | | 7 | | 2 |
| | |
| |
| |
|
Total | | 100 | | 100 | | 100 |
| | |
| |
| |
|
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The asset allocations for AEP’s other postretirement benefit plans at the end of 2004 and 2003, and target allocation for 2005, by asset category, are as follows:
| | | | | | |
| | | Target
Allocation
| | Percentage of Plan Assets at Year End
|
| | | 2005
| | 2004
| | 2003
|
| Asset Category | | (in percentages) |
Equity Securities | | 70 | | 70 | | 61 |
Debt Securities | | 28 | | 28 | | 36 |
Other | | 2 | | 2 | | 3 |
| | |
| |
| |
|
Total | | 100 | | 100 | | 100 |
| | |
| |
| |
|
AEP’s investment strategy for their employee benefit trust funds is to use a diversified mixture of equity and fixed income securities to preserve the capital of the funds and to maximize the investment earnings in excess of inflation within acceptable levels of risk. AEP regularly reviews the actual asset allocation and periodically rebalances the investments to the targeted allocation when considered appropriate. Because of a discretionary contribution at the end of 2004, the actual pension asset allocation was different from the target allocation at the end of the year. The asset portfolio was rebalanced to the target allocation in January 2005.
AEP bases its determination of pension expense or income on a market-related valuation of assets which reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over a five-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the market-related value of assets. Since the market-related value of assets recognizes gains or losses over a five-year period, the future value of assets will be impacted as previously deferred gains or losses are recorded.
AEP’s combined pension funds are underfunded in total (plan assets are less than projected benefit obligations) at December 31, 2004.
AEP made an additional discretionary contribution in the fourth quarter of 2004 and intends to make additional discretionary contributions in 2005 to meet its goal of fully funding all qualified pension plans by the end of 2005.
The weighted-average assumptions as of December 31, used in the measurement of AEP’s benefit obligations are shown in the following tables:
| | | | | | | | |
| | | Pension Plans
| | Other Postretirement Benefit Plans
|
| | | 2004
| | 2003
| | 2004
| | 2003
|
| | | (in percentages) |
Discount Rate | | 5.50 | | 6.25 | | 5.80 | | 6.25 |
Rate of Compensation Increase | | 3.70 | | 3.70 | | N/A | | N/A |
The method used to determine the discount rate that AEP utilizes for determining future benefit obligations was revised in 2004. Historically, it has been based on the Moody’s AA bond index which includes long-term bonds that receive one of the two highest ratings given by a recognized rating agency. The discount rate determined on this basis was 6.25% at December 31, 2003 and would have been 5.75% at December 31, 2004. In 2004, AEP changed to a duration based method where a hypothetical portfolio of high quality corporate bonds was constructed with a
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duration similar to the duration of the benefit plan liability. The composite yield on the hypothetical bond portfolio was used as the discount rate for the plan. The discount rate at December 31, 2004 under this method was 5.50% for pension plans and 5.80% for other postretirement benefit plans.
The rate of compensation increase assumed varies with the age of the employee, ranging from 3.5% per year to 8.5% per year, with an average increase of 3.7%.
The contribution to the pension fund is based on the minimum amount required by the U.S. Department of Labor or the amount of the pension expense for accounting purposes, whichever is greater, plus the additional discretionary contributions to fully fund the qualified pension plans. The contribution to the other postretirement benefit plans’ trust is generally based on the amount of the other postretirement benefit plans’ expense for accounting purposes and is provided for in agreements with state regulatory authorities.
The Company participates in the AEP system qualified pension plan, a defined benefit plan that covers all employees. Net periodic benefit cost for the period from January 01, 2005 to January 25, 2005 and the years ended December 31, 2004 and 2003 were $101,333, $1,102,000 and $965,000, respectively.
Postretirement benefits other than pensions are provided for retired employees for medical and death benefits under an AEP System plan. The accrued costs were $89,000 in January 2005 and $816,000 and $1,186,000 in 2004 and 2003, respectively.
The weighted-average assumptions as of January 1, used in the measurement of AEP’s benefit costs are shown in the following tables:
| | | | | | | | | | | | |
| | | Pension Plans
| | Other Postretirement Benefit Plans
|
| | | 2004
| | 2003
| | 2002
| | 2004
| | 2003
| | 2002
|
| | | (in percentages) |
Discount Rate | | 6.25 | | 6.75 | | 7.25 | | 6.25 | | 6.75 | | 7.25 |
Expected Return on Plan Assets | | 8.75 | | 9.00 | | 9.00 | | 8.35 | | 8.75 | | 8.75 |
Rate of Compensation Increase | | 3.70 | | 3.70 | | 3.70 | | N/A | | N/A | | N/A |
The expected return on plan assets for 2004 was determined by evaluating historical returns, the current investment climate, rate of inflation, and current prospects for economic growth. After evaluating the current yield on fixed income securities as well as other recent investment market indicators, the expected return on plan assets was reduced to 8.75% for 2004. The expected return on other postretirement benefit plan assets (a portion of which is subject to capital gains taxes as well as unrelated business income taxes) was reduced to 8.35%.
A defined contribution employee savings plan required that the Company make contributions to the plan totaling $643,000 and $640,000 in 2004 and 2003.
In 2002, there were no separately identifiable costs related to associated net pension benefit costs, postretirement benefit costs or savings plan contributions as theses costs were included in an overall fringe benefit charge to HPL. AEP does not allocate pension liabilities to its subsidiaries, including HPL.
F-44
7. Derivatives, Hedging and Financial Instruments
Derivatives and Hedging
We apply SFAS 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. Derivatives include interest rate swaps, commodity swaps, options and futures contracts and certain physical gas purchases and sales contracts.
SFAS 133 requires recognition of all derivative instruments as either assets or liabilities in the statement of financial position at fair value unless the contracts qualify for normal purchase or normal sale treatment. Our accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies, and has been designated, as part of a hedging relationship. To qualify for designation in a hedging relationship, specific criteria have to be met and the appropriate formal documentation maintained. We evaluate the hedge relationship at inception and ongoing to verify that the relationship is expected to remain highly effective in offsetting changes in cash flows during the hedge designation period. Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in SFAS 133. These contracts are not reported at fair value, as otherwise required by SFAS 133.
For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), we initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income and subsequently reclassify it to Revenues or Gas Purchases in the Consolidated Statement of Operations when the forecasted transaction affects earnings. The remaining gain or loss on the derivative instrument in excess of the cumulative change in the present value of future cash flows of the hedged item, if any, is recognized currently in Revenues during the period of change.
Cash Flow Hedging Strategies
We enter into forward and swap transactions for the purchase and sale of natural gas to manage the variable price risk related to the forecasted purchases and sales of natural gas. We closely monitor the potential impacts of commodity price changes and, where appropriate, enter into contracts to protect margins for a portion of future sales. We do not hedge all variable price risk exposure related to the forecasted purchases and sales of natural gas.
F-45
The following table represents the activity in Accumulated Other Comprehensive Income (Loss) (“AOCI”) for derivative contracts that qualify as cash flow hedges at January 25, 2005:
| | | | |
| | | Amount (in thousands)
| |
Beginning Balance, December 31, 2001 | | $ | — | |
Changes in fair value | | | — | |
Reclasses from AOCI to net earnings | | | — | |
| | |
|
|
|
Balance December 31, 2002 | | | — | |
Changes in fair value | | | (281 | ) |
Reclasses from AOCI to net earnings | | | — | |
| | |
|
|
|
Balance December 31, 2003 | | | (281 | ) |
Changes in fair value | | | 35,683 | |
Reclasses from AOCI to net earnings | | | 281 | |
| | |
|
|
|
Balance December 31, 2004 | | | 35,683 | |
Changes in fair value | | | 1,052 | |
Reclasses from AOCI to net earnings | | | (19,634 | ) |
| | |
|
|
|
Ending Balance, January 25, 2005 | | $ | 17,101 | |
| | |
|
|
|
8. Income Taxes
The details of income tax (benefit) expenses applicable to continuing operations are as follows (in thousands):
| | | | | | | | | | | | | |
| | | Period from January 1, 2005 to January 25, 2005
| | Year Ended December 31,
|
| | | | 2004
| | 2003
| | | 2002
|
FEDERAL | | | | | | | | | | | | | |
Current | | $ | 4,402 | | $ | 18,296 | | $ | (484 | ) | | $ | 21,285 |
Deferred | | | 3,075 | | | 4,398 | | | (81,111 | ) | | | 2,319 |
| | |
|
| |
|
| |
|
|
| |
|
|
Total Income Tax as Reported | | $ | 7,477 | | $ | 22,694 | | $ | (81,595 | ) | | $ | 23,604 |
| | |
|
| |
|
| |
|
|
| |
|
|
F-46
The following is a reconciliation of the difference between the amount of federal income taxes computed by multiplying book income before federal income taxes by the statutory rate, and the amount of income taxes reported (in thousands).
| | | | | | | | | | | | | | | | |
| | | Period from January 1, 2005 to January 25, 2005
| | | Year Ended December 31,
| |
| | | | 2004
| | | 2003
| | | 2002
| |
Net Income (Loss) | | $ | 13,521 | | | $ | 44,026 | | | $ | (216,571 | ) | | $ | 43,457 | |
Income Tax Expense (Credit) | | | 7,477 | | | | 22,694 | | | | (81,595 | ) | | | 23,604 | |
| | |
|
|
| |
|
|
| |
|
|
| |
|
|
|
Pre-Tax Income (Loss) | | $ | 20,998 | | | $ | 66,720 | | | $ | (298,166 | ) | | $ | 67,061 | |
| | |
|
|
| |
|
|
| |
|
|
| |
|
|
|
Income Tax on Pre-Tax Income at Statutory Rate (35%) | | | 7,349 | | | | 23,352 | | | | (104,358 | ) | | | 23,471 | |
Increase (Decrease) in Income Tax Resulting from the Following Items: | | | | | | | | | | | | | | | | |
Impairment of Goodwill (nondeductible portion) | | | — | | | | — | | | | 23,021 | | | | — | |
Other | | | 128 | | | | (658 | ) | | | (258 | ) | | | 133 | |
| | |
|
|
| |
|
|
| |
|
|
| |
|
|
|
Total Income Taxes as Reported | | $ | 7,477 | | | $ | 22,694 | | | $ | (81,595 | ) | | $ | 23,604 | |
| | |
|
|
| |
|
|
| |
|
|
| |
|
|
|
Effective Income Tax Rate | | | 35.67 | % | | | 34.01 | % | | | 27.37 | % | | | 35.20 | % |
The following table shows the elements of the net deferred tax asset and the significant temporary differences:
| | | | | | | | |
| | | Year Ended December 31,
| |
| | | 2004
| | | 2003
| |
Property Related Temporary Differences | | $ | (21,018 | ) | | $ | (13,412 | ) |
Impaired Assets | | | 52,957 | | | | 51,910 | |
Provisions for Losses | | | 8,398 | | | | 8,398 | |
Tax Basis Goodwill | | | 21,931 | | | | 25,370 | |
Price-Risk Management Assets (Net) | | | 13,587 | | | | 9,417 | |
Other Comprehensive Income (Loss) | | | (19,214 | ) | | | 151 | |
Cash Flow Hedges | | | — | | | | — | |
Prepaid Leases | | | 37,238 | | | | 35,888 | |
All Other (Net) | | | 4,521 | | | | 4,442 | |
| | |
|
|
| |
|
|
|
Net Deferred Tax Assets | | $ | 98,400 | | | $ | 122,164 | |
| | |
|
|
| |
|
|
|
We join in the filing of a consolidated federal income tax return with our affiliated companies in the AEP System. The allocation of the AEP System’s current consolidated federal income tax to the System companies is in accordance with SEC rules under the 1935 Act. These rules permit the allocation of the benefit of current tax losses to the System companies giving rise to them in determining their current tax expense. The tax loss of the System parent company, AEP Co., Inc., is allocated to its subsidiaries with taxable income. With the exception of the loss of the parent company, the method of allocation approximates a separate return result for each company in the consolidated group.
F-47
The IRS and other taxing authorities routinely examine our returns. Returns for the years 2001 through 2003 are presently being audited by the IRS. Management is not aware of any issues for open tax years that upon final resolution are expected to have a material adverse effect on results of operations.
9. Leases
Leases include property, plant and equipment and gas pipeline rights of way. Leases of property, plant and equipment are for periods up to 10 years and require payments of related property taxes, maintenance and operating costs. Leases of gas pipeline rights of way range from one year to perpetuity. The majority of the leases have purchase or renewal options and will be renewed or replaced by other leases.
Property, plant, and equipment under capital leases at December 31, 2004 are predominantly general plant equipment and at December 31, 2003 are predominately the assets leased from BAM Lease Company. The assets leased from BAM Lease Company were purchased by HPL in November 2004 as described in Note 3. The $120.1 million value for leased assets became part of owned pipeline and equipment with this purchase. The BAM Lease Company lease payments were prepaid at the acquisition of HPC, therefore, there are no future payment obligations for the remainder of the primary lease term.
Property, plant and equipment under capital leases and related obligations recorded on the Consolidated Balance Sheets are as follows (in thousands):
| | | | | | |
| | | Year Ended
December 31,
|
| | | 2004
| | 2003
|
Property, Plant and Equipment Under Capital Leases | | | | | | |
Production and Other | | $ | 28 | | $ | 120,094 |
| | |
|
| |
|
|
Total Property, Plant and Equipment | | | 28 | | | 120,094 |
Accumulated Amortization | | | 3 | | | 15,097 |
| | |
|
| |
|
|
Net Property, Plant and Equipment Under Capital Leases | | $ | 25 | | $ | 104,997 |
| | |
|
| |
|
|
Obligations Under Capital Leases | | | | | | |
Non-current Liability | | $ | 16 | | $ | 3 |
Liability | | | 9 | | | 1 |
| | |
|
| |
|
|
Total Obligations Under Capital Leases | | $ | 25 | | $ | 4 |
| | |
|
| |
|
|
Lease rentals for operating and capital leases were as follows (in thousands):
| | | | | | | | | |
| | | Period from
January 1, 2005 to
January 25, 2005
| | Year Ended December 31,
|
| | | | 2004
| | 2003
|
Lease Payments on Operating Leases | | $ | 195 | | $ | 1,900 | | $ | 1,287 |
Amortization of Capital Leases | | | 5 | | | 3 | | | 6,923 |
Interest on Capital Leases | | | — | | | 3 | | | — |
| | |
|
| |
|
| |
|
|
Total Lease Rental Cost | | $ | 200 | | $ | 1,906 | | $ | 8,210 |
| | |
|
| |
|
| |
|
|
F-48
Future minimum lease payments consisted of the following at December 31, 2004:
| | | |
Capital Leases
| | (in thousands)
|
2005 | | $ | 9 |
2006 | | | 8 |
2007 | | | 7 |
2008 | | | 2 |
2009 | | | — |
Later Years | | | — |
| | |
|
|
Total Future Minimum Lease Payments | | | 26 |
Less Estimated Interest Element | | | 1 |
| | |
|
|
Estimated Present Value of Future Minimum Lease Payments | | $ | 25 |
| | |
|
|
| |
Noncancelable Operating Leases
| | (in thousands)
|
2005 | | $ | 337 |
2006 | | | 275 |
2007 | | | 209 |
2008 | | | 131 |
2009 | | | 83 |
Later Years | | | 102 |
| | |
|
|
Total Future Minimum Lease Payments | | $ | 1,137 |
| | |
|
|
10. Concentration of Credit Risks
For the period from January 1, 2005 to January 25, 2005, one non-affiliated customer represented more than 10% of related total revenues. At December 31, 2004, two non-affiliated customers represented more than 10% of related total revenues or accounts receivable. At December 31, 2003, one non-affiliated customer represented more than 10% of the related total revenues or accounts receivable. At December 31, 2004, one non-affiliated customer comprised approximately 55% of the net Price-Risk Management Assets and Liabilities. At December 31, 2003, four non-affiliated customers comprised approximately 45% of the net Price-Risk Management Assets and Liabilities.
11. Related Party Transactions
American Electric Power Service Corporation (“AEPSC”), a wholly owned subsidiary of AEP and affiliate of HPL, provides certain managerial and professional services to AEP System companies. The costs of the services are billed to its affiliated companies by AEPSC on a direct-charge basis, whenever possible, and on reasonable basis of proration for shared services. The billings for services are made at cost and include no compensation for the use of equity capital, which is furnished to AEPSC by AEP. Billings from AEPSC are capitalized or expensed depending on the nature of the services rendered. AEPSC and its billings are subject to the regulation of the SEC under the 1935 Act. For the period from January 1, 2005 to January 25, 2005 and the years ended December 31, 2004, 2003 and 2002, HPL recognized costs of $.6 million, $5.5 million, $5.0 million and $5.4 million for these services.
HPL purchases and sells gas and enters into financial hedge transactions with AEPES and other affiliates. These transactions are conducted at market prices and settlements are handled according to standard industry practices. For the period from January 1, 2005 to January 25,
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2005 and the years ended December 31, 2004, 2003 and 2002, HPL had sales of $55.2 million, $862.3 million, $899.2 million and $574.0 million and purchases of $20.6 million,$760.3 million, $464.5 million and $388.2 million to and from AEPES. Included in these sales are settlement receipt (payments) of financial hedge transactions in January 2005 of $36.2 million and in 2004, 2003 and 2002 of $17.0 million, $(19.8) million and $(17.5) million.
HPL entered into a long-term Asset Management Agreement, which was terminated December 15, 2004, with AEPES for the exclusive rights to manage injections of natural gas into, and withdrawals of natural gas from, the Bammel storage facility, and to make use of natural gas injection, withdrawal and storage capacity not otherwise contractually committed by HPL that may be available from the Bammel storage facility from time to time. In exchange for these rights, AEPES agreed to pay HPL a fixed, annual Asset Management fee of $25 million. In addition, AEPES agreed to pay HPL a market based rate for storage services on the available space that was not contractually committed to third parties. For the period ended December 31, 2004, 2003 and 2002, HPL had revenues of $28.5 million, $29.8 million and $30.1 million related to the Asset Management Agreement.
AEP has established a money pool to coordinate short-term borrowings for certain subsidiaries including HPL. Interest income earned from amounts advanced to the AEP money pool by HPL, for the period from January 1, 2005 to January 25, 2005 and the years ended December 31, 2004, 2003 and 2002, was $.1 million, $2.3 million, $2.5 million and $4.9 million. Interest expense incurred from amounts borrowed from the AEP money pool by HPL, for the period from January 1, 2005 to January 25, 2005 and years ended December 31, 2004 was $.4 million, and $.2 million. Interest income and expenses are recorded in Interest Income – Affiliated and Interest Expense – Affiliated on the Statements of Operations. Amounts loaned to or borrowed from the money pool at period end are classified as Advances to/from Affiliates on the Consolidated Balance Sheets.
Prior to January 2005, HPL purchased physical gas in the spot market, which in turn, was sold to AEP operating companies at cost for their fuel requirements. These transactions did not occur subsequent to December 31, 2004. The related sales were as follows:
| | | | | | | | | |
| | | Year Ended December 31,
|
| | | 2004
| | 2003
| | 2002
|
| | | (in thousands) |
AEP Texas Central Company | | $ | 129,682 | | $ | 195,527 | | $ | 157,346 |
AEP Texas North Company | | | 45,767 | | | 44,197 | | | 64,385 |
12. Guarantees
There are certain immaterial liabilities recorded for guarantees entered subsequent to December 31, 2002 in accordance with FIN 45 “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” There is no collateral held in relation to any guarantees in excess of our ownership percentages. In the event any guarantee is drawn, there is no recourse to third parties unless specified below.
Prior to December 31, 2004, AEPESGH had outstanding debt, which was collateralized with the assets of HPL. This debt was paid in full on December 15, 2004.
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Indemnifications And Other Guarantees
Contracts
HPL enters into several types of contracts, which would require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, our exposure generally does not exceed the sale price. We cannot estimate the maximum potential exposure for any of these indemnifications executed prior to December 31, 2002 due to the uncertainty of future events.
Master Operating Lease
We lease certain equipment under a master operating lease. Under the lease agreement, the lessor is guaranteed to receive up to 87% of the unamortized balance of the equipment at the end of the lease term. If the fair market value of the leased equipment is below the unamortized balance at the end of the lease term, we have committed to pay the difference between the fair market value and the unamortized balance, with the total guarantee not to exceed 87% of the unamortized balance. At January 25, 2005, the maximum potential loss for these lease agreements was approximately $285 thousand assuming the fair market value of the equipment is zero at the end of the lease term.
13. Subsequent Events
On November 10, 2005 AEP sold the 2% limited partner interest in HPL for $16.6 million in cash. As a result, HPL became a wholly owned subsidiary of La Grange Acquisition, L.P.
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