ITEM 1. Business.
OUR BUSINESS
Introduction
The Company was incorporated under the laws of the State of Delaware in 1932. The Company owns and operates assets in the regulated and unregulated natural gas industry and is primarily engaged in the gathering, processing, transportation, storage and distribution of natural gas in the United States. The Company operates in three reportable segments: Transportation and Storage, Gathering and Processing, and Distribution.
BUSINESS SEGMENTS
Reportable Segments
The Company’s operations, as reported, include three reportable segments:
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The Transportation and Storage segment is primarily engaged in the interstate transportation and storage of natural gas and also provides LNG terminalling and regasification services. Its operations are conducted through Panhandle and its 50 percent equity ownership interest in Florida Gas through Citrus.
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The Gathering and Processing segment is primarily engaged in the gathering, treating, processing and redelivery of natural gas and NGL in Texas and New Mexico. Its operations are conducted through SUGS.
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The Distribution segment is primarily engaged in the local distribution of natural gas in Missouri and Massachusetts. Its operations are conducted through the Company’s operating divisions Missouri Gas Energy and New England Gas Company.
The Company has other operations that support and expand its natural gas and other energy sales, which are not included in its reportable segments. These operations do not meet the quantitative thresholds for determining reportable segments and have been combined for disclosure purposes in the Corporate and Other activities category. For information about the revenues, operating income, assets and other financial information relating to the Corporate and Other activities, see Item 8. Financial Statements and Supplementary Data, Note 17 - Reportable Segments.
The Company also provides various corporate services to support its operating businesses, including executive management, accounting, communications, human resources, information technology, insurance, internal audit, investor relations, environmental, legal, payroll, purchasing, insurance, tax and treasury.
Sales of products or services between segments are billed at regulated rates or at market rates, as applicable. There were no material intersegment revenues during the years ended December 31, 2009, 2008 or 2007.
Transportation and Storage Segment
Services
The Transportation and Storage segment is primarily engaged in the interstate transportation of natural gas to Midwest, Southwest and Florida markets and related storage, and also provides LNG terminalling and regasification services. The Transportation and Storage segment’s operations are conducted through Panhandle and Florida Gas.
For the years ended December 31, 2009, 2008 and 2007, the Transportation and Storage segment’s operating revenues were $749.2 million, $721.6 million and $658.4 million, respectively. Earnings from unconsolidated investments related to Citrus were $75 million, $74.9 million and $98.9 million for the years ended December 31, 2009, 2008 and 2007, respectively.
For information about operating revenues, EBIT, earnings from unconsolidated investments, assets and other financial information relating to the Transportation and Storage segment, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations - Business Segment Results - Transportation and Storage Segment and Item 8. Financial Statements and Supplementary Data, Note 17 - Reportable Segments.
Panhandle. Panhandle owns and operates a large natural gas open-access interstate pipeline network. The pipeline network, consisting of the PEPL transmission system, the Trunkline transmission system and the Sea Robin transmission system, serves customers in the Midwest and Southwest with a comprehensive array of transportation and storage services. PEPL’s transmission system consists of four large diameter pipelines extending approximately 1,300 miles from producing areas in the Anadarko Basin of Texas, Oklahoma and Kansas through Missouri, Illinois, Indiana, Ohio and into Michigan. Trunkline’s transmission system consists of two large diameter pipelines extending approximately 1,400 miles from the Gulf Coast areas of Texas and Louisiana through Arkansas, Mississippi, Tennessee, Kentucky, Illinois and Indiana to a point on the Indiana-Michigan border. Sea Robin’s transmission system consists of two offshore Louisiana natural gas supply systems extending approximately 81 miles into the Gulf of Mexico. In connection with its natural gas transmission and storage systems, Panhandle has five natural gas storage fields located in Illinois, Kansas, Louisiana, Michigan and Oklahoma. Southwest Gas operates four of these fields and Trunkline operates one. Through Trunkline LNG, Panhandle owns and operates an LNG terminal in Lake Charles, Louisiana.
Panhandle earns most of its revenue by entering into firm transportation and storage contracts, providing capacity for customers to transport and store natural gas, or LNG, in its facilities. Panhandle provides firm transportation services under contractual arrangements to local distribution company customers and their affiliates, natural gas marketers, producers, other pipelines, electric power generators and a variety of end-users. Panhandle’s pipelines offer both firm and interruptible transportation to customers on a short-term and seasonal basis. Demand for natural gas transmission on Panhandle’s pipeline systems is seasonal, with the highest throughput and a higher portion of annual total operating revenues and net earnings occurring in the traditional winter heating season, which occurs during the first and fourth calendar quarters. Average reservation revenue rates realized by Panhandle are dependent on certain factors, including but not limited to rate regulation, customer demand for reserved capacity, capacity sold levels for a given period and, in some cases, utilization of capacity. Commodity revenues, which are more short-term, sensitive and variable in nature, are dependent upon a number of factors including weather, storage and pipeline capacity availability levels, and customer demand for firm and interruptible services, including parking services. The majority of Panhandle’s revenues are related to firm capacity reservation charges, which reservation charges account for approximately 83 percent of total segment revenues and 29 percent of consolidated revenues in 2009.
Florida Gas. Florida Gas is an open-access interstate pipeline system with a mainline capacity of 2.1 Bcf/d and approximately 5,000 miles of pipelines extending from south Texas through the Gulf Coast region of the United States to south Florida. Florida Gas’ pipeline system primarily receives natural gas from natural gas producing basins along the Louisiana and Texas Gulf Coast, Mobile Bay and offshore Gulf of Mexico. Florida Gas is the principal transporter of natural gas to the Florida energy market, delivering over 66 percent of the natural gas consumed in the state. In addition, Florida Gas’ pipeline system operates and maintains over 60 interconnects with major interstate and intrastate natural gas pipelines, which provide Florida Gas’ customers access to diverse natural gas producing regions.
Florida Gas earns the majority of its revenue by entering into firm transportation contracts. Florida Gas also earns variable revenue from charges assessed on each unit of transportation provided.
Demand for natural gas transmission service on the Florida Gas pipeline system is somewhat seasonal, with the highest throughput and related net earnings occurring in the traditional summer cooling season during the second and third calendar quarters, primarily due to increased natural gas-fired electric generation loads. The Company’s share of net earnings of Florida Gas is reported in Earnings from unconsolidated investments in the Consolidated Statement of Operations.
The following table provides a summary of pipeline transportation and LNG terminal usage volumes (in TBtu) associated with the reported results of operations for the periods presented:
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(1)
Represents 100 percent of Florida Gas versus the Company's effective equity ownership interest of 50 percent.
The following table provides a summary of certain statistical information associated with Panhandle and Florida Gas at the date indicated:
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(1) Sea Robin’s contracts are primarily interruptible, with only four firm contracts in place.
(2) Represents 100 percent of Florida Gas versus the Company's effective equity ownership interest of 50 percent.
Recent System Enhancements - Completed or Under Construction
LNG Terminal Enhancement. The Company commenced construction of an enhancement at its Trunkline LNG terminal in February 2007. This infrastructure enhancement project (IEP), will increase send out flexibility at the terminal and lower fuel costs. On August 6, 2009, FERC issued a conditional order granting Trunkline LNG authorization to commence partial service of IEP. Although the key components of the enhancement, a portion of the ambient air vaporizer system and the NGL recovery units, were successfully tested in the fourth quarter of 2009, mechanical issues were identified during the commissioning process that required attention. Trunkline LNG has made warranty claims regarding certain of those conditions and is effecting IEP system modifications prior to placing the project into full service. On February 9, 2010, Trunkline LNG filed with FERC a request to place the facility in full service upon the completion of certain modifications. Full service is expected no later than the end of the first quarter of 2010. Total construction costs are expected to be approximately $430 million, plus capitalized interest. The negotiated rate with the project’s customer, BG LNG Services, will be adjusted based on final capital costs pursuant to a contract-based formula. In addition, Trunkline LNG and BG LNG Services agreed to extend the existing terminal and pipeline services agreements to coincide with the IEP contract, which runs 20 years from the in-service date. Approximately $457.2 million and $351.3 million of costs, including capitalized interest of $43.8 million and $20 million, are included in the line item Construction work-in-progress at December 31, 2009 and 2008, respectively.
Florida Gas Phase VIII Expansion. In November 2009, FERC approved Florida Gas’ certificate application to construct an expansion, which will increase its natural gas capacity into Florida by approximately 820 MMcf/d (Phase VIII Expansion). The Phase VIII Expansion includes construction of approximately 500 miles of large diameter pipeline and the installation of approximately 200,000 horsepower of compression. Florida Gas anticipates an in-service date in the spring of 2011, at a currently estimated cost of approximately $2.4 billion, including capitalized equity and debt costs. Approximately $737 million of capital costs have been recorded as of December 31, 2009. To date, Florida Gas has entered into firm transportation service agreements with shippers for 25-year terms accounting for approximately 74 percent of the available expansion capacity which, depending on elections by one of the shippers, may increase to 83 percent of such capacity.
Significant Customers
The following table provides the percentage of Transportation and Storage segment Operating revenues and related weighted average contract lives of Panhandle’s significant customers for the period presented:
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(1)
Panhandle has no single customer, or group of customers under common control, that accounted for ten percent or more of the Company’s total consolidated operating revenues.
Panhandle’s customers are subject to change during the year as a result of capacity release provisions that allow customers to release all or part of their capacity, which generally occurs for a limited time period. Under the terms of Panhandle’s tariffs, a temporary capacity release does not relieve the original customer from its payment obligations if the replacement customer fails to pay.
The following table provides information related to Florida Gas’ significant customers for the period presented:
Regulation and Rates
Panhandle and Florida Gas are subject to regulation by various federal, state and local governmental agencies, including those specifically described below. See also Item 1A.
ITEM 1A. Risk Factors.
The risks and uncertainties described below are not the only ones faced by the Company. Additional risks and uncertainties that the Company is unaware of, or that it currently deems immaterial, may become important factors that affect it. If any of the following risks occur, the Company’s business, financial condition, results of operations or cash flows could be materially and adversely affected.
RISKS THAT RELATE TO SOUTHERN UNION
Southern Union has substantial debt and may not be able to obtain funding or obtain funding on acceptable terms because of deterioration in the credit and capital markets. This may hinder or prevent Southern Union from meeting its future capital needs.
Southern Union has a significant amount of debt outstanding. As of December 31, 2009, consolidated debt on the Consolidated Balance Sheet totaled $3.6 billion outstanding, compared to total capitalization (long and short-term debt plus stockholders' equity) of $6.1 billion.
Some of the Company’s debt obligations contain financial covenants concerning debt-to-capital ratios and interest coverage ratios. The Company’s failure to comply with any of these covenants could result in an event of default which, if not cured or waived, could result in the acceleration of outstanding debt obligations or render it unable to borrow under certain credit agreements. Any such acceleration or inability to borrow could cause a material adverse change in the Company’s financial condition.
The Company relies on access to both short- and long-term credit as a significant source of liquidity for capital requirements not satisfied by the cash flow from its operations. A deterioration in the Company’s financial condition could hamper its ability to access the capital markets.
Global financial markets and economic conditions have been, and may continue to be, disrupted and volatile. The debt and equity capital markets have been exceedingly distressed. These issues, along with significant write-offs in the financial services sector, the re-pricing of credit risk and the current weak economic conditions have made, and may continue to make, obtaining funding more difficult.
As a result of concerns about the stability of financial markets generally and the solvency of counterparties specifically, the cost of obtaining money from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, refused to refinance existing debt at maturity at all or on terms similar to current debt and reduced and, in some cases, ceased to provide funding to borrowers.
Due to these factors, the Company cannot be certain that funding will be available if needed and, to the extent required, on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, the Company may be unable to grow its existing business, complete acquisitions, refinance its debt or otherwise take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on the Company’s revenues and results of operations.
Further, because of the need for certain state regulatory approvals in order to incur long-term debt and issue capital stock, the Company may not be able to access the capital markets on a timely basis. Restrictions on the Company’s ability to access capital markets could affect its ability to execute its business plan or limit its ability to pursue improvements or acquisitions on which it may otherwise rely for future growth.
See additional related information in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Financial Sector Exposure.
Credit ratings downgrades could increase the Company’s financing costs and limit its ability to access the capital markets.
As of December 31, 2009, both Southern Union’s and Panhandle’s debt are rated BBB- by Fitch Ratings, Baa3 by Moody's Investor Services, Inc. and BBB- by Standard & Poor's. If the Company’s credit ratings are downgraded below investment grade or if there are times when it is placed on "credit watch," both borrowing costs and the costs of maintaining certain contractual relationships could increase. Lower credit ratings could also adversely affect the Distribution segment’s relationships with state regulators, who may be unwilling to allow the Company to pass along increased debt service costs to natural gas customers.
The financial soundness of the Company’s customers could affect its business and operating results.
As a result of the recent disruptions in the financial markets and other macroeconomic challenges that have impacted the economy of the United States and other parts of the world, the Company’s customers may experience cash flow concerns. As a result, if customers’ operating and financial performance deteriorates, or if they are unable to make scheduled payments or obtain credit, customers may not be able to pay, or may delay payment of, accounts receivable owed to the Company. Any inability of the Company’s customers to pay for services could adversely affect the Company’s financial condition, results of operations and cash flows.
The Company depends on distributions from its subsidiaries and joint ventures to meet its needs.
The Company is dependent on the earnings and cash flows of, and dividends, loans, advances or other distributions from its subsidiaries to generate the funds necessary to meet its obligations. The availability of distributions from such entities is subject to their earnings and capital requirements, the satisfaction of various covenants and conditions contained in financing documents by which they are bound or in their organizational documents, and in the case of the regulated subsidiaries, regulatory restrictions that limit their ability to distribute profits to Southern Union.
The Company owns 50 percent of Citrus, the holding company for Florida Gas. As such, the Company cannot control or guarantee the receipt of distributions from Florida Gas through Citrus.
The Company’s growth strategy entails risk for investors.
The Company may actively pursue acquisitions in the energy industry to complement and diversify its existing businesses. As part of its growth strategy, Southern Union may:
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examine and potentially acquire regulated or unregulated businesses, including transportation and storage assets and gathering and processing businesses within the natural gas industry;
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enter into joint venture agreements and/or other transactions with other industry participants or financial investors;
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selectively divest parts of its business, including parts of its core operations; and
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continue expanding its existing operations.
The Company’s ability to acquire new businesses will depend upon the extent to which opportunities become available, as well as, among other things:
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its success in valuing and bidding for the opportunities;
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its ability to assess the risks of the opportunities;
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its ability to obtain regulatory approvals on favorable terms; and
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its access to financing on acceptable terms.
Once acquired, the Company’s ability to integrate a new business into its existing operations successfully will largely depend on the adequacy of implementation plans, including the ability to identify and retain employees to manage the acquired business, and the ability to achieve desired operating efficiencies. The successful integration of any businesses acquired in the future may entail numerous risks, including:
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the risk of diverting management's attention from day-to-day operations;
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the risk that the acquired businesses will require substantial capital and financial investments;
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the risk that the investments will fail to perform in accordance with expectations; and
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the risk of substantial difficulties in the transition and integration process.
These factors could have a material adverse effect on the Company’s business, financial condition, results of operations and cash flows, particularly in the case of a larger acquisition or multiple acquisitions in a short period of time.
The consideration paid in connection with an investment or acquisition also affects the Company’s financial results. To the extent it issues shares of capital stock or other rights to purchase capital stock, including options or other rights, existing stockholders may be diluted and earnings per share may decrease. In addition, acquisitions or expansions may result in the incurrence of additional debt.
The Company is subject to operating risks.
The Company’s operations are subject to all operating hazards and risks incident to handling, storing, transporting and providing customers with natural gas or NGL, including adverse weather conditions, explosions, pollution, release of toxic substances, fires and other hazards, each of which could result in damage to or destruction of its facilities or damage to persons and property. If any of these events were to occur, the Company could suffer substantial losses. Moreover, as a result, the Company has been, and likely will be, a defendant in legal proceedings and litigation arising in the ordinary course of business. Although the Company maintains insurance coverage, such coverage may be inadequate to protect the Company from all expenses related to these risks.
Terrorist attacks, such as the attacks that occurred on September 11, 2001, have resulted in increased costs, and the consequences of terrorism may adversely impact the Company’s results of operations.
The impact that terrorist attacks, such as the attacks of September 11, 2001, may have on the energy industry in general, and on the Company in particular, is not known at this time. Uncertainty surrounding military activity may affect the Company’s operations in unpredictable ways, including disruptions of fuel supplies and markets and the possibility that infrastructure facilities, including pipelines, LNG facilities, gathering facilities and processing plants, could be direct targets of, or indirect casualties of, an act of terror or a retaliatory strike. The Company may have to incur significant additional costs in the future to safeguard its physical assets.
The success of the pipeline and gathering and processing businesses depends, in part, on factors beyond the Company’s control.
Third parties own most of the natural gas transported and stored through the pipeline systems operated by Panhandle and Florida Gas. Additionally, third parties produce all of the natural gas gathered and processed by SUGS, and third parties provide all of the NGL transportation and fractionation services for SUGS. As a result, the volume of natural gas or NGL transported, stored, gathered, processed or fractionated depends on the actions of those third parties and is beyond the Company’s control. Further, other factors beyond the Company’s and those third parties’ control may unfavorably impact the Company’s ability to maintain or increase current transmission, storage, gathering or processing rates, to renegotiate existing contracts as they expire or to remarket unsubscribed capacity. High utilization of contracted capacity by firm customers reduces capacity available for interruptible transportation and parking services.
The success of the pipeline and gathering and processing businesses depends on the continued development of additional natural gas reserves in the vicinity of their facilities and their ability to access additional reserves to offset the natural decline from existing sources connected to their systems.
The amount of revenue generated by Panhandle and Florida Gas ultimately depends upon their access to reserves of available natural gas. Additionally, the amount of revenue generated by SUGS depends substantially upon the volume of natural gas gathered and processed and NGL extracted. As the reserves available through the supply basins connected to these systems naturally decline, a decrease in development or production activity could cause a decrease in the volume of natural gas available for transmission, gathering or processing. If production from these natural gas reserves is substantially reduced and not replaced with other sources of natural gas, such as new wells or interconnections with other pipelines, and certain of the Company’s assets are consequently not utilized, the Company may have to accelerate the recognition and settlement of AROs. Investments by third parties in the development of new natural gas reserves or other sources of natural gas in proximity to the Company’s facilities depend on many factors beyond the Company’s control. Revenue reductions or the acceleration of AROs resulting from the decline of natural gas reserves and the lack of new sources of natural gas may have a material adverse effect on the Company’s business, financial condition, results of operations and cash flows.
The pipeline and gathering and processing businesses revenues are generated under contracts that must be renegotiated periodically.
The revenues of Panhandle, Florida Gas and SUGS are generated under contracts that expire periodically and must be replaced. Although the Company will actively pursue the renegotiation, extension and/or replacement of all of its contracts, it cannot assure that it will be able to extend or replace these contracts when they expire or that the terms of any renegotiated contracts will be as favorable as the existing contracts. If the Company is unable to renew, extend or replace these contracts, or if the Company renews them on less favorable terms, it may suffer a material reduction in revenues and earnings.
The expansion of the Company’s pipeline and gathering and processing systems by constructing new facilities subjects the Company to construction and other risks that may adversely affect the financial results of the Company’s pipeline and gathering and processing businesses.
The Company may expand the capacity of its existing pipeline, storage, LNG, and gathering and processing facilities by constructing additional facilities. Construction of these facilities is subject to various regulatory, development and operational risks, including:
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the Company’s ability to obtain necessary approvals and permits from FERC and other regulatory agencies on a timely basis and on terms that are acceptable to it;
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the ability to access sufficient capital at reasonable rates to fund expansion projects, especially in periods of prolonged economic decline;
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the availability of skilled labor, equipment, and materials to complete expansion projects;
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adverse weather conditions;
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potential changes in federal, state and local statutes, regulations, and orders, including environmental requirements that prevent a project from proceeding or increase the anticipated cost of the project;
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impediments on the Company’s ability to acquire rights-of-way or land rights on a timely basis or on terms that are acceptable to it;
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the Company’s ability to construct projects within anticipated costs, including the risk that the Company may incur cost overruns, which may be material, resulting from inflation or increased costs of equipment, materials, labor, contractor productivity or other factors beyond its control, that the Company may not be able to recover from its customers;
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the lack of future growth in natural gas supply and/or demand; and
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the lack of transportation, storage or throughput commitments or gathering and processing commitments.
Any of these risks could prevent a project from proceeding, delay its completion or increase its anticipated costs. There is also the risk that a downturn in the economy and its potential negative impact upon natural gas demand could result in either slower development in the Company’s expansion projects or adjustments in the contractual commitments supporting such projects. As a result, new facilities could be delayed or may not achieve the Company’s expected investment return, which could adversely affect the Company’s business, financial condition, results of operations and cash flows.
The inability to continue to access lands owned by third parties could adversely affect the Company’s ability to operate and/or expand its pipeline and gathering and processing businesses.
The ability of Panhandle, Florida Gas or SUGS to operate in certain geographic areas will depend on their success in maintaining existing rights-of-way and obtaining new rights-of-way. Securing additional rights-of-way is also critical to the Company’s ability to pursue expansion projects. Even for Panhandle and Florida Gas, which generally have the right of eminent domain, the Company cannot assure that it will be able to acquire all of the necessary new rights-of-way or maintain access to existing rights-of-way upon the expiration of the current rights-of-way or that all of the rights-of-way will be obtainable in a timely fashion. The Company’s financial position could be adversely affected if the costs of new or extended rights-of-way materially increase or the Company is unable to obtain or extend the rights-of-way timely.
Federal, state and local jurisdictions may challenge the Company’s tax return positions.
The positions taken by the Company in its tax return filings require significant judgment, use of estimates, and the interpretation and application of complex tax laws. Significant judgment is also required in assessing the timing and amounts of deductible and taxable items. Despite management’s belief that the Company’s tax return positions are fully supportable, certain positions may be challenged successfully by federal, state and local jurisdictions.
The Company is subject to extensive federal, state and local laws and regulations regulating the environmental aspects of its business that may increase its costs of operation, expose it to environmental liabilities and require it to make material unbudgeted expenditures.
The Company is subject to extensive federal, state and local laws and regulations regulating the environmental aspects of its business (including air emissions), which are complex, change from time to time and have tended to become increasingly strict. These laws and regulations have necessitated, and in the future may necessitate, increased capital expenditures and operating costs. In addition, certain environmental laws may result in liability without regard to fault concerning contamination at a broad range of properties, including currently or formerly owned, leased or operated properties and properties where the Company disposed of, or arranged for the disposal of, waste.
The Company is currently monitoring or remediating contamination at several of its facilities and at waste disposal sites pursuant to environmental laws and regulations and indemnification agreements. The Company cannot predict with certainty the sites for which it may be responsible, the amount of resulting cleanup obligations that may be imposed on it or the amount and timing of future expenditures related to environmental remediation because of the difficulty of estimating cleanup costs and the uncertainty of payment by other PRPs.
Costs and obligations also can arise from claims for toxic torts and natural resource damages or from releases of hazardous materials on other properties as a result of ongoing operations or disposal of waste. Compliance with amended, new or more stringently enforced existing environmental requirements, or the future discovery of contamination, may require material unbudgeted expenditures. These costs or expenditures could have a material adverse effect on the Company’s business, financial condition, results of operations or cash flows, particularly if such costs or expenditures are not fully recoverable from insurance or through the rates charged to customers or if they exceed any amounts that have been reserved.
A recent determination that emissions of carbon dioxide and other “greenhouse gases” present an endangerment to public health could result in regulatory initiatives that increase the Company’s costs of doing business and the costs of its services.
On April 17, 2009, the EPA issued a notice of its proposed finding and determination that emissions of carbon dioxide, methane, and other “greenhouse gases” (GHGs) presented an endangerment to human health and the environment because emissions of such gases contribute to warming of the earth’s atmosphere and other climatic changes. Once finalized, EPA’s finding and determination would allow the agency to begin regulating GHG emissions under existing provisions of the Clean Air Act. In late September 2009, EPA announced two sets of proposed regulations in anticipation of finalizing its findings and determination, one rule to reduce emissions of GHGs from motor vehicles and the other to control emissions of GHGs from stationary sources. The motor vehicle rules are expected to be adopted in March 2010, with the stationary source permitting rule to be approved later in 2010. It may take the EPA several years to impose regulations limiting emissions of GHGs from existing stationary sources due to legal challenges on the stationary rule. In addition, on September 22, 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the United States, including the Company’s processing plants and many compressor stations, beginning in 2011 for emissions occurring in 2010. Any limitation imposed by the EPA on GHG emissions from the Company’s natural gas-fired compressor stations and processing facilities or from the combustion of natural gas or natural gas liquids that it produces could increase its costs of doing business and/or increase the cost and reduce demand for its services.
The adoption of climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the products and services the Company provides.
The Kyoto Protocol was adopted in 1997 by the United Nations to address global climate change by reducing emissions of carbon dioxide and other greenhouse gases. The treaty went into effect on February 16, 2005. The United States has not adopted the Kyoto Protocol. However, on June 26, 2009, the United States House of Representatives approved adoption of the “American Clean Energy and Security Act of 2009,” also known as the “Waxman-Markey cap-and-trade legislation” (ACESA), which would establish an economy-wide cap-and-trade program in the United States to reduce emissions of GHGs, including carbon dioxide and methane that may be contributing to warming of the Earth’s atmosphere and other climatic changes. ACESA would require an overall reduction in GHG emissions of 17 percent (from 2005 levels) by 2020, and by over 80 percent by 2050. Under ACESA, covered sources of GHG emissions would be required to obtain GHG emission “allowances” corresponding to their annual emissions of GHGs. The number of emission allowances issued each year would decline as necessary to meet ACESA’s overall emission reduction goals. As the number of GHG emission allowances declines each year, the cost or value of allowances is expected to escalate significantly. The net effect of ACESA would be to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products, natural gas and NGLs.
The United States Senate has begun work on its own legislation for controlling and reducing emissions of GHGs in the United States. If the Senate adopts GHG legislation that is different from ACESA, the two versions of the bill would need to be reconciled in both chambers of Congress and both chambers would be required to approve identical legislation before it would become law. President Obama has indicated that he is in support of the adoption of legislation to control and reduce emissions of GHGs through an emission allowance permitting system that results in fewer allowances being issued each year but that allows parties to buy, sell and trade allowances as needed to fulfill their GHG emission obligations. Although it is not possible at this time to predict whether or when the Senate may act on climate change legislation or how any bill approved by the Senate could be reconciled with ACESA, any laws or regulations that may be adopted to restrict or reduce emissions of GHGs would likely require the Company to incur increased operating costs. Further, current or future rate structures or shipper or producer contracts and prevailing market conditions might not allow the Company to recover the additional costs incurred to comply with such laws and/or regulations and may affect the Company’s ability to provide services. While the Company may be able to include some or all of such increased costs in its rate structures or shipper or producer contracts, such recovery of costs is uncertain and may depend on events beyond the Company’s control. Such matters could have a material adverse effect on demand for the Company’s gathering, treating, processing, distribution or transportation services.
Even if such legislation is not adopted at the national level, more than one-third of the states have begun taking actions to control and/or reduce emissions of GHGs, with most of the state-level initiatives focused on large sources of GHG emissions, such as coal-fired electric plants. It is possible that smaller sources of emissions could become subject to GHG emission limitations or allowance purchase requirements in the future. Any one of these climate change regulatory and legislative initiatives could have a material adverse effect on the Company’s business, financial condition, results of operations and cash flows.
The Company is subject to risks associated with climate change.
It has been advanced that emissions of greenhouse gases are linked to climate change. Climate change and the costs that may be associated with its impact and the regulation of GHGs have the potential to affect the Company’s business in many ways, including negatively impacting the costs it incurs in providing its products and services, including costs to operate and maintain its facilities, install new emission controls on its facilities, acquire allowances to authorize its GHG emissions, pay any taxes related to GHG emissions and administer and manage a GHG emissions program, higher insurance premiums or the potential for increased insurance claims in areas affected by adverse weather and coastal regions in the event of rising sea levels, the demand for and consumption of its products and services (due to change in both costs and weather patterns), and the economic health of the regions in which it operates, all of which could have a material adverse effect on the Company’s business, financial condition, results of operations and cash flows.
RISKS THAT RELATE TO THE COMPANY’S TRANSPORTATION AND STORAGE BUSINESS
The Company’s transportation and storage business is highly regulated.
The Company’s transportation and storage business is subject to regulation by federal, state and local regulatory authorities. FERC, the U.S. Department of Transportation and various state and local regulatory agencies regulate the interstate pipeline business. In particular, FERC has authority to regulate rates charged by Panhandle and Florida Gas for the transportation and storage of natural gas in interstate commerce. FERC also has authority over the construction, acquisition, operation and disposition of these pipeline and storage assets. In addition, the U.S. Coast Guard has oversight over certain issues including the importation of LNG.
The Company’s rates and operations are subject to extensive regulation by federal regulators as well as the actions of Congress and state legislatures and, in some respects, state regulators. The Company cannot predict or control what effect future actions of regulatory agencies may have on its business or its access to the capital markets. Furthermore, the nature and degree of regulation of natural gas companies has changed significantly during the past several decades and there is no assurance that further substantial changes will not occur or that existing policies and rules will not be applied in a new or different manner. Should new and more stringent regulatory requirements be imposed, the Company’s business could be unfavorably impacted and the Company could be subject to additional costs that could adversely affect its financial condition or results of operations if these costs are not ultimately recovered through rates.
The Company’s transportation and storage business is influenced by fluctuations in costs, including operating costs such as insurance, postretirement and other benefit costs, wages, outside contractor services costs, asset retirement obligations for certain assets and other operating costs. The profitability of regulated operations depends on the business’ ability to collect such increased costs as a part of the rates charged to its customers. To the extent that such operating costs increase in an amount greater than that for which revenue is received, or for which rate recovery is allowed, this differential could impact operating results. The lag between an increase in costs and the ability of the Company to file to obtain rate relief from FERC to recover those increased costs can have a direct negative impact on operating results. As with any request for an increase in rates in a regulatory filing, once granted, the rate increase may not be adequate. In addition, FERC may prevent the business from passing along certain costs in the form of higher rates.
FERC may also exercise its Section 5 authority to initiate proceedings to review rates that it believes may not be just and reasonable. FERC has recently exercised this authority with respect to several other pipeline companies, as it had in 2007 with respect to the Company’s Southwest Gas Storage Company. If FERC were to initiate a Section 5 proceeding against the Company and find that the Company’s rates at that time were not just and reasonable, the applicable rates the Company is allowed to charge customers could be reduced and the reduction could potentially have a material adverse effect on the Company’s business, financial condition, results of operations or cash flows.
The pipeline businesses are subject to competition.
The interstate pipeline businesses of Panhandle and Florida Gas compete with those of other interstate and intrastate pipeline companies in the transportation and storage of natural gas. The principal elements of competition among pipelines are rates, terms of service and the flexibility and reliability of service. Natural gas
competes with other forms of energy available to the Company’s customers and end-users, including electricity, coal and fuel oils. The primary competitive factor is price. Changes in the availability or price of natural gas and
other forms of energy, the level of business activity, conservation, legislation and governmental regulations, the capability to convert to alternate fuels and other factors, including weather and natural gas storage levels, affect the demand for natural gas in the areas served by Panhandle and Florida Gas.
Substantial risks are involved in operating a natural gas pipeline system.
Numerous operational risks are associated with the operation of a complex pipeline system. These include adverse weather conditions, accidents, the breakdown or failure of equipment or processes, the performance of pipeline facilities below expected levels of capacity and efficiency, the collision of equipment with pipeline facilities (such as may occur if a third party were to perform excavation or construction work near the facilities) and other catastrophic events beyond the Company’s control. In particular, the Company’s pipeline system, especially those portions that are located offshore, may be subject to adverse weather conditions, including hurricanes, earthquakes, tornadoes, extreme temperatures and other natural phenomena, making it more difficult for the Company to realize the historic rates of return associated with these assets and operations. A casualty occurrence might result in injury or loss of life, extensive property damage or environmental damage. Insurance proceeds may not be adequate to cover all liabilities or expenses incurred or revenues lost.
Fluctuations in energy commodity prices could adversely affect the pipeline businesses.
If natural gas prices in the supply basins connected to the pipeline systems of Panhandle and Florida Gas are higher than prices in other natural gas producing regions able to serve the Company’s customers, the volume of natural gas transported by the Company may be negatively impacted. Natural gas prices can also affect customer demand for the various services provided by the Company.
The pipeline businesses are dependent on a small number of customers for a significant percentage of their sales.
Panhandle’s top two customers accounted for 35 percent of its 2009 revenue. Florida Gas’ top two customers accounted for 54 percent of its 2009 revenue. The loss of any one or more of these customers could have a material adverse effect on the Company’s business, financial condition, results of operations or cash flows.
The Company is exposed to the credit risk of its transportation and storage customers in the ordinary course of business.
Transportation service contracts obligate customers to pay charges for reservation of capacity, or reservation charges, regardless of whether they transport natural gas on the pipeline system. Customers with natural gas imbalances on the pipeline system may also owe natural gas to the Company. As a result, the Company’s profitability will depend upon the continued financial performance and creditworthiness of its customers rather than just upon the amount of capacity provided under service contracts.
Generally, customers are rated investment grade or, as permitted by the Company’s tariff, are required to make pre-payments or deposits, or to provide collateral, if their creditworthiness does not meet certain criteria. Nevertheless, the Company cannot predict to what extent future declines in customers' creditworthiness may negatively impact its business.
RISKS THAT RELATE TO THE COMPANY’S GATHERING AND PROCESSING BUSINESS
The Company’s gathering and processing business is unregulated.
Unlike the Company’s returns on its regulated transportation and distribution businesses, the natural gas gathering and processing operations conducted at SUGS are not regulated for cost-based ratemaking purposes and may potentially have a higher level of risk in recovering incurred costs than the Company’s regulated operations.
Although SUGS operates in an unregulated market, the business is subject to certain regulatory risks, most notably environmental and safety regulations. Moreover, the Company cannot predict when additional legislation or regulation might affect the gathering and processing industry, nor the impact of any such changes on the Company’s business, financial position, results of operations or cash flows.
The Company’s gathering and processing business is subject to competition.
The gathering and processing industry is expected to remain highly competitive. Most customers of SUGS have access to more than one gathering and/or processing system. The Company’s ability to compete depends on a number of factors, including the infrastructure and contracting strategies of competitors in the Company’s gathering region and the efficiency, quality and reliability of the Company’s plant and gathering system.
In addition to SUGS’ current competitive position in the gathering and processing industry, its business is subject to pricing risks associated with changes in the supply of, and the demand for, natural gas and NGL. If natural gas or NGL prices in the producing areas connected to the Company’s gathering system are comparatively higher than prices in other natural gas producing regions, the volume of natural gas that SUGS chooses to process may, to the extent operationally feasible, be reduced to maximize returns to the Company. Similarly, since the demand for natural gas or NGL is primarily a function of commodity prices (including prices for alternative energy sources), customer usage rates, weather, economic conditions and service costs, the volume processed, or the NGL extracted during processing, by SUGS may be reduced based on these market conditions on a daily basis after analysis by the Company.
The Company’s profit margin in the gathering and processing business is highly dependent on energy commodity prices.
SUGS’ gross margin is largely derived from (a) percentage of proceeds arrangements based on the volume and quality of natural gas gathered and/or NGL recovered through its facilities and (b) specified fee arrangements for a range of services. Under percent-of-proceeds arrangements, SUGS generally gathers and processes natural gas from producers for an agreed percentage of the proceeds from the sales of the resulting residue natural gas and NGL. The percent-of-proceeds arrangements, in particular, expose SUGS’ revenues and cash flows to risks associated with the fluctuation of the price of natural gas, NGL and crude oil and their relationships to each other.
The markets and prices for natural gas and NGL depend upon factors beyond the Company’s control. These factors include demand for these commodities, which fluctuates with changes in market and economic conditions, and other factors, including:
·
the impact of seasonality and weather;
·
general economic conditions;
·
the level of domestic crude oil and natural gas production and consumption;
·
the level of worldwide crude oil and NGL production and consumption;
·
the availability and level of natural gas and NGL storage;
·
the availability of imported natural gas, LNG, NGL and crude oil;
·
actions taken by foreign oil and natural gas producing nations;
·
the availability of local, intrastate and interstate transportation systems;
·
the availability of NGL transportation and fractionation capacity;
·
the availability and marketing of competitive fuels;
·
the impact of energy conservation efforts;
·
the extent of governmental regulation and taxation; and
·
the availability and effective liquidity of natural gas and NGL derivative counterparties.
To manage its commodity price risk related to natural gas and NGL, the Company uses a combination of puts, fixed-rate (i.e., receive fixed price) or floating-rate (i.e. receive variable price) index and basis swaps, NGL gross processing spread puts and fixed-rate swaps and exchange-traded futures and options. These derivative financial instruments allow the Company to preserve value and protect margins because changes in the value of the derivative financial instruments are highly effective in offsetting changes in physical market commodity prices and reducing basis risk. Basis risk exists primarily due to price differentials between cash market delivery locations and futures contract delivery locations. For information related to derivative financial instruments, see Item 8. Financial Statements and Supplementary Data - Note 10 Derivative Instruments and Hedging Activities - Gathering and Processing Segment.
A reduction in demand for NGL products by the petrochemical, refining or heating industries could materially adversely affect the Company’s gathering and processing business.
The NGL products the Company produces have a variety of applications, including for use as heating fuels, petrochemical feed stocks and refining blend stocks. A reduction in demand for NGL products, whether because of general economic conditions, new government regulations, reduced demand by consumers for products made with NGL products, increased competition from petroleum-based products due to pricing differences, mild winter weather, severe weather such as hurricanes causing damage to Gulf Coast petrochemical facilities or other reasons, could result in a decline in the value of the NGL products the Company sells and/or reduce the volume of NGL products the Company produces.
Operational risks are involved in operating a gathering and processing business.
Numerous operational risks are associated with the operation of a natural gas gathering and processing business. These include adverse weather conditions, accidents, the breakdown or failure of equipment or processes, the performance of processing and fractionation facilities below expected levels of capacity or efficiency, the collision of equipment with facilities and catastrophic events such as explosions, fires, earthquakes, floods, landslides, tornadoes, lightning or other similar events beyond the Company’s control. A casualty occurrence might result in injury or loss of life, extensive property damage or environmental damage. Insurance proceeds may be inadequate to cover all liabilities or expenses incurred or revenues lost.
The Company does not obtain independent evaluations of natural gas reserves dedicated to its gathering and processing business, potentially resulting in future volumes of natural gas available to the Company being less than anticipated.
The Company does not obtain independent evaluations of natural gas reserves connected to its gathering systems due to the unwillingness of producers to provide reserve information, as well as the cost of such evaluations. Accordingly, the Company does not have independent estimates of total reserves dedicated to its gathering systems or the anticipated life of such reserves. If the total reserves or estimated lives of the reserves connected to the Company’s gathering systems are less than anticipated and the Company is unable to secure additional sources of natural gas, then the volumes of natural gas in the future could be less than anticipated. A decline in the volumes of natural gas and associated NGL in the Company’s gathering and processing business could have a material adverse effect on its business.
The Company’s gathering and processing business accepts some credit risk in dealing with customers.
SUGS derives its revenues from customers engaged primarily in the natural gas and utility industries, and extends payment credit to these customers. SUGS’ accounts receivable primarily consist of mid- to large-size domestic customers with credit ratings of investment grade or better. Moreover, SUGS maintains trading relationships with counterparties that include reputable U.S. broker-dealers and other financial institutions and evaluates the ability of each counterparty to perform under the terms of the derivative agreements. Nevertheless, the Company cannot predict to what extent future declines in customers’ creditworthiness may negatively impact its business.
The Company depends on one natural gas producer for a significant portion of its supply of natural gas. The loss of this producer or the replacement of its contracts on less favorable terms could result in a decline in the Company’s volumes and/or gross margin.
SUGS’ largest natural gas supplier for the year ended December 31, 2009 accounted for approximately 20 percent of the Company’s wellhead throughput under multiple contracts. The loss of all or even a portion of the natural gas volumes supplied by this producer or the extension or replacement of these contracts on less favorable terms, if at all, as a result of competition or otherwise, could reduce the Company’s gross margin. Although this producer represents a large volume of natural gas, the gross margin per unit of volume is significantly lower than the average gross margin per unit of volume on the Company’s gathering and processing system due to the lack of need for services required to make the natural gas merchantable (e.g. high pressure, low NGL content, essentially transmission pipeline quality natural gas).
RISKS THAT RELATE TO THE COMPANY’S DISTRIBUTION BUSINESS
The distribution business is highly regulated and the Company’s revenues, operating results and financial condition may fluctuate with the distribution business’ ability to achieve timely and effective rate relief from state regulators.
The Company’s distribution business is subject to regulation by the MPSC and the MDPU. These authorities regulate many aspects of the Company’s distribution operations, including construction and maintenance of facilities, operations, safety, the rates that can be charged to customers and the maximum rate of return that the Company is allowed to realize. The ability to obtain rate increases depends upon regulatory discretion.
The distribution business is influenced by fluctuations in costs, including operating costs such as insurance, postretirement and other benefit costs, wages, changes in the provision for the allowance for doubtful accounts associated with volatile natural gas costs and other operating costs. The profitability of regulated operations depends on the business’ ability to recover costs related to providing services to its customers. To the extent that such operating costs increase in an amount greater than that for which rate recovery is allowed, this differential could impact operating results until the business files for and is allowed an increase in rates. The lag between an increase in costs and the rate relief obtained from the regulators can have a direct negative impact on operating results. As with any request for an increase in rates in a regulatory filing, once granted, the rate increase may not be adequate. In addition, regulators may prevent the business from passing along some costs in the form of higher rates.
The distribution business’ operating results and liquidity needs are seasonal in nature and may fluctuate based on weather conditions and natural gas prices.
The natural gas distribution business is a seasonal business with a significant percentage of annual operating revenues and EBIT occurring in the traditional winter heating season in the first and fourth calendar quarters. The business is also subject to seasonal and other variations in working capital due to changes in natural gas prices and the fact that customers pay for the natural gas delivered to them after they use it, whereas the business is required to pay for the natural gas before delivery. As a result, fluctuations in natural gas prices may have a significant effect on results of operations and cash flows.
Operational risks are involved in operating a distribution business.
Numerous risks are associated with the operations of a natural gas distribution business. These include adverse weather conditions, accidents, the breakdown or failure of equipment or processes, the performance of suppliers’ processing facilities below expected levels of capacity or efficiency, the collision of equipment with facilities and catastrophic events such as explosions, fires, earthquakes, floods, landslides, tornadoes, lightning or other similar events beyond the Company’s control. A casualty occurrence might result in injury or loss of life, extensive property damage or environmental damage. Insurance proceeds may be inadequate to cover all liabilities or expenses incurred or revenues lost.
CAUTIONARY FACTORS THAT MAY AFFECT FUTURE RESULTS
The disclosure and analysis in this Form 10-K contains forward-looking statements that set forth anticipated results based on management’s current plans and assumptions. From time to time, Southern Union also provides forward-looking statements in other materials it releases to the public as well as oral forward-looking statements. Such statements give the Company’s current expectations or forecasts of future events; they do not relate strictly to historical or current facts. Southern Union has tried, wherever possible, to identify such statements by using words such as “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” “will” and similar expressions in connection with any discussion of future operating or financial performance. In particular, these include statements relating to future actions, future performance or results of current and anticipated services, expenses, interest rates, the outcome of contingencies, such as legal proceedings, and financial results.
Southern Union cannot guarantee that any forward-looking statement will be realized, although management believes that the Company has been prudent and reasonable in its plans and assumptions. Achievement of future results is subject to risks, uncertainties and potentially inaccurate assumptions. If known or unknown risks or uncertainties should materialize, or if underlying assumptions should prove inaccurate, actual results could differ materially from past results and those anticipated, estimated or projected. Readers should bear this in mind as they consider forward-looking statements.
Southern Union undertakes no obligation to update publicly forward-looking statements, whether as a result of new information, future events or otherwise. Readers are advised, however, to consult any further disclosures the Company makes on related subjects in its Form 10-K, Form 10-Q and Form 8-K reports to the SEC. Also note that Southern Union provides the following cautionary discussion of risks, uncertainties and possibly inaccurate assumptions relevant to its businesses. These are factors that, individually or in the aggregate, management believes could cause the Company’s actual results to differ materially from expected and historical results. Southern Union notes these factors for investors as permitted by the Private Securities Litigation Reform Act of 1995. Readers should understand that it is not possible to predict or identify all such factors. Consequently, readers should not consider the following to be a complete discussion of all potential risks or uncertainties.
Factors that could cause actual results to differ materially from those expressed in the Company’s forward-looking statements include, but are not limited to, the following:
·
changes in demand for natural gas or NGL and related services by the Company’s customers, in the composition of the Company’s customer base and in the sources of natural gas available to the Company;
·
the effects of inflation and the timing and extent of changes in the prices and overall demand for and availability of natural gas or NGL as well as electricity, oil, coal and other bulk materials and chemicals;
·
adverse weather conditions, such as warmer than normal weather in the Company’s service territories, and the operational impact of natural disasters;
·
changes in laws or regulations, third-party relations and approvals, decisions of courts, regulators and governmental bodies affecting or involving Southern Union, including deregulation initiatives and the impact of rate and tariff proceedings before FERC and various state regulatory commissions;
·
the speed and degree to which additional competition is introduced to Southern Union’s business and the resulting effect on revenues;
·
the outcome of pending and future litigation;
·
the Company’s ability to comply with or to challenge successfully existing or new environmental regulations;
·
unanticipated environmental liabilities;
·
the Company’s exposure to highly competitive commodity businesses through its Gathering and Processing segment;
·
the Company’s ability to acquire new businesses and assets and integrate those operations into its existing operations, as well as its ability to expand its existing businesses and facilities;
·
the Company’s ability to control costs successfully and achieve operating efficiencies, including the purchase and implementation of new technologies for achieving such efficiencies;
·
the impact of factors affecting operations such as maintenance or repairs, environmental incidents, natural gas pipeline system constraints and relations with labor unions representing bargaining-unit employees;
·
exposure to customer concentration with a significant portion of revenues realized from a relatively small number of customers and any credit risks associated with the financial position of those customers;
·
changes in the ratings of the debt securities of Southern Union or any of its subsidiaries;
·
changes in interest rates and other general capital markets conditions, and in the Company’s ability to continue to access the capital markets;
·
acts of nature, sabotage, terrorism or other acts causing damage greater than the Company’s insurance coverage limits;
·
market risks beyond the Company’s control affecting its risk management activities including market liquidity, commodity price volatility and counterparty creditworthiness; and
·
other risks and unforeseen events.
ITEM 1B.
ITEM 1B. Unresolved Staff Comments.
N/A
ITEM 2.
ITEM 2. Properties.
TRANSPORTATION AND STORAGE
See Item 1. Business - Business Segments - Transportation and Storage Segment for information concerning the general location and characteristics of the important physical properties and assets of the Transportation and Storage segment.
GATHERING AND PROCESSING
See Item 1. Business - Business Segments - Gathering and Processing Segment for information concerning the general location and characteristics of the important physical properties and assets of the Gathering and Processing segment.
DISTRIBUTION
See Item 1. Business - Business Segments - Distribution Segment for information concerning the general location and characteristics of the important physical properties and assets of the Distribution segment.
OTHER
The Company’s other businesses primarily consist of PEI Power Corporation, a wholly-owned subsidiary of the Company, which has ownership interests in two electric power plants that share a site in Archbald, Pennsylvania. PEI Power Corporation wholly owns one plant, a 25 megawatt electric cogeneration facility fueled by a combination of natural gas and methane, and owns 49.9 percent of the second plant, a 45 megawatt natural gas-fired electric generation facility, through a joint venture with Cayuga Energy.
ITEM 3.
ITEM 3. Legal Proceedings.
The Company and certain of its affiliates are occasionally parties to lawsuits and administrative proceedings incidental to their businesses involving, for example, claims for personal injury and property damage, contractual matters, various tax matters, and rates and licensing. The Company and its affiliates are also subject to various federal, state and local laws and regulations relating to the environment, as described in Item 1. Business. Several of these companies have been named parties to various actions involving environmental issues. Based on the Company’s current knowledge and subject to future legal and factual developments, the Company’s management believes that it is unlikely that these actions, individually or in the aggregate, will have a material adverse effect on its consolidated financial position, results of operations or cash flows. For additional information regarding various pending administrative and judicial proceedings involving regulatory, environmental and other legal matters, reference is made to Item 8, Financial Statements and Supplementary Data, Note 18 - Regulation and Rates and Note 14 - Commitments and Contingencies. Also see Item 1A. Risk Factors - Cautionary Factors That May Affect Future Results.
ITEM 4.
ITEM 4. Reserved.
PART II
ITEM 5.
ITEM 5. Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
MARKET INFORMATION
Southern Union’s common stock is traded on the New York Stock Exchange under the symbol “SUG.” The high and low sales prices for shares of Southern Union common stock and the cash dividends per share declared in each quarter since January 1, 2008 are set forth below:
Provisions in certain of Southern Union’s long-term debt and bank credit facilities limit the issuance of divi­dends on capital stock. Under the most restrictive provisions in effect, Southern Union may not declare or issue any dividends on its common stock or acquire or retire any of Southern Union’s common stock, unless no event of default exists and the Company meets certain financial ratio requirements, which presently are met. Southern Union’s ability to pay cash dividends may be limited by certain debt restrictions at Panhandle and Citrus that could limit Southern Union’s access to funds from Panhandle and Citrus for debt service or dividends. For additional related information, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Financing Activities - Dividend Restrictions and Item 8. Financial Statements and Supplementary Data, Note 15 - Stockholders’ Equity and Note 7 - Debt Obligations.
COMMON STOCK PERFORMANCE GRAPH
The following performance graph compares the performance of Southern Union’s common stock to the Standard & Poor’s 500 Stock Index (“S&P 500 Index”) and the Bloomberg U.S. Pipeline Index. The comparison assumes $100 was invested on December 31, 2004, in Southern Union common stock, the S&P 500 Index and the Bloomberg U.S. Pipeline Index. Each case assumes reinvestment of dividends.
The following companies constitute the Bloomberg U.S. Pipeline Index used in the graph: Enbridge, Inc., Spectra Energy Corp., TransCanada Corp., and Williams Companies, Inc.
HOLDERS
As of February 24, 2010, there were 5,913 holders of record of Southern Union’s common stock, and 124,414,274 shares of Southern Union’s common stock were issued and outstanding. The holders of record do not include persons whose shares are held of record by a bank, brokerage house or clearing agency, but do include any such bank, brokerage house or clearing agency that is a holder of record.
EQUITY COMPENSATION PLANS
Equity compensation plans approved by stockholders include the Southern Union Company Third Amended and Restated 2003 Stock and Incentive Plan and the 1992 Long-Term Stock Incentive Plan (1992 Plan). While Southern Union options are still outstanding under the 1992 Plan, the 1992 Plan expired on July 1, 2002 and no shares are available for future grant thereunder. Under both plans, stock options and SARs are issued having an exercise price equal to the fair market value of the Company’s common stock on the date of grant. Stock options typically vest ratably over three, four or five years and SARs vest over three years.
The following table sets forth the number of outstanding options and SARs, the weighted average exercise price of outstanding options and SARs and the number of shares remaining available for issuance as of December 31, 2009:
Number of Securities
to Be Issued Upon
Weighted Average
Number of Securities
Exercise of
Exercise Price of
Remaining Available for
Outstanding
Outstanding
Future Issuance Under
Options/SARs
Options/SARs
Equity Compensation Plans
Plans approved by stockholders
3,384,618 (1), (2)
$19.38
4,695,399
_________________
(1)
Excludes 378,974 shares of restricted stock that were outstanding at December 31, 2009.
(2)
Assumes the number of securities issued from the exercise of SARs outstanding equals the appreciation from the award’s grant date to the exercise date.
UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
The following table presents information with respect to purchases during the three months ended December 31, 2009 made by Southern Union or any “affiliated purchaser” of Southern Union (as defined in Rule 10b-18(a)(3)) of equity securities that are registered pursuant to Section 12 of the Exchange Act.
__________________
(1)
Shares of common stock purchased in open-market transactions and held in various Company employee benefit plan trusts by the trustees using cash amounts deferred by the participants in such plans (and quarterly cash dividends issued by the Company on shares held in such plans).
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA.
___________________
(1)
Includes the impact of the March 1, 2006 acquisition of Sid Richardson Energy Services, Ltd. and related entites, and the August 24, 2006 dispositions of PG Energy and the Rhode Island operations of New England Gas Company. See note 4 below for additional related information regarding the asset dispositions.
(2)
The Company’s investment in CCE Holdings was accounted for using the equity method until it became a wholly-owned subsidiary on December 1, 2006.
(3)
Net earnings from continuing operations are net of dividends on preferred stock of $8.7 million, $12.2 million, $17.4 million, $17.4 million and $17.4 million for the years ended December 31, 2009, 2008, 2007, 2006 and 2005, respectively. Additionally, net earnings from continuing operations are net of the $3.5 million Loss on extinguishment of preferred stock applicable to the year ended December 31, 2008. For additional related information, see Item 8. Financial Statements and Supplementary Data, Note16 - Preferred Securities.
(4)
On August 24, 2006, the Company completed the sales of the assets of its PG Energy natural gas distribution division to UGI Corporation and the Rhode Island operations of its New England Gas Company natural gas distribution division to National Grid USA. These dispositions were accounted for as discontinued operations in the Consolidated Statement of Operations.
(5)
Earnings per share for all periods presented were computed based on the weighted average number of shares of common stock and common stock equivalents out­standing during the period, adjusted for the five percent stock dividend distributed on September 1, 2005.
(6)
No cash dividends on common stock were paid during the reporting period prior to 2006. See Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities and Item 8. Financial Statements and Supplementary Data, Note 15 - Stockholders’ Equity - Dividends.
ITEM 7.
ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
INTRODUCTION
This Management’s Discussion and Analysis of Financial Condition and Results of Operations is provided as a supplement to the accompanying consolidated financial statements and notes to help provide an understanding of Southern Union’s financial condition, changes in financial condition and results of operations. The following section includes an overview of the Company’s business as well as recent developments that management of the Company believes are important in understanding its results of operations, and to anticipate future trends in those operations. Subsequent sections include an analysis of the Company’s results of operations on a consolidated basis and on a segment basis for each reportable segment, and information relating to the Company’s liquidity and capital resources, quantitative and qualitative disclosures about market risk and other matters.
The Company’s business purpose is to provide gathering, processing, transportation, storage and distribution of natural gas and NGL in a safe, efficient and dependable manner. The Company’s reportable business segments are determined based on the way internal managerial reporting presents the results of the Company’s various businesses to its executive management for use in determining the performance of the businesses and in allocating resources to the businesses as well as based on similarities in economic characteristics, products and services, types of customers, methods of distribution and regulatory environment. The Company operates in three reportable segments: Transportation and Storage, Gathering and Processing, and Distribution.
BUSINESS STRATEGY
The Company’s strategy is focused on achieving profitable growth and enhancing stockholder value. The Company seeks to balance its entrepreneurial focus with respect to maximizing cash and capital appreciation return to shareholders with preservation of its investment grade credit ratings. The key elements of its strategy include the following:
·
Expanding through development of the Company’s existing businesses. The Company will continue to pursue growth opportunities through the expansion of its existing asset base, while maintaining its focus on providing safe and reliable service to its customers. In each of its business segments, the Company identifies opportunities for organic growth through incremental volumes and system enhancements to generate operating efficiencies. In its transportation and distribution businesses, the Company seeks rate increases and/or improved rate design as appropriate to achieve a fair return on its investment. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Investing Activities for information related to the Company’s principal capital expenditure projects. See Item 8. Financial Statements and Supplementary Data, Note 18 - Regulation and Rates for information related to ratemaking activities.
·
New initiatives. The Company regularly assesses strategies to enhance stockholder value, including diversification of earning sources through strategic acquisitions or joint ventures in the diversified natural gas industry.
·
Disciplined capital expenditures and cost containment programs. The Company will continue to focus on system optimization and cost savings while making prudent capital expenditures across its base of energy infrastructure assets.
RESULTS OF OPERATIONS
Overview
The Company evaluates operational and financial segment performance using several factors, of which the primary financial measure is EBIT, a non-GAAP measure. The Company defines EBIT as Net earnings available for common stockholders, adjusted for the following:
·
items that do not impact net earnings, such as extraordinary items, discontinued operations and the impact of changes in accounting principles;
·
income taxes;
·
interest;
·
dividends on preferred stock; and
·
loss on extinguishment of preferred stock.
EBIT may not be comparable to measures used by other companies and should be considered in conjunction with net earnings and other performance measures such as operating income or net cash flows provided by operating activities.
The following table provides a reconciliation of EBIT (by segment) to Net earnings available for common stockholders for the periods presented:
Year ended December 31, 2009 versus the year ended December 31, 2008. The Company’s $108.5 million decrease in Net earnings available for common stockholders was primarily due to the lower EBIT contribution of $185.8 million from the Gathering and Processing segment resulting from lower operating revenues of $687.1 million, excluding hedging gains and losses, attributable to lower market-driven realized average natural gas and NGL prices and the impact of $101.7 million of lower revenues from hedging activities, partially offset by lower market-driven natural gas and NGL purchase costs of $593 million in 2009 versus 2008.
These reductions in earnings were partially offset by:
·
Higher EBIT contribution of $7.1 million from the Transportation and Storage segment primarily due to higher operating revenues of $27.5 million largely attributable to higher interruptible parking revenues of $17.1 million due to customer demand, market conditions and the availability of system capacity and higher transportation reservation revenues of $13.3 million primarily due to higher average rates realized on PEPL, partially offset by higher net operating, maintenance and general expenses of $7.8 million and higher depreciation and amortization expense of $9.8 million primarily resulting from increases in property, plant and equipment placed in service;
·
Higher EBIT contribution of $5.9 million from the Distribution segment primarily due to the impact of $8.1 million of income in 2009 resulting from settlements with insurance companies related to certain environmental matters;
·
Higher EBIT contribution of $13.8 million from Corporate and other activities primarily due to the impact of $10.8 million of income in 2009 resulting from settlements with insurance companies related to certain environmental matters and higher legal fees of $5.9 million in the 2008 period;
·
Lower interest expense of $10.6 million primarily attributable to lower interest expense of $10.1 million due to lower LIBOR interest rates associated with the Company’s variable rate debt and the impact of a $6.8 million increase in interest costs capitalized attributable to higher average capital project balances outstanding in 2009 compared to 2008, partially offset by higher net interest expense of $7.1 million attributable to higher net debt balances outstanding on the Company’s fixed-rate debt obligations;
·
Impact of a $3.5 million loss recorded in the 2008 period related to the Company’s purchase of 459,999 shares of its Preferred Stock and the reduction in related dividends of $3.5 million; and
·
Lower federal and state income tax expense of $32.9 million primarily due to lower pre-tax earnings of $148.4 million, partially offset by the impact of a 29 percent EITR in the 2009 period versus a 26 percent EITR in 2008.
Year ended December 31, 2008 versus the year ended December 31, 2007. The Company’s $68.1 million increase in Net earnings available for common stockholders was primarily due to:
·
Higher EBIT contribution of $80 million from the Gathering and Processing segment primarily due to higher market-driven realized average natural gas and NGL prices and the impact of $50.1 million of higher net hedging gains in the 2008 period versus the 2007 period, partially offset by a reduction in gross margin of approximately $10.6 million resulting from the impact of Hurricane Ike on the Company’s third-party NGL fractionator, the establishment of a $3 million bad debt reserve for a customer that filed for bankruptcy protection, and higher depreciation expense of $3.2 million.
This earnings improvement was partially offset by:
·
Higher interest expense of $4.3 million primarily attributable to higher interest expense of $21.1 million in 2008 associated with new debt issued during the 2008 and 2007 periods primarily to fund capital expenditures for enhancement projects in the Transportation and Storage segment and retire maturing debt, partially offset by lower interest expense of $13.1 million on the $465 million 2012 Term Loan agreement in 2008 primarily due to lower LIBOR interest rates, and higher capitalized interest of $4.3 million resulting from higher average capital project balances outstanding in the 2008 period versus the 2007 period;
·
Lower EBIT contribution of $2.6 million from the Transportation and Storage segment primarily due to lower equity earnings attributable to Citrus of $24 million primarily resulting from $18.7 million of nonrecurring gains in the 2007 period related to the settlement of litigation and the sale of bankruptcy-related receivables, partially offset by higher EBIT contributions of $21.4 million in 2008 from Panhandle primarily attributable to higher transportation reservation revenues, partially offset by higher operating expenses; and
·
Higher income taxes of $9.5 million primarily due to higher pre-tax income in 2008, partially offset by a lower EITR in the 2008 period versus the 2007 period primarily attributable to a $22.1 million tax benefit resulting from a reduction in the Company’s deferred income tax liability in the fourth quarter of 2008 associated with the dividends received deduction for anticipated dividends from the Company’s unconsolidated investment in Citrus.
Business Segment Results
Transportation and Storage Segment. The Transportation and Storage segment is primarily engaged in the interstate transportation and storage of natural gas in the Midwest and from the Gulf Coast to Florida, and LNG terminalling and regasification services. The Transportation and Storage segment’s operations, conducted through Panhandle and Florida Gas, are regulated as to rates and other matters by FERC. Demand for natural gas transmission on Panhandle’s pipeline systems is seasonal, with the highest throughput and a higher portion of annual total operating revenues and EBIT occurring in the traditional winter heating season, which occurs during the first and fourth calendar quarters. Florida Gas’ pipeline system experiences the highest throughput in the traditional summer cooling season during the second and third calendar quarters, primarily due to increased natural gas-fired electric generation loads.
The Company’s business within the Transportation and Storage segment is conducted through both short- and long-term contracts with customers. Shorter-term contracts, which can increase the volatility of revenues, are driven by changes in market conditions and competition with other pipelines, changing supply sources and volatility in natural gas prices. Since the majority of the revenues within the Transportation and Storage segment are related to firm capacity reservation charges, changes in commodity prices and volumes transported do not have as significant an impact on revenues over the short-term. However, longer-term demand for capacity may be affected by changes in commodity prices and volumes transported. Over the past several years, the weighted average life of contracts has actually trended somewhat higher as customers have exhibited an increased focus in securing longer-term supply and related transport capacity from the supply and market areas served by the Company. For additional information related to Transportation and Storage segment risk factors and the weighted average remaining lives of firm transportation and storage contracts, see Item 1A. Risk Factors - Risks that Relate to the Company’s Transportation and Storage Segment and Item 1. Business - Business Segments - Transportation and Storage Segment, respectively.
The Company’s regulated transportation and storage businesses periodically file for changes in their rates, which are subject to approval by FERC. Although a significant portion of the Company’s contracts are discounted or negotiated rate contracts, changes in rates and other tariff provisions resulting from these regulatory proceedings have the potential to impact negatively the Company’s results of operations and financial condition. For information related to the status of current rate filings, see Item 1. Business - Business Segments - Transportation and Storage Segment.
The following table illustrates the results of operations applicable to the Company’s Transportation and Storage segment for the periods presented:
_____________
(1)
Represents 100 percent of Florida Gas natural gas volumes transported versus the Company’s effective equity ownership interest of 50 percent.
See Item 1. Business - Business Segments - Transportation and Storage Segment for additional related
operational and statistical information associated with the Transportation and Storage segment.
Year ended December 31, 2009 versus the year ended December 31, 2008. The $7.1 million EBIT improvement in the year ended December 31, 2009 versus the same period in 2008 was primarily due to a higher EBIT contribution from Panhandle.
Panhandle’s $7.1 million EBIT increase was primarily due to:
·
Higher operating revenues of $27.5 million primarily as the result of:
o
Higher interruptible parking revenues of $17.1 million resulting from customer demand for parking services, market conditions and the availability of system capacity;
o
Higher transportation reservation revenues of $13.3 million primarily due to higher average rates realized on PEPL and contributions from various expansion projects primarily consisting of the Trunkline Field Zone Expansion and PEPL East End Enhancement projects, partially offset by lower average rates realized on Trunkline and $1.2 million of additional revenues in the 2008 period attributable to the extra day in the 2008 leap year;
o
A $5.1 million increase in LNG terminalling revenue primarily due to higher reservation revenues attributable to a one-time annual rate increase associated with certain capacity effective January 1, 2009; and
o
Lower transportation usage revenues of $7.4 million primarily due to reduced volumes flowing on Sea Robin after Hurricane Ike.
The increased revenues were offset by:
·
Higher operating, maintenance and general expenses of $7.8 million in 2009 versus 2008 primarily attributable to:
o
A $5.6 million increase in benefits primarily due to higher medical costs;
o
A $5.5 million increase in third-party transportation and storage expense primarily due to additional capacity contracted;
o
A $4.8 million increase in fuel tracker costs primarily due to a net over-recovery in 2008 versus a net under-recovery in 2009; and
o
A $6.4 million decrease in expense due to a provision reversal in 2009 related to past take-or-pay settlement contractual indemnities for which performance by the Company has not been required;
·
Increased depreciation and amortization expense of $9.8 million in 2009 versus 2008 due to a $136 million increase in property, plant and equipment placed in service after December 31, 2008. Depreciation and amortization expense is expected to continue to increase primarily due to significant capital additions, including capital spending associated with the LNG terminal infrastructure enhancement construction project; and
·
Higher taxes, other than on income and revenues, of $2.5 million primarily due to higher property tax assessments resulting from property additions and higher operating income. Property tax expense is expected to continue to increase primarily due to significant property additions, which has been partially mitigated by certain temporary property tax abatements.
See Item 8. Financial Statements and Supplementary Data, Note 14 - Commitments and Contingencies - Other Commitments and Contingencies - 2008 Hurricane Damage for additional information related to the repair and abandonment provisions and insurance recovery resulting from hurricane damage.
Equity earnings, primarily attributable to the Company’s unconsolidated investment in Citrus, were higher by $32,000 in 2009 versus 2008 primarily due to the following items, adjusted where applicable to reflect the Company’s proportional equity share:
·
Higher other income of $23.5 million largely driven by higher equity AFUDC resulting from Florida Gas’ Phase VIII Expansion project. Due to the increasing levels of capitalized project costs, AFUDC is expected to continue to trend higher until completion of the Phase VIII Expansion project;
·
Higher operating revenues of $1.8 million primarily due to higher reservation revenues of $2.4 million resulting from increased capacity from prior expansions, partially offset by the impact of additional revenues in the 2008 period attributable to the extra day in the 2008 leap year;
·
Higher debt interest cost of $19 million primarily due to interest on a $500 million construction and term loan agreement funded in October 2008 and on the $600 million 7.90% Senior Notes issued in May 2009, partially offset by higher debt AFUDC, lower average outstanding revolver debt balances and lower LIBOR interest rates;
·
Higher income tax of $2.5 million primarily due to higher pretax earnings;
·
Higher depreciation expense of $2.3 million primarily due to increased property, plant and equipment placed in service after December 31, 2008; and
·
Higher operating expenses of $1 million primarily due to higher overall costs experienced in 2009 applicable to employee labor, outside service costs and other operating costs.
See Item 8. Financial Statements and Supplementary Data, Note 5 - Unconsolidated Investments - Citrus for additional information related to Florida Gas.
Year ended December 31, 2008 versus the year ended December 31, 2007. The $2.6 million EBIT reduction in the year ended December 31, 2008 versus the same period in 2007 was primarily due to lower equity earnings from unconsolidated investments of $24 million, partially offset by a higher 2008 EBIT contribution from Panhandle totaling $21.4 million.
Equity earnings, primarily attributable to the Company’s unconsolidated investment in Citrus, were lower by $24 million in 2008 versus 2007 primarily due to the following items, adjusted where applicable to reflect the Company’s proportional equity share:
·
A $15.1 million nonrecurring gain recorded in the 2007 period related to the settlement of litigation;
·
A $3.6 million nonrecurring gain recorded in the 2007 period related to the sale of bankruptcy-related receivables;
·
Higher operating expenses of $6 million primarily due to increased property taxes and higher overall costs experienced in 2008 applicable to employee labor and benefits, outside contract services costs and other operating costs;
·
Higher depreciation expense of $2.6 million primarily due to increased plant placed in service;
·
Higher interest expense of $4.5 million due to higher debt balances, including the $500 million Construction Loan Agreement related to the Phase VIII Expansion project, which was funded on October 1, 2008;
·
Higher operating revenues of $4.7 million primarily due to higher reservation revenues of $4.5 million attributable to increased capacity from prior expansions and the extra day in 2008 for the leap year; and
·
Lower income taxes of $9.4 million primarily due to lower pre-tax earnings.
Panhandle’s $21.4 million EBIT improvement was primarily due to $63.2 million in higher operating revenues primarily related to the following items:
·
Higher transportation reservation revenues of $49.1 million primarily due to the phased completion of the Trunkline Field Zone Expansion project during the period from December 2007 to February 2008 and reduced discounting resulting in higher average rates realized on contracts driven by higher customer demand, and approximately $1.2 million of additional revenues attributable to the extra day in the 2008 leap year;
·
Higher transportation commodity revenues of $7.1 million primarily due to a rate increase on Sea Robin, net of related customer liability refund provisions and the impact of approximately $4.1 million of lower revenues attributable to reduced volumes flowing after Hurricane Ike;
·
Higher interruptible parking revenues of $8.2 million resulting from customer demand for parking services and market conditions;
·
Higher storage revenues of $6.7 million primarily due to increased leased storage capacity; and
·
A $6.5 million decrease in LNG terminalling revenue due to lower volumes from decreased LNG cargoes during 2008.
These increased revenues were offset by:
·
Higher operating, maintenance and general expenses of $21.6 million primarily attributable to:
o
Expense of $13.5 million related to damage to the Company’s facilities resulting from Hurricanes Gustav and Ike;
o
A $10.2 million increase in contract storage costs resulting from an increase in leased storage capacity;
o
A $4 million increase in insurance costs primarily due to higher property premiums;
o
A $3.5 million net increase in labor primarily due to merit increases;
o
A $5.7 million decrease in fuel tracker costs primarily due to a net over-recovery in 2008 versus a net under-recovery in 2007; and
o
A $5.5 million decrease in LNG power costs resulting from a reduced number of LNG cargoes during 2008;
·
Increased depreciation and amortization expense of $18.2 million due to a $387.8 million increase in property, plant and equipment placed in service after December 31, 2007; and
·
Increased taxes, other than on income, of $2.4 million primarily due to higher property taxes attributable to higher property tax assessments resulting from increased operating income, partially offset by lower compressor fuel tax on a reduced number of LNG cargoes.
Gathering and Processing Segment. The Gathering and Processing segment is primarily engaged in connecting wells of natural gas producers to its gathering system, treating natural gas to remove impurities to meet pipeline quality specifications, processing natural gas for the removal of NGL, and redelivering natural gas and NGL to a variety of markets. Its operations are conducted through SUGS. SUGS’ natural gas supply contracts primarily include fee-based, percent-of-proceeds, conditioning fee and wellhead purchase contracts. These natural gas supply contracts vary in length from month-to-month to a number of years, with many of the contracts having a term of three to five years. SUGS’ primary sales customers include producers, power generating companies, utilities, energy marketers, and industrial end-users located primarily in the Gulf Coast and southwestern United States. SUGS’ business is not generally seasonal in nature.
The majority of SUGS’ gross margin is derived from the sale of NGL and natural gas equity volumes. The prices of NGL and natural gas are subject to fluctuations in response to changes in supply, demand, market uncertainty and a variety of factors beyond the Company’s control. The Company monitors these risks and manages the associated commodity price risk using both economic and accounting hedge derivative instruments. For additional information related to the Company’s commodity price risk management, see Item 8. Financial Statements and Supplementary Data, Note 10 - Derivative Instruments and Hedging Activities - Commodity Contracts - Gathering and Processing Segment and, Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk - Commodity Price Risk - Gathering and Processing Segment.
The following table presents the results of operations applicable to the Company’s Gathering and Processing segment for the periods presented:
________________
(1)
Cost of natural gas and other energy consists of natural gas and NGL purchase costs and producer and other fees.
(2)
Gross margin consists of Operating revenues less Cost of natural gas and other energy. The Company believes that this measurement is more meaningful for understanding and analyzing the Gathering and Processing segment’s operating results for the periods presented because commodity costs are a significant factor in the determination of the segment’s revenues.
(3)
Volumes processed by SUGS include volumes sold under various buy-sell arrangements. For the years ended December 31, 2009, 2008 and 2007, the Company’s operating revenues and related volumes attributable to its buy-sell arrangements for natural gas totaled $41.4 million, $95.7 million and $91.6 million, and 11.7 million MMBtus, 12.2 million MMBtus and 13.6 million MMBtus, respectively. The Company’s operating revenues and related volumes attributable to its buy-sell arrangements for NGL totaled $69.2 million and $117.9 million and 91.2 million gallons and 83 million gallons, for the years ended December 31, 2009 and 2008, respectively, and was insignificant for the 2007 period.
(4)
Excludes impact of realized and unrealized commodity derivative gains and losses detailed in the above EBIT presentation.
Year ended December 31, 2009 versus the year ended December 31, 2008. The $185.8 million EBIT reduction in the year ended December 31, 2009 versus the same period in 2008 was primarily due to the following items:
·
Lower gross margin of $196.6 million primarily as the result of:
o
Lower operating revenues of $687.1 million largely attributable to lower market-driven realized average natural gas and NGL prices (unadjusted for the impact of realized and unrealized commodity derivative gains and losses) of $3.43 per MMBtu and $0.78 per gallon in the 2009 period versus $7.67 per MMBtu and $1.37 per gallon in the 2008 period, respectively;
o
Lower market-driven natural gas and NGL purchase costs of $593 million in the 2009 period versus the 2008 period;
o
A $101.7 million reduction in revenues from hedging activities primarily due to a net loss of $44.6 million in the 2009 period versus a net gain of $57.1 million in the 2008 period (which includes the impact of $44.8 million of unrealized losses recorded in 2009);
o
A reduction of approximately $10.6 million in gross margin in 2008 resulting from damage by Hurricane Ike to the Company’s third-party NGL fractionator; and
o
A reduction of approximately $4.9 million in gross margin attributable to a fire on July 17, 2009 at the Keystone processing plant resulting in a production outage until August 1, 2009 and additional reduced production flow;
·
Higher depreciation and amortization expense of $4 million primarily attributable to a $68.2 million increase in property, plant and equipment placed in service after December 31, 2008;
·
Lower operating, maintenance and general expenses of $10.4 million primarily due to:
o
A $5.8 million decrease in maintenance, contract services and other plant operating costs largely attributable to a 2009 cost reduction initiative primarily related to the Company’s variable and discretionary costs;
o
A $2.3 million loss in 2008 related to the settlement of the GP II Energy litigation;
o
Higher bad debt expense of $2.2 million recorded in 2008 versus 2009 associated with a company that filed for bankruptcy protection in 2008;
o
A $1.8 million decrease in chemical and lubricants costs, which generally track the price of oil;
o
A $1.5 million decrease in utility costs primarily due to lower compressor fuel costs attributable to the declining costs of natural gas in 2009 versus 2008; and
o
A $4.6 million net loss in 2009 versus 2008 primarily resulting from the write-off of property and equipment damaged by the fire at the Keystone natural gas processing plant in 2009; and
·
Higher equity earnings of $5.4 million from the Company’s unconsolidated investment in Grey Ranch primarily due to higher volumes in 2009 versus the 2008 period resulting from an increase in capacity from 90 MMcf/d to 200 MMcf/d effective December 31, 2008 and due to a plant outage at the processing plant during the third quarter of 2008 resulting from a fire at the facility in June 2008.
Year ended December 31, 2008 versus the year ended December 31, 2007. The $80 million EBIT increase for the year ended December 31, 2008 versus the same period in 2007 was primarily due to the following items:
·
Higher gross margin of $93.3 million primarily as the result of:
o
A $50.1 million increase in hedging gains in the 2008 period versus the 2007 period (which includes the impact of $59.7 million of unrealized gains recorded in 2008);
o
Higher market-driven realized average natural gas and NGL prices (unadjusted for the impact of realized and unrealized commodity derivative gains and losses) of $7.67 per MMBtu and $1.37 per gallon in the 2008 period versus $6.26 per MMBtu and $1.13 per gallon in the 2007 period;
o
Favorable gross margin impact of lower levels of fuel, flare, and unaccounted for natural gas losses in the 2008 period versus the unusually high levels experienced in the first and second quarters of 2007; and unfavorable gross margin impact of approximately $10.6 million resulting from damage by Hurricane Ike on the Company’s third-party NGL fractionator. Commencing September 11, 2008, the Company was forced to shut in its natural gas processing plants and attendant production for approximately a week and operated at reduced production levels for the remainder of the month.
SUGS’ higher gross margin was partially offset by the following items:
·
Operating, maintenance and general expenses were higher by $6.1 million primarily due to:
o
A $3 million bad debt reserve for receivables associated with a customer that filed for bankruptcy protection in 2008;
o
A $2.3 million increase in chemical and lubricants costs, which generally track with the price of oil; and
o
A $2.1 million increase in utility costs primarily due to higher compressor fuel costs resulting from rising overall average cost of natural gas in 2008 versus 2007.
·
Higher depreciation expense of $3.2 million primarily attributable to a $50.3 million increase in property, plant and equipment placed in service after 2007; and
·
Lower equity earnings of $2.3 million from the Company’s unconsolidated investment in Grey Ranch, which was out of service for approximately five months during 2008 because of a fire at the Grey Ranch processing plant.
For further information related to SUGS’ derivative instruments and hedging activities, see Item 7A. Quantitative and Qualitative Disclosures About Market Risk - Commodity Price Risk - Gathering and Processing Segment and Item 8.
ITEM 8. Financial Statements and Supplementary Data.
The information required here is included in the report as set forth in the Index to Consolidated Financial Statements on page.
ITEM 9.
ITEM 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
ITEM 9A.
ITEM 9A. Controls and Procedures.
EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES
Southern Union has established disclosure controls and procedures to ensure that information required to be disclosed by the Company, including consolidated entities, in reports 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. The Company’s disclosure controls and procedures are designed to ensure that information required to be disclosed in the reports it files or submits under the Exchange Act is accumulated and communicated to management, including the Company’s CEO and CFO, as appropriate, to allow timely decisions regarding required disclosure. The Company performed an evaluation under the supervision and with the participation of management, including its CEO and CFO, and with the participation of personnel from its Legal, Internal Audit, Insurance and Financial Reporting Departments, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of the end of the period covered by this report. Based on that evaluation, Southern Union’s CEO and CFO concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2009.
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is defined in Exchange Act Rule 13a-15(f) as a process designed by, or under the supervision of, the Company’s principal executive officer and principal financial officers, or persons performing similar functions, and effected by the Company’s board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP, and includes those policies and procedures that:
·
Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company;
·
Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the Company; and
·
Provide reasonable assurance regarding the prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.
Exchange Act Rules 13a-15(c) and 15d-15(c) and Section 404 of the Sarbanes-Oxley Act of 2002 require management of the Company to conduct an annual evaluation of the Company’s internal control over financial reporting and to provide a report on management’s assessment, including a statement as to whether or not internal control over financial reporting is effective.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management’s evaluation of the effectiveness of the Company’s internal control over financial reporting was based on the framework in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation under that framework and applicable SEC rules, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2009.
The Company’s internal control over financial reporting as of December 31, 2009 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report, which is included herein.
Southern Union Company
March 1, 2010
CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING
There were no changes in the Company’s internal control over financial reporting that occurred during the quarter ended December 31, 2009 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
ITEM 9B.
ITEM 9B. Other Information.
All information required to be reported on Form 8-K for the quarter ended December 31, 2009 was appropriately reported.
On February 24, 2010, each of the Company’s independent directors voluntarily executed and delivered a conditional letter of resignation to the Board. Each conditional letter of resignation provides that the resignation shall only become effective upon its acceptance by a majority of the Board, and only in the event that a majority of the Board determines that the director is not meeting the strategic needs of the Company or the business oversight or other provisions of the Company’s Corporate Governance Guidelines.
This action was taken individually and voluntarily by each independent director. The independent directors believe that such action was appropriate and in the best interests of the Company’s shareholders in light of the recent focus on director qualifications by the SEC and others as well as the changes to the Company’s Corporate Governance Guidelines recently adopted by the Board.
The conditional letters of resignation may not be withdrawn and each director must recuse himself/herself from the Board’s consideration, if any, of his/her conditional resignation.
In addition, on February 24, 2010, the Board approved an amendment to Section 5 of Article XII of the Company’s Bylaws. This amendment modified language relating to the effectiveness of a resignation by a director of the Company as such language otherwise would have been inconsistent with the previously described conditional letters of resignation. A copy of the Company’s amended Bylaws is attached as Exhibit 3(b) hereto.
On February 26, 2010, the Company entered into the Sixth Amended and Restated Revolving Credit Agreement with the banks named therein in the amount of $550 million. The 2010 Revolver is a refinancing of the Revolver, which was otherwise scheduled to mature on May 28, 2010. The 2010 Revolver will mature on May 28, 2013. Borrowings on the 2010 Revolver are available for the Company’s working capital, other general corporate purposes and letter of credit requirements. The interest rate and commitment fee under the 2010 Revolver are calculated using a pricing grid, which is based upon the credit rating for the Company’s senior unsecured notes. The annualized interest rate and commitment fee rate bases for the 2010 Revolver at February 26, 2010 were LIBOR, plus 275 basis points, and 50 basis points, respectively.
The foregoing description is qualified in its entirety by reference to the 2010 Revolver, which is attached hereto as Exhibit 10(a).
PART III
ITEM 10.
ITEM 10. Directors, Executive Officers and Corporate Governance.
There is incorporated in this Item 10 by reference the information that will appear in the Company’s definitive proxy statement for the 2010 Annual Meeting of Stockholders under the captions Meetings and Committees of the Board - Board of Directors, 2009 Executive Compensation - Named Executive Officers, Section 16(a) Beneficial Ownership Reporting Compliance, Corporate Governance - Code of Ethics, Meetings and Committees of the Board - Board Committees - Corporate Governance Committee and - Audit Committee.
The Company, by and through the audit committee of its Board, has adopted a Code of Ethics and Business Conduct (Code) designed to reflect requirements of the Sarbanes-Oxley Act of 2002, New York Stock Exchange rules and other applicable laws, rules and regulations. The Code applies to all of the Company’s directors, officers and employees. Any amendment to the Code will be posted promptly on Southern Union’s website (http://www.sug.com).
ITEM 11.
ITEM 11. Executive Compensation.
There is incorporated in this Item 11 by reference the information that will appear in the Company’s definitive proxy statement for the 2010 Annual Meeting of Stockholders under the captions Compensation Discussion and Analysis, 2009 Executive Compensation, 2009 Director Compensation, and Meetings and Committees of the Board - Board Committees - Compensation Committee.
ITEM 12.
ITEM 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
There is incorporated in this Item 12 by reference the information that will appear in the Company’s definitive proxy statement for the 2010 Annual Meeting of Stockholders under the caption Security Ownership of Certain Beneficial Owners and Management.
ITEM 13.
ITEM 13. Certain Relationships and Related Transactions, and Director Independence.
There is incorporated in this Item 13 by reference the information that will appear in the Company’s definitive proxy statement for the 2010 Annual Meeting of Stockholders under the caption Corporate Governance - Transactions with Related Persons and - Review, Approval or Ratification of Transactions with Related Persons, and Corporate Governance - Director Independence and - Lead Independent Director.
ITEM 14.
ITEM 14. Principal Accountant Fees and Services.
There is incorporated in this Item 14 by reference the information that will appear in the Company’s definitive proxy statement for the 2010 Annual Meeting of Stockholders under the caption Meetings and Committees of the Board - Board Committees - Audit Committee.
PART IV
ITEM 15.
ITEM 15. Exhibits, Financial Statement Schedules.
(a)(1) and (2)
Financial Statements and Financial Statement Schedules.
(a)(3)
Exhibits.
Exhibit No. Description
2(a)
Purchase and Sale Agreement between Southern Union Company and UGI Corporation, dated as of January 26, 2006. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on January 30, 2006 and incorporated herein by reference.)
2(b)
First Amendment to the Purchase and Sale Agreement between Southern Union Company and UGI Corporation, dated as of August 24, 2006. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on August 30, 2006 and incorporated herein by reference.)
2(c)
Purchase and Sale Agreement between Southern Union Company and National Grid USA, dated as of February 15, 2006. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on February 17, 2006 and incorporated herein by reference.)
2(d)
Limited Settlement Agreement between Southern Union Company, Narragansett Electric Company d/b/a National Grid, the Department of the Attorney General for the State of Rhode Island and the Rhode Island Department of Environmental Management, dated as of August 24, 2006. (Filed as Exhibit 10.2 to Southern Union’s Current Report on Form 8-K filed on August 30, 2006 and incorporated herein by reference.)
2(e)
First Amendment to the Purchase and Sale Agreement between Southern Union Company and National Grid USA, dated as of August 24, 2006. (Filed as Exhibit 10.3 to Southern Union’s Current Report on Form 8-K filed on August 30, 2006 and incorporated herein by reference.)
3(a)
Amended and Restated Certificate of Incorporation of Southern Union Company. (Filed as Exhibit 3(a) to Southern Union’s Annual Report on Form 10-K for the year ended December 31, 2005 and incorporated herein by reference.)
3(b)
By-Laws of Southern Union Company, as amended. (Filed as Exhibit 3(b) hereto.)
3(c)
Certificate of Designations, Preferences and Rights re: Southern Union Company’s 7.55% Noncumulative Preferred Stock, Series A. (Filed as Exhibit 4.1 to Southern Union’s Form 8-A/A dated October 17, 2003 and incorporated herein by reference.)
4(a)
Specimen Common Stock Certificate. (Filed as Exhibit 4(a) to Southern Union's Annual Report on Form 10-K for the year ended December 31, 1989 and incorporated herein by reference.)
4(b)
Senior Debt Securities Indenture between Southern Union and The Chase Manhattan Bank (National Association), which changed its name to JP Morgan Chase Bank and then to JP Morgan Chase Bank, N.A., which was then succeeded to by The Bank of New York Trust Company, N.A., which changed its name to The Bank of New York Mellon Trust Company N.A., as Trustee (Filed as Exhibit 4.1 to Southern Union’s Current Report on Form 8-K dated February 15, 1994 and incorporated here-in by reference.)
4(c)
Officers' Certificate dated January 31, 1994 setting forth the terms of the 7.60% Senior Debt Securities due 2024. (Filed as Exhibit 4.2 to Southern Union's Current Report on Form 8-K dated February 15, 1994 and incorporated herein by reference.)
4(d)
Officer's Certificate of Southern Union Company dated November 3, 1999 with respect to 8.25% Senior Notes due 2029. (Filed as Exhibit 99.1 to Southern Union's Current Report on Form 8-K filed on November 19, 1999 and incorporated herein by reference.)
4(e)
Form of Supplemental Indenture No. 1, dated June 11, 2003, between Southern Union Company and JP Morgan Chase Bank, which changed its name to JP Morgan Chase Bank, N.A., the predecessor to The Bank of New York Trust Company, N.A., which changed its name to The Bank of New York Mellon Trust Company, N.A. (Filed as Exhibit 4.5 to Southern Union’s Form 8-A/A dated June 20, 2003 and incorporated herein by reference.)
4(f)
Supplemental Indenture No. 2, dated February 11, 2005, between Southern Union Company and JP Morgan Chase Bank, N.A., the predecessor to The Bank of New York Trust Company, N.A., which changed its name to The Bank of New York Mellon Trust Company, N.A. (Filed as Exhibit 4.4 to Southern Union’s Form 8-A/A dated February 22, 2005 and incorporated herein by reference.)
4(g)
Subordinated Debt Securities Indenture between Southern Union and The Chase Manhattan Bank (National Association), which changed its name to JP Morgan Chase Bank and then to JP Morgan Chase Bank, N.A., which was then succeeded to by The Bank of New York Trust Company, N.A., which changed its name to The Bank of New York Mellon Trust Company, N.A., as Trustee (Filed as Exhibit 4-G to Southern Union’s Registration Statement on Form S-3 (No. 33-58297) and incorporated herein by reference.)
4(h)
Second Supplemental Indenture, dated October 23, 2006, between Southern Union Company and The Bank of New York Trust Company, N.A., now known as The Bank of New York Mellon Trust Company, N.A. (Filed as Exhibit 4.1 to Southern Union’s Form 8-K/A dated October 24, 2006 and incorporated herein by reference.)
4(i)
2006 Series A Junior Subordinated Notes Due November 1, 2066 dated October 23, 2006. (Filed as Exhibit 4.2 to Southern Unions Current Report on Form 8-K/A filed on October 24, 2006 and incorporated herein by reference.)
4(j)
Replacement Capital Covenant, dated as of October 23, 2006 by Southern Union Company, a Delaware corporation with its successors and assigns, in favor of and for the benefit of each Covered Debtor (as defined in the Covenant). (Filed as Exhibit 4.3 to Southern Union’s Current Report on Form 8-K/A filed on October 24, 2006 and incorporated herein by reference.)
4(k) Southern Union is a party to other debt instruments, none of which authorizes the issuance of debt securities in an amount which exceeds 10% of the total assets of
Southern Union. Southern Union hereby agrees to furnish a copy of any of these instruments to the Commission upon request.
10(a)
Sixth Amended and Restated Revolving Credit Agreement, dated as of February 26, 2010, among the Company, as borrower, and the lenders party thereto. (Filed as Exhibit 10(a) hereto.)
10(b)
First Amendment to Construction and Term Loan Agreement between Citrus Corp., as borrower, and Pipeline Funding Company, LLC, as lender and administrative agent, dated as of August 6, 2008. (Filed as Exhibit 10(a) to Southern Union Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2008 and incorporated herein by reference.)
10(c)
Construction and Term Loan Agreement between Citrus Corp., as borrower, and Pipeline Funding Company, LLC, as lender and administrative agent, dated as of February 5, 2008. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on February 8, 2008 and incorporated herein by reference.)
10(d)
Amendment Number 1 to the Amended and Restated Credit Agreement between Trunkline LNG Holdings, LLC, as borrower, Panhandle Eastern Pipe Line Company, LP and CrossCountry Citrus, LLC, as guarantors, the financial institutions listed therein and Bayerische Hypo-Und Vereinsbank AG, New York Branch, as administrative agent, dated as of June 13, 2008. (Filed as Exhibit 10(d) to Southern Union Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2008 and incorporated herein by reference.)
10(e)
Amended and Restated Credit Agreement between Trunkline LNG Holdings, LLC, as borrower, Panhandle Eastern Pipeline Company, LP and CrossCountry Citrus, LLC, as guarantors, the financial institutions listed therein and Bayerische Hypo-Und Vereinsbank AG, New York Branch, as administrative agent, dated as of June 29, 2007. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on July 6, 2007 and incorporated herein by reference.)
10(f)
Credit Agreement between Trunkline LNG Holdings, LLC, as borrower, Panhandle Eastern Pipeline Company, LP and Trunkline LNG Company, LLC, as guarantors, the financial institutions listed therein and Hypo-Und Vereinsbank AG, New York Branch, as administrative agent, dated as of March 15, 2007. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on March 21, 2007 and incorporated herein by reference.)
10(g)
Form of Indemnification Agreement between Southern Union Company and each of the Directors of Southern Union Company and certain senior executive officers. (Filed as Exhibit 10(g) to Southern Union’s Annual Report on Form 10-K for the year ended December 31, 2008 and incorporated herein by reference.)
10(h)
Southern Union Company 1992 Long-Term Stock Incentive Plan, As Amended. (Filed as Exhibit 10(l) to Southern Union’s Annual Report on Form 10-K for the year ended June 30, 1998 and incorporated herein by reference.) *
10(i)
Southern Union Company Director's Deferred Compensation Plan. (Filed as Exhibit 10(g) to Southern Union's Annual Report on Form 10-K for the year ended December 31, 1993 and incorporated herein by reference.)
10(j)
First Amendment to Southern Union Company Director’s Deferred Compensation Plan, effective April 1, 2007. (Filed as Exhibit 10(h) to Southern Union Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2007 and incorporated herein by reference.)
10(k)
Southern Union Company Amended Supplemental Deferred Compensation Plan with Amendments. (Filed as Exhibit 4 to Southern Union’s Form S-8 filed May 27, 1999 and incorporated herein by reference.) *
10(l)
Second Amended and Restated Southern Union Company 2003 Stock and Incentive Plan. (Filed as Exhibit 4 to Form S-8, SEC File No. 333-138524, filed on November 8, 2006 and incorporated herein by reference.) *
10(m)
Third Amended and Restated Southern Union Company 2003 Stock and Incentive Plan. (Filed as Appendix I to Southern Union’s proxy statement on Schedule 14A filed on April 16, 2009 and incorporated herein by reference).*
10(n)
Form of Long Term Incentive Award Agreement, dated December 28, 2006, between Southern Union Company and the undersigned. (Filed as Exhibit 99.1 to Southern Union’s Form 8-K dated January 3, 2007) and incorporated herein by reference.) *
10(o)
Employment Agreement between Southern Union Company and George L. Lindemann, dated as of August 28, 2008. (Filed as Exhibit 10(f) to Southern Union Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 and incorporated herein by reference.) *
10(p)
Employment Agreement between Southern Union Company and Eric D. Herschmann, dated as of August 28, 2008. (Filed as Exhibit 10(g) to Southern Union Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 and incorporated herein by reference.) *
10(q)
Employment Agreement between Southern Union Company and Robert O. Bond, dated as of August 28, 2008. (Filed as Exhibit 10(h) to Southern Union Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 and incorporated herein by reference.) *
10(r)
Employment Agreement between Southern Union Company and Monica M. Gaudiosi, dated as of August 28, 2008. (Filed as Exhibit 10(i) to Southern Union Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 and incorporated herein by reference.) *
10(s)
Employment Agreement between Southern Union Company and Richard N. Marshall, dated as of August 28, 2008. (Filed as Exhibit 10(j) to Southern Union Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 and incorporated herein by reference.) *
10(t)
Form of Change in Control Severance Agreement, between Southern Union Company and certain Executives (filed as Exhibit 10.2 to Southern Union’s Current Report on Form 8-K filed on August 28, 2008 and incorporated herein by reference.) *
10(u)
Capital Stock Agreement dated June 30, 1986, as amended April 3, 2000 ("Agreement"), among El Paso Energy Corporation (as successor in interest to Sonat, Inc.); CrossCountry Energy, LLC (assignee of Enron Corp., which is the successor in interest to InterNorth, Inc. by virtue of a name change and successor in interest to Houston Natural Gas Corporation by virtue of a merger) and Citrus Corp. (Filed as Exhibit 10(t) to Southern Union’s Annual Report on Form 10-K for the year ended December 31, 2008 and incorporated herein by reference.)
10(v)
Certificate of Incorporation of Citrus Corp. (Filed as Exhibit 10(q) to Southern Union’s Annual Report on Form 10-K for the year ended December 31, 2006 and incorporated herein by reference.)
10(w)
By-Laws of Citrus Corp., filed herewith. (Filed as Exhibit 10(r) to Southern Union’s Annual Report on Form 10-K for the year ended December 31, 2006 and incorporated herein by reference.)
Ratio of earnings to fixed charges.
Code of Ethics and Business Conduct. (Filed as Exhibit 14 to Southern Union’s Annual Report on Form 10-K filed on March 16, 2006 and incorporated herein by reference.)
Subsidiaries of the Registrant.
23.1
Consent of Independent Registered Public Accounting Firm for Southern Union Company.
23.2 Consent of Independent Registered Public Accounting Firm for Citrus Corp.
Power of Attorney.
31.1
Certificate by Chief Executive Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) promulgated under the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2
Certificate by Chief Financial Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) promulgated under the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1
Certificate by Chief Executive Officer pursuant to Rule 13a-14(b) or Rule 15d-14(b) promulgated under the Securities Exchange Act of 1934 and Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350.
32.2
Certificate by Chief Financial Officer pursuant to Rule 13a-14(b) or Rule 15d-14(b) promulgated under the Securities Exchange Act of 1934 and Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350.
____________
* Management contract or compensation plan or arrangement
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Southern Union has duly caused this report to be signed by the undersigned, thereunto duly authorized, on March 1, 2010.
SOUTHERN UNION COMPANY
By: /s/ George L. Lindemann
George L. Lindemann
Chairman of the Board and
Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of Southern Union and in the capacities indicated as of March 1, 2010.
Signature/Name
Title
/s/ George L. Lindemann*
George L. Lindemann
Chairman of the Board and
Chief Executive Officer
(Principal Executive Officer)
/s/ Eric D. Herschmann*
Eric D. Herschmann
Vice Chairman of the Board, President and Chief Operating Officer
/s/ Richard N. Marshall
Richard N. Marshall
Senior Vice President and Chief Financial Officer
(Principal Financial Officer)
/s/ George E. Aldrich
George E. Aldrich
Senior Vice President and Controller
(Chief Accounting Officer)
/s/ Michal Barzuza*
Michal Barzuza
/s/ David Brodsky*
David Brodsky
Director
Director
/s/ Frank W. Denius*
Frank W. Denius
Director
/s/ Kurt A. Gitter, M.D.*
Kurt A. Gitter, M.D
Director
/s/ Herbert H. Jacobi*
Herbert H. Jacobi
Director
/s/ Thomas N. McCarter, III*
Thomas N. McCarter, III
Director
/s/ George Rountree, III*
George Rountree, III
Director
/s/ Allan D. Scherer*
Allan Scherer
Director
*By: /s/ RICHARD N. MARSHALL
*By: /s/ ROBERT M. KERRIGAN, III
Richard N. Marshall
Robert M. Kerrigan, III
Senior Vice President and Chief Financial Officer
Vice President, Assistant General Counsel and
Attorney-in-fact
Secretary
Attorney-in-fact
SOUTHERN UNION COMPANY AND SUBSIDIARIES
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Financial Statements and Supplementary Data:
Page(s):
Consolidated Statement of Operations
Consolidated Balance Sheet
-
Consolidated Statement of Cash Flows
Consolidated Statement of Stockholders’ Equity and Comprehensive Income
-
Notes to Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm
All schedules are omitted as the required information is not applicable or the information is presented in the consolidated financial statements or related notes.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF OPERATIONS
The accompanying notes are an integral part of these consolidated financial statements.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
ASSETS
The accompanying notes are an integral part of these consolidated financial statements.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
STOCKHOLDERS' EQUITY AND LIABILITIES
The accompanying notes are an integral part of these consolidated financial statements.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS
The accompanying notes are an integral part of these consolidated financial statements.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME
The accompanying notes are an integral part of these consolidated financial statements.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME
(Continued)
The Company’s common stock is $1 par value. Therefore, the change in Common Stock, $1 par value, is equivalent to the change in the number of shares of common stock issued.
The accompanying notes are an integral part of these consolidated financial statements.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Corporate Structure
Operations. The Company was incorporated under the laws of the State of Delaware in 1932. The Company owns and operates assets in the regulated and unregulated natural gas industry and is primarily engaged in the gathering, processing, transportation, storage and distribution of natural gas in the United States. Through Panhandle, the Company owns and operates approximately 10,000 miles of interstate pipelines that transport up to 5.5 Bcf/d of natural gas from the Gulf of Mexico, South Texas and the Panhandle regions of Texas and Oklahoma to major U.S. markets in the Midwest and Great Lakes regions. Panhandle also owns and operates a LNG import terminal located on Louisiana’s Gulf Coast. Through its investment in Citrus, the Company has an interest in and operates Florida Gas, an interstate pipeline company that transports natural gas from producing areas in South Texas through the Gulf Coast region to Florida. Through SUGS, the Company owns approximately 5,500 miles of natural gas and NGL pipelines, four cryogenic plants with a combined capacity of 410 MMcf/d and five natural gas treating plants with combined capacities of 585 MMcf/d. SUGS is primarily engaged in connecting wells of natural gas producers to its gathering system, treating natural gas to remove impurities to meet pipeline quality specifications, processing natural gas for the removal of NGL, and redelivering natural gas and NGL to a variety of markets. Its operations are located in West Texas and Southeast New Mexico. Through Southern Union’s regulated utility operations, Missouri Gas Energy and New England Gas Company, the Company serves natural gas end-user customers in Missouri and Massachusetts, respectively.
2. Summary of Significant Accounting Policies and Other Matters
The FASB Accounting Standards Codification (Codification) became effective on July 1, 2009, officially becoming the single source of authoritative nongovernmental GAAP, superseding existing FASB, American Institute of Certified Public Accountants, Emerging Issues Task Force, and related accounting literature. Only one level of authoritative GAAP now exists. All other accounting literature is considered non-authoritative. The Codification reorganizes the thousands of GAAP pronouncements into roughly 90 accounting topics and displays them using a consistent structure. Also included in the Codification is relevant SEC guidance organized using the same topical structure in separate sections within the Codification. The Codification is effective for financial statements that cover interim and annual periods ending after September 15, 2009. The Company’s financial statements have only been impacted to the extent that all references to authoritative accounting literature have been referenced in accordance with the Codification.
Basis of Presentation. The Company’s consolidated financial statements have been prepared in accordance with GAAP.
Principles of Consolidation. The consolidated financial statements include the accounts of Southern Union and its wholly-owned subsidiaries. Investments in which the Company has significant influence over the operations of the investee are accounted for using the equity method. All sig­nifi­cant intercompany accounts and transactions are eliminated in consolidation. Certain reclassifications have been made to prior years' financial statements to conform to the current year presentation.
Use of Estimates. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Property, Plant and Equipment. Ongoing additions of property, plant and equipment are stated at cost. The Company capitalizes all construction-related direct labor and material costs, as well as indirect construction costs. The cost of replacements and betterments that extend the useful life of property, plant and equipment is also capitalized. The cost of repairs and replacements of minor property, plant and equipment items is charged to expense as incurred.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
When property, plant and equipment is retired within the Company’s Transportation and Storage and Distribution segments, the original cost less salvage value is charged to accumulated depreciation and amortization. When entire regulated operating units of property, plant and equipment are retired or sold or non-regulated properties are retired or sold, the property and related accumulated depreciation and amortization accounts are reduced, and any gain or loss is recorded in earnings. When property, plant and equipment is retired within the Company’s Gathering and Processing segment, the original cost less salvage value and accumulated depreciation and amortization balances are removed, with the resulting gain or loss recorded in earnings.
The Company computes depreciation expense using the straight-line method. Depreciation rates for the utility plants are approved by the applicable regulatory commissions.
Computer software, which is a component of property, plant and equipment, is stated at cost and is generally amortized on a straight-line basis over its useful life on a product-by-product basis.
For additional information, see Note 12 - Property, Plant and Equipment.
Asset Impairment. An impairment loss is recognized when the carrying amount of a long-lived asset used in operations is not recoverable and exceeds its fair value. The carrying amount of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset.
A long-lived asset is tested for recoverability whenever events or changes in circumstances indicate that its carrying amount may not be recoverable. The long-lived assets of Sea Robin were evaluated as of December 31, 2009 and 2008 because indicators of potential impairment were evident primarily due to the impacts associated with Hurricane Ike and due to reductions in the estimated payout from the Company’s insurance carrier for reimbursable expenditures for the repair, retirement or replacement of the Company’s property, plant and equipment damaged by Hurricane Ike, which is more fully discussed in Note 14 - Commitments and Contingencies - Other Commitments and Contingencies - 2008 Hurricane Damage. Additionally, the long-lived assets of SUGS were evaluated as of December 31, 2008 because indicators of potential impairment were evident due to the onset of significant market-driven commodity price reductions in late 2008. The analyses indicated no recoverability issues were evident. With the recovery of commodity prices during 2009, no impairment test was necessary for SUGS at December 31, 2009.
Goodwill. Goodwill resulting from a purchase business combination is not amortized, but instead is tested for impairment at the Company’s Distribution segment reporting unit level at least annually by applying a fair-value based test. The annual impairment test is updated if events or circumstances occur that would more likely than not reduce the fair value of the reporting unit below its book carrying value. See Note 19 - Goodwill.
Cash and Cash Equivalents. Cash equivalents consist of highly liquid investments, which are readily convertible into cash and have original maturities of three months or less.
Under the Company’s cash management system, checks issued but not presented to banks frequently result in book overdraft balances for accounting purposes and are classified in accounts payable in the Consolidated Balance Sheet. At December 31, 2009 and 2008, such book overdraft balances classified in accounts payable were approximately $26.2 million and $17.6 million, respectively.
Segment Reporting. The Company is principally engaged in the transportation and storage, gathering and processing and distribution of natural gas in the United States, and reports these operations under three reportable segments: the Transportation and Storage segment, the Gathering and Processing segment and the Distribution segment. See Note 17 - Reportable Segments for additional related information.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Transportation and Storage Revenues. In the Transportation and Storage segment, revenues from transportation and storage of natural gas and LNG terminalling are based on capacity reservation charges and commodity usage charges. Reservation revenues are based on contracted rates and capacity reserved by customers and are recognized monthly. Revenues from commodity usage charges are also recognized monthly, based on the volumes received from or delivered to customers, depending on the tariff of that particular Panhandle entity, with any differences in received and delivered volumes resulting in an imbalance. Volume imbalances generally are settled in-kind with no impact on revenues, with the exception of PEPL’s subsidiary, Trunkline, which settles certain imbalances in cash pursuant to its tariff, and records gains and losses on such cashout sales as a component of revenue, to the extent not owed back to customers.
Gathering and Processing Revenues and Cost of Sales Recognition. The business operations of the Gathering and Processing segment consist of connecting wells of natural gas producers to the Company’s gathering system, treating natural gas to remove impurities, processing natural gas for the removal of NGL and then redelivering or marketing the treated natural gas and/or processed NGL to third parties. The terms and conditions of purchase arrangements with producers, including those limited arrangements with the same counterparty, offer various alternatives with respect to taking title to the purchased natural gas and/or NGL. These arrangements include (i) purchasing all or a specified percentage of natural gas and/or NGL delivered from producers and treating or processing in the Company’s plant facilities and (ii) making other direct purchase of natural gas and/or NGL at specified delivery points to meet operational or marketing obligations. Cost of sales primarily includes the cost of purchased natural gas and/or NGL to which the Company has taken title. Operating revenues are derived from the sale of natural gas and/or NGL in the period in which the physical product is delivered to the customer and title is transferred. Operating revenues and cost of sales within the Gathering and Processing segment are reported on a gross basis.
Natural Gas Distribution Revenues and Natural Gas Purchase Costs. In the Distribution segment, natural gas utility customers are billed on a monthly-cycle basis. The related cost of natural gas and revenue taxes are matched with cycle-billed revenues through utilization of purchased natural gas adjustment provisions in tariffs approved by the regulatory agencies having jurisdiction. Revenues from natural gas delivered but not yet billed are accrued, along with the related natural gas purchase costs and revenue-related taxes. Unbilled receivables related to the Distribution segment recorded in Accounts receivable in the Consolidated Balance Sheet at December 31, 2009 and 2008 were $47.3 million and $60.4 million, respectively.
Accounts Receivable and Allowance for Doubtful Accounts. The Company manages trade credit risks to minimize exposure to uncollectible trade receivables. In the Transportation and Storage and Gathering and Processing segments, prospective and existing customers are reviewed for creditworthiness based upon pre-established standards. Customers that do not meet minimum standards are required to provide additional credit support. In the Distribution segment, concentrations of credit risk in trade receivables are limited due to the large customer base with relatively small individual account balances. Additionally, the Company requires a deposit from customers in the Distribution segment who lack a credit history or whose credit rating is substandard. The Company utilizes the allowance method for recording its allowance for uncollectible accounts, which is primarily based on the application of historical bad debt percentages applied against its aged accounts receivable. Increases in the allowance are recorded as a component of operating expenses. Reductions in the allowance are recorded when receivables are written off or subsequently collected.
The following table presents the balance in the allowance for doubtful accounts and activity for the periods presented:
SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Earnings Per Share. Basic earnings per share is computed based on the weighted average number of common shares outstanding during each period. Diluted earnings per share is computed based on the weighted average number of common shares outstanding during each period, increased by the assumed conversion of equity units (as applicable for years 2007 and 2008), the assumed exercises of stock options and SARs, and the assumed vesting of restricted stock. See Note 4 - Earnings Per Share.
Stock-Based Compensation. The Company measures all employee stock-based compensation using a fair value method and records the related expense in its Consolidated Statement of Operations. For more information, see Note 13 - Stock-Based Compensation.
Accumulated Other Comprehensive Loss. The main components of comprehensive income (loss) that relate to the Company are net earnings, unrealized gain (loss) on hedging activities and unrealized actuarial gain (loss) and prior service credits (cost) on pension and other postretirement plans. For more information, see Note 6 - Accumulated Other Comprehensive Loss.
Inventories. In the Transportation and Storage segment, inventories consist of natural gas held for operations and materials and supplies, both of which are carried at the lower of weighted average cost or market, while natural gas owed back to customers is valued at market. The natural gas held for operations that the Company does not expect to consume in its operations in the next twelve months is reflected in non-current assets.
In the Gathering and Processing segment, inventories consist of non-fractionated Y-grade NGL and materials and supplies, both of which are stated at the lower of weighted average cost or market. Materials and supplies are primarily comprised of compressor components and parts.
In the Distribution segment, inventories consist of natural gas in underground storage and materials and supplies. The natural gas in underground storage inventory carrying value is stated at weighted average cost and is not adjusted to a lower market value because, pursuant to purchased natural gas adjustment clauses, actual natural gas costs are recovered in customers’ rates. Materials and supplies inventory is also stated at weighted average cost.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The components of inventory at the dates indicated are as follows:
____________________
(1)
Natural gas volumes held for operations at December 31, 2009 and 2008 were 35,039,000 MMBtu and 31,751,000 MMBtu, respectively.
(2)
NGL at December 31, 2009 and December 31, 2008 was 6,680,000 gallons and 20,453,000 gallons, respectively.
(3)
Natural gas volumes in underground storage at December 31, 2009 and December 31, 2008 were 11,742,000 MMBtu and 12,702,000 MMBtu, respectively.
Unconsolidated Investments. Investments in affiliates over which the Company may exercise significant influence, generally 20 percent to 50 percent ownership interests, are accounted for using the equity method. Any excess of the Company’s investment in affiliates, as compared to its share of the underlying equity, that is not recognized as goodwill is amortized over the estimated economic service lives of the underlying assets. Other investments over which the Company may not exercise significant influence are accounted for under the cost method. A loss in value of an investment, other than a temporary decline, is recognized in earnings. Evidence of a loss in value might include, but would not necessarily be limited to, absence of an ability to recover the carrying amount of the investment or inability of the investee to sustain an earnings capacity that would justify the carrying amount of the investment. A current fair value of an investment that is less than its carrying amount may indicate a loss in value of the investment. All of the above factors are considered in the Company’s review of its equity method investments. See Note 5 - Unconsolidated Investments.
Regulatory Assets and Liabilities. The Company is subject to regulation by certain state and federal authorities. In its Distribution segment, the Company has accounting policies that are in accordance with the accounting requirements and ratemaking practices of the applicable regulatory authorities. The application of these accounting policies allows the Company to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and revenues will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the Consolidated Statement of Operations by an unregulated company. These deferred assets and liabilities then flow through the results of operations in the period in which the same amounts are included in rates and recovered from or refunded to customers. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities requires judgment and interpretation of laws and regulatory commission orders. If, for any reason, the Company ceases to meet the criteria for application of regulatory accounting treatment for all or part of its operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the Consolidated Balance Sheet and included in the Consolidated Statement of Operations for the period in which the discontinuance of regulatory accounting treatment occurs. See Note 3 - Regulatory Assets.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Fair Value Measurement. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about nonperformance risk, which is primarily comprised of credit risk (both the Company’s own credit risk and counterparty credit risk) and the risks inherent in the inputs to any applicable valuation techniques. The Company places more weight on current market information concerning credit risk (e.g. current credit default swap rates) as opposed to historical information (e.g. historical default probabilities and credit ratings). These inputs can be readily observable, market corroborated, or generally unobservable. The Company endeavors to utilize the best available information, including valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. A three-tier fair value hierarchy, which prioritizes the inputs used to measure fair value is as follows:
·
Level 1 - Observable inputs such as quoted prices in active markets for identical assets or liabilities;
·
Level 2 - Observable inputs such as: (i) quoted prices for similar assets or liabilities in active markets; (ii) quoted prices for identical or similar assets or liabilities in markets that are not active and do not require significant adjustment based on unobservable inputs; or (iii) valuations based on pricing models, discounted cash flow methodologies or similar techniques where significant inputs (e.g., interest rates, yield curves, etc.) are derived principally from observable market data, or can be corroborated by observable market data, for substantially the full term of the assets or liabilities; and
·
Level 3 - Unobservable inputs, including valuations based on pricing models, discounted cash flow methodologies or similar techniques where at least one significant model assumption or input is unobservable. Unobservable inputs are used to the extent that observable inputs are not available and reflect the Company’s own assumptions about the assumptions market participants would use in pricing the assets or liabilities. Unobservable inputs are based on the best information available in the circumstances, which might include the Company’s own data.
Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of these assets and liabilities and their placement within the fair value hierarchy.
The Company’s Level 1 instruments primarily consist of trading securities related to a non-qualified deferred compensation plan that are valued based on active market quotes. The Company’s Level 2 instruments include commodity derivative instruments, such as natural gas and NGL processing spread swap derivatives, fixed-price forward sales contracts and certain natural gas basis swaps, and interest-rate swap derivatives that are valued based on pricing models where significant inputs are observable. The Company does not have any Level 3 instruments at December 31, 2009.
See Note 11 - Fair Value Measurement and Note 8 - Benefits - Pension and Other Postretirement Plans - Plan Assets for additional information regarding the assets and liabilities of the Company measured on a recurring and nonrecurring basis, respectively.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Natural Gas Imbalances. In the Transportation and Storage and Gathering and Processing segments, natural gas imbalances occur as a result of differences in volumes of natural gas received and delivered. In the Transportation and Storage segment, the Company records natural gas imbalance in-kind receivables and payables at cost or market, based on whether net imbalances have reduced or increased system natural gas balances, respectively. Net imbalances that have reduced system natural gas are valued at the cost basis of the system natural gas, while net imbalances that have increased system natural gas and are owed back to customers are priced, along with the corresponding system natural gas, at market.
In the Gathering and Processing segment, the Company records natural gas imbalances as receivables and payables in which imbalances due from a pipeline are recorded at the lower of cost or market and imbalances due to a pipeline are recorded at market. Market prices are based upon Gas Daily indexes.
Fuel Tracker. The fuel tracker applicable to the Company’s Transportation and Storage segment is the cumulative balance of compressor fuel volumes owed to the Company by its customers or owed by the Company to its customers. The customers, pursuant to each pipeline’s tariff and related contracts, provide all compressor fuel to the pipeline based on specified percentages of the customer’s natural gas volumes delivered into the pipeline. The percentages are designed to match the actual natural gas consumed in moving the natural gas through the pipeline facilities, with any difference between the volumes provided versus volumes consumed reflected in the fuel tracker. The tariff of Trunkline Gas contains explicit language which, in conjunction with the customers’ contractual obligations, allows the Company to record an asset and direct bill customers for any fuel ultimately under-recovered. Effective November 2008, Trunkline LNG entered into a settlement with its customer which provides for monthly reimbursement of actual fuel usage costs, resulting in Trunkline LNG no longer having a fuel tracker. The other FERC-regulated Panhandle entities record an expense when fuel is under-recovered or record a credit to expense to the extent any under-recovered prior period balances are subsequently recouped as they do not have such explicit billing rights specified in their tariffs. Liability accounts are maintained for net volumes of compressor fuel natural gas owed to customers collectively. The pipelines’ fuel reimbursement is in-kind and non-discountable.
Interest Cost Capitalized. The Company capitalizes interest on certain qualifying assets that are undergoing activities to prepare them for their intended use. Interest costs incurred during the construction period are capitalized and amortized over the life of the assets. Capitalized interest for the years ended December 31, 2009, 2008 and 2007 was $25.7 million, $19 million and $14.7 million, respectively.
Derivative Instruments and Hedging Activities. All derivatives are recognized on the Consolidated Balance Sheet at their fair value. On the date the derivative contract is entered into, the Company designates the derivative as (i) a hedge of the fair value of a recognized asset or liability or of an unrecognized firm commitment (a fair value hedge); (ii) a hedge of a forecasted transaction or the variability of cash flows to be received or paid in conjunction with a recognized asset or liability (a cash flow hedge); or (iii) an instrument that is held for trading or non-hedging purposes (a trading or economic hedging instrument). For derivatives treated as a fair value hedge, the effective portion of changes in fair value is recorded as an adjustment to the hedged item. The ineffective portion of a fair value hedge is recognized in earnings if the short cut method of assessing effectiveness is not used. Upon termination of a fair value hedge of a debt instrument, the resulting gain or loss is amortized to earnings through the maturity date of the debt instrument. For derivatives treated as a cash flow hedge, the effective portion of changes in fair value is recorded in Accumulated other comprehensive loss until the related hedged items impact earnings. Any ineffective portion of a cash flow hedge is reported in current-period earnings. For derivatives treated as trading or economic hedging instruments, changes in fair value are reported in current-period earnings. Fair value is determined based upon quoted market prices and pricing models using assumptions that market participants would use. See Note 10 - Derivative Instruments and Hedging Activities and Note 11 - Fair Value Measurement for additional related information.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Asset Retirement Obligations. Legal obligations associated with the retirement of long-lived assets are required to be recognized at their fair value at the time the obligations are incurred. Upon initial recognition of a liability, costs are capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related long-lived asset. In certain rate jurisdictions, the Company is permitted to include annual charges for cost of removal in its regulated cost of service rates charged to customers.
For more information, see Note 21 - Asset Retirement Obligations.
Income Taxes. Income taxes are accounted for under the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in earnings in the period that includes the enactment date. Valuation allowances are established when necessary to reduce deferred tax assets to the amounts more likely than not to be realized.
The determination of the Company’s provision for income taxes requires significant judgment, use of estimates, and the interpretation and application of complex tax laws. Significant judgment is required in assessing the timing and amounts of deductible and taxable items. Reserves are established when, despite management’s belief that the Company’s tax return positions are fully supportable, management believes that certain positions may be successfully challenged. When facts and circumstances change, these reserves are adjusted through the provision for income taxes.
Pensions and Other Postretirement Benefit Plans. Employers are required to recognize in their balance sheets the overfunded or underfunded status of defined benefit pension and postretirement plans, measured as the difference between the fair value of the plan assets and the benefit obligation (the projected benefit obligation for pension plans and the accumulated postretirement benefit obligation for other postretirement plans). Each overfunded plan is recognized as an asset and each underfunded plan is recognized as a liability. Employers must recognize the change in the funded status of the plan in the year in which the change occurs through Accumulated other comprehensive loss in stockholders’ equity. Effective December 31, 2008, the Company adopted the measurement date provisions of applicable benefit plan authoritative accounting guidance, which requires plan assets and benefit obligations to be measured as of its fiscal year-end balance sheet date.
See Note 8 - Benefits for additional related information.
Commitments and Contingencies. The Company is subject to proceedings, lawsuits and other claims related to environmental and other matters. Accounting for contingencies requires significant judgments by management regarding the estimated probabilities and ranges of exposure to potential liability. For further discussion of the Company’s commitments and contingencies, see Note 14 - Commitments and Contingencies.
New Accounting Principles
Accounting Principles Recently Adopted
In March 2008, the FASB issued authoritative guidance relating to disclosures about derivative instruments and hedging activities, which requires additional disclosures to provide users of financial statements with an enhanced understanding of how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for and how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. The guidance is effective for fiscal years and interim periods beginning after November 15, 2008. See Note 10 - Derivative Instruments and Hedging Activities, which reflects the disclosure required by this guidance.
In June 2009 and February 2010, the FASB issued authoritative guidance that establishes general standards of accounting for and disclosure of events that occur after the balance sheet date, but before financial statements are issued or are available to be issued. This guidance establishes (1) the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements; (2) the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements; and (3) the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. This guidance is effective for interim or annual financial periods ending after June 15, 2009.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In April 2009, the FASB issued authoritative guidance for estimating fair value when the volume and level of activity for the asset or liability have significantly decreased and also includes guidance on identifying circumstances that indicate a transaction is not orderly. The provisions of the guidance are applied prospectively and are effective for interim and annual reporting periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. The Company early adopted the guidance in the first quarter of 2009, the impact of which was not material to the Company’s consolidated financial statements.
In April 2009, the FASB issued authoritative guidance that requires disclosures about fair value of financial instruments for interim reporting periods of publicly traded companies as well as in annual financial statements. The provisions of the guidance are effective for interim reporting periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. The Company early adopted the guidance in the first quarter of 2009, resulting in the disclosure of certain fair value information associated with the Company’s debt obligations. See Note 7 - Debt Obligations for the related information.
In December 2008, the FASB issued authoritative guidance relating to an employer’s disclosure about plan assets of a defined benefit pension or other postretirement plan. The provisions of the guidance are effective for fiscal years ending after December 15, 2009. See Note 8 - Benefits - Pension and Other Postretirement Plans - Plan Assets, which reflects the disclosure required by this guidance applicable to the Company’s pension and other postretirement plan assets.
In August 2009, the FASB issued authoritative guidance regarding the fair value measurement of liabilities that clarifies the valuation techniques required in circumstances in which a quoted price in an active market for the identical liability is not available. The guidance is effective in the first interim or annual reporting period following issuance. This guidance did not materially impact the Company’s consolidated financial statements.
In September 2009, the FASB issued authoritative guidance regarding the fair value measurement of investments in certain entities that calculate net asset value per share (or its equivalent) and requires disclosure by major category of investment about the attributes of applicable investments. The guidance is effective for interim and annual reporting periods ending after December 15, 2009, with early adoption permitted. See Note 8 - Benefits - Pension and Other Postretirement Plans - Plan Assets, which reflects the disclosure required by this guidance applicable to certain of the Company’s pension plan assets.
Accounting Principles Not Yet Adopted
In June 2009, the FASB issued authoritative guidance that changes how a company determines when an entity that is insufficiently capitalized or is not controlled through voting (or similar rights) should be consolidated. The determination is based on, among other things, an entity’s purpose and design and a company’s ability to direct the activities of the entity that most significantly affect the entity’s economic performance. The guidance is effective as of the beginning of the first annual reporting period, and for interim periods within that first period, after November 15, 2009, with early adoption prohibited. This guidance is not expected to materially impact the Company’s consolidated financial statements.
In January 2010, the FASB issued authoritative guidance to improve disclosure requirements related to fair value measurements. This guidance requires new disclosures associated with the three tier fair value hierarchy for transfers in and out of Levels 1 and 2 and for activity within Level 3. It also clarifies existing disclosure requirements related to the level of disaggregation and disclosures about certain inputs and valuation techniques. This guidance is effective for interim or annual financial periods beginning after December 15, 2009, except for the disclosures related to activity within Level 3, which is effective for interim or annual financial periods beginning after December 15, 2010. The Company is currently evaluating the impact of this guidance on its consolidated financial statements.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
3. Regulatory Assets
The Company records regulatory assets with respect to its Distribution segment operations. Although Panhandle’s natural gas transmission systems and storage operations are subject to the jurisdiction of the FERC in accordance with the Natural Gas Act of 1938 and Natural Gas Policy Act of 1978, it does not currently apply regulatory accounting policies in accounting for its operations. In 1999, prior to its acquisition by Southern Union, Panhandle discontinued the application of regulatory accounting policies primarily due to the level of discounting from tariff rates and its inability to recover specific costs.
The following table provides a summary of regulatory assets at the dates indicated:
The Company’s regulatory assets at December 31, 2009 relating to Distribution segment operations that are being recovered through current rates totaled $43.7 million. The remaining recovery period associated with these assets ranged from 3 months to 84 months. The Company expects that the $28.6 million of regulatory assets at December 31, 2009 not currently in rates will be included in its rates as rate cases occur in the future. The Company’s regulatory assets at December 31, 2008 relating to Distribution segment operations that are being recovered through current rates totaled $43.5 million. The remaining recovery period associated with these assets ranged from 15 months to 93 months.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
4. Earnings Per Share
The following table summarizes the Company’s basic and diluted earnings EPS calculations for the periods presented:
A reconciliation of the shares used in the basic and diluted EPS calculations is shown in the following table for the periods presented:
For the years ended December 31, 2009, 2008 and 2007, no adjustments were required in Net earnings available for common stockholders in the diluted EPS calculations.
Except for the Company’s purchase of common stock used to pay employee federal and state income tax obligations associated with vested restricted stock awards and exercises of SARs, the Company did not purchase any shares of its common stock outstanding during the years ended December 31, 2009, 2008 and 2007, respectively.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The table below includes information related to stock options and SARs that were outstanding but have been excluded from the computation of weighted-average stock options due to the exercise price exceeding the weighted-average market price of the Company’s common shares.
See Note 15 - Stockholders’ Equity - 2008 Equity Issuances for information related to the 5% Equity Units issued on February 11, 2005, which subsequently had a dilutive effect on EPS through 2008.
5. Unconsolidated Investments
A summary of the Company’s unconsolidated equity investments at the dates indicated is as follows:
Equity Investments. Unconsolidated investments at December 31, 2009 and 2008 included the Company’s 50 percent, 50 percent, 29 percent and 49.9 percent investments in Citrus, Grey Ranch, Lee 8 Partnership and PEI Power II, respectively. The Company accounts for these investments using the equity method. The Company’s share of net earnings or loss from these equity investments is recorded in Earnings from unconsolidated investments in the Consolidated Statement of Operations.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Summarized financial information for the Company’s equity investments is as follows:
Citrus
Dividends. Citrus did not pay dividends to the Company during the year ended December 31, 2009. During the years ended December 31, 2008 and 2007, Citrus paid dividends of $77.2 million and $103.6 million, respectively, to the Company. Retained earnings at December 31, 2009 and 2008 included undistributed earnings from Citrus of $81.5 million and $6.4 million, respectively.
Citrus Excess Net Investment. The Company’s equity investment balances include amounts in excess of the Company’s share of the underlying equity of the investee of $640 million and $629 million as of December 31, 2009 and 2008, respectively. These amounts relate to the Company’s 50 percent equity ownership interest in Citrus. The excess net investment of the Company’s 50 percent share of the underlying Citrus equity as of December 31, 2009 was as follows:
____________________
(1)
Accretion of this amount increases equity earnings and accumulated net accretion.
(2)
The Company’s tax basis in the investment in Citrus includes equity goodwill.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Contingent Matters Potentially Impacting Southern Union Through the Company’s Investment in Citrus
Florida Gas Phase VIII Expansion. In November 2009, FERC approved Florida Gas’ certificate application to construct an expansion, which will increase its natural gas capacity into Florida by approximately 820 MMcf/d (Phase VIII Expansion). The Phase VIII Expansion includes construction of approximately 500 miles of large diameter pipeline and the installation of approximately 200,000 horsepower of compression. Florida Gas anticipates an in-service date in the spring of 2011, at a currently estimated cost of approximately $2.4 billion, including capitalized equity and debt costs. Approximately $737 million of capital costs have been recorded as of December 31, 2009. To date, Florida Gas has entered into firm transportation service agreements with shippers for 25-year terms accounting for approximately 74 percent of the available expansion capacity which, depending on elections by one of the shippers, may increase to 83 percent of such capacity.
Prior to the in-service date of the Phase VIII Expansion project, the Company expects to make estimated equity contributions to Citrus in a total amount of $150 million to $250 million, with its 50 percent equity partner in Citrus making matching contributions. These total estimated equity contributions of $300 million to $500 million will be utilized by Citrus to make equity investments in Florida Gas in order to maintain appropriate debt and equity ratios during the construction period for the Phase VIII Expansion project. Citrus has not determined the exact timing or size of any individual equity contributions at this point, although the funds will generally be needed by Citrus in the latter part of 2010. The Company and its equity partner in Citrus also do not plan to take any cash dividends from Citrus until after the Phase VIII Expansion project is in-service.
Citrus Construction Loan Agreement. On February 5, 2008, Citrus entered into a $500 million unsecured construction and term loan agreement (Construction Loan Agreement) with a wholly-owned subsidiary of FPL Group Capital Inc., which is a wholly-owned subsidiary of FPL Group, Inc. Citrus is investing the proceeds of this loan into Florida Gas primarily to finance a portion of the Phase VIII Expansion. On October 1, 2008, Citrus borrowed the full $500 million available under the Construction Loan Agreement. At December 31, 2008, the effective interest rate applicable to the construction loan was 8.77 percent, which was comprised of LIBOR of 3.42 percent plus a margin of 5.35 percent.
The Construction Loan Agreement was converted to a fixed interest rate of 9.393 percent on October 8, 2009. Interest will be payable in semi-annual installments over the next five years. The required semi-annual payments will begin to include principal beginning five and one-half years after conversion, and the loan has a final balloon maturity of $300 million in principal on October 8, 2029.
Citrus Swap Rate Lock Agreements. In July 2009, Citrus entered into a series of forward starting swap rate lock agreements (Swap Rate Lock Agreements) with a total notional amount of $175 million with regard to the expected conversion of the Construction Loan Agreement. The Swap Rate Lock Agreements were designed to hedge against the potential changes in future cash flows payable under the Construction Loan Agreement upon its conversion to a twenty-year fixed-rate term loan, which occurred on October 8, 2009. The Swap Rate Lock Agreements were settled by Citrus on October 8, 2009 for a loss of $9.2 million.
Florida Gas Rate Filing. Florida Gas filed a rate case with FERC on October 1, 2009, reflecting a $107 million increase in its annual cost of service as compared to its prior rate case settlement, including certain amounts already in current rates for subsequent expansions and amounts currently collected via surcharges. The new rates will go into effect on April 1, 2010, subject to refund.
Environmental Matters. Florida Gas is responsible for environmental remediation of contamination resulting from past releases of hydrocarbons and chlorinated compounds at certain sites on its natural gas transmission systems. Florida Gas is implementing a program to remediate such contamination. Activities vary with site conditions and locations, the extent and nature of the contamination, remedial requirements and complexity. The ultimate liability and total costs associated with these sites will depend upon many factors. These sites are generally managed in the normal course of business or operations. The Company believes the outcome of these matters will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SPCC Rules. In October 2007, the EPA proposed amendments to the SPCC rules with the stated intention of providing greater clarity, tailoring requirements, and streamlining requirements. In December 2008, the EPA again extended the SPCC rule compliance dates until November 10, 2010, permitting owners and operators of facilities to prepare or amend and implement SPCC plans in accordance with previously enacted modifications to the regulations. Florida Gas has reviewed the impact of the modified regulations on its operations and estimates the cost associated with the new regulatory requirements will not exceed $100,000.
Regulatory Assets and Liabilities. Florida Gas is subject to regulation by certain state and federal authorities. Florida Gas has accounting policies that conform to regulatory accounting standards and are in accordance with the accounting requirements and ratemaking practices of applicable regulatory authorities. Florida Gas management’s assessment of the probability of its recovery or pass through of regulatory assets and liabilities requires judgment and interpretation of laws and regulatory commission orders. If, for any reason, Florida Gas ceases to meet the criteria for application of regulatory accounting treatment for all or part of its operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from its consolidated balance sheet, resulting in an impact to the Company’s share of its equity earnings. Florida Gas’ regulatory asset and liability balances at December 31, 2009 were $21.9 million and $13.7 million, respectively.
Florida Gas Pipeline Relocation Costs. The FDOT/FTE has various turnpike/State Road 91 widening projects that have impacted or may, over time, impact one or more of Florida Gas’ mainline pipelines located in FDOT/FTE rights-of-way. A dispute exists with the FDOT/FTE over the rights of Florida Gas under certain easements and other agreements associated with the State Road 91 projects to, among other matters, receive reimbursement for the relocation costs incurred by Florida Gas and the nature and scope of such easements. The first phase of the State Road 91 projects included replacement of approximately 11.3 miles of existing 18- and 24-inch pipelines in Broward County, Florida due to the widening of State Road 91 by the FDOT/FTE. Construction is complete and the new facilities were placed in service in March 2008. The FDOT/FTE plans additional projects that may affect Florida Gas’ pipelines within FDOT/FTE rights-of-way. The total miles of pipe that may ultimately be affected by all of the FDOT/FTE widening projects, and any associated relocation and/or rights-of-way costs, cannot be determined at this time.
The various FDOT/FTE projects are the subject of state court litigation. In January 2007, Florida Gas filed a complaint against FDOT/FTE in the Seventeenth Judicial Circuit, Broward County, Florida, to seek relief for three specific sets of FDOT/FTE widening projects in Broward County. The case was subsequently transferred to the Broward County Complex Business Civil Division 07. The complaint seeks damages for the breach of easement and relocation agreements for the completed State Road 91 relocation project and injunctive relief as well as damages for the two other sets of projects upon which construction has yet to commence. The FDOT/FTE filed counterclaims against Florida Gas alleging, among other matters, that Florida Gas is subject to estoppel, claims for breach of contract, trespass, unjust enrichment, and fraud in the inducement regarding the removal from service of the existing 18- and 24-inch pipelines. Further, the FDOT/FTE is seeking to place a constructive trust over any revenues associated with the previously existing and newly constructed pipelines and to obtain a declaratory judgment that Florida Gas is responsible for all relocation costs and is not entitled to workspace and uniform minimum area with respect to its pipelines. The Court has allowed the FDOT/FTE to include counts of fraud and trespass in its counterclaim but has disallowed a demand for punitive damages on those counts. A supplemental motion for temporary injunction and a motion for partial summary judgment is pending against Florida Gas on the extent of the rights Florida Gas claims under the easements at issue, the breach of the easements by the FDOT/FTE for failing to provide adequate rights-of-way, the failure of the FDOT/FTE to reimburse Florida Gas for the costs of relocation, and inverse condemnation as a result of the FDOT/FTE’s claim that Florida Gas breached the easements. In December 2009, both parties filed additional motions for summary judgment on numerous matters at issue in the case. The FDOT/FTE is claiming approximately $30 million in actual damages based on the most current information provided by the FDOT/FTE. The FDOT/FTE is seeking the Court’s permission to supplement these claims with as yet undetermined amounts associated with its claim for a constructive trust over revenues from the subject pipelines for the period April 2008 through January 2009. Florida Gas is seeking reimbursement of relocation costs in the amount of approximately $90 million. The trial is set for May 2010.
A 2007 action brought by the FDOT/FTE against Florida Gas in Orange County, Florida, seeking a declaratory judgment that, under existing agreements, Florida Gas is liable for the costs of relocation associated with FDOT/FTE projects, has been stayed pending resolution of the Broward County, Florida action.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Should Florida Gas be denied reimbursement by the FDOT/FTE for relocation expenses, such costs are expected to be covered by operating cash flows and additional borrowings. Florida Gas is seeking rate recovery at FERC for all reasonable and prudent costs incurred in the first phase of relocating its pipelines due to the FDOT/FTE projects as the issue of reimbursement is being litigated. Florida Gas will continue to seek such recovery for other phases to the extent not reimbursed by the FDOT/FTE. There can be no assurance that Florida Gas will be successful in obtaining complete reimbursement for any such relocation costs from the FDOT/FTE or from its customers or that the timing of such reimbursement will fully compensate Florida Gas for its costs.
Federal Pipeline Integrity Rules. On December 15, 2003, the U.S. Department of Transportation issued a final rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule defines as HCAs. The rule requires operators to identify and risk rank HCAs along their pipelines and perform baseline integrity assessments, comprised of in-line inspection (smart pigging), hydrostatic testing or direct assessments. While identification and location of all HCAs and the majority of the required risk assessments has been completed by Florida Gas, it is not practicable to determine with certainty the total scope of required remediation activities prior to completion of the assessments and inspections. The required modifications and inspections are currently estimated to be in the range of approximately $28 million to $53 million per year through 2013.
In addition to the cost of the HCA requirements, Florida Gas is required under other regulations from time to time to undertake certain actions that may include testing or upgrading portions of its system by pipeline replacement. Florida Gas recorded $40 million of capital expenditures in 2009 to meet these requirements, and expects approximately $60 million of additional capital expenditures to be incurred during 2010. Due to the nature of the factors affecting these costs, it is anticipated that future annual costs will decline significantly from the expected 2010 levels.
Other Equity Investments
The Company’s investments in Grey Ranch, the Lee 8 partnership and PEI Power are accounted for under the equity method. Grey Ranch operates a 200 MMcf/d carbon dioxide treatment facility. The Lee 8 partnership operates a 3.0 Bcf natural gas storage facility in Michigan. PEI Power II owns a 45-megawatt, natural gas-fired electric generation plant operated through a joint venture with Cayuga Energy in Pennsylvania.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
6. Accumulated Other Comprehensive Loss
The table below provides an overview of Comprehensive income (loss) for the periods presented:
The table below provides an overview of the components in Accumulated other comprehensive loss as of the dates indicated:
See Note 8 - Benefits for information related to an amendment of Panhandle’s other postretirement benefit plans in March 2008, which resulted in a $6.6 million net of tax reduction in the net prior service credit included in Accumulated other comprehensive loss.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
7. Debt Obligations
The following table sets forth the debt obligations of Southern Union and applicable units of Panhandle under their respective notes and bonds at the dates indicated:
The fair value of the Company’s term loans and credit facilities as of December 31, 2009 and 2008, and the Short-Term Facility as of December 31, 2009, were determined using the market approach, which utilized reported recent loan transactions for parties of similar credit quality and remaining life, as there is no active secondary market for loans of that type and size.
The fair value of the Company’s other long-term debt as of December 31, 2009 and 2008 was also determined using the market approach, which utilized observable market data to corroborate the estimated credit spreads and prices for the Company’s non-bank long-term debt securities in the secondary market. Those valuations were based in part upon the reported trades of the Company’s non-bank long-term debt securities where available and the actual trades of debt securities of similar credit quality and remaining life where no secondary market trades were reported for the Company’s non-bank long-term debt securities.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Long-Term Debt
Southern Union has $3.56 billion of long-term debt, including net premiums of $2.6 million, recorded at December 31, 2009, of which $140.5 million is current. Debt of $3.1 billion is at fixed rates ranging from 5.60 percent to 9.44 percent. Southern Union also has floating rate debt totaling $510.4 million, bearing an interest rate of 0.78 to 3.98 percent as of December 31, 2009.
As of December 31, 2009, the Company has scheduled long-term debt payments, excluding credit facility payments and net premiums on debt, as follows:
Each note or bond is an obligation of Southern Union or a unit of Panhandle, as noted above. Panhandle’s debt is non-recourse to Southern Union. All debts that are listed as debt of Southern Union are direct obligations of Southern Union. None of the Company’s long-term debt is cross-collateralized and most of its long-term debt obligations contain cross-default provisions.
8.125% Senior Notes. In June 2009, PEPL issued $150 million in senior notes due June 1, 2019 with an interest rate of 8.125 percent (8.125% Senior Notes). In connection with the issuance of the 8.125% Senior Notes, PEPL incurred underwriting and discount costs totaling approximately $1 million, resulting in approximately $149 million in proceeds to PEPL. These proceeds were used to repay borrowings under the Company’s credit facilities and to repay the $60.6 million of 6.50% Senior Notes that matured on July 15, 2009.
7.00% Senior Notes. In June 2008, PEPL issued $400 million in senior notes due June 15, 2018 with an interest rate of 7.00 percent (7.00% Senior Notes). In connection with the issuance of the 7.00% Senior Notes, PEPL incurred underwriting and discount costs totaling approximately $4.1 million, resulting in approximately $395.9 million in proceeds to PEPL. These proceeds were advanced to Southern Union and used to repay borrowings under its credit facilities. Southern Union repaid PEPL a portion of the advance to retire the $300 million 4.80% Senior Notes in August 2008.
6.20% Senior Notes. On October 26, 2007, PEPL issued $300 million in senior notes due November 1, 2017 with an interest rate of 6.20 percent (6.20% Senior Notes). In connection with the issuance of the 6.20% Senior Notes, PEPL incurred underwriting and discount costs of approximately $2.7 million. The debt was priced to the public at 99.741 percent, resulting in $297.3 million in proceeds to PEPL. The proceeds were initially advanced to Southern Union and used to repay approximately $246 million outstanding under credit facilities. The remaining proceeds of $51.3 million were invested by Southern Union and subsequently utilized to fund working capital obligations of PEPL.
Term Loans. On August 5, 2009, the Company entered into a two-year $150 million term loan (2009 Term Loan) with a syndicate of banks. The interest rate associated with the 2009 Term Loan is based, at the Company’s option, upon either LIBOR or the prime lending rate, plus a credit spread based upon the Company’s credit ratings. Borrowings under the 2009 Term Loan are available for general corporate purposes. The proceeds of the 2009 Term Loan were used to repay borrowings under the credit facilities. At December 31, 2009, the balance of the 2009 Term Loan was $150 million at an effective interest rate of 3.98 percent. The balance and effective interest rate of the 2009 Term Loan at February 24, 2010 were $150 million and 3.98 percent, respectively.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
On March 15, 2007, LNG Holdings, as borrower, and PEPL and Trunkline LNG, as guarantors, entered into a $455 million unsecured term loan facility due March 13, 2012 (2012 Term Loan). The interest rate under the 2012 Term Loan is a floating rate tied to LIBOR or prime rate, at the Company’s option, in addition to a margin tied to the rating of PEPL’s senior unsecured debt. The proceeds of the 2012 Term Loan were used to repay approximately $455 million in existing indebtedness that matured in March 2007, including the $200 million 2.75% Senior Notes and the LNG Holdings $255.6 million Term Loan. LNG Holdings has entered into interest rate swap agreements that effectively fix the interest rate applicable to the 2012 Term Loan at 4.98 percent plus a credit spread of 0.625 percent, based upon PEPL’s credit rating for its senior unsecured debt. The balance of the 2012 Term Loan was $455 million at each of December 31, 2009 and 2008. See Note 10 - Derivative Instruments and Hedging Activities - Interest Rate Swaps for information regarding interest rate swaps.
On December 1, 2006, LNG Holdings, as borrower, and PEPL and CrossCountry Citrus, LLC, as guarantors, entered into the $465 million 2006 Term Loan due April 4, 2008. On June 29, 2007, the parties entered into an amended and restated term loan facility (Amended Credit Agreement). The Amended Credit Agreement extended the maturity of the term loan from April 4, 2008 to June 29, 2012, and decreased the interest rate from LIBOR plus 87.5 basis points to LIBOR plus 55 basis points, based upon the current credit rating of PEPL's senior unsecured debt. The balance of the Amended Credit Agreement was $360.4 million and $360.4 million at effective interest rates of 0.78 percent and 1.02 percent at December 31, 2009 and 2008, respectively. The balance and effective interest rate of the Amended Credit Agreement at February 24, 2010 were $360.4 million and 0.78 percent, respectively.
Remarketing Obligation. In February 2005, the Company issued $100 million aggregate principal amount of 4.375% Senior Notes due in February 2008 in conjunction with the issuance of its 5% Equity Units. Each equity unit was comprised of a senior note in the principal amount of $50 and a forward purchase contract under which the equity unit holder agreed to purchase shares of Southern Union common stock in February 2008 at a price based on the preceding 20-day average closing price subject to a minimum conversion price per share of $22.74 and a maximum conversion price per share of $28.42. On February 8, 2008, the Company remarketed the 4.375% Senior Notes, which yielded no cash proceeds for the Company. The interest rate on the Senior Notes was reset to 6.089 percent per annum from and after February 19, 2008. See Note 15 - Stockholders’ Equity - 2008 Equity Issuance for additional related information. The 6.089% Senior Notes will mature on February 16, 2010.
Short-Term Debt Obligations, Excluding Current Portion of Long-Term Debt
Credit Facilities. The Company’s $400 million Fifth Amended and Restated Revolving Credit Agreement (Revolver) is a committed credit facility that matures on May 28, 2010. Borrowings under the Revolver are available for Southern Union’s working capital and letter of credit requirements and for other general corporate purposes. The interest rate for the Revolver is based on LIBOR, plus 62.5 basis points. The Revolver is also subject to a commitment fee based on the rating of the Company’s unsecured senior notes. As of December 31, 2009, the commitment fees were an annualized 0.15 percent.
The Company has an additional $20 million short-term committed credit facility that matures on July 21, 2010.
Balances of $80 million and $251.5 million were outstanding under the Company’s credit facilities at effective interest rates of 0.85 percent and 1.16 percent at December 31, 2009 and 2008, respectively. The Company classifies its borrowings under the credit facilities as short-term debt as the individual borrowings are generally for periods of 15 to 180 days. At maturity, the Company may (i) retire the outstanding balance of each borrowing with available cash on hand and/or proceeds from a new borrowing, or (ii) at the Company’s option, extend the borrowing’s maturity date for up to an additional 90 days. As of February 24, 2010, there was a balance of $110 million outstanding under the Company’s credit facilities at an average effective interest rate of 0.85 percent.
On February 26, 2010, the Company entered into the Sixth Amended and Restated Revolving Credit Agreement with the banks named therein in the amount of $550 million (2010 Revolver). The 2010 Revolver is a refinancing of the Revolver, which was otherwise scheduled to mature on May 28, 2010. The 2010 Revolver will mature on May 28, 2013. Borrowings on the 2010 Revolver are available for the Company’s working capital, other general corporate purposes and letter of credit requirements. The interest rate and commitment fee under the 2010 Revolver are calculated using a pricing grid, which is based upon the credit rating for the Company’s senior unsecured notes. The annualized interest rate and commitment fee rate bases for the 2010 Revolver at February 26, 2010 were LIBOR, plus 275 basis points, and 50 basis points, respectively. The Company’s additional $20 million short-term committed credit facility is expected to be renewed in July 2010 for an additional 364-day period.
Short-Term Facility. On August 11, 2008, Southern Union entered into a short-term 364 day credit agreement in the amount of $150 million with an interest rate based, at the Company’s option, upon either LIBOR plus 125 basis points or the prime lending rate. Borrowings under the facility were available for general corporate purposes. This facility was repaid in July 2009 with borrowings under the Company’s credit facilities.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Restrictive Covenants. The Company is not party to any lending agreement that would accelerate the maturity date of any obligation due to a failure to maintain any specific credit rating, nor would a reduction in any credit rating, by itself, cause an event of default under any of the Company’s lending agreements. Covenants exist in certain of the Company’s debt agreements that require the Company to maintain a certain level of net worth, to meet certain debt to total capitalization ratios and to meet certain ratios of earnings before depreciation, interest and taxes to cash interest expense. A failure by the Company to satisfy any such covenant would give rise to an event of default under the associated debt, which could become immediately due and payable if the Company did not cure such default within any permitted cure period or if the Company did not obtain amendments, consents or waivers from its lenders with respect to such covenants.
The Company’s restrictive covenants include restrictions on debt levels, restrictions on liens securing debt and guarantees, restrictions on mergers and on the sales of assets, capitalization requirements, dividend restrictions, cross default and cross-acceleration and prepayment of debt provisions. A breach of any of these covenants could result in acceleration of Southern Union’s debt and other financial obligations and that of its subsidiaries. Under the current credit agreements, the significant debt covenants and cross defaults are as follows:
(a)
Under the Company’s Revolver, the consolidated debt to total capitalization ratio, as defined therein, cannot exceed 65 percent;
(b)
Under the Company’s Revolver, the Company must maintain an earnings before interest, tax, depreciation and amortization interest coverage ratio of at least 2.00 times;
(c)
Under the Company’s First Mortgage Bond indentures for the Fall River Gas division of New England Gas Company, the Company’s consolidated debt to total capitalization ratio, as defined therein, cannot exceed 70 percent at the end of any calendar quarter; and
(d)
All of the Company’s major borrowing agreements contain cross-defaults if the Company defaults on an agreement involving at least $2 million of principal.
In addition to the above restrictions and default provisions, the Company and/or its subsidiaries are subject to a number of additional restrictions and covenants. These restrictions and covenants include limitations on additional debt at some of its subsidiaries; limitations on the use of proceeds from borrowing at some of its subsidiaries; limitations, in some cases, on transactions with its affiliates; limitations on the incurrence of liens; potential limitations on the abilities of some of its subsidiaries to declare and pay dividends and potential limitations on some of its subsidiaries to participate in the Company’s cash management program; and limitations on the Company’s ability to prepay debt.
Retirement of Debt Obligations
The Company repaid the $100 million 6.089% Senior Notes in February 2010 primarily using draw downs under the credit facilities. The Company has $40.5 million 8.25% Senior Notes maturing in April 2010, which the Company plans to retire upon maturity by utilizing some combination of cash flows from operations or draw downs under existing credit facilities.
8. Benefits
Pension and Other Postretirement Benefit Plans
The Company has funded non-contributory defined benefit pension plans (pension plans) that cover substantially all Distribution segment employees. Normal retirement age is 65, but certain plan provisions allow for earlier retirement. Pension benefits are calculated under formulas principally based on average earnings and length of service for salaried and non-union employees and average earnings and length of service or negotiated non-wage based formulas for union employees.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Company has postretirement health care and life insurance plans (other postretirement plans) that cover substantially all Distribution and Transportation and Storage segment employees and, effective January 1, 2008, all Corporate employees. The health care plans generally provide for cost sharing between the Company and its retirees in the form of retiree contributions, deductibles, coinsurance and a fixed cost cap on the amount the Company pays annually to provide future retiree health care coverage under certain of these plans.
Obligations and Funded Status
Pension and other postretirement benefit liabilities are accrued on an actuarial basis during the years an employee provides services. The following tables contain information at the dates indicated about the obligations and funded status of the Company’s pension and other postretirement plans on a combined basis.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table summarizes information at the dates indicated for plans with an accumulated benefit obligation in excess of plan assets.
Net Periodic Benefit Cost
Net periodic benefit cost for the periods presented includes the components noted in the table below.
___________________
(1)
In the Distribution segment, the Company recovers certain qualified pension benefit plan and other postretirement benefit plan costs through rates charged to utility customers. Certain utility commissions require that the recovery of these costs be based on the Employee Retirement Income Security Act of 1974, as amended, or other utility commission specific guidelines. The difference between these regulatory-based amounts and the periodic benefit cost calculated pursuant to GAAP is deferred as a regulatory asset or liability and amortized to expense over periods in which this difference will be recovered in rates, as promulgated by the applicable utility commission.
The estimated net actuarial loss (gain) and prior service cost (credit) for pension plans that will be amortized from Accumulated other comprehensive loss into net periodic benefit cost during 2010 are $8 million and $552,000, respectively. The estimated net actuarial loss (gain) and prior service cost (credit) for other postretirement plans that will be amortized from Accumulated other comprehensive loss into net periodic benefit cost during 2010 are $(1.8) million and $(1.6) million, respectively.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Assumptions
The weighted-average assumptions used in determining benefit obligations for the periods presented are shown in the table below.
The weighted-average assumptions used in determining net periodic benefit cost for the periods presented are shown in the table below.
The Company employs a building block approach in determining the expected long-term rate of return on the plans’ assets, with proper consideration of diversification and rebalancing. Historical markets are studied and long-term historical relationships between equities and fixed-income are preserved consistent with the widely accepted capital market principle that assets with higher volatility generate a greater return over the long run. Current market factors such as inflation and interest rates are evaluated before long-term market assumptions are determined. Peer data and historical returns are reviewed to ensure reasonableness and appropriateness.
The assumed health care cost trend rates used for measurement purposes with respect to the Company’s other postretirement benefit plans are shown in the table below.
Assumed health care cost trend rates have a significant effect on the amounts reported for health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:
SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Plan Assets
The Company’s overall investment strategy is to maintain an appropriate balance of actively managed investments with the objective of optimizing longer-term returns while maintaining a high standard of portfolio quality and achieving proper diversification. To achieve diversity within its pension plan asset portfolio, the Company has targeted the following asset allocations: equity of 60 percent to 70 percent, fixed income of 30 percent to 40 percent and real estate and cash of 0 percent to 10 percent. To achieve diversity within its other postretirement plan asset portfolio, the Company has targeted the following asset allocations: equity of 25 percent to 35 percent, fixed income of 65 percent to 75 percent and cash and cash equivalents of 0 percent to 10 percent. These target allocations are monitored by the Investment Committee of the Board in conjunction with an external investment advisor. On occasion, the asset allocations may fluctuate as compared to these guidelines as a result of Investment Committee actions.
The fair value of the Company’s pension plan assets at December 31, 2009 by asset category is as follows:
The fair value of the Company’s other postretirement plan assets at December 31, 2009 by asset category is as follows:
___________________
(1)
This fund of funds invests primarily in a diversified portfolio of equity and fixed income securities and real estate assets and real estate securities. As of December 31, 2009, the fund was primarily comprised of approximately 30 percent large-cap U.S. equities, 9 percent multi-cap U.S. equities, 5 percent small-cap U.S. equities, 20 percent international equities, 30 percent fixed income securities, 3 percent cash, and 3 percent in other investments. These investments are generally redeemable on a daily basis at the net asset value per share of the investment.
(2)
Primarily includes hedge funds that invest in multiple strategies, including relative value, opportunistic/macro, long/short equities, merger arbitrage/event driven, credit, and short selling strategies, to generate long-term capital appreciation through a portfolio having a diversified risk profile with relatively low volatility and a low correlation with traditional equity and fixed-income markets. These investments can generally be redeemed effective as of the last day of a calendar quarter at the net asset value per share of the investment with approximately 65 days prior written notice.
(3)
This fund of funds primarily invests in a combination of equity, fixed income and short-term mutual funds. As of December 31, 2009, the fund was primarily comprised of approximately 16 percent large-cap U.S. equities, 3 percent small-cap U.S. equities,10 percent international equities, 57 percent fixed income securities, 10 percent cash, and 4 percent in other investments.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Level 1 plan assets are valued based on active market quotes. The Level 2 plan assets are valued based on the net asset value per share (or its equivalent) of the investments, which was not determinable through publicly published sources but was determined by the Company to be calculated consistent with authoritative accounting guidelines. See Note 2 - Summary of Significant Accounting Policies and Other Matters - Fair Value Measurements for information related to the framework used by the Company to measure the fair value of its pension and other postretirement plan assets.
Contributions
The Company expects to contribute approximately $6.5 million to its pension plans and approximately $15.4 million to its other postretirement plans in 2010. The Company funds the cost of the plans in accordance with federal regulations, not to exceed the amounts deductible for income tax purposes.
Benefit Payments
The Company’s estimate of expected benefit payments, which reflect expected future service, as appropriate, in each of the next five years and in the aggregate for the five years thereafter are shown in the table below.
The Medicare Prescription Drug Act provides for a prescription drug benefit under Medicare (Medicare Part D) as well as a federal subsidy, which is not taxable, to sponsors of retiree health care benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare Part D.
Defined Contribution Plan
The Company sponsors a defined contribution savings plan (Savings Plan) that is available to all employees. The Company provided maximum matching contributions based upon certain Savings Plan provisions during 2007 through 2009 ranging from 2 percent to 6.25 percent of the participant’s compensation paid into the Savings Plan. Company con­tributions are 100 percent vested after five years of continuous service for all plans other than Missouri Gas Energy union employees and employees of the Fall River operation, which are 100 percent vested after six years of continuous service. Company contribu­tions to the Savings Plan during the years ended December 31, 2009, 2008 and 2007 were $7 million, $5.2 million and $3.8 million, respectively.
In addition, the Company makes employer contributions to separate accounts, re­ferred to as Retirement Power Accounts, within the defined contribution plan. The contribution amounts are determined as a percentage of compensation and range from 3.5 percent to 12 percent. Company contributions to Retirement Power Accounts during the years ended December 31, 2009, 2008 and 2007 were $7.9 million, $7.4 million and $6.6 million, respectively.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
9. Taxes on Income
The following table provides a summary of the current and deferred components of income tax expense for the periods presented:
Deferred income taxes result from temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. The principal components of the Company’s deferred tax assets (liabilities) at the dates indicated are as follows:
SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The differences between the Company’s EITR and the U.S. federal income tax statutory rate for the periods presented are as follows:
Income tax expense in 2008 includes a benefit of $20.7 million resulting from a reduction in the Company’s deferred income tax liability in 2008 associated with the dividends received deduction for anticipated dividends from the Company’s unconsolidated investment in Citrus. Due to the anticipated increase in dividends from Citrus after the completion of the Phase VIII Expansion, the Company expects the entire deferred income tax liability related to its investment in Citrus would be realized at the Company’s statutory income tax rate less the dividends received deduction.
A reconciliation of the changes in unrecognized tax benefits for the periods presented is as follows:
As of December 31, 2009, the Company has unrecognized tax benefits for capitalization policies and state filing positions of $2.3 million and $10.6 million, respectively. However, only $10.6 million ($6.9 million, net of federal tax) of the unrecognized tax benefits for certain state filing positions would impact the Company’s EITR if recognized. The Company believes it is reasonably possible that its unrecognized tax benefits may be reduced by $1 million ($650,000, net of federal tax) within the next twelve months due to settlement of certain state filing positions.
The Company’s policy is to classify and accrue interest expense and penalties on income tax underpayments (overpayments) as a component of income tax expense in its Consolidated Statement of Operations, which is consistent with the recognition of these items in prior reporting periods.
During 2009, the Company recognized interest and penalties of $457,000 ($306,000, net of federal tax). At December 31, 2009, the Company has interest and penalties accrued of $802,000 ($521,000, net of federal tax).
The Company is no longer subject to U.S. federal, state or local examinations for the tax period ended December 31, 2004 and prior years, except June 30, 2004, to the extent of $1.3 million of refund claims.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
10. Derivative Instruments and Hedging Activities
The Company is exposed to certain risks in its ongoing business operations. The primary risks managed by using derivative instruments are interest rate risk and commodity price risk. Interest rate swaps and treasury rate locks are the principal derivative instruments used by the Company to manage interest rate risk associated with its long-term borrowings, although other interest rate derivative contracts may also be used from time to time. Natural gas price swaps and NGL processing spread swaps are the principal derivative instruments used by the Company to manage commodity price risk associated with purchases and/or sales of natural gas and/or NGL, although other commodity derivative contracts may also be used from time to time. The Company recognizes all derivative instruments as assets or liabilities at fair value in the Consolidated Balance Sheet.
Interest Rate Contracts
The Company enters into interest rate swaps to manage its exposure to changes in interest payments on long-term debt attributable to movements in market interest rates, and enters into treasury rate locks to manage its exposure to changes in future interest payments attributable to changes in treasury rates prior to the issuance of new long-term debt instruments.
Interest Rate Swaps. As of December 31, 2009, the Company had outstanding pay-fixed interest rate swaps with a total notional amount of $455 million applicable to the 2012 Term Loan. These interest rate swaps are accounted for as cash flow hedges, with the effective portion of changes in their fair value recorded in Accumulated other comprehensive loss and reclassified into Interest expense in the same periods during which the related interest payments on long-term debt impact earnings. As of December 31, 2009, approximately $12.2 million of net after-tax losses in Accumulated other comprehensive loss related to these interest rate swaps is expected to be amortized into Interest expense during the next twelve months. Any ineffective portion of the cash flow hedge is reported in current-period earnings.
Treasury Rate Locks. As of December 31, 2009, the Company had no outstanding treasury rate locks. However, certain of its treasury rate locks that settled in prior periods are associated with interest payments on outstanding long-term debt. These treasury rate locks are accounted for as cash flow hedges, with the effective portion of their settled value recorded in Accumulated other comprehensive loss and reclassified into Interest expense in the same periods during which the related interest payments on long-term debt impact earnings. As of December 31, 2009 approximately $661,000 of net after-tax losses in Accumulated other comprehensive loss related to these treasury rate locks will be amortized into Interest expense during the next twelve months.
Commodity Contracts - Gathering and Processing Segment
The Company enters into natural gas price swaps and NGL processing spread swaps to manage its exposure to changes in margin on forecasted sales of equity (Company-owned) natural gas and NGL volumes resulting from movements in market commodity prices.
Natural Gas Price Swaps. As of December 31, 2009, the Company had outstanding receive-fixed natural gas price swaps with a total notional amount of 16,425,000 MMBtus and 7,300,000 MMBtus for 2010 and 2011, respectively. These natural gas price swaps are accounted for as cash flow hedges, with the effective portion of changes in their fair value recorded in Accumulated other comprehensive loss and reclassified into Operating revenues in the same periods during which the forecasted natural gas sales impact earnings. As of December 31, 2009, approximately $2.8 million of net after-tax loss in Accumulated other comprehensive loss related to these natural gas price swaps is expected to be amortized into Operating revenues during the next twelve months. Any ineffective portion of the cash flow hedge is reported in current-period earnings.
NGL Processing Spread Swaps. As of December 31, 2009, the Company had outstanding receive-fixed NGL processing spread swaps with a total notional amount of 14,600,000 MMBtu and 7,300,000 MMBtu equivalents for 2010 and 2011, respectively. These processing spread swaps are accounted for as economic hedges, with changes in their fair value recorded in Operating revenues.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Commodity Contracts - Distribution Segment
The Company enters into natural gas commodity price swaps to manage the exposure to changes in the cost of forecasted purchases of natural gas passed through to utility customers that result from movements in market commodity prices. The cost of the derivative instruments and settlement of the respective obligations are recovered from utility customers through the purchased natural gas adjustment clause as authorized by the applicable regulatory authority and therefore do not impact earnings.
Natural Gas Price Swaps. As of December 31, 2009, the Company had outstanding pay-fixed natural gas price swaps with total notional amounts of 23,430,000 MMBtus and 12,550,000 MMBtus for 2010 and 2011, respectively. These natural gas price swaps are accounted for as economic hedges, with changes in their fair value recorded to Deferred natural gas purchases.
Summary Financial Statement Information
The following table summarizes the fair value amounts of the Company’s asset derivative instruments and their location reported in the Consolidated Balance Sheet at the dates indicated:
_____________
(1)
See Note 11 - Fair Value Measurement for information related to the framework used by the Company to measure the fair value of its derivative instruments as of December 31, 2009.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table summarizes the fair value amounts of the Company’s liability derivative instruments and their location reported in the Consolidated Balance Sheet at the dates indicated:
_____________
(1)
See Note 11 - Fair Value Measurement for information related to the framework used by the Company to measure the fair value of its derivative instruments as of December 31, 2009.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table summarizes the location and amount of derivative instrument gains and losses reported in the Company’s condensed consolidated financial statements for the periods presented:
_________________
(1)
See Note 6 - Accumulated Other Comprehensive Income (Loss) for additional related information.
Derivative Instrument Contingent Features
Certain of the Company’s derivative instruments contain provisions that require the Company’s debt to be maintained at an investment grade credit rating from each of the major credit rating agencies. If the Company’s debt were to fall below investment grade, the Company would be in violation of these provisions, and the counterparties to the derivative instruments could request immediate payment. The aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a net liability position at December 31, 2009 is $12.7 million.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
11. Fair Value Measurement
The following tables set forth the Company’s assets and liabilities that are measured at fair value on a recurring basis at the dates indicated:
___________________
(1)
The Company’s commodity derivative asset balance is primarily associated with two separate counterparties, one of which comprised $68.9 million of the asset balance and the other of which comprised $20.1 million of the asset balance as of December 31, 2008.
The Company’s Level 1 instruments primarily consist of trading securities related to a non-qualified deferred compensation plan that are valued based on active market quotes. The Company’s Level 2 instruments primarily include natural gas and NGL processing spread swap derivatives and interest-rate swap derivatives that are valued based on pricing models where significant inputs are observable. The Company reclassified certain of its processing spread swap derivatives and interest-rate swap derivatives from Level 3 to Level 2 during 2008 and 2009 as it obtained additional observable market data to corroborate all significant inputs to the models used to measure the fair value of these liabilities.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table provides a reconciliation of the change in the Company’s Level 3 assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs for the periods presented.
___________________
(1)
The amount included in operating revenues for the year ended December 31, 2008 that is attributable to the change in unrealized gains or losses relating to commodity derivative assets and commodity derivative liabilities held at December 31, 2008 were gains of $52.1 million and $100,000, respectively.
(2)
The amount included in operating revenues for the year ended December 31, 2009 that is attributable to the change in unrealized gains or losses relating to commodity derivative assets and commodity derivative liabilities held at December 31, 2009 were gains of $725,000 and $221,000, respectively.
The approximate fair value of the Company’s cash and cash equivalents, accounts receivable and accounts payable is equal to book value, due to their short-term nature.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
12. Property, Plant and Equipment
The following table provides a summary of property, plant and equipment at the dates indicated:
_________________
(1)
The composite weighted-average depreciation rates for the years ended December 31, 2009, 2008 and 2007 were 3.5 percent, 3.5 percent and 3.4 percent, respectively.
(2)
Includes capitalized computerized software cost totaling:
Amortization expense of capitalized computer software costs for the years ended December 31, 2009, 2008 and 2007 was $13.1 million, $12.1 million and $10.6 million, respectively. Computer software costs are amortized between four and fifteen years.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
13. Stock-Based Compensation
The fair value of each stock option and SAR award is estimated on the date of grant using a Black-Scholes option pricing model. The Company’s expected volatilities are based on historical volatility of the Company’s common stock. To the extent that volatility of the Company’s common stock price increases in the future, the estimates of the fair value of stock options and SARs granted in the future could increase, thereby increasing share-based compensation expense in future periods. Additionally, the expected dividend yield is considered for each grant on the date of grant. The Company’s expected term of stock options and SARs granted was derived from the average midpoint between vesting and the contractual term. In the future, as information regarding post-vesting termination becomes more accessible, the Company may change the method of deriving the expected term. This change could impact the fair value of stock options and SARs granted in the future. The risk-free rate is based on the U.S. Treasury yield curve in effect at the time of grant.
The following table represents the Black-Scholes estimated ranges under the Company’s plans for stock options and SARs awards granted in the periods presented:
SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Stock Options
The following table provides information on stock options granted, exercised, forfeited, outstanding and exercisable under the Third Amended and Restated 2003 Stock and Incentive Plan (Third Amended 2003 Plan) and the 1992 Long-Term Stock Incentive Plan (1992 Plan) for the periods presented:
The following table summarizes information about stock options outstanding under the Third Amended 2003 Plan and the 1992 Plan at December 31, 2009:
SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Stock Appreciation Rights
The following table provides information on SARs granted, exercised, forfeited, outstanding and exercisable under the Third Amended 2003 Plan for the periods presented:
No SARs were exercised during the 2007 through 2008 annual periods.
The SARs that have been awarded vest in equal installments on the first three anniversaries of the grant date. Each SAR entitles the holder to shares of Southern Union’s common stock equal to the fair market value of Southern Union’s common stock in excess of the grant date price for each SAR on the applicable exercise date.
The following table summarizes information about SARs outstanding under the Third Amended 2003 Plan at December 31, 2009:
The weighted average remaining contractual life of options and SARs outstanding under the Third Amended 2003 Plan and the 1992 Plan at December 31, 2009 was 8.28 and 1.42 years, respectively. The weighted average remaining contractual life of options and SARs exercisable under the Third Amended 2003 Plan and the 1992 Plan at December 31, 2009 was 6.93 and 1.42 years, respectively. The aggregate intrinsic value of total options and SARs outstanding and exercisable at December 31, 2009 was $18.4 million and $6.3 million, respectively.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As of December 31, 2009, there was $12.8 million of total unrecognized compensation cost related to non-vested stock options and SARs compensation arrangements granted under the stock option plans. That cost is expected to be recognized over a weighted-average contractual period of 2.50 years. The total fair value of options and SARs vested as of December 31, 2009 was $12.3 million. Compensation expense recognized related to stock options and SARs totaled $5.4 million ($3.5 million, net of tax), $3.9 million ($2.7 million, net of tax) and $1.5 million ($1.2 million, net of tax) for the years ended December 31, 2009, 2008 and 2007, respectively. Cash received from the exercise of stock options was $3.8 million for the year ended December 31, 2009.
The intrinsic value of options exercised during the year ended December 31, 2009 was approximately $2.2 million. The Company realized an additional tax benefit of approximately $447,000 for the excess amount of deductions related to stock options over the historical book compensation expense multiplied by the statutory tax rate in effect, which has been reported as an increase in financing cash flows in the Consolidated Statement of Cash Flows.
Restricted Stock
The Company’s Third Amended 2003 Plan also provides for grants of restricted stock equity units, which are settled in shares of the Company's common stock, and restricted stock liability units, which are settled in cash. The Company settles restricted stock equity units with shares of its common stock and restricted stock liability units with cash. The restrictions associated with a grant of restricted stock equity units under the Third Amended 2003 Plan generally expire equally over a period of three years. Restrictions on certain grants made to non-employee directors and senior executives of the Company expire over a shorter time period, in certain cases less than one year, and may be subject to accelerated expiration over a shorter term if certain criteria are met. The restrictions associated with a grant of restricted stock liability units expire equally over a period of three years and are payable in cash at the vesting date.
The following table provides information on restricted stock equity awards granted, vested and forfeited for the periods presented:
SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table provides information on restricted stock liability awards granted, vested and forfeited for the periods presented:
As of December 31, 2009, there was $18.7 million of total unrecognized compensation cost related to non-expired, restricted stock equity units and restricted stock liability units compensation arrangements granted under the restricted stock plans. That cost is expected to be recognized over a weighted-average contractual period of 2.39 years. The total fair value of restricted stock equity and liability units that vested during the year ended December 31, 2009 was $7.4 million. Compensation expense recognized related to restricted stock equity and liability units totaled $6.8 million ($4.3 million, net of tax), $3.7 million ($2.3 million, net of tax), and $3 million ($1.9 million, net of tax) for the years ended December 31, 2009, 2008 and 2007, respectively.
The Company settled the restricted stock liability awards vesting in 2009 and 2008 with cash payments of $4.4 million and $1.1 million, respectively.
14. Commitments and Contingencies
Environmental
The Company’s operations are subject to federal, state and local laws and regulations regarding water quality, hazardous and solid waste management, air quality control and other environmental matters. These laws and regulations require the Company to conduct its operations in a specified manner and to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals. Failure to comply with environmental requirements may expose the Company to significant fines, penalties and/or interruptions in operations. The Company’s environmental policies and procedures are designed to achieve compliance with such laws and regulations. These evolving laws and regulations and claims for damages to property, employees, other persons and the environment resulting from current or past operations may result in significant expenditures and liabilities in the future. The Company engages in a process of updating and revising its procedures for the ongoing evaluation of its operations to identify potential environmental exposures and enhance compliance with regulatory requirements.
The Company is allowed to recover environmental remediation expenditures through rates in certain jurisdictions within its Distribution segment. Although significant charges to earnings could be required prior to rate recovery for jurisdictions that do not have rate recovery mechanisms, management does not believe that environmental expenditures will have a material adverse effect on the Company's consolidated financial position, results of operations or cash flows.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The table below reflects the amount of accrued liabilities recorded in the unaudited interim Condensed Consolidated Balance Sheet at the dates indicated to cover probable environmental response actions:
During the years ended December 31, 2009, 2008 and 2007, the Company had $12 million, $12 million and $9.3 million of expenditures related to environmental cleanup programs, respectively.
SPCC Rules. In October 2007, the EPA proposed amendments to the SPCC rules with the stated intention of providing greater clarity, tailoring requirements, and streamlining requirements. The most recent extension by the EPA sets the SPCC rule compliance date as November 10, 2010, permitting owners and operators of facilities to prepare or amend and implement SPCC Plans in accordance with previously enacted modifications to the regulations. The Company is currently reviewing the impact of the modified regulations on its operations in its Transportation and Storage and Gathering and Processing segments and may incur costs for tank integrity testing, alarms and other associated corrective actions as well as potential upgrades to containment structures. Costs associated with such activities cannot be estimated with certainty at this time, but the Company believes such costs will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.
Air Quality Control. In February 2009, EPA proposed a rule that requires reductions in a number of pollutants, including formaldehyde and carbon monoxide, for all engines regardless of size at Area Sources (sources that emit less than ten tons per year of any one Hazardous Air Pollutant (HAP) or twenty-five tons per year of all HAPs) and engines less than 500 horsepower at Major Sources (sources that emit ten tons per year or more of any one HAP or twenty-five tons per year of all HAPs). The rule is scheduled to be finalized in August 2010 with compliance required in 2013. It is anticipated that the limits adopted in this rule will be used in a future EPA rule that is scheduled to be finalized in 2013, with compliance required in 2016. This future rule is expected to require reductions in formaldehyde and carbon monoxide emissions from engines greater than 500 horsepower at Major Sources.
Nitrogen oxides are the primary air pollutant from natural gas-fired engines. Nitrogen oxide emissions may form ozone in the atmosphere. EPA lowered the ozone standard to seventy-five parts per billion (ppb) in 2008 with compliance anticipated in 2013 to 2015. In January 2010, EPA proposed lowering the standard to sixty to seventy ppb in lieu of the seventy-five ppb standard, with compliance required in 2014 or later.
In January 2010, EPA finalized a 100 ppb one-hour nitrogen dioxide standard. Based on the current nitrogen dioxide monitoring network, only one county in the United States fails to meet the new standard. The rule requires the installation of new nitrogen dioxide monitors in urban communities and roadways by 2013. This new network may result in additional nitrogen dioxide non-attainment areas. Facility specific impacts may occur prior to the installation of the new monitors if ambient air quality modeling is required to demonstrate compliance with the new standard.
The Company is currently reviewing the potential impact of the proposed rules regarding HAPs and ozone on operations in its Transportation and Storage and Gathering and Processing segments and the potential costs associated with the installation of emission control systems on its existing engines. Costs associated with these activities cannot be estimated with any certainty at this time, but the Company believes such costs will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Transportation and Storage Segment Environmental Matters
Natural Gas Transmission Systems. Panhandle is responsible for environmental remediation at certain sites on its natural gas transmission systems for contamination resulting from the past use of lubricants containing PCBs in compressed air systems; the past use of paints containing PCBs; and the prior use of wastewater collection facilities and other on-site disposal areas. Panhandle has developed and implemented a program to remediate such contamination. The primary remaining remediation activity on the Panhandle systems is associated with past use of paints containing PCBs or PCB impacts to equipment surfaces and to a building at one location.
The amount of estimated costs to remediate PCBs at the Company’s facilities was increased in 2009 by a total of approximately $5.1 million. The PCB assessments are ongoing and the related estimated remediation costs are subject to further change. The Company believes the total PCB remediation costs will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.
Other remediation typically involves the management of contaminated soils and may involve remediation of groundwater. Activities vary with site conditions and locations, the extent and nature of the contamination, remedial requirements, complexity and sharing of responsibility. The ultimate liability and total costs associated with these sites will depend upon many factors. If remediation activities involve statutory joint and several liability provisions, strict liability, or cost recovery or contribution actions, Panhandle could potentially be held responsible for contamination caused by other parties. In some instances, Panhandle may share liability associated with contamination with other PRPs. Panhandle may also benefit from contractual indemnities that cover some or all of the cleanup costs. These sites are generally managed in the normal course of business or operations. The Company believes the outcome of these matters will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.
Air Quality Control. The KDHE has established certain contingency measures as part of the agency’s ozone maintenance plan for the Kansas City area. These measures will be triggered if there are any new elevated ozone readings in the Kansas City area. One of the NOx emission sources that will be impacted is the PEPL Louisburg compressor station. In addition, the EPA has revised the ozone standard and the Kansas City area will likely be designated as a non-attainment area under the new and stricter standard. Issues associated with reducing emissions at the Louisburg compressor station are being discussed with the KDHE. In the event KDHE requires emission reductions, it is estimated that approximately $14 million in capital expenditures will be required.
On December 18, 2009, PEPL received an information request from the EPA under Section 114(a) of the federal Clean Air Act. The information request seeks certain documents and records pertaining to maintenance activities and capital projects associated with combustion emission sources located at eight compressor stations in Illinois and Indiana. The first set of responses was provided February 1, 2010.
Gathering and Processing Segment Environmental Matters
Gathering and Processing Systems. SUGS is responsible for environmental remediation at certain sites on its gathering and processing systems, resulting primarily from releases of hydrocarbons. SUGS has a program to remediate such contamination. The remediation typically involves the management of contaminated soils and may involve remediation of groundwater. Activities vary with site conditions and locations, the extent and nature of the contamination, remedial requirements and complexity. The ultimate liability and total costs associated with these sites will depend upon many factors. These sites are generally managed in the normal course of business or operations. The Company believes the outcome of these matters will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.
Air Quality Control. On June 16, 2006, SUGS, as the facility operator and holder of a 50 percent interest in a partnership that leases the Grey Ranch facility, submitted information to the TCEQ in connection with a request to permit the Grey Ranch facility to continue its current level of emissions. The State of Texas required all previously grandfathered emission sources to obtain permits or shut down by March 1, 2008. By letter dated September 5, 2007, the TCEQ issued a permit extending the existing emission levels to March 1, 2009.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
On December 17, 2008, the TCEQ issued a permit to SUGS for the installation of control devices and approval of a long term emission control strategy that achieves specific emission rates. SandRidge, a Roc Gas affiliate that became the operator and responsible for the permit on October 1, 2009, installed two thermal oxidizers to meet the emission control strategy outlined in the permit application. The first thermal oxidizer was completed and operational on February 28, 2009. The second thermal oxidizer was operational on July 9, 2009.
On October 7, 2009, SUGS received a notice of violation (NOV) from NMED for alleged violations at its West Eunice, New Mexico facility. On November 19, 2009, NMED submitted a proposed settlement offer of $247,000 to vacate the alleged violations. The NMED and SUGS are engaged in ongoing settlement discussions.
In addition to the West Eunice matter, SUGS has been engaged in discussions with the NMED relative to potential violations of federal and state air regulations at its Jal 3 facility. Although no enforcement action has been taken to date, SUGS anticipates NMED will issue a NOV in 2010.
Distribution Segment Environmental Matters
The Company is responsible for environmental remediation at various contaminated sites that are primarily associated with former MGPs and sites associated with the operation and disposal activities of former MGPs that produced a fuel known as “town gas”. Some byproducts of the historic manufactured gas process may be regulated substances under various federal and state environmental laws. To the extent these byproducts are present in soil or groundwater at concentrations in excess of applicable standards, investigation and remediation may be required. The sites include properties that are part of the Company’s ongoing operations, sites formerly owned or used by the Company and sites owned by third parties. Remediation typically involves the management of contaminated soils and may involve removal of old MGP structures and remediation of groundwater. Activities vary with site conditions and locations, the extent and nature of the contamination, remedial requirements, complexity and sharing of responsibility; some contamination may be unrelated to former MGPs. The ultimate liability and total costs associated with these sites will depend upon many factors. If remediation activities involve statutory joint and several liability provisions, strict liability, or cost recovery or contribution actions, the Company could potentially be held responsible for contamination caused by other parties. In some instances, the Company may share liability associated with contamination with other PRPs and may also benefit from insurance policies or contractual indemnities that cover some or all of the cleanup costs. These sites are generally managed in the normal course of business or operations. The Company believes the outcome of these matters will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.
North Attleborough MGP Site in Massachusetts (North Attleboro Site). In November 2003, the MADEP issued a Notice of Responsibility to New England Gas Company, acknowledging receipt of prior notifications and investigative reports submitted by New England Gas Company, following the discovery of suspected coal tar material at the North Attleboro Site. Subsequent sampling in the adjacent river channel revealed sediment impacts necessitating the investigation of off-site properties. The Company, working with the MADEP, is in the process of performing assessment work at these properties. In a September 2006 report filed with MADEP, the Company proposed a remedy for the upland portion of the North Attleboro Site by means of an engineered barrier. Construction of this remedy was completed in October 2008. Assessment activities continue at the remaining areas on-site and at the off-site properties. It is estimated that the Company will spend approximately $9 million over the next several years to complete the investigation and remediation activities at the North Attleboro Site, as well as maintain the engineered barrier. As New England Gas Company is allowed to recover environmental remediation expenditures through rates associated with its Massachusetts operations, the estimated costs associated with the North Attleboro Site have been included in Regulatory assets in the Condensed Consolidated Balance Sheet.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Litigation
The Company is involved in legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business, some of which involve substantial amounts. Where appropriate, the Company has made accruals in order to provide for such matters. The Company believes the final disposition of these proceedings will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.
Bay Street, Tiverton, Rhode Island Site. For several years the Company was involved in litigation with numerous plaintiffs and RIDEM alleging soils in a residential neighborhood (Bay Street) in Tiverton, Rhode Island had been impacted by historic MGP residuals. In May 2009, a settlement was reached that resolved all claims between all plaintiffs and the Company and all claims between the Town of Tiverton and the Company in the civil litigation, and also resolved all issues with RIDEM. Under the terms of the settlement, on August 25, 2009, the Company paid $11.5 million to the plaintiffs, who will be responsible for any necessary remediation in the Bay Street area. As New England Gas Company is allowed to recover environmental remediation expenditures through rates, the $11.5 million settlement amount has been included in Regulatory Assets in the Condensed Consolidated Balance Sheet.
Mercury Release. In October 2004, New England Gas Company discovered that one of its facilities had been broken into and that mercury had been released both inside a building and in the immediate vicinity, including a parking lot in a neighborhood several blocks away. Mercury from the parking lot was apparently tracked into nearby apartment units, as well as other buildings. Cleanup was completed at the property and nearby apartment units. The vandals who broke into the facility were arrested and convicted. In October 2007, the U.S. Attorney in Rhode Island filed a three-count indictment against the Company in the U.S. District Court for the District of Rhode Island alleging violation of permitting requirements under the federal RCRA and notification requirements under the federal Emergency Planning and Community Right to Know Act (EPCRA) relating to the 2004 incident. The Company entered a not guilty plea on October 29, 2007 and trial commenced on September 22, 2008. On October 15, 2008, the jury acquitted Southern Union on the EPCRA count and one of the two RCRA counts and found the Company guilty on the other RCRA count. On July 23, 2009, the Court denied the Company's motion for acquittal and alternatively for a new trial with respect to the sole count on which the Company was found guilty. On October 2, 2009, the Court imposed a fine of $6 million and a payment of $12 million in community service. The sentence has been suspended while the Company pursues an appeal of the conviction and the sentence. The Company filed its Notice of Appeal to the U.S. Court of Appeals for the First Circuit on October 7, 2009. On February 16, 2010 the Company filed its Brief of the appeal with the First Circuit. The Company believes the outcome of this matter will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.
Jack Grynberg. Jack Grynberg, an individual, filed actions for damages against a number of companies, including Panhandle, alleging mis-measurement of natural gas volumes and Btu content, resulting in lower royalties to mineral interest owners. Among the defendants are Panhandle, Citrus, Florida Gas and certain of their affiliates (Company Defendants). On October 20, 2006, the District Judge in the U.S. District Court for the District of Wyoming, to which the actions were transferred, ordered the dismissal of the case against the Company Defendants. Grynberg’s appeals were denied at all levels including at the United States Supreme Court. The parties are now seeking recovery of certain costs from Grynberg associated with the defense of the action. A similar action, known as the Will Price litigation, also has been filed against a number of companies, including Panhandle, in U.S. District Court for the District of Kansas. On September 19, 2009, the Court denied plaintiffs’ request for class certification. Plaintiffs have filed a motion for reconsideration. Panhandle and the other Company Defendants believe that their measurement practices conformed to the terms of their FERC natural gas tariffs, which were filed with and approved by FERC. As a result, the Company believes that it has meritorious defenses to the Will Price lawsuit (including FERC-related affirmative defenses, such as the filed rate/tariff doctrine, the primary/exclusive jurisdiction of FERC, and the defense that Panhandle and the other Company Defendants complied with the terms of their tariffs) and will continue to vigorously defend the case. The Company does not believe the outcome of the Will Price litigation will have a material adverse effect on its consolidated financial position, results of operations or cash flows.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Southwest Gas Litigation. Appeals have been completed in an action in the U.S. District Court for the District of Arizona in which the jury awarded the Company nearly $400,000 in actual damages, and, after reduction on appeal, approximately $1.2 million in punitive damages, along with costs of approximately $100,000 and interest. The award is the result of a trial, which was concluded in December 2002, at which the Company pursued claims against former Arizona Corporation Commissioner James Irvin, regarding his conduct during certain competing efforts to acquire Southwest Gas Corporation. The Company received approximately $1.9 million fulfilling the judgment. Following the receipt of payment, the Company filed a Satisfaction of Judgment with the U.S. District Court marking the termination of this litigation.
East End Project. The East End Project involved the installation of a total of approximately 31 miles of pipeline in and around Tuscola, Illinois, Montezuma, Indiana and Zionsville, Indiana. Construction began in 2007 and was completed in the second quarter of 2008. PEPL is seeking recovery of each contractor’s share of approximately $50 million of cost overruns from the construction contractor, an inspection contractor and the construction management contractor for improper welding, inspection and construction management of the East End Project. Certain of the contractors have filed counterclaims against PEPL for alleged underpayments of approximately $18 million. The matter is pending in state court in Harris County, Texas. Trial is set for September 2010. The Company does not believe the outcome of this case will have a material adverse effect on its consolidated financial position, results of operations or cash flows.
Energy Resources Technology. Energy Resources Technology (ERT) filed suit against Sea Robin on November 9, 2009 alleging breach of contract due to delays in repairs of damages to Sea Robin’s subsea pipeline suffered during Hurricane Ike. ERT alleges it has lost $110 million of revenue due to nonperformance under its firm transportation contract. The suit was filed in state court in Harris County, Texas and has been removed to the United States District Court for the Southern District of Texas. The Company does not believe the outcome of this case will have a material adverse effect on its consolidated financial position, results of operations or cash flows.
Other Commitments and Contingencies
Retirement of Debt Obligations. See Note 7 - Debt Obligations - Retirement of Debt Obligations for information related to the Company’s debt maturing in 2010.
2008 Hurricane Damage. In September 2008, Hurricanes Gustav and Ike came ashore on the Louisiana and Texas coasts. Damage from the hurricanes affected the Company’s Transportation and Storage segment. Offshore transportation facilities, including Sea Robin and Trunkline’s Terrebonne system, suffered damage to several platforms and gathering pipelines. In late July 2009, during testing to put the remaining offshore facilities back in service, Sea Robin experienced a pipeline rupture in an area where the pipeline had previously been displaced during Hurricane Ike and subsequently re-buried. Sea Robin experienced reduced volumes until January 2010 when the remainder of the damaged facilities was placed back in service.
The Company has recorded Hurricane Ike related expenses of approximately $12.3 million and $10.5 million, net of insurance recoveries of $2.1 million and nil, in 2009 and 2008, respectively. The capital replacement and retirement expenditures relating to Hurricane Ike have been increased during 2009 to approximately $185 million and are expected to be incurred through 2010. These estimates are subject to further revision as certain work, primarily retirements, is ongoing. Approximately $110 million and $23 million of the capital replacement and retirement expenditures were incurred as of December 31, 2009 and 2008, respectively. The Company anticipates reimbursement from OIL Insurance Limited (OIL), its member mutual property insurer, for a significant portion of the damages in excess of its $10 million deductible; however, the recoverable amount is subject to pro rata reduction to the extent that the level of total accepted claims from all insureds exceeds the carrier’s $750 million aggregate exposure limit. OIL has announced that it has reached the $750 million aggregate exposure limit and has revised its estimated payout amount to approximately 61 percent based on estimated claim information it has received. OIL is currently making interim payouts at the rate of 50 percent of accepted claims. The Company received $36.7 million in 2009 for claims submitted to date with respect to Hurricane Ike. The final amount of any applicable pro rata reduction cannot be determined until OIL has received and assessed all claims.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Purchase Commitments. At December 31, 2009, the Company had purchase commitments for natural gas transportation services, storage services and certain quantities of natural gas at a combination of fixed, variable and market-based prices that have an aggregate value of approximately $814.6 million. The Company’s purchase commitments may be extended over several years depending upon when the required quantity is purchased. The Company has purchased natural gas tariffs in effect for all its utility service areas that provide for recovery of its purchase natural gas costs under defined methodologies and the Company believes that all costs incurred under such commitments will be recovered through its purchased natural gas tariffs.
Missouri Safety Program. Pursuant to a 1989 MPSC order, Missouri Gas Energy is engaged in its service territories in the Missouri Safety Program. This program includes replacement of Company and customer-owned natural gas service and yard lines, the movement and resetting of meters, the replacement of cast iron mains and the replacement and cathodic protection of bare steel mains. In recognition of the significant capital expenditures associated with this safety program, the MPSC initially permitted the deferral and subsequent recovery through rates of depreciation expense, property taxes and associated carrying costs over a 10-year period. On August 28, 2003, the State of Missouri passed certain statutes that provided Missouri Gas Energy the ability to adjust rates periodically to recover depreciation expense, property taxes and carrying costs associated with the Missouri Safety Program, as well as investments in public improvement projects. The continuation of the Missouri Safety Program will result in significant levels of future capital expenditures. The Company incurred capital expenditures of $14.4 million in 2009 related to this program and estimates incurring approximately $115.1 million over the next 10 years, after which all service lines, representing about 30 percent of the annual safety program investment, will have been replaced.
Regulation and Rates. See Note 18 - Regulation and Rates for potential contingent matters associated with the Company’s regulated operations.
15. Stockholders’ Equity
Dividends. The table below presents the amount of cash dividends declared and paid in the respective periods:
Under the terms of the indenture governing its senior unsecured notes (Senior Notes), Southern Union may not declare or pay any cash or asset dividends on its common stock (other than dividends and distributions payable solely in shares of its common stock or in rights to acquire its common stock) or acquire or retire any shares of its common stock, unless no event of default exists and certain financial ratio requirements are satisfied. Currently, the Company is in compliance with these requirements and, therefore, the Senior Note indenture does not prohibit the Company from paying cash dividends.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Stock Award Plans. The Third Amended 2003 Plan allows for awards in the form of stock options (either incentive stock options or non-qualified options), SARs, stock bonus awards, restricted stock, performance units or other equity-based rights. The persons eligible to receive awards under the Third Amended 2003 Plan include all of the employees, directors, officers and agents of, and other service providers to, the Company and its affiliates and subsidiaries. Under the Third Amended 2003 Plan: (i) no participant may receive in any calendar year awards covering more than 500,000 shares; (ii) the exercise price for a stock option may not be less than 100 percent of the fair market value of the common stock on the date of grant; and (iii) no award may be granted after September 28, 2013.
The Company maintains its 1992 Plan, under which options to purchase 8,491,540 shares of its common stock were authorized to be granted until July 1, 2002 to officers and key employees. Options granted under the 1992 Plan are exercisable for ten years from the date of grant or such lesser period as may be designated for particular options, and become exercisable after a specified period of time from the date of grant in cumulative annual installments.
For more information on share-based awards, see Note 13 - Stock-Based Compensation.
2008 Equity Issuance. On February 19, 2008, the Company received $100 million from the issuance of 3,693,240 shares of common stock in conjunction with the remarketing of its 4.375% Senior Notes and the consummation of the forward stock purchase contracts that were issued with the 4.375% Senior Notes as part of the February 2005 5% Equity Units issuance. See Note 7 - Debt Obligations - Long-Term Debt - Remarketing Obligation for additional related information.
16. Preferred Securities
On October 8, 2003, the Company issued 9,200,000 depositary shares, each representing a 1/10th interest in a share of its 7.55% Noncumulative Preferred Stock, Series A (Liquidation Preference $250 Per Share) (Preferred Stock), at the public offering price of $25 per share, or $230 million in the aggregate.
On May 22, 2008, the Company announced that the finance committee of its Board had authorized a program to repurchase a portion of the depositary shares representing ownership of its Preferred Stock at the Company’s discretion in the open market and/or through privately negotiated transactions, subject to market conditions, applicable legal requirements and other factors. During the year ended December 31, 2008, the Company paid $115.2 million to repurchase 4,599,987 depository shares representing 459,999 shares of Preferred Stock, resulting in a $3.5 million non-cash loss adjustment charged to Retained earnings related to the write-off of issuance costs, which reduced Net earnings available for common stockholders. Effective October 8, 2008, the Company has the right to redeem all of the outstanding Preferred Stock at par upon applicable notice.
17. Reportable Segments
The Company’s reportable business segments are organized based on the way internal managerial reporting presents the results of the Company’s various businesses to its executive management for use in determining the performance of the businesses and in allocating resources to the businesses, as well as based on similarities in economic characteristics, products and services, types of customers, methods of distribution and regulatory environment. The Company operates in three reportable segments: Transportation and Storage, Gathering and Processing, and Distribution.
The Transportation and Storage segment operations are conducted through Panhandle and the Company’s investment in Citrus. The Gathering and Processing segment operations are conducted through SUGS. The Distribution segment is primarily engaged in the local distribution of natural gas in Missouri and Massachusetts, through its Missouri Gas Energy and New England Gas Company operating divisions, respectively. See Note 1 - Corporate Structure for additional information associated with the Company’s reportable segments.
The remainder of the Company’s business operations, which do not meet the quantitative threshold for segment reporting, are presented as Corporate and other activities. Corporate and other activities consist of unallocated corporate costs, a wholly-owned subsidiary with ownership interests in electric power plants, and other miscellaneous activities.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Company evaluates operational and financial segment performance based on several factors, of which the primary financial measure is EBIT, a non-GAAP measure. The Company defines EBIT as Net earnings available for common stockholders, adjusted for the following:
·
items that do not impact net earnings, such as extraordinary items, discontinued operations and the impact of changes in accounting principles;
·
income taxes;
·
interest;
·
dividends on preferred stock; and
·
loss on extinguishment of preferred stock.
EBIT may not be comparable to measures used by other companies and should be considered in conjunction with net earnings and other performance measures such as operating income or net cash flows provided by operating activities.
Sales of products or services between segments are billed at regulated rates or at market rates, as applicable. There were no material intersegment revenues during the years ended December 31, 2009, 2008 and 2007.
The following tables set forth certain selected financial information for the Company’s segments for the periods presented or at the dates indicated:
SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
_______________________
(1)
Includes net period changes in capital accruals totaling $(22) million, $(21.9) million and $71.8 million million for the years ended December 31, 2009, 2008 and 2007, respectively.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Significant Customers and Credit Risk. The following tables provide summary information of significant customers for Panhandle and SUGS by applicable segment and on a consolidated basis for the periods presented. The Distribution segment has no single customer, or group of customers under common control, that accounted for ten percent or more of the Company’s Distribution segment or consolidated operating revenues for the periods presented.
_____________
(1)
For the five-year period ended December 31, 2014, SUGS has contracted to sell its entire owned or controlled output of NGL to Conoco Phillips Company (Conoco). Pricing for the NGL equity volumes sold to Conoco throughout the contract period will be OPIS pricing based at Mont Belvieu, Texas delivery points. SUGS has an option to extend the sales agreement for an additional five year period.
18. Regulation and Rates
Panhandle. The Company commenced construction of an enhancement at its Trunkline LNG terminal in February 2007. This IEP will increase send out flexibility at the terminal and lower fuel costs. On August 6, 2009, FERC issued a conditional order granting Trunkline LNG authorization to commence partial service of IEP. Although the key components of the enhancement, a portion of the ambient air vaporizer system and the NGL recovery units, were successfully tested in the fourth quarter of 2009, mechanical issues were identified during the commissioning process that required attention. Trunkline LNG has made warranty claims regarding certain of those conditions and is effecting IEP system modifications prior to placing the project into full service. On February 9, 2010, Trunkline LNG filed with FERC a request to place the facility in full service upon the completion of certain modifications. Full service is expected no later than the end of the first quarter of 2010. Total construction costs are expected to be approximately $430 million, plus capitalized interest. The negotiated rate with the project’s customer, BG LNG Services, will be adjusted based on final capital costs pursuant to a contract-based formula. In addition, Trunkline LNG and BG LNG Services agreed to extend the existing terminal and pipeline services agreements to coincide with the IEP contract, which runs 20 years from the in-service date. Approximately $457.2 million and $351.3 million of costs, including capitalized interest of $43.8 million and $20 million, are included in the line item Construction work-in-progress at December 31, 2009 and 2008, respectively.
On August 31, 2009, Sea Robin filed with FERC to implement a rate surcharge to recover Hurricane Ike-related costs not otherwise recovered from insurance proceeds or from other third parties, with initial accumulated net costs of approximately $38 million included in the filing. On September 30, 2009, FERC approved the surcharge to be effective March 1, 2010, subject to refund and the outcome of hearings to be established by FERC to explore issues set forth in certain customer protests, including the costs to be included and the applicability of the surcharge to discounted contracts. See Note 14 - Commitments and Contingencies - Other Commitments and Contingencies for information related to total anticipated capital and abandonment costs attributable to Hurricane Ike, approximately $135 million of which is related to Sea Robin, and other information regarding reimbursement of a portion of such costs from the Company’s insurance carrier.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
On December 15, 2003, the U.S. Department of Transportation issued a final rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule defines as HCAs. This rule resulted from the enactment of the Pipeline Safety Improvement Act of 2002. The rule requires operators to have identified HCAs along their pipelines by December 2004, and to have begun baseline integrity assessments, comprised of in-line inspection (smart pigging), hydrostatic testing or direct assessment, by June 2004. Operators were required to rank the risk of their pipeline segments containing HCAs and to complete assessments on at least 50 percent of the segments using one or more of these methods by December 2007. Assessments will generally be conducted on the higher risk segments first, with the balance being completed by December 2012. In addition, some system modifications will be necessary to accommodate the in-line inspections. As of December 31, 2009 and 2008, the Company had completed 89 percent and 83 percent of the required risk assessments, respectively. All systems operated by the Company will be compliant with the rule; however, while identification and location of all the HCAs has been completed, it is not practicable to determine with certainty the total scope of required remediation activities prior to completion of the assessments and inspections. The required modifications and inspections are currently estimated to be in the range of approximately $6 million to $30 million per year through 2013.
Missouri Gas Energy. On April 2, 2009, Missouri Gas Energy made a filing with the MPSC seeking to implement an annual base rate increase of approximately $32.4 million. Missouri Gas Energy’s proposals in this case include continuation of the distribution rate structure, first approved by the MPSC in April 2007, that eliminates the impact of weather and conservation for residential margin revenues and earnings in Missouri, and expansion of that rate structure into Missouri Gas Energy’s small commercial customer class. On February 10, 2010, the MPSC issued its Report and Order in this case, authorizing a revenue increase of $16.2 million and approving distribution rate structures for Missouri Gas Energy’s residential and small general service customers (which comprise approximately 99 percent of its total customers and approximately 96 percent of its operating revenues) that eliminate the impact of weather and conservation for residential and small general service margin revenues and related earnings in Missouri. The new rates became effective February 28, 2010.
On July 1, 2008, the Circuit Court of Greene County, Missouri made a docket entry indicating that, following judicial review, it had affirmed the Report and Order issued by the MPSC resolving Missouri Gas Energy’s general rate increase that went into effect on April 3, 2007. Following appeals of that ruling by both Missouri Gas Energy and the Office of the Public Counsel, the Southern District of the Missouri Court of Appeals affirmed the Report and Order of the MPSC by opinion issued on August 28, 2009. The office of the Public Counsel sought review of the Court of Appeals’ opinion in the Missouri Supreme Court and by order issued on November 17, 2009, the Missouri Supreme Court declined review. Therefore, the Court of Appeals’ opinion and the MPSC’s Report and Order are now final and not subject to further judicial review.
New England Gas Company. On September 15, 2008, New England Gas Company made a filing with the MDPU seeking recovery of approximately $4 million, or 50 percent of the amount by which its 2007 earnings fell below a return on equity of 7 percent. This filing was made pursuant to New England Gas Company’s rate settlement approved by the MDPU in 2007. On February 2, 2009, the MDPU issued its order denying the Company’s requested earnings sharing adjustments in its entirety. The Company appealed that decision to the Massachusetts Supreme Judicial Court on February 17, 2009. On November 13, 2009, the Company made a similar filing with MDPU, also pursuant to the above-referenced settlement, to recover approximately $1.7 million, representing 50 percent of its 2008 earnings deficiency. That filing is currently awaiting MDPU action.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
19. Goodwill
The following table displays changes in the carrying amount of goodwill, which relates solely to the Distribution segment:
The Company evaluates goodwill of its Distribution segment reporting unit annually for potential impairment.
20. Leases
The Company leases certain facilities, equipment and office space under cancelable and non-cancelable operating leases. The minimum annual rentals under operating leases for the next five years ending December 31 are as follows: 2010-$17.5 million; 2011- $17.4 million; 2012-$14.9 million; 2013- $15 million; 2014-$14.2 million; and $76.1 million in total thereafter. Rental expense was $22.7 million, $19.2 million and $19.9 million for the years ended December 31, 2009, 2008 and 2007, respectively.
21. Asset Retirement Obligations
An ARO is required to be recorded when a legal obligation to retire an asset exists. An ARO should be recorded for all assets with legal retirement obligations, even if the enforcement of the obligation is contingent upon the occurrence of events beyond the company’s control (Conditional ARO). The fair values of the AROs were calculated using present value techniques. These techniques reflect assumptions such as removal and remediation costs, inflation and profit margins that third parties would demand to settle the amount of the future obligation. The Company did not include a market risk premium for unforeseeable circumstances in its fair value estimates because such a premium could not be reliably estimated.
Although a number of other assets in the Company’s system are subject to agreements or regulations that give rise to an ARO or a Conditional ARO upon the Company’s discontinued use of these assets, AROs were not recorded for most of these assets because the fair values of these AROs were not reliably estimable. The principal reason the fair values of these AROs were not subject to reliable estimation was because the lives of the underlying assets are indeterminate. Management has concluded that the Panhandle pipeline system, as a whole, and the SUGS natural gas gathering and processing system, as a whole, have indeterminate lives. In reaching this conclusion, management considered its intent for operating the systems, the economic life of the underlying assets, its past practices and industry practice.
The Company intends to operate the pipeline and the natural gas gathering and processing systems indefinitely as a going concern. Individual component assets have been and will continue to be replaced, but the pipeline and the natural gas gathering and processing systems will continue in operation as long as supply and demand for natural gas exists. Based on the widespread use of natural gas in industrial and power generation activities and current estimates of recoverable reserves, management expects supply and demand to exist for the foreseeable future.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Company has in place a rigorous repair and maintenance program that keeps the pipeline and the natural gas gathering and processing systems in good working order. Therefore, although some of the individual assets on the systems may be replaced, the pipeline and the natural gas gathering and processing systems themselves will remain intact indefinitely. AROs generally do not arise unless a pipeline or a facility (or portion thereof) is abandoned. The Company does not intend to make any such abandonments as long as supply and demand for natural gas remains relatively stable.
The following table is a general description of ARO and associated long-lived assets at December 31, 2009:
As of December 31, 2009, the Company has recorded $1 million that is legally restricted for the purpose of settling AROs.
The following table is a reconciliation of the carrying amount of the ARO liability for the periods presented:
The Company determined that certain of its offshore facilities damaged by Hurricane Ike will not be replaced. The Company is required by federal regulations to remove or abandon in place such facilities when they are no longer useful. This resulted in the establishment of an ARO and recognition of expense of $8.3 million and $7 million, respectively, in 2009, and $33.8 million and $4 million, respectively, in 2008. The amount expensed represents the ARO cost not previously accrued. For additional information related to the impact of the 2008 hurricanes, see Note 14 - Commitments and Contingencies - Other Commitments and Contingencies - 2008 Hurricane Damage.
22. Other Income and Expense Items
Other, net income for the year ended December 31, 2009 totaling $21.4 million consists primarily of $20.3 million of settlements with insurance companies related to certain environmental matters and collection of a $1.9 million settlement amount awarded to the Company related to the Southwest Gas litigation action filed by the Company in 2002 against former Arizona Corporation Commissioner James Irvin.
Operating, maintenance and general expense for the year ended December 31, 2007 includes a $6.9 million impairment of the Company’s former corporate office building due to a change in the Company’s expected proceeds from the sale of the building.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
23. Quarterly Operations (Unaudited)
The following table presents the operating results for each quarter of the year ended December 31, 2009:
The following table presents the operating results for each quarter of the year ended December 31, 2008:
The sum of EPS by quarter in the above tables may not equal the net earnings per common and common share equivalents for the applicable year due to variations in the weighted average common and common share equivalents outstanding used in computing such amounts.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Stockholders and Board of Directors
of Southern Union Company:
In our opinion, the accompanying consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Southern Union Company and its subsidiaries (the "Company") at December 31, 2009 and 2008 and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control over Financial Reporting under item 9A. Our responsibility is to express opinions on these financial statements and on the Company's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included 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, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
March 1, 2010
Citrus Corp. and Subsidiaries
Consolidated Financial Statements
Years ended December 31, 2009, 2008 and 2007
with Report of Independent Registered Public Accounting Firm
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of Citrus Corp.:
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, of comprehensive income, of stockholders’ equity and of cash flows present fairly, in all material respects, the financial position of Citrus Corp. and subsidiaries (the "Company") at December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009 in conformity with accounting principles generally accepted in the United States of America. 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 of these statements 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. An audit 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, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
/s/PricewaterhouseCoopers LLP
Houston, Texas
February 25, 2010
The accompanying notes are an integral part of these consolidated financial statements.
The accompanying notes are an integral part of these consolidated financial statements.
The accompanying notes are an integral part of these consolidated financial statements.
The accompanying notes are an integral part of these consolidated financial statements.
CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Corporate Structure
Citrus Corp. (Citrus), a holding company formed in 1986, owns 100 percent of the membership interest in Florida Gas Transmission Company, LLC (Florida Gas), and 100 percent of the stock of Citrus Energy Services, Inc. (CESI) (collectively, the Company). On March 3, 2008, Citrus Trading Corp., which was wholly-owned by Citrus and which no longer had any ongoing activity, was dissolved. At December 31, 2009, the stock of Citrus was owned 50 percent by El Paso Citrus Holdings, Inc. (EPCH), a wholly-owned subsidiary of El Paso Corporation (El Paso), and 50 percent by CrossCountry Citrus, LLC (CCC), a wholly-owned subsidiary of CrossCountry Energy, LLC (CrossCountry) an indirect subsidiary of Southern Union Company (Southern Union).
Florida Gas, an open-access interstate natural gas pipeline extending from south Texas through the Gulf Coast region of United States to south Florida, is engaged in the interstate transmission of natural gas and is subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC). Florida Gas’ pipeline system primarily receives natural gas from producing basins along the Louisiana and Texas Gulf Coast, Mobile Bay and offshore Gulf of Mexico, and transports natural gas to the Florida market.
The Company evaluated subsequent events through February 25, 2010, the date on which these accompanying financial statements were issued.
2. Summary of Significant Accounting Policies and Other Matters
Basis of Presentation. The Company’s consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP). The FASB Accounting Standards Codification (Codification) became effective on July 1, 2009, officially becoming the single source of authoritative nongovernmental GAAP, superseding existing Financial Accounting Standards Board (FASB), American Institute of Certified Public Accountants, Emerging Issues Task Force, and related accounting literature. Only one level of authoritative GAAP now exists. The Codification is effective for financial statements that cover interim and annual periods ending after September 15, 2009. The Company’s consolidated financial statements have only been impacted to the extent that all references to authoritative accounting literature have been referenced in accordance with the Codification.
Regulatory Accounting. Florida Gas’ accounting policies conform to authoritative guidance which is in accordance with the accounting requirements and ratemaking practices of the regulatory authorities. Accordingly, certain assets and liabilities that result from the regulated ratemaking process are recorded that would not be recorded under GAAP for non-regulated entities. Certain allowable regulatory deferrals of phase-in costs are prohibited under GAAP. As a consequence, certain phase-in costs of Florida Gas’ Phase III expansion are not deferred for GAAP, but are deferred for future recovery for ratemaking purposes.
Use of Estimates. The preparation of financial statements in conformity with GAAP 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. Actual results could differ from those estimates.
Cash and Cash Equivalents. All liquid investments with maturities of three months or less at the date of purchase are considered cash equivalents. The carrying amount of cash and cash equivalents approximates fair value because of the short maturity of these investments.
Materials and Supplies. Materials and supplies are valued at the lower of cost or market value. Materials transferred out of warehouses are priced at average cost. Materials and supplies include spare parts which are critical to the pipeline system operations.
CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Natural Gas Imbalances. Natural gas imbalances occur as a result of differences in volumes of natural gas received and delivered. These imbalances due to or from shippers and operators are valued at an appropriate index price. Natural gas imbalances are settled in cash or made up in-kind subject to terms of Florida Gas’ tariff, and generally do not impact earnings. Natural gas imbalance receivables from customers are recorded in Exchange gas receivable and natural gas imbalance payables are recorded in Exchange gas payable in the accompanying consolidated balance sheet.
Fuel Tracker. The fuel tracker is the cumulative balance owed to Florida Gas by its customers or owed by Florida Gas to its customers for gas used in the operation of its system, including costs incurred in the operation of electric compression and gas lost from the system or otherwise unaccounted for. The customers, pursuant to Florida Gas’ tariff and related contracts, provide fuel to Florida Gas based on specified percentages of the customers’ natural gas volumes delivered into the pipeline. The percentages are designed to match the actual fuel consumed in moving the natural gas through Florida Gas’ facilities, with any difference between the volumes provided versus fuel consumed reflected in the fuel tracker. A regulatory liability is recorded in the accompanying consolidated balance sheet for net volumes of natural gas owed to customers collectively. Whenever fuel is due from customers from prior under recovery based on contractual and specific tariff provisions a regulatory asset is recorded. Natural gas owed from or to customers is valued at market and a surcharge is invoiced to recover or refund the previous under or over collections. Changes in the balances have no effect on the consolidated income of Florida Gas.
Property, Plant and Equipment. Property, Plant and Equipment consists primarily of natural gas pipeline and related facilities and is recorded at its original cost. Florida Gas capitalizes all construction-related direct labor and material costs, as well as indirect construction costs. The cost of replacements and betterments that extend the useful life of property, plant and equipment is also capitalized. The cost of repairs and replacements of minor property, plant and equipment items is charged to expense as incurred.
When property, plant and equipment is retired, the original cost less salvage value is charged to accumulated depreciation and amortization. When entire regulated operating units of property, plant and equipment are retired or sold, the property and related accumulated depreciation and amortization accounts are reduced, and any gain or loss is recorded in income.
The Company amortized that portion of its investment in Florida Gas property which is in excess of historical cost (acquisition adjustment) on a straight-line basis at an annual composite rate of 1.6 percent based upon the estimated remaining useful life of the pipeline system.
Florida Gas has provided for depreciation of assets, on a straight-line basis, at an annual composite rate of 2.78 percent, 2.75 percent and 2.77 percent for the years ended December 31, 2009, 2008 and 2007, respectively.
The recognition of an allowance for funds used during construction (AFUDC) is a utility accounting practice with calculations under guidelines prescribed by the FERC and capitalized as part of the cost of utility plant. It represents the cost of capital invested in construction work-in-progress. AFUDC has been segregated into two component parts - borrowed funds and equity funds. The allowance for borrowed and equity funds used during construction, including related amounts to gross up equity AFUDC to a before tax basis, totaled $73.2 million, $15.6 million and $10.3 million for the years ended December 31, 2009, 2008 and 2007, respectively. AFUDC-borrowed funds are included as a reduction in Interest expense and AFUDC-equity funds are included in Other income in the accompanying statements of income.
Asset Impairment. An impairment loss is recognized when the carrying amount of a long-lived asset used in operations is not recoverable and exceeds its fair value. The carrying amount of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset.
Environmental Expenditures. Environmental expenditures that relate to an existing condition caused by past operations, and do not contribute to current or future generation, are expensed. Environmental expenditures relating to current or future revenues are expensed or capitalized as appropriate. Liabilities are recorded when environmental assessments and/or clean-ups are probable and the cost can be reasonably estimated. Remediation obligations are not discounted because the timing of future cash flow streams is not predictable. See Note 13 - Commitment and Contingencies.
CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Revenues. Revenues from transportation of natural gas are based on capacity reservation charges and commodity usage charges. Reservation revenues are based on contracted rates and capacity reserved by the customers and are recognized monthly. Revenues from commodity usage charges are also recognized monthly based on the volumes of natural gas delivered. Revenues for all services are generally based on the thermal quantity of natural gas delivered or subscribed at a rate specified in the contract.
Because Florida Gas is subject to FERC regulations, revenues collected during the pendency of a rate proceeding may be required by the FERC to be refunded in the final order. Florida Gas establishes reserves for such potential refunds, as appropriate. There were no reserves for potential rate refund at December 31, 2009 and 2008, respectively.
Accounts Receivable and Allowance for Doubtful Accounts. The Company manages trade credit risks to minimize exposure to uncollectible trade receivables. Prospective and existing customers are reviewed for creditworthiness based upon pre-established standards. Customers that do not meet minimum standards are required to provide additional credit support. The Company considers many factors including historical customer collection experience, general and specific economic trends and known specific issues related to individual customers, sectors, and transactions that might impact collectability. Increases in the allowance are recorded as a component of operating expenses. Reductions in the allowance are recorded when receivables are written off or subsequently collected. Unrecovered accounts receivable charged against the allowance for doubtful accounts were nil, nil and $0.3 million in the years ended December 31, 2009, 2008 and 2007, respectively.
The following table presents the relative contribution to the Company’s total operating revenue of each customer that comprised at least ten percent of its operating revenues for the periods presented. Revenues from individual third party and affiliate customers exceeding 10 percent of total revenues were approximately 54 percent, 55 percent and 56 percent of total revenue for the years ended December 31, 2009, 2008 and 2007, respectively.
The Company had the following transportation receivables from these customers at the dates indicated:
The Company has a concentration of customers in the electric and natural gas utility industries. These concentrations of customers may impact the Company's overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic or other conditions. Credit losses incurred on receivables in these industries compare favorably to losses experienced in the Company's receivable portfolio as a whole. The Company also has a concentration of customers located in the southeastern United States, primarily within the state of Florida. Receivables are generally not collateralized. From time to time, specifically identified customers having perceived credit risk are required to provide prepayments, deposits, or other forms of security to the Company. Florida Gas sought additional assurances from customers due to credit concerns, and had customer deposits totaling $1.4 million and $1.6 million, and prepayments of $181,000 and $43,000 at December 31, 2009 and 2008, respectively. The Company's management believes that the portfolio of Florida Gas’ receivables, which includes regulated electric utilities, regulated local distribution companies, and municipalities, is of minimal credit risk.
CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Other Postretirement Benefit Plans. Employers are required to recognize in their balance sheets the overfunded or underfunded status of defined benefit postretirement plans, measured as the difference between the fair value of the plan assets and the benefit obligation (the projected benefit obligation for pension plans and the accumulated postretirement benefit obligation for other postretirement plans). Each overfunded plan is recognized as an asset and each underfunded plan is recognized as a liability. Employers must recognize the change in the funded status of the plan through Accumulated other comprehensive loss in stockholders’ equity in the year in which the change occurs. Effective December 31, 2008, the Company adopted the measurement date provisions of applicable benefit plan authoritative accounting guidance, which require plan assets and benefit obligations to be measured as of its fiscal year-end balance sheet date.
Prior to the adoption of the recognition and disclosure provisions of applicable benefit plan accounting authoritative guidance, changes in the funded status were not immediately recognized; rather they were deferred and recognized ratably over future periods. Upon adoption of the recognition provisions, the Company recognized the amounts of these prior changes in the funded status of its defined postretirement benefit plans. The Company recognized net periodic benefit expense to the extent of amounts recorded in rates with any difference recorded as a regulatory asset or liability. Unrecognized prior service costs (benefits) and gains and/or losses are not recorded as change to Accumulated other comprehensive loss, but rather as a regulatory asset or regulatory liability, reflecting amounts due from or to customers, respectively.
See Note 8 - Benefits for additional related information.
Derivative and Hedging Activities. All derivatives are recognized on the consolidated balance sheet at their fair value. On the date the derivative contract is entered into, the Company designates the derivative as (i) a hedge of the fair value of a recognized asset or liability or of an unrecognized firm commitment (a fair value hedge); (ii) a hedge of a forecasted transaction or the variability of cash flows to be received or paid in conjunction with a recognized asset or liability (a cash flow hedge); or (iii) an instrument that is held for trading or non-hedging purposes (a trading or economic hedging instrument). For derivatives treated as a fair value hedge, the effective portion of changes in fair value is recorded as an adjustment to the hedged item. The ineffective portion of a fair value hedge is recognized in earnings if the short cut method of assessing effectiveness is not used. Upon termination of a fair value hedge of a debt instrument, the resulting gain or loss is amortized to earnings through the maturity date of the debt instrument. For derivatives treated as a cash flow hedge, the effective portion of changes in fair value is recorded in Accumulated other comprehensive loss until the related hedged items impact earnings. Any ineffective portion of a cash flow hedge is reported in current-period earnings. Upon termination of a cash flow hedge, the resulting gain or loss is amortized to earnings through the maturity date of the hedged forecasted transactions. For derivatives treated as trading or economic hedging instruments, changes in fair value are reported in current-period earnings. Fair value is determined based upon quoted market prices and pricing models using assumptions that market participants would use. As of December 31, 2009 and 2008, the Company does not have any hedges in place; it is only amortizing previously terminated cash flow hedges.
Fair Value Measurement. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about nonperformance risk, which is primarily comprised of credit risk (both the Company’s own credit risk and counterparty credit risk) and the risks inherent in the inputs to any applicable valuation techniques. The Company places more weight on current market information concerning credit risk (e.g. current credit default swap rates) as opposed to historical information (e.g. historical default probabilities and credit ratings). These inputs can be readily observable, market corroborated, or generally unobservable. The Company endeavors to utilize the best available information, including valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. A three-tier fair value hierarchy, which prioritizes the inputs used to measure fair value, is as follows:
·
Level 1 - Observable inputs such as quoted prices in active markets for identical assets or liabilities;
·
Level 2 - Observable inputs such as: (i) quoted prices for similar assets or liabilities in active markets; (ii) quoted prices for identical or similar assets or liabilities in markets that are not active and do not require significant adjustment based on unobservable inputs; or (iii) valuations based on pricing models, discounted cash flow methodologies or similar techniques where significant inputs (e.g., interest rates, yield curves, etc.) are derived principally from observable market data, or can be corroborated by observable market data, for substantially the full term of the assets or liabilities; and
·
Level 3 - Unobservable inputs, including valuations based on pricing models, discounted cash flow methodologies or similar techniques where at least one significant model assumption or input is unobservable. Unobservable inputs are used to the extent that observable inputs are not available and reflect the Company’s own assumptions about the assumptions market participants would use in pricing the assets or liabilities. Unobservable inputs are based on the best information available in the circumstances, which might include the Company’s own data.
CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of these assets and liabilities and their placement within the fair value hierarchy.
See Note 8 - Benefits - Other Postretirement Benefit Plans - Plan Assets for additional information regarding the assets of the Company measured on a non-recurring basis.
Asset Retirement Obligations (ARO). Legal obligations associated with the retirement of long-lived assets are required to be recognized at their fair value at the time the obligations are incurred. Upon initial recognition of a liability, costs are capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related long-lived asset. The Company records ARO accretion and amortization expenses as a regulatory asset based on the probability of recovery in rates in future rate cases.
For more information, see Note 5 - Asset Retirement Obligations.
Income Taxes. Income taxes are accounted for under the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in income in the period that includes the enactment date. Valuation allowances are established when necessary to reduce deferred tax assets to the amounts more likely than not to be realized.
The determination of the Company’s provision for income taxes requires significant judgment, use of estimates, and the interpretation and application of complex tax laws. Significant judgment is required in assessing the timing and amounts of deductible and taxable items. The Company evaluates its tax reserves under the recognition, measurement and derecognition thresholds required by applicable authoritative accounting guidance. Reserves are established when, despite management’s belief that the Company’s tax return positions are fully supportable, management believes that certain positions may be successfully challenged. When facts and circumstances change, these reserves are adjusted through the provision for income taxes. See Note 9 - Income Taxes.
CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
New Accounting Principles
Accounting Principles Recently Adopted.
In March 2008, the FASB issued authoritative guidance relating to disclosures about derivative instruments and hedging activities, which requires additional disclosures to provide users of financial statements with an enhanced understanding of how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for and how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. The guidance is effective for fiscal years and interim periods beginning after November 15, 2008.
In December 2008, the FASB issued authoritative guidance relating to an employer’s disclosure about plan assets of a defined benefit pension or other postretirement plan. The provisions of the guidance are effective for fiscal years ending after December 15, 2009. See Note 8 - Benefits - Other Postretirement Benefit Plans - Plan Assets, which reflects the disclosure required by this guidance applicable to certain of the Company’s postretirement health care plan assets.
In April 2009, the FASB issued authoritative guidance for estimating fair value when the volume and level of activity for the asset or liability have significantly decreased and also includes guidance on identifying circumstances that indicate a transaction is not orderly. The provisions of the guidance are applied prospectively and are effective for interim and annual reporting periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. The Company early adopted the guidance in the first quarter of 2009, the impact of which was not material to the Company’s consolidated financial statements.
In April 2009, the FASB issued authoritative guidance that requires disclosures about fair value of financial instruments for interim reporting periods of publicly traded companies as well as in annual financial statements. The provisions of the guidance are effective for interim reporting periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. The Company early adopted the guidance in the first quarter of 2009, resulting in the disclosure of certain fair value information associated with the Company’s debt obligations. See Note 7 - Debt for the related information.
In June 2009, the FASB issued authoritative guidance that establishes general standards of accounting for and disclosure of events that occur after the balance sheet date, but before financial statements are issued or are available to be issued. This guidance establishes (1) the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements; (2) the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements; and (3) the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. This guidance is effective for interim or annual financial periods ending after June 15, 2009.
In August 2009, the FASB issued authoritative guidance regarding the fair value measurement of liabilities that clarifies the valuation techniques required in circumstances in which a quoted price in an active market for the identical liability is not available. The guidance is effective in the first interim or annual reporting period following issuance. This guidance did not materially impact the Company’s consolidated financial statements.
In September 2009, the FASB issued authoritative guidance regarding the fair value measurement of investments in certain entities that calculate net asset value per share (or its equivalent) and requires disclosure by major category of investment about the attributes of applicable investments. The guidance is effective for interim and annual reporting periods ending after December 15, 2009, with early adoption permitted. This guidance did not materially impact the Company’s consolidated financial statements.
CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Accounting Principles Not Yet Adopted.
In June 2009, the FASB issued authoritative guidance that changes how a company determines when an entity that is insufficiently capitalized or is not controlled through voting (or similar rights) should be consolidated. The determination is based on, among other things, an entity’s purpose and design and a company’s ability to direct the activities of the entity that most significantly affect the entity’s economic performance. The guidance is effective as of the beginning of the first annual reporting period, and for interim periods within that first period, after November 15, 2009, with early adoption prohibited. This guidance is not expected to materially impact the Company’s consolidated financial statements.
In January 2010, the FASB issued authoritative guidance to improve disclosure requirements related to fair value measurements. This guidance requires new disclosures associated with the three- tier fair value hierarchy for transfers in and out of Levels 1 and 2 and for activity within Level 3. It also clarifies existing disclosure requirements related to the level of disaggregation and disclosures about certain inputs and valuation techniques. This guidance is effective for interim or annual financial periods beginning after December 15, 2009, except for the disclosures related to activity within Level 3, which is effective for interim or annual financial periods beginning after December 15, 2010. The Company is currently evaluating the impact of this guidance on its consolidated financial statements.
3. Regulatory Matters
Florida Gas filed a rate case with FERC on October 1, 2009, reflecting a $107 million increase in its annual cost of service as compared to its prior rate case settlement, including certain amounts already in current rates for subsequent expansions and amounts currently collected via surcharges. The new rates will go into effect on April 1, 2010, subject to refund.
Florida Gas filed a certificate application on October 31, 2008 with FERC to construct an expansion which will increase its natural gas capacity into Florida by approximately 820 million cubic feet per day (MMcf/d). The Phase VIII Expansion includes construction of approximately 500 miles of large diameter pipeline and the installation of approximately 200,000 horsepower of compression. On November 19, 2009, FERC issued a certificate to Florida Gas authorizing the Phase VIII Expansion project. Florida Gas anticipates an in-service date in spring 2011.
On December 15, 2003, the U.S. Department of Transportation issued a final rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule defines as high consequence areas (HCAs). The rule requires operators to identify and risk rank HCAs along their pipelines and perform baseline integrity assessments, comprised of in-line inspection (smart pigging), hydrostatic testing or direct assessment. While identification and location of all HCAs and the majority of the required risk assessments has been completed by Florida Gas, it is not practicable to determine with certainty the total scope of required remediation activities prior to completion of the assessments and inspections. The required modifications and inspections are currently estimated to be in the range of approximately $28 million to $53 million per year through 2013.
In addition to the cost of the HCA requirements, Florida Gas is required under other regulations from time to time to undertake certain actions that may include testing or upgrading portions of its system by pipeline replacement. Florida Gas recorded $40 million of capital expenditures in 2009 to meet these requirements, and expects approximately $60 million of additional capital expenditures to be incurred during 2010. Due to the nature of the factors affecting these costs, it is anticipated that future annual costs will decline significantly from the expected 2010 level.
CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
4. Related Party Transactions
Florida Gas purchases transportation services from Southern Natural Gas Company (Southern), a subsidiary of El Paso, in connection with its Phase III Expansion completed in early 1995. Florida Gas is currently contracted for firm capacity of 100,000 Mcf/day on Southern’s system through August 31, 2013. The amount expensed for these services totaled $7.1 million, $6.8 million and $6.8 million in the years ended December 31, 2009, 2008 and 2007, respectively. Florida Gas had net accounts payable to Southern of $600,000 and $542,000 as of December 31, 2009 and 2008, respectively.
The Company has related party activities for operational and administrative services performed by Panhandle Eastern Pipe Line Company, LP (PEPL), an indirect wholly-owned subsidiary of Southern Union, and other related parties, on behalf of the Company, and corporate service charges from Southern Union. Expenses are generally charged based on either actual usage of services or allocated based on estimates of time spent working for the benefit of the various affiliated companies. Amounts expensed by the Company were $30.6 million, $27.9 million and $21.5 million in the years ended December 31, 2009, 2008 and 2007, respectively, and included corporate service charges from Southern Union of $7.2 million, $6.3 million and $5.9 million in the years ended December 31, 2009, 2008 and 2007, respectively. Additionally, the Company receives allocated costs of certain shared business services from PEPL and Southern Union. At December 31, 2009 and 2008, the Company had current net accounts payable to affiliated companies of $10 million and $8.5 million, respectively, relating to these services.
No cash dividend was declared and paid to shareholders for the year ended December 31, 2009 primarily due to the ongoing Phase VIII Expansion capital requirements. The Company paid cash dividends to its shareholders of $154.3 million and $207.1 million in the years ended December 31, 2008, and 2007, respectively. Included in the 2008 dividend payments was a declared dividend in December 2007 of $42.6 million, paid on January 18, 2008. In June and October 2008, Citrus made capital contributions of $77.3 million and $340 million to Florida Gas, respectively.
5. Asset Retirement Obligations
ARO assets and liabilities are related to primarily offshore lateral lines in the Company’s system. An ARO is required to be recorded when a legal obligation to retire an asset exists. An ARO should be recorded for all assets with legal retirement obligations, even if the enforcement of the obligation is contingent upon the occurrence of events beyond the company’s control (Conditional ARO). The fair values of the AROs were calculated using present value techniques. These techniques reflect assumptions such as removal and remediation costs, inflation and profit margins that third parties would demand to settle the amount of the future obligation. The Company did not include a market risk premium for unforeseeable circumstances in its fair value estimates because such a premium could not be reliably estimated.
Although a number of other assets in the Company’s system are subject to agreements or regulations that give rise to an ARO or a Conditional ARO upon the Company’s discontinued use of these assets, AROs were not recorded for most of these assets because the fair values of these AROs were not reliably estimable. The principal reason the fair values of these AROs were not subject to reliable estimation was because the lives of underlying assets are indeterminate. Management has concluded that the Company’s pipeline system, as a whole, has an indeterminate life. In reaching this conclusion, management considered its intent for operating the pipeline system, the economic life of the underlying assets, its past practices and industry practice.
The Company intends to operate the pipeline system indefinitely as a going concern. Individual component assets have been and will continue to be replaced, but the pipeline system will continue in operation as long as supply and demand for natural gas exists. Based on the widespread use of natural gas in industrial and power generation activities, management expects supply and demand to exist for the foreseeable future.
The Company has in place a rigorous repair and maintenance program that keeps the pipeline system in good working order. Therefore, although some of the individual assets on the pipeline system may be replaced, the pipeline system itself will remain intact indefinitely. AROs generally do not arise unless a pipeline system (or portion thereof) is abandoned. The Company does not intend to make any such abandonments as long as supply and demand for natural gas remains relatively stable.
The following table is a general description of ARO and associated long-lived assets at December 31, 2009.
CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As of December 31, 2009, the Company has no funds legally restricted for the purpose of settling AROs.
Florida Gas recorded ARO accretion and amortization expenses of $1.5 million at December 31, 2009 (See Note 11 - Regulatory Assets) as a regulatory asset based on the probability of recovery in rates in its next rate case.
The following table is a reconciliation of the carrying amount of the ARO liability for the periods presented:
6. Comprehensive Income
Deferred gains and losses in connection with the termination of the following derivative instruments which were previously accounted for as cash flow hedges form part of other comprehensive income. Such amounts are being amortized over the terms of the hedged debt.
The table below provides an overview of comprehensive income (loss) for the periods presented:
CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
7. Debt
The following table sets forth the debt obligations at the dates indicated:
Annual maturities of long-term debt outstanding, excluding unamortized debt discount, as of the date indicated were as follows:
The Florida Gas revolving credit agreement which was originally in the amount of $300 million (2007 Florida Gas Revolver) will mature on August 16, 2012, requires interest based on LIBOR plus a margin tied to the debt rating of the Florida Gas’ senior unsecured debt, currently 0.36 percent, and has a facility fee of 0.09 percent. As of December 31, 2009, there were no outstanding debt balances under the 2007 Florida Gas Revolver.
The Citrus revolving credit facility which was originally in the amount of $200 million (2007 Citrus Revolver) will mature on August 16, 2012. As of December 31, 2009, the amount drawn under the 2007 Citrus Revolver was $5.2 million with a weighted average interest rate of 0.61 percent (based on LIBOR plus 0.36 percent), and has a facility fee of 0.09 percent.
CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The lenders of the 2007 Florida Gas Revolver and 2007 Citrus Revolver are a group of banks, previously including Lehman Brothers Bank FSB (Lehman FSB), a subsidiary of Lehman Brothers Holdings Inc. (Lehman). Lehman FSB had a total $35 million credit commitment in the Company’s total of $500 million of capacity under the 2007 Florida Gas Revolver and 2007 Citrus Revolver. Lehman and some of its subsidiaries, but not including Lehman FSB, filed for bankruptcy under Chapter 11 of the U.S. Bankruptcy code on September 15, 2008. However, Lehman FSB had been electing not to fund its pro rata share of the borrowing as required under its commitment to the facility since September 16, 2008. On October 6, 2009, the 2007 Florida Gas Revolver and the 2007 Citrus Revolver were amended, and Lehman FSB was formally removed from the agreement. The Company’s available capacity under its revolvers at December 31, 2009 was $459.8 million.
The estimated fair value of the 2007 Florida Gas Revolver and 2007 Citrus Revolver at December 31, 2009 approximates 94 percent of their carrying values. Estimated fair value amounts of other long-term debt were obtained from independent parties, and are based upon market quotations of similar debt at interest rates currently available. Judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates determined as of December 31, 2009 and 2008 are not necessarily indicative of the amounts the Company could have realized in current market exchanges.
On February 5, 2008, Citrus entered into a $500 million unsecured construction and term loan agreement (Construction Loan Agreement) with a wholly-owned subsidiary of FPL Group Capital Inc., which is a wholly-owned subsidiary of FPL Group, Inc. Citrus is investing the proceeds of this loan into Florida Gas primarily to finance a portion of the Phase VIII Expansion (as more fully disclosed in Note 13 - Commitments and Contingencies - Phase VIII Expansion). On October 1, 2008, Citrus borrowed the full $500 million available under the Construction Loan Agreement. The loan is not guaranteed by Florida Gas and does not include a prepayment option. The Construction Loan Agreement contains certain customary representations, warranties and covenants and requires the execution of a negative pledge agreement by Florida Gas. The Construction Loan Agreement requires any dividends paid by Citrus after October 1, 2008 and prior to the Phase VIII Expansion in-service date to be re-contributed by the partners within twelve months of any such dividends.
The $500 million construction and term loan, with an interest rate based upon LIBOR plus a margin of 5.35 percent, was converted to a twenty-year fixed-rate term loan with a fixed interest rate of 9.393 percent on October 8, 2009. Interest will be payable in semi-annual installments over the next five years. The required semi-annual payments will begin to include principal beginning five and one-half years after conversion, and the loan has a final balloon maturity of $300 million in principal on October 8, 2029.
In July 2009, Citrus entered into a series of forward starting swap rate lock agreements (Swap Rate Lock Agreements) with a total notional amount of $175 million with regard to the expected conversion of the Construction Loan Agreement. The Swap Rate Lock Agreements were designed to hedge against the potential changes in future cash flows payable under the Construction Loan Agreement upon its conversion to a twenty-year fixed-rate term loan, which occurred on October 8, 2009. The Swap Rate Lock Agreements were settled by Citrus on October 8, 2009 for a loss of $9.2 million.
In May 2009, Florida Gas issued $600 million of 7.90 percent senior notes due May 15, 2019 with an offering price of $99.82 (per $100 principal). Florida Gas will use the net proceeds to partially fund the Phase VIII Expansion project and for general corporate purposes.
In June 2009, Citrus retired early its remaining $30 million 8.49 percent senior notes which were scheduled to mature in November 2009. The debt retirement included accrued interest of $283,000 and a $900,000 redemption premium.
Under the terms of its debt agreements, Florida Gas may incur additional debt to refinance maturing obligations if the refinancing does not increase aggregate indebtedness, and thereafter, if Citrus’ and Florida Gas’ consolidated debt does not exceed specific debt to total capitalization ratios, as defined in certain debt instruments. Incurrence of additional indebtedness to refinance the current maturities would not result in a debt to capitalization ratio exceeding these limits.
CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The agreements relating to Florida Gas’ debt include, among other things, restrictions as to the payment of dividends and maintaining certain restrictive financial covenants, including a required ratio of funded debt to total capitalization. At December 31, 2009, the Company no longer was subject to a limitation on additional restricted payments including dividends and loans to affiliates. The Company is subject, under the currently most restrictive debt covenant of a maximum 65 percent of consolidated funded debt to total capitalization, to a limitation of $655.7 million of total additional indebtedness at December 31, 2009.
As of December 31, 2009, Citrus has a $500 million construction and term loan and $5.2 million in its revolving credit agreement outstanding, in addition to all of Florida Gas’ debt obligations. Florida Gas guarantees the Citrus revolving credit agreement indebtedness; however, Florida Gas’ assets are not pledged as collateral for any of the aforementioned Citrus debt. All of the debt obligations of Citrus and Florida Gas have events of default that contain commonly used cross-default provisions. An event of default by either Citrus or Florida Gas on any of their borrowed money obligations, in excess of certain thresholds which is not cured within defined grace periods, would cause the other debt obligations of Citrus and Florida Gas to be accelerated. As of December 31, 2009, Citrus is not in default of any of its debt obligations.
8. Benefits
Other Postretirement Benefit Plans
The Company has postretirement health care and life insurance plans (other postretirement plans) that cover substantially all employees. The health care plan generally provides for cost sharing between the Company and its retirees in the form of retiree contributions, deductibles and coinsurance on the amount the Company pays annually to provide future retiree health care coverage under certain of these plans.
CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Obligations and Funded Status
Postretirement benefit liabilities are accrued on an actuarial basis during the years an employee provides services. The following tables contain information at the dates indicated about the obligations and funded status of the Company’s other postretirement plans.
(1)
The Plan was amended to provide an annual increase to the dollar multiplier used to establish initial account balances for employees who retire on or after October 1, 2008. This amendment was adopted in late September 2009. It is required that amendments be measured and recognized at the time of adoption. Accordingly, the amendment was measured at September 30, 2009, the end of the month nearest to the month of adoption.
(2) Plan assets are recorded at fair value versus a calculated value as of the December 31, 2009 and 2008 measurement dates. Plan assets at December 31, 2008 include the amounts of assets received from the Enron Trust of $7.1 million as final settlement.
(3) Underfunded balance is recognized as a deferred credit-other, offset by a regulatory asset for amounts due from customers, in the consolidated balance sheet.
CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Net Periodic Benefit Cost
Net periodic benefit cost of the Company’s other postretirement benefit plan for the periods presented includes the components noted in the table below.
Assumptions
The weighted-average discount rate used in determining benefit obligations was 5.97 percent, 6.14 percent and 6.09 percent for the years ended December 31, 2009, 2008 and 2007, respectively.
The weighted-average assumptions used in determining net periodic benefit cost for the periods presented are shown in the table below.
Florida Gas employs a building block approach in determining the expected long-term rate of return on the plan’s assets with proper consideration for diversification and rebalancing. Historical markets are studied and long-term historical relationships between equities and fixed-income are preserved consistent with the widely accepted capital market principle that assets with higher volatility generate a greater return over the long run. Current market factors such as inflation and interest rates are evaluated before long-term market assumptions are determined. The long-term portfolio return is established via a building block approach with proper consideration of diversification and rebalancing. Peer data and historical returns are reviewed to check for reasonableness and appropriateness.
The assumed health care cost trend rates used for measurement purposes are shown in the table below.
CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Assumed health care cost trend rates have a significant effect on the amounts reported for health care plan. A one-percentage-point change in assumed health care cost trend rates would have the following effects:
Plan Assets
Florida Gas’ overall investment strategy is to maintain an appropriate balance of actively managed investments with the objective of optimizing long-term returns while maintaining a high standard of portfolio quality and achieving proper diversification. To achieve diversity within its other postretirement benefit plan asset portfolio, the Company has targeted the following asset allocations: equity of 25 percent to 35 percent, fixed income of 65 percent to 75 percent and cash and cash equivalents of 0 percent to 10 percent. These target allocations are monitored by the board of directors in conjunction with an external investment advisor. On occasion, the asset allocations may fluctuate as compared to these guidelines as a result of the board of directors’ actions.
The fair value of Florida Gas’ other postretirement plan assets at December 31, 2009, by asset category is as follows:
(1)
This fund of funds invests primarily in a diversified portfolio of equity, fixed income and short-term mutual funds. As of December 31, 2009, the fund was primarily comprised of approximately 16 percent large-cap U.S. equities, 3 percent small-cap U.S. equities,10 percent international equities, 57 percent fixed income securities, 10 percent cash, and 4 percent in other investments.
The other postretirement plan assets are classified as Level 1 assets within the fair value hierarchy as their value is based on active market quotes. See Note 2 - Summary of Significant Accounting Policies and Other Matters - Fair Value Measurement for information related to the framework used by the Company to measure the fair value of its other postretirement plan asset.
Contributions
Florida Gas expects to contribute approximately $1.9 million to its other postretirement benefit plan in 2010 and approximately $2.1 million annually thereafter, subject to adjustment to reflect the final outcome of its rate case proceeding filed October 1, 2009 (Docket No. RP10-21-000).
CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Benefit Payments
Florida Gas’ estimate of expected benefit payments, which reflect expected future service, as appropriate, in each of the next five years and in the aggregate for the five years thereafter are shown in the table below.
The Medicare Prescription Drug Act provides a prescription drug benefit under Medicare (Medicare Part D) as well as a federal subsidy, which is not taxable, to sponsors of retiree health care benefit plan that provides a prescription drug benefit that is at least actuarially equivalent to Medicare Part D.
Defined Contribution Plan
Florida Gas sponsors a defined contribution saving plan (Savings Plan) that is available to all employees. Florida Gas contributed 50 percent of the participant’s contributions paid into the Savings Plan up to a maximum of four percent of eligible compensation through December 31, 2007. The matching was increased effective January 1, 2008 to 100 percent of the first two percent and 50 percent of the next three percent of the participant’s compensation paid into the Savings Plan. Effective January 1, 2009, the matching was increased to 100 percent of the first five percent for a maximum of five percent of the participant’s compensation paid into the Savings Plan. Company contributions are 100 percent vested after five years of continuous service. Florida Gas' contributions to the Savings Plan during the years ended December 31, 2009, 2008 and 2007 were $1.1 million, $728,000 and $348,000, respectively.
In addition, Florida Gas makes employer contributions to separate accounts, referred to as Profit Sharing Plan, within the defined contribution plan. The contribution amounts are determined as five percent of compensation. Florida Gas’ contribution to the Profit Sharing Plan during the years ended December 31, 2009, 2008 and 2007 were $1.4 million, $1.3 million and $1.2 million, respectively.
Prior to December 1, 2004, Florida Gas was a participating employer in the Enron Gas Pipelines Employee Benefit Trust (Enron Trust), a voluntary employees’ beneficiary association (VEBA) under Section 501(c)(9) of the Internal Revenue Code of 1986, as amended (Tax Code), which provided certain postretirement medical, life insurance and dental benefits to employees of Florida Gas and certain other Enron affiliates pursuant to the Enron Corp Medical Plan and the Enron Corp. Medical Plan for Inactive Participants. Enron made the determination to partition the Enron Trust and distribute the assets and liabilities of the Enron Trust among the participating employers of the Enron Trust on a pro rata basis according to the contributions and liabilities associated with each participating employer. With regard to its sponsored plan, Florida Gas has entered into a VEBA trust (the “VEBA Trust”) agreement with JPMorgan Chase Bank Trust Company as trustee. Florida Gas contributed $1.0 million and $1.3 million to the VEBA Trust for the years ended December 31, 2009 and 2008, respectively. Upon settlement of the Enron Trust on March 3, 2008, the $7.1 million distribution of assets to Florida Gas from the Enron Trust was contributed to the VEBA Trust.
CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Florida Gas’ other postretirement benefit plans weighted-average asset allocation by asset category for the $10.7 million and $8.2 million of assets actually in the VEBA Trust at December 31, 2009 and 2008, respectively, were approximately as follows:
9. Income Taxes
The following table provides a summary of the current and deferred components of income tax expense for the periods presented:
The actual income tax expense differs from the amount computed by applying the statutory federal tax rate of 35 percent to income before income taxes as follows:
CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Company files a consolidated federal income tax return separate from that of its stockholders. Florida Gas is included in the consolidated federal income tax return filed by Citrus. Pursuant to a tax sharing agreement with Citrus, Florida Gas will pay its share of taxes based on its taxable income, which will generally equal the liability that the Company would have incurred as a separate taxpayer.
The principal components of the Company's deferred income tax assets (liabilities) recognized at the dates indicated are as follows:
Effective January 1, 2009, the Company evaluates its tax reserves (unrecognized tax benefits) under the recognition, measurement and derecognition thresholds. The amount of unrecognized tax benefits did not have a material impact to the Company’s consolidated financial statements.
10. Property, Plant and Equipment
The following table provides a summary of property, plant and equipment at the dates indicated:
Amortization expense of capitalized computer software costs for the years ended December 31, 2009, 2008 and 2007 was $1.7 million, $1.5 million and $1.5 million, respectively. Computer software costs are amortized over 10 years.
CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
11. Regulatory Assets
The principal components of the Company's regulatory assets at the dates indicated were as follows:
(1)
Ramp-up assets are regulatory assets which Florida Gas was specifically allowed to establish in the FERC certificates authorizing the Phase IV and V Expansion projects.
12. Deferred Credits
The principal components of the Company's regulatory liabilities at the dates indicated were as follows:
(1) Balancing tool is a regulatory method by which Florida Gas recovers or refunds the net costs of operational natural gas balancing of the pipeline’s system. The balance can be a deferred charge or credit, depending on timing, rate changes and operational activities.
CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The principal components of the Company's other deferred credits at the dates indicated were as follows:
13. Commitments and Contingencies
Litigation. The Company is involved in legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the original course of business, some of which involve substantial amounts. Where appropriate, the Company has made accruals in order to provide for such matters. The Company believes the final disposition of these proceedings will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.
Jack Grynberg, an individual, filed actions for damages against a number of companies, including Florida Gas and Citrus, which was transferred to the U.S. District Court for the District of Wyoming, alleging mis-measurement of natural gas volumes and Btu content, resulting in lower royalties to mineral interest owners. On October 20, 2006, the District Judge ordered the dismissal of the case against the Company. Grynberg appeals were denied at all levels including at the United States Supreme Court. The Company is now seeking recovery of certain costs from Grynberg associated with the defense of the action.
Phase VIII Expansion. Florida Gas anticipates an in-service date in spring 2011, for the Phase VIII Expansion (See Note 3 - Regulatory Matters), at a currently estimated cost of $2.4 billion, including capitalized equity and debt costs. Approximately $737.3 million is recorded in Construction work in progress at December 31, 2009. Of the remaining project costs, commitments representing approximately $1.0 billion have already been entered into, primarily for pipeline and compression installation and materials. To date, Florida Gas has entered into firm transportation service agreements with shippers for transportation service for 25-year terms accounting for approximately 74 percent of the available expansion capacity which, depending on elections by one of the shippers, may increase to 83 percent of such capacity.
Liquidity and Capital Requirements. The Company plans to finance its $346.5 million in debt maturing in 2010 and Florida Gas’ planned significant 2010 capital expenditures for the Phase VIII Expansion and other capital projects with cash flows from operations, new capital market debt, utilization of revolving credit facilities, and equity contributions from its partners. Prior to the in-service date of the Phase VIII Expansion project, the Company expects to receive equity contributions from its partners in a total amount of $300 million to $500 million. These equity contributions will be utilized by the Company to make equity investments in Florida Gas in order to maintain appropriate debt and equity ratios during the construction period for the Phase VIII Expansion project. The Company has not determined the exact timing or size of any individual equity contributions at this point, although the funds are generally expected to be needed by the Company in the latter part of 2010. The Company does not plan to make any cash dividends to its partners until after the Phase VIII Expansion project is in-service. The Company believes, based on Florida Gas’ investment grade credit ratings and its general financial condition, successful historical access to capital and debt markets, and market expectations regarding the Company’s future earnings and cash flows, that it will be able to refinance its maturing obligations and obtain financing for its additional financing needs under acceptable terms. There can be no assurance, however, that Citrus or Florida Gas would be able to achieve acceptable refinancing terms in any negotiation of new capital market debt or bank financings.
CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Environmental Reserve. The Company’s operations are subject to federal, state and local laws and regulations regarding water quality, hazardous and solid waste management, air quality control and other environmental matters. These laws and regulations require the Company to conduct its operations in a specific manner and to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals. Failure to comply with environmental requirements may expose the Company to significant fines, penalties and/or interruptions in operations. The Company’s environmental policies and procedures are designed to achieve compliance with such laws and regulations. These evolving laws and regulations and claims for damages to property, employees, other persons and the environment resulting from current or past operations may result in significant expenditures and liabilities in the future. The Company engages in a process of updating and revising its procedures for the ongoing evaluation of its operations to identify potential environmental exposures and enhance compliance with regulatory requirements.
Florida Gas conducts assessment, remediation, and ongoing monitoring of soil and groundwater impact which resulted from its past waste management practices at its Rio Paisano and Station 11 facilities. The liability is recognized in other current liabilities and in other deferred credits and in total amounted to $1.5 million and $1.6 million at December 31, 2009 and 2008, respectively. Amounts are not discounted because of uncertainty related to timing. Costs of $0.1 million, $0.1 million and $0.2 million were expensed during the years ended December 31, 2009, 2008 and 2007, respectively. Florida Gas recorded the estimated costs of remediation to be spent after April 1, 2010 of $1.1 million and $1.1 million at December 31, 2009 and 2008, respectively (See Note 11 - Regulatory Assets), as a regulatory asset based on the probability of recovery in rates in its next rate case.
Spill Prevention Control and Countermeasure Rules (SPCC). In October 2007, the United States Environmental Protection Agency (EPA) proposed amendments to the SPCC rules with the stated intention of providing greater clarity, tailoring requirements, and streamlining requirements. The most recent extension by the EPA sets the SPCC rule compliance date as November 10, 2010, permitting owners and operators of facilities to prepare or amend and implement SPCC Plans in accordance with previously enacted modifications to the regulations. The Company is currently reviewing the impact of the modified regulations on its operations and may incur costs for tank integrity testing, alarms and other associated corrective actions as well as potential upgrades to containment structures. Costs associated with such activities cannot be estimated with the certainty at this time, but the Company believes such costs will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.
Air Quality Control. In February 2009, EPA proposed a rule that requires reductions in a number of pollutants, including formaldehyde and carbon monoxide, for all engines regardless of size at Area Sources (sources that emit less than ten tons per year of any one Hazardous Air Pollutant (HAP) or twenty-five tons per year of all HAPs) and engines less than 500 horsepower at Major Sources (sources that emit ten tons per year or more of any one HAP or twenty-five tons per year of all HAPs). The rule is scheduled to be finalized in August 2010 with compliance required in 2013. It is anticipated that the limits adopted in this rule will be used in a future EPA rule that is scheduled to be finalized in 2013, with compliance required in 2016. This future rule is expected to require reductions in formaldehyde and carbon monoxide emissions from engines greater than 500 horsepower at Major Sources.
Nitrogen oxides are the primary air pollutant from natural gas-fired engines. Nitrogen oxide emissions may form ozone in the atmosphere. EPA lowered the ozone standard to seventy-five parts per billion (ppb) in 2008 with compliance anticipated in 2013 to 2015. In January 2010, EPA proposed lowering the standard to sixty to seventy ppb in lieu of the seventy-five ppb standard, with compliance required in 2014 or later.
In January 2010, EPA finalized a 100 ppb one-hour nitrogen dioxide standard. Based on the current nitrogen dioxide monitoring network, only one county in the United States fails to meet the new standard. The rule requires the installation of new nitrogen dioxide monitors in urban communities and roadways by 2013. This new network may result in additional nitrogen dioxide non-attainment areas. Facility specific impacts may occur prior to the installation of the new monitors if ambient air quality modeling is required to demonstrate compliance with the new standard.
CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Company is currently reviewing the potential impact of the proposed rules regarding HAPs and ozone on operations and the potential costs associated with the installation of emission control systems on its existing engines. Cost associated with these activities cannot be estimated with any certainty at this time, but the Company believes such costs will not have a material adverse effect on its consolidated financial position, results of operations or cash flow.
Florida Gas Pipeline Relocation Costs. The Florida Department of Transportation, Florida’s Turnpike Enterprise (FDOT/FTE) has various turnpike/State Road 91 widening projects that have impacted or may, over time, impact one or more of Florida Gas’ mainline pipelines located in FDOT/FTE rights-of-way. A dispute exists with the FDOT/FTE over the rights of Florida Gas under certain easements and other agreements associated with the State Road 91 projects to, among other matters, receive reimbursement for the relocation costs incurred by Florida Gas and the nature and scope of such easements. The first phase of the State Road 91 projects included replacement of approximately 11.3 miles of existing 18- and 24-inch pipelines in Broward County, Florida due to the widening of State Road 91 by the FDOT/FTE. Construction is complete and the new facilities were placed in service in March 2008. The FDOT/FTE plans additional projects that may affect Florida Gas’ pipelines within FDOT/FTE rights-of-way. The total miles of pipe that may ultimately be affected by all of the FDOT/FTE widening projects, and any associated relocation and/or rights-of-way costs, cannot be determined at this time.
The various FDOT/FTE projects are the subject of state court litigation. In January 2007, Florida Gas filed a complaint against FDOT/FTE in the Seventeenth Judicial Circuit, Broward County, Florida, to seek relief for three specific sets of FDOT/FTE widening projects in Broward County. The case was subsequently transferred to the Broward County Complex Business Civil Division 07. The complaint seeks damages for the breach of easement and relocation agreements for the completed State Road 91 relocation project and injunctive relief as well as damages for the two other sets of projects upon which construction has yet to commence. The FDOT/FTE filed counterclaims against Florida Gas alleging, among other matters, that Florida Gas is subject to estoppel, claims for breach of contract, trespass, unjust enrichment, and fraud in the inducement regarding the removal from service of the existing 18- and 24-inch pipelines. Further, the FDOT/FTE is seeking to place a constructive trust over any revenues associated with the previously existing and newly constructed pipelines and to obtain a declaratory judgment that Florida Gas is responsible for all relocation costs and is not entitled to workspace and uniform minimum area with respect to its pipelines. The Court has allowed the FDOT/FTE to include counts of fraud and trespass in its counterclaim but has disallowed a demand for punitive damages on those counts. A supplemental motion for temporary injunction and a motion for partial summary judgment is pending against Florida Gas on the extent of the rights Florida Gas claims under the easements at issue, the breach of the easements by the FDOT/FTE for failing to provide adequate rights-of-way, the failure of the FDOT/FTE to reimburse Florida Gas for the costs of relocation, and inverse condemnation as a result of the FDOT/FTE’s claim that Florida Gas breached the easements. In December 2009, both parties filed additional motions for summary judgment on numerous matters at issue in the case. The FDOT/FTE is claiming approximately $30 million in actual damages based on the most current information provided by the FDOT/FTE. The FDOT/FTE is seeking the Court’s permission to supplement these claims with as yet undetermined amounts associated with its claim for a constructive trust over revenues from the subject pipelines for the period April 2008 through January 2009. Florida Gas is seeking reimbursement of relocation costs in the amount of approximately $90 million. The trial is set for May 2010.
A 2007 action brought by the FDOT/FTE against Florida Gas in Orange County, Florida, seeking a declaratory judgment that, under existing agreements, Florida Gas is liable for the costs of relocation associated with FDOT/FTE projects, has been stayed pending resolution of the Broward County, Florida action.
Should Florida Gas be denied reimbursement by the FDOT/FTE for relocation expenses, such costs are expected to be covered by operating cash flows and additional borrowings. Florida Gas is seeking rate recovery at FERC for all reasonable and prudent costs incurred in the first phase of relocating its pipelines due to the FDOT/FTE projects as the issue of reimbursement is being litigated. Florida Gas will continue to seek such recovery for other phases to the extent not reimbursed by the FDOT/FTE. There can be no assurance that Florida Gas will be successful in obtaining complete reimbursement for any such relocation costs from the FDOT/FTE or from its customers or that the timing of such reimbursement will fully compensate Florida Gas for its costs.
See Note 3 - Regulatory Matters for other potential contingent matters applicable to the Company.