Item 1. Business
In this report, Transcontinental Gas Pipe Line Company, LLC (Transco) is at times referred to in the first person as “we,” “us” or “our.”
Since we meet the conditions set forth in General Instruction (I) (1) (a) and (b) of Form 10-K, the information in this Item 1 is in a reduced disclosure format.
On December 31, 2009, we were a wholly-owned subsidiary of Williams Gas Pipeline Company, LLC (WGP). WGP is a wholly-owned subsidiary of The Williams Companies, Inc. (Williams). On December 31, 2008, Transcontinental Gas Pipe Line Corporation was converted from a corporation to a limited liability company and thereafter is known as Transcontinental Gas Pipe Line Company, LLC. Effective December 31, 2008, we distributed all of our ownership interest in our wholly-owned subsidiaries to WGP and adjusted financial and operating information retrospectively to reflect this transaction.
Effective September 2009, WGP contributed its ownership interests in certain entities to us as follows: TransCardinal Company, LLC (TransCardinal) and Cardinal Operating Company, LLC (Cardinal Operating); TransCarolina LNG Company, LLC (TransCarolina) and Pine Needle Operating Company, LLC (Pine Needle Operating). Accordingly, we have adjusted financial and operating information retrospectively to reflect this transaction.
On February 17, 2010, Williams completed a strategic restructuring, pursuant to which Williams contributed substantially all of its domestic midstream and pipeline businesses, which includes us, into Williams Partners L.P. (WPZ). WPZ is a master limited partnership with publicly traded units. It is controlled by and consolidated with Williams. Effective February 17, 2010, we are a wholly-owned subsidiary of WPZ, approximately 82 percent of whose limited partnership interests and all of its 2 percent general partnership interest as of such date are owned by Williams.
GENERAL
We are an interstate natural gas transmission company that owns a natural gas pipeline system extending from Texas, Louisiana, Mississippi and the Gulf of Mexico through Alabama, Georgia, South Carolina, North Carolina, Virginia, Maryland, Pennsylvania and New Jersey to the New York City metropolitan area. We also hold a minority interest in Cardinal Pipeline Company, LLC (Cardinal) an intrastate natural gas pipeline located in North Carolina. Our principal business is the interstate transportation of natural gas, which the Federal Energy Regulatory Commission (FERC) regulates.
At December 31, 2009, our system had a mainline delivery capacity of approximately 4.7 MMdt of gas per day from production areas to our primary markets. Using our Leidy Line along with market-area storage and transportation capacity, we can deliver an additional 3.9 MMdt of gas per day for a system-wide delivery capacity total of approximately 8.6 MMdt of gas per day. The system is comprised of approximately 10,000 miles of mainline and branch transmission pipelines, 45 compressor stations, four underground storage fields and a liquefied natural gas (LNG) storage facility. Compression facilities at sea level rated capacity total approximately 1.5 million horsepower.
We have natural gas storage capacity in four underground storage fields located on or near our pipeline system and/or market areas and we operate two of these storage fields. We also have storage capacity in an LNG storage facility that we own and operate. The total usable gas storage capacity available to us and our customers in such underground storage fields and LNG storage facility and through storage service contracts is approximately 204 Bcf of gas. In addition, through wholly-owned subsidiaries we operate and own a 35 percent interest in Pine Needle LNG Company, LLC (Pine Needle) an LNG storage facility with 4 Bcf of storage capacity. Storage capacity permits our customers to inject gas into storage during the summer and off-peak periods for delivery during peak winter demand periods.
As discussed below, one of our affiliates, Williams Gas Marketing, Inc. (WGM) manages our jurisdictional merchant gas sales through an agency agreement. (See Part I, Item. Business-Sales Services.)
MARKETS AND TRANSPORTATION
Our natural gas pipeline system serves customers in Texas and 11 southeast and Atlantic seaboard states including major metropolitan areas in Georgia, North Carolina, Washington, D.C., New York, New Jersey and Pennsylvania.
Our major customers are public utilities and municipalities that provide service to residential, commercial, industrial and electric generation end users. Shippers on our pipeline system include public utilities, municipalities, intrastate pipelines, direct industrial users, electrical generators, gas marketers and producers. Our two largest customers in 2009 were National Grid (formerly known as KeySpan Corporation) and Public Service Enterprise Group, which accounted for approximately 10.4 percent and 9.6 percent, respectively, of our total operating revenues. Our firm transportation agreements are generally long-term agreements with various expiration dates and account for the major portion of our business. Additionally, we offer interruptible transportation services under shorter-term agreements.
Our total system deliveries for the years 2009, 2008 and 2007 are shown below.
Our facilities are divided into eight rate zones. Five are located in the production area and three are located in the market area. Long-haul transportation is gas that is received in one of the production-area zones and delivered in a market-area zone. Market-area transportation is gas that is both received and delivered within market-area zones. Production-area transportation is gas that is both received and delivered within production-area zones.
PIPELINE PROJECTS
The pipeline projects listed below were either completed during 2009 or are significant future pipeline projects for which we have customer commitments.
Sentinel Expansion Project. The Sentinel Expansion Project is a recently completed expansion of our existing natural gas transmission system from the Leidy Hub in Clinton County, Pennsylvania and from the Pleasant Valley interconnection with Cove Point LNG in Fairfax County, Virginia to various delivery points requested by the shippers under the project. The capital cost of the project is estimated to be up to approximately $229 million. Phase 1 was placed into service in December 2008. Phase II was placed into service in November 2009.
Eminence Enhancement Project. The Eminence Enhancement Project is a recently completed project involving the installation of additional compression at our Eminence Storage Field in Covington County, Mississippi, which will give project customers enhanced storage injection rights. The capital cost of the project is estimated to be approximately $12 million. The project was placed into service on October 1, 2009.
Mobile Bay South Expansion Project. The Mobile Bay South Expansion Project involves the addition of compression at our Station 85 in Choctaw County, Alabama to allow us to provide firm transportation service southbound on the Mobile Bay line from Station 85 to various delivery points. In May 2009 we received approval from the FERC. The capital cost of the project is estimated to be approximately $37 million. We plan to place the project into service by May 2010.
Mobile Bay South II Expansion Project. The Mobile Bay South II Expansion Project involves the addition of compression at our Station 85 in Choctaw County, Alabama and modifications to existing facilities at our Station 83 in Mobile County, Alabama to allow us to provide additional firm transportation service southbound on the Mobile Bay line from Station 85 to various delivery points. In November 2009 we filed an application with the FERC. The capital cost of the project is estimated to be approximately $36 million. We plan to place the project into service by May 2011.
85 North Expansion Project. The 85 North Expansion Project involves an expansion of our existing natural gas transmission system from Station 85 in Choctaw County, Alabama to various delivery points as far north as North Carolina. In September 2009 we received approval from the FERC. The capital cost of the project is estimated to be approximately $241 million. We plan to place the project into service in phases, in July 2010 and May 2011.
Pascagoula Expansion Project. The Pascagoula Expansion Project involves the construction of a new pipeline to be jointly owned with Florida Gas Transmission connecting our existing Mobile Bay Lateral to the outlet pipeline of a proposed LNG import terminal in Mississippi. In August 2009 we filed an application with the FERC. Our share of the capital cost of the project is estimated to be up to approximately $34 million. We plan to place the project into service in September 2011.
Mid-South Expansion Project. The Mid-South Expansion Project involves an expansion of our mainline from Station 85 in Choctaw County, Alabama to markets as far downstream as North Carolina. We anticipate filing an application with the FERC in the fourth quarter of 2010. The capital cost of the project is estimated to be approximately $200 million. We plan to place the project into service in September 2012.
Mid-Atlantic Connector Project. The Mid-Atlantic Connector Project involves an expansion of our mainline from an existing interconnection with East Tennessee Natural Gas in North Carolina to markets as far downstream as Maryland. We anticipate filing an application with the FERC in the first quarter of 2011. The capital cost of the project is estimated to be approximately $55 million. We plan to place the project into service in November 2012.
Rockaway Delivery Lateral Project. The Rockaway Delivery Lateral Project involves the construction of a three-mile offshore lateral to National Grid’s distribution system in New York. We anticipate filing an application with the FERC in the third quarter of 2010. The capital cost of the project is estimated to be approximately $120 million. We plan to place the project into service in November 2013.
Northeast Connector Project. The Northeast Connector Project involves an expansion of our existing natural gas transmission system from southeastern Pennsylvania to the proposed Rockaway Delivery Lateral. The capital cost of the project is estimated to be approximately $37 million. We plan to place the project into service in November 2013.
REGULATORY MATTERS
Our transportation rates are established through the FERC ratemaking process. Key determinants in the ratemaking process are (1) costs of providing service, including depreciation expense, (2) allowed rate of return, including the equity component of the capital structure and related income taxes, and (3) volume throughput assumptions. The allowed rate of return is determined in each rate case. Rate design and the allocation of costs between the demand and commodity rates also impact profitability. As a result of these proceedings, certain revenues may be collected subject to refund. We record estimates of rate refund liabilities considering our and third-party regulatory proceedings, advice of counsel and other risks.
Since September 1, 1992, we have designed our rates using the straight fixed-variable (SFV) method of rate design. Under the SFV method of rate design, substantially all fixed costs, including return on equity and income taxes, are included in a demand charge to customers and all variable costs are recovered through a commodity charge to customers. While the use of SFV rate design limits our opportunity to earn incremental revenues through increased throughput, it also limits our risk associated with fluctuations in throughput.
On March 1, 2001, we submitted to the FERC a general rate filing (Docket No. RP01-245) designed to recover increased costs. All cost of service, throughput and throughput mix, cost allocation and rate design issues in this rate proceeding have been resolved by settlement or litigation. The resulting rates were effective from September 1, 2001 to March 1, 2007. A tariff matter in this proceeding has not yet been resolved.
On August 31, 2006, we submitted to the FERC a general rate filing (Docket No. RP06-569) designed to recover increased costs. The rates became effective March 1, 2007, subject to refund and the outcome of a hearing. All issues in this proceeding except one have been resolved by settlement.
The one issue reserved for litigation or further settlement relates to our proposal to change the design of the rates for service under one of our storage rate schedules, which was implemented subject
to refund on March 1, 2007. A hearing on that issue was held before a FERC Administrative Law Judge (ALJ) in July 2008. In November 2008, the ALJ issued an initial decision in which he determined that Transco’s proposed incremental rate design is unjust and unreasonable. On January 21, 2010, the FERC reversed the ALJ’s initial decision, and approved our proposed incremental rate design. Parties may seek rehearing of the FERC order.
SALES SERVICE
As discussed above, WGM manages our jurisdictional merchant gas sales, which are made to customers pursuant to a blanket sales certificate issued by the FERC. Through an agency agreement, WGM is authorized to make gas sales on our behalf in order to manage our gas purchase obligations. WGM receives all margins associated with jurisdictional merchant gas sales business and, as our agent, assumes all market and credit risk associated with our jurisdictional merchant gas sales. Consequently, our merchant gas sales service has no impact on our operating income or results of operations.
Our gas sales volumes managed by WGM for the years 2009, 2008 and 2007 in TBtus were 0.4, 0.3 and 2.0, respectively.
TRANSACTIONS WITH AFFILIATES
We engage in transactions with Williams and other Williams’ subsidiaries. (See Note 1 and Note 9 of Notes to Consolidated Financial Statements.)
REGULATION
Interstate gas pipeline operations Our interstate transmission and storage activities are subject to regulation by the FERC under the Natural Gas Act of 1938 (NGA) and under the Natural Gas Policy Act of 1978 (NGPA), and, as such, our rates and charges for the transportation of natural gas in interstate commerce, the extension, enlargement or abandonment of jurisdictional facilities, and accounting, among other things, are subject to regulation. We hold certificates of public convenience and necessity issued by the FERC authorizing ownership and operation of pipelines, facilities and properties under the NGA. We are also subject to the Natural Gas Pipeline Safety Act of 1968, as amended by Title I of the Pipeline Safety Act of 1979, and the Pipeline Safety Improvement Act of 2002 which regulate safety requirements in the design, construction, operation and maintenance of interstate gas transmission facilities. The FERC’s Standards of Conduct govern the relationship between natural gas transmission providers and marketing function employees as defined by the rule. The standards of conduct are intended to prevent natural gas transmission providers from preferentially benefiting gas marketing functions by requiring the employees of a transmission provider that perform transmission functions to function independently from gas marketing employees and by restricting the information that transmission providers may provide to gas marketing employees. Under the Energy Policy Act of 2005, the FERC is authorized to impose civil penalties of up to $1 million per day for each violation of its rules.
Environmental We are subject to the National Environmental Policy Act and federal, state and local laws and regulations relating to environmental quality control. Management believes that, capital expenditures and operation and maintenance expenses required to meet applicable environmental standards and regulations are generally recoverable in rates. For these reasons, management believes
that compliance with applicable environmental requirements is not likely to have a material effect upon our competitive position or earnings. (See Note 3 of Notes to Consolidated Financial Statements.)
Pipeline Integrity Regulations We have developed an Integrity Management Plan that meets the United States Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA) final rule pursuant to the requirements of the Pipeline Safety Improvement Act of 2002. In meeting the integrity regulations, we have identified high consequence areas and completed our baseline assessment plan. We are on schedule to complete the required assessments within specified timeframes. Currently, we estimate that the cost to perform required assessments and remediation will be between $150 million and $220 million over the remaining assessment period of 2010 through 2012, the majority of which are capital expenditures. Management considers the costs associated with compliance with the rule to be prudent costs incurred in the ordinary course of business and, therefore, recoverable through our rates.
COMPETITION
The natural gas industry has undergone significant change over the past two decades. A highly-liquid competitive commodity market in natural gas and increasingly competitive markets for natural gas services, including competitive secondary markets in pipeline capacity, have developed. As a result, pipeline capacity is being used more efficiently, and peaking and storage services are increasingly effective substitutes for annual pipeline capacity.
Local distribution company (LDC) and electric industry restructuring by states have affected pipeline markets. Although pipeline operators are increasingly challenged to accommodate the flexibility demanded by customers and allowed under tariffs, the changes implemented at the state level have not required renegotiation of` LDC contracts. The state plans have in some cases discouraged LDCs from signing long-term contracts for new capacity.
States are in the process of developing new energy plans that will encourage utilities to develop energy saving measures and diversify their energy supplies to include renewable sources. This could lower the growth of gas demand. Resistance to coal-fired electricity generation could increase it.
These factors have increased the risk that customers will reduce their contractual commitments for pipeline capacity. Future utilization of pipeline capacity will depend on competition from LNG imported into markets, as well as the growth of natural gas demand.
EMPLOYEES
At January 31, 2010 we had 1,335 full time employees. As a result of Williams’ restructuring of its business units, all of our former employees were transferred to another Williams affiliate effective as of February 16, 2010. All of Transco’s functions previously performed by our employees will be provided by the Williams affiliate through a new service agreement executed pursuant to the restructuring. (See Note 9 of Notes to Consolidated Financial Statements.)
Item 1A.
Item 1A. Risk Factors
FORWARD LOOKING STATEMENTS/RISK FACTORS AND CAUTIONARY
STATEMENT FOR PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF
THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
Certain matters contained in this report include “forward-looking statements” within the meaning of section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. These forward-looking statements relate to anticipated financial performance, management’s plans and objectives for future operations, business prospects, outcome of regulatory proceedings, market conditions and other matters. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995.
All statements, other than statements of historical facts, included in this report that address activities, events or developments that we expect, believe or anticipate will exist or may occur in the future, are forward-looking statements. Forward-looking statements can be identified by various forms of words such as “anticipates,” “believes,” “seeks,” “could,” “may,” “should,” “continues,” “estimates,” “expects,” “forecasts,” “intends,” “might,” “goals,” “objectives,” “planned,” “potential,” “projects,” “scheduled,” “will,” or other similar expressions. These forward-looking statements are based on management’s beliefs and assumptions and on information currently available to management and include, among others, statements regarding:
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Amounts and nature of future capital expenditures;
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Expansion and growth of our business and operations;
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Financial condition and liquidity;
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Business strategy;
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Cash flow from operations or results of operations;
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Rate case filings; and
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Natural gas prices and demand.
Forward-looking statements are based on numerous assumptions, uncertainties and risks that could cause future events or results to be materially different from those stated or implied in this report. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors which could cause actual results to differ from results contemplated by the forward-looking statements include, among others, the following:
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Availability of supplies (including the uncertainties inherent in assessing and estimating future natural gas reserves), market demand, volatility of prices, and the availability and cost of capital;
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Inflation, interest rates and general economic conditions (including future disruptions and volatility in the global credit markets and the impact of these events on our customers and suppliers);
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The strength and financial resources of our competitors;
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Development of alternative energy sources;
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The impact of operational and development hazards;
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Costs of, changes in, or the results of laws, government regulations (including proposed climate change legislation), environmental liabilities, litigation, and rate proceedings;
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Our costs for defined benefit pension plans and other postretirement benefit plans;
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Changes in maintenance and construction costs;
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Changes in the current geopolitical situation;
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Our exposure to the credit risk of our customers;
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Risks related to strategy and financing, including restrictions stemming from our debt agreements, future changes in our credit rating and the availability and cost of credit;
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Risks associated with future weather conditions;
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Acts of terrorism; and
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Additional risks described in our filings with the Securities and Exchange Commission (SEC).
Given the uncertainties and risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement, we caution investors not to unduly rely on our forward-looking statements. We disclaim any obligations to and do not intend to update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments.
In addition to causing our actual results to differ, the factors listed above and referred to below may cause our intentions to change from those statements of intention set forth in this report. Such changes in our intentions may also cause our results to differ. We may change our intentions, at any time and without notice, based upon changes in such factors, our assumptions or otherwise.
Because forward-looking statements involve risks and uncertainties, we caution that there are important factors, in addition to those listed above, that may cause actual results to differ materially from those contained in the forward-looking statements. These factors are described in the following section.
RISK FACTORS
You should carefully consider the following risk factors in addition to the other information in this report. Each of these factors could adversely affect our business, operating results, and financial condition as well as adversely affect the value of an investment in our securities.
Risks Inherent to our Industry and Business
Our natural gas transportation, storage and gathering activities involve numerous risks that might result in accidents and other operating risks and hazards.
Our operations are subject to all the risks and hazards typically associated with the transportation and storage of natural gas. These operating risks include, but are not limited to:
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fires, blowouts, cratering and explosions;
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uncontrolled releases of natural gas;
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pollution and other environmental risks;
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natural disasters;
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aging pipeline infrastructure and mechanical problems;
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damages to pipelines and pipeline blockages;
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operator error;
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damage inadvertently caused by third party activity, such as operation of construction equipment; and
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terrorist attacks or threatened attacks on our facilities or those of other energy companies.
These risks could result in loss of human life, personal injuries, significant damage to property, environmental pollution, impairment of our operations and substantial losses to us. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses, and only at levels we believe to be appropriate. The location of certain segments of our pipeline in or near populated areas, including residential areas, commercial business centers and industrial sites, could increase the level of damages resulting from these risks. In spite of any precautions taken, an event such as those described above could cause considerable harm to people or property and could have a material adverse effect on our financial condition and results of operations, particularly if the event is not fully covered by insurance. Accidents or other operating risks could further result in loss of service available to our customers. Such circumstances, including those arising from maintenance and repair activities, could result in service interruptions on segments of our pipeline infrastructure. Potential customer impacts arising from service interruptions on segments of our pipeline infrastructure could include limitations on the pipeline’s ability to satisfy customer requirements, obligations to provide reservation charge credits to customers in times of constrained capacity, and solicitation of existing customers by
others for potential new pipeline projects that would compete directly with existing services. Such circumstances could adversely impact our ability to meet contractual obligations and retain customers, with a resulting negative impact on our business, financial condition, results of operations and cash flows.
Increased competition from alternative natural gas transportation and storage options and alternative fuel sources could have a significant financial impact on us.
We compete primarily with other interstate pipelines and storage facilities in the transportation and storage of natural gas. Some of our competitors may have greater financial resources and access to greater supplies of natural gas than we do. Some of these competitors may expand or construct transportation and storage systems that would create additional competition for natural gas supplies or the services we provide to our customers. Moreover, WPZ and its other affiliates, including Williams may not be limited in their ability to compete with us. Further, natural gas also competes with other forms of energy available to our customers, including electricity, coal, fuel oils and other alternative energy sources.
The principal elements of competition among natural gas transportation and storage assets are rates, terms of service, access to natural gas supplies, flexibility and reliability. FERC’s policies promoting competition in natural gas markets could have the effect of increasing the natural gas transportation and storage options for our traditional customer base. As a result, we could experience some “turnback” of firm capacity as the primary terms of existing agreements expire. If we are unable to remarket this capacity or can remarket it only at substantially discounted rates compared to previous contracts, we or our remaining customers may have to bear the costs associated with the turned back capacity. Increased competition could reduce the amount of transportation or storage capacity contracted on our system or, in cases where we do not have long-term fixed rate contracts, could force us to lower our transportation or storage rates. Competition could intensify the negative impact of factors that significantly decrease demand for natural gas or increase the price of natural gas in the markets served by our pipeline system, such as competing or alternative forms of energy, a regional or national recession or other adverse economic conditions, weather, higher fuel costs and taxes or other governmental or regulatory actions that directly or indirectly increase the price of natural gas or limit the use of, or increase the demand for, natural gas. Our ability to renew or replace existing contracts at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of our competitors. Please read “Part I. Item 1. Business--Competition”. All of these competitive pressures could have a material adverse effect on our business, financial condition, results of operations and cash flows.
We may not be able to maintain or replace expiring natural gas transportation and storage contracts at favorable rates or on a long-term basis.
Our primary exposure to market risk occurs at the time the terms of existing transportation and storage contracts expire and are subject to termination. Although none of our material contracts are terminable in 2010, upon expiration of the terms we may not be able to extend contracts with existing customers or obtain replacement contracts at favorable rates or on a long-term basis.
The extension or replacement of existing contracts depends on a number of factors beyond our control, including:
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the level of existing and new competition to deliver natural gas to our markets;
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the growth in demand for natural gas in our markets;
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whether the market will continue to support long-term firm contracts;
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whether our business strategy continues to be successful;
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the level of competition for natural gas supplies in the production basins serving us; and
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the effects of state regulation on customer contracting practices.
Any failure to extend or replace a significant portion of our existing contracts may have a material adverse effect on our business, financial condition, results of operations and cash flows.
Competitive pressures could lead to decreases in the volume of natural gas contracted or transported through our pipeline system.
Although most of our pipeline system’s current capacity is fully contracted, the FERC has taken certain actions to strengthen market forces in the natural gas pipeline industry that have led to increased competition throughout the industry. In a number of key markets, interstate pipelines are now facing competitive pressure from other major pipeline systems, enabling local distribution companies and end users to choose a transmission provider based on considerations other than location. Other entities could construct new pipelines or expand existing pipelines that could potentially serve the same markets as our pipeline system. Any such new pipelines could offer transportation services that are more desirable to shippers because of locations, facilities, or other factors. These new pipelines could charge rates or provide service to locations that would result in greater net profit for shippers and producers and thereby force us to lower the rates charged for service on our pipeline in order to extend our existing transportation service agreements or to attract new customers. We are aware of proposals by competitors to expand pipeline capacity in certain markets we also serve which, if the proposed projects proceed, could increase the competitive pressure upon us. There can be no assurance that we will be able to compete successfully against current and future competitors and any failure to do so could have a material adverse effect on our business and results of operations.
Any significant decrease in supplies of natural gas in our areas of operation could adversely affect our business and operating results.
Our business is dependent on the continued availability of natural gas production and reserves. The development of the additional natural gas reserves requires significant capital expenditures by others for exploration and development drilling and the installation of production, gathering, storage, transportation and other facilities that permit natural gas to be produced and delivered to our pipeline system. Low prices for natural gas, regulatory limitations, including environmental regulations, or the lack of available capital for these projects could adversely affect the development and production of additional reserves, as well as gathering, storage, pipeline transmission and import and export of natural gas supplies, adversely impacting our ability to fill the capacities of our transmission and gathering facilities.
Production from existing wells and natural gas supply basins with access to our pipeline will
naturally decline over time. The amount of natural gas reserves underlying these wells may also be less than anticipated, and the rate at which production from these reserves declines may be greater than anticipated. Additionally, the competition for natural gas supplies to serve other markets could reduce the amount of natural gas supply for our customers. Accordingly, to maintain or increase the contracted capacity or the volume of natural gas transported, or throughput, on our pipeline and cash flows associated with the transportation of natural gas, our customers must compete with others to obtain adequate supplies of natural gas.
If new supplies of natural gas are not obtained to replace the natural decline in volumes from existing supply area, or if natural gas supplies are diverted to serve other markets, or if environmental regulators restrict new natural gas drilling, the overall volume of natural gas transported and stored on our system would decline, which could have a material adverse effect on our business, financial condition and results of operations.
Decreases in demand for natural gas could adversely affect our business.
Demand for our transportation services depends on the ability and willingness of shippers with access to our facilities to satisfy their demand by deliveries through our system. Any decrease in this demand could adversely affect our business. Demand for natural gas is also affected by weather, future industrial and economic conditions, fuel conservation measures, alternative fuel requirements, governmental regulation, or technological advances in fuel economy and energy generation devices, all of which are matters beyond our control. Additionally, in some cases, new LNG import facilities built near our markets could result in less demand for our gathering and transmission facilities.
Significant prolonged changes in natural gas prices could affect supply and demand and cause a termination of our transportation and storage contracts or a reduction in throughput on our system.
Higher natural gas prices over the long term could result in a decline in the demand for natural gas and, therefore, in our long-term transportation and storage contracts or throughput on our system. Also, lower natural gas prices over the long term could result in a decline in the production of natural gas resulting in reduced contracts or throughput on our system. As a result, significant prolonged changes in natural gas prices could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Some portions of our current pipeline infrastructure and other assets have been in use for many decades, which may adversely affect our business.
Some portions of our assets, including our pipeline infrastructure, have been in use for many decades. The current age and condition of our assets could result in a material adverse impact on our business, financial condition and results of operations if the costs of maintaining our facilities exceed current expectations.
We are subject to risks associated with climate change.
There is a growing belief that emissions of greenhouse gases may be linked to climate change. Climate change and the costs that may be associated with its impacts and the regulation of greenhouse gases have the potential to affect our business in many ways, including negatively impacting the costs
we incur in providing our products and services, the demand for and consumption of our products and services (due to change in both costs and weather patterns), and the economic health of the regions in which we operate, all of which can create financial risks.
Our operations are subject to governmental laws and regulations relating to the protection of the environment, including those relating to climate change, which could expose us to significant costs and liabilities and could exceed our current expectations.
The risk of substantial environmental costs and liabilities is inherent in natural gas transportation and storage operations, and we may incur substantial environmental costs and liabilities in the performance of these types of operations. Our operations are subject to extensive federal, state and local environmental laws and regulations governing environmental protection, the discharge of materials into the environment and the security of chemical and industrial facilities. These laws include:
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the Clean Air Act (CAA) and analogous state laws, which impose obligations related to air emissions;
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the Clean Water Act (CWA) and analogous state laws, which regulate discharge of wastewaters from our facilities to state and federal waters;
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the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), and analogous state laws that regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or locations to which we have sent wastes for disposal; and
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the Resource Conservation and Recovery Act (RCRA), and analogous state laws that impose requirements for the handling and discharge of solid and hazardous waste from our facilities.
These laws and regulations may impose numerous obligations that are applicable to our operations including the acquisition of permits to conduct regulated activities, the incurrence of capital expenditures to limit or prevent releases of materials from our pipeline and facilities, and the imposition of substantial costs and penalties for spills, releases and emissions of various regulated substances into the environment resulting from those operations. Various governmental authorities, including the U.S. Environmental Protection Agency and analogous state agencies, and the United States Department of Homeland Security have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly actions. Failure to comply with these laws, regulations, and permits may result in the assessment of administrative, civil, and criminal penalties, the imposition of remedial obligations, the imposition of stricter conditions on or revocation of permits, and the issuance of injunctions limiting or preventing some or all of our operations.
There is inherent risk of incurring significant environmental costs and liabilities in our business, some of which may be material, due to our handling of petroleum hydrocarbons and wastes, the occurrence of air emissions and water discharges related to our operations, historical industry operations, and waste disposal practices. Joint and several, strict liability may be incurred without regard to fault under certain environmental laws and regulations, including CERCLA, RCRA and analogous state laws, and in connection with spills or releases of natural gas and wastes on, under, or from our properties and facilities. Private parties, including the owners of properties through which our
pipeline passes and facilities where our wastes are taken for reclamation or disposal, may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage arising from our operations. In addition, increasingly strict laws, regulations and enforcement policies could materially increase our compliance costs and the cost of any remediation that may become necessary. Our insurance may not cover all environmental risks and costs or may not provide sufficient coverage if an environmental claim is made against us.
Our business may be adversely affected by increased costs due to stricter pollution control requirements or liabilities resulting from non-compliance with required operating or other regulatory permits. Also, we might not be able to obtain or maintain from time to time all required environmental regulatory approvals for our operations. If there is a delay in obtaining any required environmental regulatory approvals, or if we fail to obtain and comply with them, the operation of our facilities could be prevented or become subject to additional costs, resulting in potentially material adverse consequences to our business, financial condition, results of operations and cash flows.
We make assumptions and develop expectations about possible expenditures related to environmental conditions based on current laws and regulations and current interpretations of those laws and regulations. If the interpretation of laws or regulations, or the laws and regulations themselves, change, our assumptions may change, and any new capital costs incurred to comply with such changes may not be recoverable under our regulatory rate structure or our customer contracts. In addition, new environmental laws and regulations might adversely affect our activities, including storage and transportation, as well as waste management and air emissions. For instance, federal and state agencies could impose additional safety requirements, any of which could have a material adverse effect on our business, financial condition, results of operations and cash flows
We may be subject to legislative and regulatory responses to climate change with which compliance may be costly.
Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases,” (GHGs) may be contributing to warming of the earth’s atmosphere, and various governmental bodies have considered legislative and regulatory responses in this area. Legislative and regulatory responses related to GHGs and climate change create the potential for financial risk. The United States Congress and certain states have for some time been considering various forms of legislation related to GHG emissions. There have also been international efforts seeking legally binding reductions in emissions of GHGs. In addition, increased public awareness and concern may result in more state, federal, and international proposals to reduce or mitigate the emission of GHGs.
Several bills have been introduced in the United States Congress that would compel GHG emission reductions. On June 26, 2009, the U.S. House of Representatives passed the “American Clean Energy and Security Act” which is intended to decrease annual GHG emissions through a variety of measures, including a “cap and trade” system which limits the amount of GHGs that may be emitted and incentives to reduce the nation’s dependence on traditional energy sources. The U.S. Senate is currently considering similar legislation, and numerous states have also announced or adopted programs to stabilize and reduce GHGs. In addition, on December 7, 2009, the EPA issued a final determination that six GHGs are a threat to public safety and welfare. This determination could ultimately lead to the direct regulation of GHG emissions in our industry under the CAA. While it is not clear whether or when any federal or state climate change law will be passed, any of these actions could result in
increased costs to (i) operate and maintain our facilities, (ii) install new emission controls on our facilities, and (iii) administer and manage any GHG emissions program. If we are unable to recover or pass through a significant level of our costs related to complying with climate change regulatory requirements imposed on us, it could have a material adverse effect on our results of operations. To the extent financial markets view climate change and GHG emissions as a financial risk, this could negatively impact our cost of and access to capital.
The failure of new sources of natural gas production or LNG import terminals to be successfully developed in North America could increase natural gas prices and reduce the demand for our services.
New sources of natural gas production in the United States and Canada, particularly in areas of shale development are expected to become an increasingly significant component of future U.S. natural gas supply in North America. Additionally, increases in LNG supplies are expected to be imported through new LNG import terminals, particularly in the Gulf Coast region. If these additional sources of supply are not developed, natural gas prices could increase and cause consumers of natural gas to turn to alternative energy sources, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Certain of our services are subject to long-term, fixed-price contracts that are not subject to adjustment, even if our cost to perform such services exceeds the revenues received from such contracts.
We provide some services pursuant to long-term, fixed price contracts. It is possible that costs to perform services under such contracts will exceed the revenues we collect for our services. Although most of the services are priced at cost-based rates that are subject to adjustment in rate cases, under FERC policy, a regulated service provider and a customer may mutually agree to sign a contract for service at a “negotiated rate” that may be above or below the FERC regulated cost-based rate for that service. These “negotiated rate” contracts are not generally subject to adjustment for increased costs that could be produced by inflation or other factors relating to the specific facilities being used to perform the services.
We depend on certain key customers for a significant portion of our revenues. The loss of any of these key customers or the loss of any contracted volumes could result in a decline in our business.
We rely on a limited number of customers for a significant portion of our revenues. Our largest customers, National Grid (formerly known as KeySpan Corporation) and Public Service Enterprise Group accounted for approximately 10.4 percent and 9.6 percent, respectively, of our operating revenues for the year ended December 31, 2009. The loss of even a portion of our contracted volumes as a result of competition, creditworthiness, inability to negotiate extensions or replacements of contracts or otherwise, could have a material adverse effect on our business, financial condition, results of operations and cash flows, unless we are able to acquire comparable volumes from other sources.
We are exposed to the credit risk of our customers and our credit risk management may not be adequate to protect against such risk.
We are subject to the risk of loss resulting from nonpayment and/or nonperformance by our customers in the ordinary course of business. Generally our customers are rated investment grade, are
otherwise considered creditworthy or are required to make pre-payments or provide security to satisfy credit concerns. However, our credit procedures and policies may not be adequate to fully eliminate customer credit risk. We cannot predict to what extent our business would be impacted by deteriorating conditions in the economy, including declines in our customers’ creditworthiness. If we fail to adequately assess the creditworthiness of existing or future customers, unanticipated deterioration in their creditworthiness and any resulting increase in nonpayment and/or nonperformance by them could cause us to write down or write off doubtful accounts. Such write-downs or write-offs could negatively affect our operating results for the period in which they occur, and, if significant, could have a material adverse effect on our business, results of operations, cash flows and financial condition.
If third-party pipelines and other facilities interconnected to our pipeline and facilities become unavailable to transport natural gas, our revenues could be adversely affected.
We depend upon third-party pipelines and other facilities that provide delivery options to and from our pipeline and storage facilities. Because we do not own these third-party pipelines or facilities, their continuing operation is not within our control. If these pipelines or facilities were to become temporarily or permanently unavailable for any reason, or if throughput were reduced because of testing, line repair, damage to pipelines or facilities, reduced operating pressures, lack of capacity, increased credit requirements or rates charged by such pipelines or facilities or other causes, we and our customers would have reduced capacity to transport, store or deliver natural gas or NGL products to end use markets or to receive deliveries of mixed NGLs, thereby reducing our revenues. Further, although there are laws and regulations designed to encourage competition in wholesale market transactions, some companies may fail to provide fair and equal access to their transportation systems or may not provide sufficient transportation capacity for other market participants. Any temporary or permanent interruption at any key pipeline interconnect causing a material reduction in volumes transported on our pipeline or stored at our facilities could have a material adverse effect on our business, financial condition, results of operations and cash flows.
We do not own all of the land on which our pipeline and facilities are located, which could disrupt our operations.
We do not own all of the land on which our pipeline and facilities have been constructed. As such, we are subject to the possibility of increased costs to retain necessary land use. We obtain, in certain instances, the rights to construct and operate our pipeline on land owned by third parties and governmental agencies for a specific period of time. Our loss of any of these rights, through our inability to renew right of way contracts or otherwise could have a material adverse effect on our business, financial condition, results of operations and cash flows.
We do not insure against all potential losses and could be seriously harmed by unexpected liabilities or by the inability of the insurers we do use to satisfy our claims.
We are not fully insured against all risks inherent to our business, including environmental accidents that might occur. In addition, we do not maintain business interruption insurance in the type and amount to cover all possible risks of loss. Williams currently maintains excess liability insurance with limits of $610 million per occurrence and in the aggregate annually and a deductible of $2 million per occurrence. This insurance covers Williams, its subsidiaries, and certain of its affiliates, including us, for legal and contractual liabilities arising out of bodily injury, personal injury or property damage, including resulting loss of use, to third parties. This excess liability insurance includes coverage for
sudden and accidental pollution liability for full limits, with the first $135 million of insurance also providing gradual pollution liability coverage for natural gas and natural gas liquids operations. Pollution liability coverage excludes: release of pollutants subsequent to their disposal; release of substances arising from the combustion of fuels that result in acidic deposition, and testing, monitoring, clean-up, containment, treatment or removal of pollutants from property owned, occupied by, rented to, used by or in the care, custody or control of Williams and its affiliates.
Williams does not insure onshore underground pipelines for physical damage, except at river crossings and at certain locations such as compressor stations. Williams maintains coverage of $300 million per occurrence for physical damage to onshore assets and resulting business interruption caused by terrorist acts committed by a U.S. person or interest. Also, all of Williams’ insurance is subject to deductibles. If a significant accident or event occurs for which we are not fully insured, it could adversely affect our operations and financial condition. We may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. Changes in the insurance markets subsequent to hurricane losses in recent years have impacted named windstorm insurance coverage, rates and availability of Gulf of Mexico area exposures , and we may elect to self insure a portion of our asset portfolio. We cannot assure you that we will in the future be able to obtain the levels or types of insurance we would otherwise have obtained prior to these market changes or that the insurance coverage we do obtain will not contain large deductibles or fail to cover certain hazards or cover all potential losses. The occurrence of any operating risks not fully covered by insurance could have a material adverse effect on our business, financial condition, results of operations and cash flows.
In addition, certain insurance companies that provide coverage to us, including American International Group, Inc., have experienced negative developments that could impair their ability to pay any of our potential claims. As a result, we could be exposed to greater losses than anticipated and replacement insurance may have to obtained , at a greater cost, if available.
Execution of our capital projects subjects us to construction risks, increases in labor costs and materials, and other risks that may adversely affect financial results.
A significant portion of our growth is accomplished through the construction of new transportation and storage facilities as well as the expansion of existing facilities. Construction of these facilities is subject to various regulatory, development and operational risks, including:
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the ability to obtain necessary approvals and permits by regulatory agencies on a timely basis and on acceptable terms;
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the availability of skilled labor, equipment, and materials to complete expansion projects;
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potential changes in federal, state and local statutes and regulations, including environmental requirements, that prevent a project from proceeding or increase the anticipated cost of the project;
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impediments on our ability to acquire rights-of-way or land rights on a timely basis and on acceptable terms;
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the ability to construct projects within estimated costs, including the risk of cost overruns resulting from inflation or increased costs of equipment, materials, labor or other factors beyond our control, that may be material; and
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the ability to access capital markets to fund construction projects.
Any of these risks could prevent a project from proceeding, delay its completion or increase its anticipated costs. As a result, new facilities may not achieve expected investment return, which could adversely affect results of operations, financial position or cash flows.
Potential changes in accounting standards might cause us to revise our financial results and disclosures in the future, which might change the way analysts measure our business or financial performance.
Regulators and legislators continue to take a renewed look at accounting practices, financial disclosures, companies’ relationships with their independent registered public accounting firms, and retirement plan practices. We cannot predict the ultimate impact of any future changes in accounting regulations or practices in general with respect to public companies or the energy industry or in our operations specifically. In addition, the Financial Accounting Standards Board (FASB), the SEC or the FERC could enact new accounting standards or FERC orders, as the case may be, that might impact how we are required to record revenues, expenses, assets, liabilities and equity.
Risks Related to Strategy and Financing
Our debt agreements and Williams’ and WPZ’s public indentures contain financial and operating restrictions that may limit our access to credit and affect our ability to operate our business. In addition, our ability to obtain credit in the future will be affected by Williams’ and WPZ’s credit ratings.
Our public indentures contain various covenants that, among other things, limit our ability to grant certain liens to support indebtedness, merge, or sell substantially all of our assets. In addition, our new credit facility entered into as part of Williams’ restructuring (New Credit Facility) contains certain financial covenants and restrictions on our ability and our subsidiaries’ ability to incur indebtedness, to consolidate or allow any material change in the nature of our business, enter into certain affiliate transactions, and make certain distributions during an event of default. These covenants could adversely affect our ability to finance our future operations or capital needs or engage in, expand or pursue our business activities and prevent us from engaging in certain transactions that might otherwise be considered beneficial to us. Our ability to comply with these covenants may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, our current assumptions about future economic conditions turn out to be incorrect or unexpected events occur, our ability to comply with these covenants may be significantly impaired.
Williams’ and WPZ’s public indentures contain covenants that restrict their and our ability to incur liens to support indebtedness. These covenants could adversely affect our ability to finance our future operations or capital needs or engage in, expand or pursue our business activities and prevent us from engaging in certain transactions that might otherwise be considered beneficial to us.
Williams’ and WPZ’s ability to comply with the covenants contained in their respective debt instruments may be affected by events beyond our and their control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, Williams’ or WPZ’s ability to comply with these covenants may be negatively impacted.
Our failure to comply with the covenants in our debt agreements could result in events of default. Upon the occurrence of such an event of default, the lenders could elect to declare all amounts outstanding under a particular facility to be immediately due and payable and terminate all commitments, if any, to extend further credit. Certain payment defaults or an acceleration under our public indentures or other material indebtedness could cause a cross-default or cross-acceleration of our New Credit Facility. Such a cross-default or cross-acceleration could have a wider impact on our liquidity than might otherwise arise from a default or acceleration of a single debt instrument. If an event of default occurs, or if our New Credit Facility cross-defaults, and the lenders under the affected debt agreements accelerate the maturity of any loans or other debt outstanding to us, we may not have sufficient liquidity to repay amounts outstanding under such debt agreements. For more information regarding our debt agreements, please read “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations- Capital Resources and Liquidity”.
Substantially all of Williams’ and WPZ’s operations are conducted through their respective subsidiaries. Williams’ and WPZ’s cash flows are substantially derived from loans, dividends and distributions paid to them by their respective subsidiaries. Williams’ and WPZ’s cash flows are typically utilized to service debt and pay dividends or distributions on their equity, with the balance, if any, reinvested in their respective subsidiaries as loans or contributions to capital. Due to our relationship with Williams and WPZ, our ability to obtain credit will be affected by Williams’ and WPZ’s credit ratings. If Williams or WPZ were to experience deterioration in their respective credit standing or financial condition, our access to credit and our ratings could be adversely affected. Any future downgrading of a Williams’ or WPZ’s credit rating would likely also result in a downgrading of our credit rating. A downgrading of a Williams’ or WPZ’s credit rating could limit our ability to obtain financing in the future upon favorable terms, if at all.
Future disruptions in the global credit markets may make debt markets less accessible, create a shortage in the availability of credit and lead to credit market volatility.
In 2008, global credit markets experienced a shortage in overall liquidity and a resulting disruption in the availability of credit. Future disruptions in the global financial marketplace, including the bankruptcy or restructuring of financial institutions, could make debt markets inaccessible and adversely affect the availability of credit already arranged and the availability and cost of credit in the future. We have availability under the New Credit Facility, but our ability to borrow under that facility could be impaired if one or more of our lenders fails to honor its contractual obligation to lend to us.
Adverse economic conditions, could adversely affect our results of operations.
A slowdown in the economy has the potential to negatively impact our business in many ways. Included among these potential negative impacts are reduced demand and lower prices for our products and services, increased difficulty in collecting amounts owed to us by our customers and a reduction in
our credit ratings (either due to tighter rating standards or the negative impacts described above), which could result in reducing our access to credit markets, raising the cost of such access or requiring us or Williams to provide additional collateral to third parties.
A downgrade of our credit ratings could impact our liquidity, access to capital, and our costs of doing business in certain ways and maintaining current credit ratings is under the control of independent third parties.
A downgrade of our credit rating might increase our cost of borrowing and could cause us to post collateral with third parties, thereby negatively impacting our available liquidity. Our ability to access capital markets could also be limited by a downgrade of our credit rating and other disruptions. Such disruptions could include:
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economic downturns;
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deteriorating capital market conditions generally;
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declining market prices for natural gas;
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terrorist attacks or threatened attacks on our facilities or those of other energy companies; and
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the overall health of the energy industry, including the bankruptcy or insolvency of other companies.
Credit rating agencies perform independent analysis when assigning credit ratings. The analysis includes a number of criteria including, but not limited to, business composition, market and operational risks, as well as various financial tests. Credit rating agencies continue to review the criteria for industry sectors and various debt ratings and may make changes to those criteria from time to time. We are currently rated investment grade by three of the major credit rating agencies. Credit ratings are not recommendations to buy, sell or hold investments in the rated entity. Ratings are subject to revision or withdrawal at any time by the ratings agencies and no assurance can be given that the credit rating agencies will continue to assign us investment grade ratings even if we meet or exceed their criteria for investment grade ratios.
Williams can exercise substantial control over our distribution policy and our business and operations and may do so in a manner that is adverse to our interests.
As of December 31, 2009, we were an indirect wholly-owned subsidiary of Williams. As of February 17, 2010, we are an indirect wholly-owned subsidiary of WPZ, approximately 82 percent of whose limited partnership interests and all of its 2 percent general partnership interest as of such date are owned by Williams. Our parent company is indirectly controlled by Williams. As a result, Williams exercises substantial control over our business and operations and makes determinations with respect to, among other things, the following:
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payment of distributions and repayment of advances;
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decisions on financings and our capital raising activities;
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mergers or other business combinations; and
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acquisition or disposition of assets.
Our management committee could decide to increase distributions or advances to our parent entities consistent with existing debt covenants which could adversely affect our liquidity.
Risks Related to Regulations that Affect our Industry
Our gas sales, natural gas transmission, and storage operations are subject to regulation by the FERC, which could have an adverse impact on our ability to establish transportation and storage rates that would allow us to recover the full cost of operating our pipeline, including a reasonable rate of return.
Our interstate gas sales, transportation, and storage operations are subject to the federal, state and local regulatory authorities. Specifically, our interstate pipeline transportation and storage services and related assets are subject to regulation by the FERC. The federal regulation extends to such matters as:
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transportation and sale for resale of natural gas in interstate commerce;
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rates, operating terms and conditions of service, including initiation and discontinuation of service;
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the types of services we may offer to our customers;
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certification and construction of new facilities;
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acquisition, extension, disposition or abandonment of facilities;
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accounts and records;
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depreciation and amortization policies;
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relationships with marketing functions within Williams involved in certain aspects of the natural gas business; and
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market manipulation in connection with interstate sales, purchases or transportation of natural gas.
Under the Natural Gas Act, FERC has authority to regulate interstate providers of natural gas pipeline transportation and storage services, and such providers may only charge rates that have been determined to be just and reasonable by FERC. In addition, FERC prohibits providers from unduly
preferring or unreasonably discriminating against any person with respect to pipeline rates or terms and conditions of service.
Regulatory actions in these areas can affect our business in many ways, including decreasing tariff rates and revenues, decreasing volumes in our pipelines, increasing our costs and otherwise altering the profitability of our business.
The FERC’s Standards of Conduct govern the relationship between natural gas transmission providers and their marketing function employees as defined by the rule. The standards of conduct are intended to prevent natural gas transmission providers from preferentially benefiting gas marketing functions by requiring the employees of a transmission provider that perform transmission functions to function independently from marketing function employees and by restricting the information that transmission providers may provide to gas marketing employees. The inefficiencies created by the restrictions on the sharing of employees and information may increase our costs, and the restrictions on the sharing of information may have an adverse impact on our senior management’s ability to effectively obtain important information about our business. Violators of the rules are subject to potentially substantial civil penalty assessments.
Unlike other pipelines that own facilities in the offshore Gulf of Mexico, we charge our transportation customers a separate fee to access our offshore facilities. The separate charge that we assess, which we refer to as an IT feeder charge, is charged only when the facilities are used, and typically is paid by producers or marketers. This means that we recover the costs included in the IT feeder charge only if our facilities are used, and because it is typically paid by producers and marketers it generally results in netback prices to producers that are slightly lower than the netbacks realized by producers transporting on other interstate pipelines. Longer term, this rate design disparity could result in producers bypassing our offshore facilities in favor of alternative transportation facilities. We have asked the FERC to allow us to eliminate the IT feeder charge and charge for transportation on our offshore facilities in the same manner as the other pipelines. Our requests have been denied.
The rates, terms and conditions for our interstate pipeline and storage services are set forth in our FERC approved tariff. Pursuant to the terms of our most recent rate settlement agreement, we must file a new rate case no later than August 31, 2012. Any successful complaint or protest against our rates could have an adverse impact on our revenues associated with providing transportation and storage services.
We could be subject to penalties and fines if we fail to comply with FERC regulations.
Our transportation and storage operations are regulated by FERC. Should we fail to comply with all applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines. Under the Energy Policy Act of 2005, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1,000,000 per day for each violation. Any material penalties or fines imposed by FERC could have a material adverse impact on our business, financial condition, results of operations and cash flows.
The outcome of future rate cases will determine the amount of income taxes we will be allowed to recover.
In May 2005, the FERC issued a statement of general policy permitting a pipeline to include in its cost-of-service computations an income tax allowance provided that an entity or individual has an actual or potential income tax liability on income from the pipeline’s public utility assets. The extent to which owners of pipelines have such actual or potential income tax liability will be reviewed by FERC on a case-by-case basis in rate cases where the amounts of the allowances will be established.
The outcome of certain FERC proceedings involving FERC policy statements is uncertain and could affect the level of return on equity that Transco may be able to achieve in any future rate proceeding.
In a 2007 proposed policy statement, FERC proposed to permit inclusion of publicly traded partnerships in the proxy group analysis relating to return on equity determinations in rate proceedings, provided that the analysis be limited to actual publicly traded partnership distributions capped at the level of the pipeline’s earnings. In 2008, FERC issued a final policy statement which rejected the concept of capping distributions in favor of an adjustment to the long-term growth rate used to calculate the equity cost of capital for publicly traded partnerships which are included in the proxy group. The effect of the application of FERC’s policy to our future rate proceedings is not certain, and we cannot ensure that such application would not adversely affect our ability to achieve a reasonable level of return on equity.
The outcome of future rate cases to set the rates we can charge customers on our pipeline might result in rates that lower our return on the capital that we have invested in our pipeline.
There is a risk that rates set by the FERC in our future rate cases will be inadequate to recover increases in operating costs or to sustain an adequate return on capital investments. There is also the risk that higher rates will cause our customers to look for alternative ways to transport their natural gas.
Legal and regulatory proceedings and investigations relating to the energy industry and capital markets have adversely affected our business and may continue to do so.
Public and regulatory scrutiny of the energy industry and of the capital markets has resulted in increased regulation being either proposed or implemented. Such scrutiny has also resulted in various inquiries, investigations and court proceedings in which we or our affiliates are named as defendants. Both the shippers on our pipeline and regulators have rights to challenge the rates we charge under certain circumstances. Any successful challenge could materially affect our results of operations.
Certain inquiries, investigations and court proceedings are ongoing. We might see adverse effects continue as a result of the uncertainty of these ongoing inquiries and proceedings, or additional inquiries and proceedings by federal or state regulatory agencies or private plaintiffs. In addition, we cannot predict the outcome of any of these inquiries or whether these inquiries will lead to additional legal proceedings against us, civil or criminal fines or penalties, or other regulatory action, including legislation, which might be materially adverse to the operation of our business and our revenues and net income or increase our operating costs in other ways. Current legal proceedings or other matters against us including environmental matters, suits, regulatory appeals and similar matters might result in adverse decisions against us. The result of such adverse decisions, either individually or in the aggregate, could
be material and may not be covered fully or at all by insurance.
Risks Related to Employees, Outsourcing of Non-Core Support Activities, and Technology
Institutional knowledge residing with current employees nearing retirement eligibility might not be adequately preserved.
In our business, institutional knowledge resides with employees who have many years of service. As these employees reach retirement age, we may not be able to replace them with employees of comparable knowledge and experience. In addition, we may not be able to retain or recruit other qualified individuals and our efforts at knowledge transfer could be inadequate. If knowledge transfer, recruiting and retention efforts are inadequate, access to significant amounts of internal historical knowledge and expertise could become unavailable to us.
Failure of or disruptions to our outsourcing relationships might negatively impact our ability to conduct our business.
Some studies indicate a high failure rate of outsourcing relationships. Although Williams has taken steps to build a cooperative and mutually beneficial relationship with its outsourcing providers and to closely monitor their performance, a deterioration in the timeliness or quality of the services performed by the outsourcing providers or a failure of all or part of these relationships could lead to loss of institutional knowledge and interruption of services necessary for us to be able to conduct our business. The expiration of such agreements or the transition of services between providers could lead to similar losses of institutional knowledge or disruptions.
Certain of our accounting, information technology, application development, and help desk services are currently provided by Williams’ outsourcing provider from service centers outside of the United States. The economic and political conditions in certain countries from which Williams’ outsourcing providers may provide services to us present similar risks of business operations located outside of the United States, including risks of interruption of business, war, expropriation, nationalization, renegotiation, trade sanctions or nullification of existing contracts and changes in law or tax policy, that are greater than in the United States.
Our allocation from Williams for costs for its defined benefit pension plans and other postretirement benefit plans are affected by factors beyond our and Williams’ control.
As a result of the restructuring, we have no employees; consequently, employees of Williams and its affiliates provide services to us. As a result, we are allocated a portion of Williams’ costs in defined benefit pension plans covering substantially all of Williams’ or its affiliates’ employees providing services to us, as well as a portion of the costs of other postretirement benefit plans covering certain eligible participants providing services to us. The timing and amount of our allocations under the defined benefit pension plans depend upon a number of factors Williams controls, including changes to pension plan benefits, as well as factors outside of Williams’ control, such as asset returns, interest rates and changes in pension laws. Changes to these and other factors that can significantly increase our allocations could have a significant adverse effect on our financial condition and results of operations.
Risks Related to Weather, Other Natural Phenomena and Business Disruption
Our assets and operations can be affected by weather and other natural phenomena.
Our assets and operations can be adversely affected by hurricanes, floods, earthquakes, tornadoes and other natural phenomena and weather conditions, including extreme temperatures, making it more difficult for us to realize the historic rates of return associated with these assets and operations. Insurance may be inadequate, and in some instances, we have been unable to obtain insurance on commercially reasonable terms or insurance may not be available. A significant disruption in operations or a significant liability for which we were not fully insured could have a material adverse effect on our business, results of operations and financial condition.
Our customers’ energy needs vary with weather conditions. To the extent weather conditions are affected by climate change or demand is impacted by regulations associated with climate change, customers’ energy use could increase or decrease depending on the duration and magnitude of the changes leading either to increased investment or decreased revenues.
Acts of terrorism could have a material adverse effect on our financial condition, results of operations and cash flows.
Our assets and the assets of our customers and others may be targets of terrorist activities that could disrupt our business or cause significant harm to our operations, such as full or partial disruption to our ability to transmit natural gas. Acts of terrorism as well as events occurring in response to or in connection with acts of terrorism could cause environmental repercussions that could result in a significant decrease in revenues or significant reconstruction or remediation costs, which could have a material adverse effect on our financial condition, results of operation and cash flows.
Item 1B.
Item 1B. Unresolved Staff Comments
None.
Item 2.
Item 2. Properties
Our gas pipeline facilities are generally owned in fee. However, a substantial portion of such facilities are constructed and maintained pursuant to rights-of-way, easements, permits, licenses or consents on and across real property owned by others. Compressor stations, with appurtenant facilities, are located in whole or in part either on lands owned or on sites held under leases or permits issued or approved by public authorities. The storage facilities are either owned or contracted for under long-term leases or easements.
Item 3.
Item 3. Legal Proceedings
The information called for by this item is provided in “Item 8. Financial Statements and Supplementary Data - Notes to Consolidated Financial Statements - Note 3. Contingent Liabilities and Commitments”.
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders
Since we meet the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K, this information is omitted.
PART II
Item 5.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
At December 31, 2009, we were an indirect wholly-owned subsidiary of Williams. As of February 17, 2010, we are an indirect wholly-owned subsidiary of WPZ, approximately 82 percent of whose limited partnerships interests as of such date are owned by Williams. Prior to our conversion to a limited liability company on December 31, 2008, we issued common stock which was not publicly traded. Upon conversion, we distributed our entire membership interest in Marsh Resources, LLC, Cardinal Operating, Pine Needle Operating, TransCardinal, and TransCarolina to WGP. We adjusted financial and operating information retrospectively to reflect this transaction.
Effective September 2009, WGP contributed its ownership interests in certain entities to us as follows: TransCardinal and Cardinal Operating, TransCarolina and Pine Needle Operating. Accordingly, we have adjusted financial and operating information retrospectively to reflect this transaction.
Our Management Committee authorized, and we paid, cash distributions in the amounts of $50 million on April 30, 2009, $50 million on July 31, 2009 and $45 million on October 26, 2009. On January 29, 2010, we paid a $50 million cash distribution. In association with Williams’ restructuring of its gas pipeline and domestic midstream businesses, our Management Committee authorized a cash distribution of approximately of $153.8 million on January 31, 2010, which we paid on February 16, 2010.
Prior to our conversion to a limited liability company, our Board of Directors declared and we paid cash dividends on common stock in the amounts of $50 million on March 31, 2008, $60 million on June 30, 2008, and $55 million on September 30, 2008. After the conversion, we distributed $55 million on December 31, 2008 to WGP.
Item 6.
Item 6. Selected Financial Data
Since we meet the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K, this information is omitted.
Item 7.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
General
The following discussion and analysis of results of operations and capital resources and liquidity should be read in conjunction with the financial statements and notes thereto included within Item 8.
On January 20, 2010, we concluded that our financial statements for the year ended December 31, 2008 should be restated due to the manner in which we have presented and recognized certain pension and postretirement obligations in certain benefit plans for which our parent, Williams, is the plan sponsor. We have previously recorded parent-allocated amounts related to these plans on a single-employer basis rather than a multi-employer accounting model. As the plan assets are not legally segregated and we are not contractually required to assume these obligations upon withdrawal, we have now concluded that the appropriate accounting model for these historical financial statements is a multi-employer model. The restatement did not have an impact on our 2008 Net Income as our expense recognized approximated our contributions to the parent-sponsored plans, nor did it have any impact on our 2008 Statement of Cash Flows.
For a discussion of additional information on the restatement, see “Item 8. Financial Statements and Supplementary Data - Notes to Consolidated Financial Statements - 2. Restatement and Change in Reporting Entity.”
Recent Market Events
During the latter part of 2008, global credit markets experienced significant instability and energy commodity prices experienced significant and rapid declines. Changes in commodity prices and volumes transported have little near-term impact on our revenues because the majority of our cost of service is recovered through firm capacity reservation charges in transportation rates. As a result, the recent decline in energy commodity prices has not significantly impacted our results of operations.
Critical Accounting Estimates
Use of estimates The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates. We believe that the nature of these estimates and assumptions is material due to the subjectivity and judgment necessary, or the susceptibility of such matters to change, and the impact of these on our financial condition or results of operations.
Regulatory Accounting We are regulated by the FERC. The ASC Topic 980, Regulated Operations (Topic 980) provides that rate-regulated public utilities account for and report regulatory assets and liabilities consistent with the economic effect of the way in which regulators establish rates if the rates established are designed to recover the costs of providing the regulated service and if the competitive environment makes it probable that such rates can be charged and collected. Accounting for businesses that are regulated and apply the provisions of Topic 980 can differ from the accounting requirements for non-regulated businesses. Transactions that are recorded differently as a result of regulatory accounting requirements include the capitalization of an equity return component on regulated capital projects, capitalization of other project costs, retirements of general plant assets, employee related benefits, environmental costs, negative salvage, asset retirement obligations and other costs and taxes included in, or expected to be included in, future rates. As a rate-regulated entity, our management has determined that it is appropriate to apply the accounting prescribed by Topic 980 and, accordingly, the accompanying consolidated financial statements include the effects of the types of transactions described above that result from regulatory accounting requirements. Management uses judgment in determining the probability that regulatory assets will be recoverable from, or regulatory
liabilities will be refunded to, customers. A summary of regulatory assets and liabilities is included in Note 11 of Notes to Consolidated Financial Statements.
Revenue subject to refund FERC regulations promulgate policies and procedures which govern a process to establish the rates that we are permitted to charge customers for natural gas sales and services, including the transportation and storage of natural gas. Key determinants in the ratemaking process are (1) costs of providing service, including depreciation expense, (2) allowed rate of return, including the equity component of the capital structure and related taxes, and (3) volume throughput assumptions.
As a result of the ratemaking process, certain revenues collected by us may be subject to possible refunds upon the issuance of final orders by the FERC in pending rate proceedings. We record estimates of rate refund liabilities considering our and third-party regulatory proceedings, advice of counsel and other risks. Depending on the results of these proceedings, the actual amounts allowed to be collected from customers could differ from management’s estimate. In addition, as a result of rate orders, tariff provisions or regulations, we are required to refund or credit certain revenues to our customers. At December 31, 2009, we had accrued approximately $1 million for potential amounts to be refunded or credited.
Contingent liabilities We record liabilities for estimated loss contingencies when we assess that a loss is probable and the amount of the loss can be reasonably estimated. Revisions to contingent liabilities are reflected in income in the period in which new or different facts or information become known or circumstances change that affect the previous assumptions with respect to the likelihood or amount of loss. Liabilities for contingent losses are based upon our assumptions and estimates, and advice of legal counsel or other third parties regarding the probable outcomes of the matter. As new developments occur or more information becomes available, our assumptions and estimates of these liabilities may change. Changes in our assumptions and estimates or outcomes different from our current assumptions and estimates could materially affect future results of operations for any particular quarterly or annual period.
Asset Retirement Obligations We record an asset and a liability equal to the present value of each expected future asset retirement obligation (ARO). The ARO asset is depreciated in a manner consistent with the depreciation of the underlying physical asset. We measure changes in the liability due to passage of time by applying an interest method of allocation. This amount is recognized as an increase in the carrying amount of the liability and offset by a regulatory asset, as such amounts are expected to be recovered in future rates. As new developments occur or more information becomes available, our assumptions and estimates of our expected future AROs may change.
Results of Operations
2009 COMPARED TO 2008
Operating Income and Net Income Operating income for 2009 was $333.6 million compared to $393.5 million for 2008. Net income for 2009 was $280.4 million compared to $1,298.9 million for 2008. The decrease in Operating income of $59.9 million (15.2 percent) was due primarily to an increase in operating costs and expenses as discussed below, partially offset by an increase in Other revenues. The decrease in Net income of $1,018.5 million (78.4 percent) was mostly attributable to the increase in (Benefit) Provision for income taxes primarily due to the benefit realized in 2008 for the
reversal of our net deferred tax liability upon the conversion from a corporation to a limited liability company on December 31, 2008 and the lower Operating income.
Sales Revenues We make jurisdictional merchant gas sales pursuant to a blanket sales certificate issued by the FERC.
Through an agency agreement, WGM manages our long-term purchase agreements and our remaining jurisdictional merchant gas sales, which excludes our cash out sales in settlement of gas imbalances. The long-term purchase agreements managed by WGM remain in our name, as do the corresponding sales of such purchased gas. Therefore, we continue to record natural gas sales revenues and the related accounts receivable and cost of natural gas sales and the related accounts payable for the jurisdictional merchant sales that are managed by WGM. WGM receives all margins associated with jurisdictional merchant gas sales business and, as our agent, assumes all market and credit risk associated with our jurisdictional merchant gas sales. Consequently, our merchant gas sales service has no impact on our operating income or results of operations.
In addition to our merchant gas sales, we also have cash out sales, which settle gas imbalances with shippers. In the course of providing transportation services to customers, we may receive different quantities of gas from shippers than the quantities delivered on behalf of those shippers. Additionally, we transport gas on various pipeline systems, which may deliver different quantities of gas on our behalf than the quantities of gas received from us. These transactions result in gas transportation and exchange imbalance receivables and payables. Our tariff includes a method whereby the majority of transportation imbalances are settled on a monthly basis through cash out sales or purchases. The cash out sales have no impact on our operating income or results of operations.
Operating Revenues: Natural gas sales decreased $53.4 million (35.6 percent) to $96.7 million for 2009 when compared to 2008. The decrease was primarily due to lower cash out sales of $59.5 million, partially offset by system management gas sales of $7.0 million in 2009. These sales were offset in our costs of natural gas sold and therefore had no impact on our operating income or results of operations.
Transportation Revenues Operating Revenues: Natural gas transportation for 2009 was $891.8 million compared to $897.6 million for 2008. The $5.8 million (0.6 percent) decrease was primarily due to lower transportation demand revenues of $6.7 million, $6.2 million lower transportation commodity revenues on lower volumes transported, the absence of a benefit recognized in 2008 of $2.9 million to revenue amounts reserved in prior years in connection with our general rate case filing, and $3.9 million lower revenues which recover electric power costs. Electric power costs are recovered from customers through transportation rates resulting in no net impact on our operating income or results of operations. These were partially offset by increased revenues of $12.6 million from the Sentinel expansion project (Phase I was placed in service in December 2008 and Phase II was placed in service in November 2009) and increased revenues of $1.2 million related to gathering revenues which were diminished in 2008 due to Hurricane Ike.
Storage Revenues Operating Revenues: Natural gas storage for 2009 were comparable to 2008.
Other Revenues Operating Revenues: Other increased $16.2 million (205.1 percent) to $24.1 million for 2009, when compared to 2008, primarily due to an increase in revenues from the Park and
Loan service of $16.6 million as a result of higher volumes parked and/or loaned by customers in 2009 due to favorable market conditions.
Operating Costs and Expenses Excluding the Cost of natural gas sales which is directly offset in revenues, our operating expenses were approximately $69.7 million (10.6 percent) higher than 2008. This increase was primarily attributable to:
°
A $7.2 million increase related to miscellaneous contractual services, other outside services, helicopter and aircraft usage, boat usage, and contract labor primarily related to Hurricane Ike damage assessment;
°
A $4.6 million increase in labor and labor related costs, primarily higher salaries, other incentive compensation costs, and pension costs; and
°
A $5.4 million net increase in other various costs.
°
A $8.4 million increase in labor and labor related costs, primarily higher salaries, other incentive compensation costs, and pension costs; and
°
A $6.7 million increase in allocated corporate expenses;
°
Partially offset by $3.0 million lower charges associated with a 2008 pipeline rupture.
°
A $10.4 million increase in fuel expense in 2009 resulting from less favorable pricing differentials between cost recoveries at spot prices and expenses recognized at weighted average prices;
°
A $3.6 million increase in costs related to the settlement of certain transportation and exchange imbalances;
°
Partially offset by $3.9 lower electric power costs in 2009. Electric power costs are recovered from customers through transportation rates resulting in no net impact on our operating income or results of operations.
Other (Income) and Other Deductions Other (income) and other deductions in 2009 were $53.5 million compared to $55.3 million in 2008. The $1.8 million decrease (3.3 percent) was primarily due to:
•
Higher Allowance for equity and borrowed funds used during construction (AFUDC) of $5.7 million due to higher construction spending in 2009 as compared to 2008;
•
Lower Interest expense-other of $1.8 million primarily due to a decrease in interest expense on rate refunds partially offset by an increase in interest on long-term debt;
•
Partially offsetting these were a decrease in Miscellaneous other income, net of $3.0 million, primarily due to lower equity AFUDC gross-up in 2009 as we no longer provide for income taxes; and
•
Lower Interest income-affiliates of $2.9 million due to the decrease in average daily balance of advances outstanding in 2009 as compared to 2008;
Provision (Benefit) for Income Taxes Provision (Benefit) for Income Taxes increased $960.5 million (100.0 percent), primarily due to a reversal of $1,072.6 million of deferred taxes in 2008, due to our conversion from a corporation to a single member limited liability company on December 31, 2008. The provision for income taxes for 2008 reflects the provision through December 31, 2008. Subsequent to the conversion to a single member limited liability company, all deferred income taxes were eliminated and we no longer provide for income tax, except for the Texas Gross Margin tax.
Effects of Inflation
We generally have experienced increased costs due to the effect of inflation on the cost of labor, materials and supplies, and property, plant and equipment. A portion of the increased labor and materials and supplies cost can directly affect income through increased operation and maintenance expenses. The cumulative impact of inflation over a number of years has resulted in increased costs for current replacement of productive facilities. The majority of our property, plant and equipment and material and supplies inventory is subject to ratemaking treatment, and under current FERC practices, recovery is limited to historical costs. We believe that we will be allowed to recover and earn a return based on increased actual costs incurred when existing facilities are replaced. Cost based regulation
along with competition and other market factors limit our ability to price services or products based upon inflation’s effect on costs.
CAPITAL RESOURCES AND LIQUIDITY
Method of Financing
We fund our capital requirements with cash flows from operating activities, repayments of advances to Williams, accessing capital markets, and, if required, borrowings under the credit agreement described below and advances from Williams.
We may raise capital through private debt offerings, as well as offerings registered pursuant to offering-specific registration statements. Interest rates, market conditions, and industry conditions will affect amounts raised, if any, in the capital markets. Historically, we have been able to access public and private markets on terms commensurate with our credit ratings to finance our capital requirements, when needed.
As of December 31, 2009, Williams had an unsecured, $1.5 billion revolving credit facility (Credit Facility) with a maturity date of May 1, 2012. Prior to the restructuring, we had access to $400 million under the Credit Facility to the extent not otherwise utilized by Williams. A participating bank, which is committed to fund up to $70 million of the Credit Facility, has filed for bankruptcy. Williams expects that its ability to borrow under this facility is reduced by this committed amount. Consequently, we expect our ability to borrow under the Credit Facility is reduced by approximately $18.7 million. The committed amounts of other participating banks under this agreement remain in effect and are not impacted by the above. As of December 31, 2009, no letters of credit have been issued by the participating institutions. There were no revolving credit loans outstanding as of December 31, 2009.
Interest under the Credit Facility is calculated based on a choice of two methods: a fluctuating rate equal to the lender’s base rate plus an applicable margin, or a periodic fixed rate equal to the London Interbank Offered Rate (LIBOR) plus an applicable margin. Williams is required to pay a commitment fee (currently 0.125 percent) based on the unused portion of the Credit Facility. The margins and commitment fee are generally based on the specific borrower’s senior unsecured long-term debt ratings.
The Credit Facility contains certain affirmative covenants and a number of restrictions on the business of the borrowers, including us. These restrictions include restrictions on the borrowers’ ability to grant liens securing indebtedness, merge or sell all or substantially all of our assets and incurrence of indebtedness. Significant financial covenants under the Credit Facility include the following:
The Credit Facility also contains events of default tied to all borrowers which in certain circumstances would cause all lending under the Credit Facility to terminate and all indebtedness outstanding under the Credit Facility to be accelerated.
In January 2008, we borrowed $100 million under the Credit Facility to retire $100 million of 6.25 percent senior unsecured notes that matured on January 15, 2008. In April 2008, we borrowed $75 million under the Credit Facility to retire $75 million of adjustable rate unsecured notes that matured on April 15, 2008.
On May 22, 2008, we issued $250 million aggregate principal amount of 6.05 percent senior unsecured notes due 2018 to certain institutional investors in a Rule 144A private debt placement. We used $175 million of the net proceeds to repay our borrowings under the Credit Facility. In September 2008, we completed an exchange of these notes for new notes that are registered under the Securities Act of 1933, as amended.
On February 17, 2010, Williams completed a strategic restructuring, which involved contributing substantially all of its domestic midstream and pipeline businesses, which includes us, into WPZ. We are now a wholly-owned subsidiary of WPZ.
As part of the restructuring, we were removed as borrowers under the Credit Facility and on February 17, 2010, we entered into a new $1.75 billion three-year senior unsecured revolving credit facility (the “New Credit Facility”) with WPZ and Northwest Pipeline GP (“Northwest”), as co-borrowers, and Citibank N.A., as administrative agent, and certain other lenders named therein. The full amount of the New Credit Facility is available to WPZ and may be increased by up to an additional $250 million. We may borrow up to $400 million under the New Credit Facility to the extent not otherwise utilized by WPZ and Northwest. At closing, WPZ borrowed $250 million under the New Credit Facility to repay the term loan outstanding under its existing senior unsecured credit agreement.
Interest on borrowings under the New Credit Facility is payable at rates per annum equal to, at the option of the borrower: (1) a fluctuating base rate equal to Citibank, N.A.’s adjusted base rate plus the applicable margin, or (2) a periodic fixed rate equal to LIBOR plus the applicable margin. The adjusted base rate will be the highest of (i) the federal funds rate plus 0.5 percent, (ii) Citibank N.A.’s publicly announced base rate, and (iii) one-month LIBOR plus 1.0 percent. WPZ pays a commitment fee (currently 0.5 percent) based on the unused portion of the New Credit Facility. The applicable margin and the commitment fee are determined by reference to a pricing schedule based on a borrower’s senior unsecured debt ratings.
The New Credit Facility contains various covenants that limit, among other things, a borrower’s and its respective subsidiaries’ ability to incur indebtedness, grant certain liens supporting indebtedness, merge or consolidate, sell all or substantially all of its assets, enter into certain affiliate transactions, make certain distributions during an event of default, and allow any material change in the nature of its business.
Under the New Credit Facility, WPZ is required to maintain a ratio of debt to Earnings Before Income Taxes, Interest, Depreciation and Amortization (EBITDA) (each as defined in the New Credit Facility) of no greater than 5.00 to 1.00 for itself and its consolidated subsidiaries. For us and our consolidated subsidiaries, the ratio of debt to capitalization (defined as net worth plus debt) is not permitted to be greater than 55%. Each of the above ratios will be tested, beginning June 30, 2010, at the end of each fiscal quarter, and the debt to EBITDA ratio is measured on a rolling four-quarter basis.
The New Credit Facility includes customary events of default, including events of default relating to non-payment of principal, interest or fees, inaccuracy of representations and warranties in any
material respect when made or when deemed made, violation of covenants, cross-payment defaults, cross acceleration, bankruptcy and insolvency events, certain unsatisfied judgments and a change of control. If an event of default with respect to a borrower occurs under the New Credit Facility, the lenders will be able to terminate the commitments for all borrowers and accelerate the maturity of the loans of the defaulting borrower under the New Credit Facility and exercise other rights and remedies.
As a participant in Williams’ cash management program, we make advances to and receive advances from Williams. At December 31, 2009, the advances due to us by Williams totaled $186.1 million. The advances are represented by demand notes. The interest rate on intercompany demand notes is based upon the weighted average cost of Williams’ debt outstanding at the end of each quarter. At December 31, 2009, the interest rate was 8.02 percent. In accordance with Williams’ restructuring of its business, our participation in the Williams’ cash management program will be terminated. On January 31, 2010 our Management Committee authorized a cash distribution which included the amount of our outstanding advances. Accordingly, the balance outstanding at December 31, 2009 and the related interest receivable were reflected as a reduction of our Owner’s Equity as the advances will not be available to us as working capital. Effective with the restructuring, we will become a participant of the Williams Partners, L.P. cash management program.
Through a wholly-owned subsidiary, we hold a 35 percent interest in Pine Needle LNG Company, LLC (Pine Needle). On March 20, 1998, Pine Needle executed an interest rate swap agreement with a bank, which swapped floating rate debt into 6.58 percent fixed rate debt. This interest rate swap qualifies as a cash flow hedge transaction under the accounting and reporting standards established by ASC Topic 815, Derivatives and Hedging. As such, our equity interest in the changes in fair value of Pine Needle’s hedge is recognized in other comprehensive income. For the years ended December 31, 2009 and 2008, our cumulative equity interest in an unrealized loss on Pine Needle’s hedge was $0.7 million and $1.1 million, respectively. The swap agreement initially had a notional amount of $53.5 million, of which $23.0 million was still outstanding at December 31, 2009. The interest rate swap is settled quarterly. The swap agreement was effective March 31, 1999 and terminates on December 31, 2013, which is also the date of the last principal payment on this long-term debt.
Credit Ratings
We have no guarantees of off-balance sheet debt to third parties and maintain no debt obligations that contain provisions requiring accelerated payment of the related obligations in the event of specified levels of declines in Williams’ or our credit ratings given by Moody’s Investors Service, Standard & Poor’s and Fitch Ratings (rating agencies).
During 2009, the credit ratings on our senior unsecured long-term debt remained unchanged with investment grade ratings from all three agencies, as shown below.
With respect to Moody’s, a rating of “Baa” or above indicates an investment grade rating. A rating below “Baa” is considered to have speculative elements. A “Ba” rating indicates an obligation that is judged to have speculative elements and is subject to substantial credit risk. The “1”, “2” and “3” modifiers show the relative standing within a major category. A “1” indicates that an obligation ranks in
the higher end of the broad rating category, “2” indicates a mid-range ranking, and “3” ranking at the lower end of the category.
With respect to Standard & Poor’s, a rating of “BBB” or above indicates an investment grade rating. A rating below “BBB” indicates that the security has significant speculative characteristics. A “BB” rating indicates that Standard & Poor’s believes the issuer has the capacity to meet its financial commitment on the obligation, but adverse business conditions could lead to insufficient ability to meet financial commitments. Standard & Poor’s may modify its ratings with a “+” or a “-” sign to show the obligor’s relative standing within a major rating category.
With respect to Fitch, a rating of “BBB” or above indicates an investment grade rating. A rating below “BBB” is considered speculative grade. A “BB” rating from Fitch indicates that there is a possibility of credit risk developing, particularly as the result of adverse economic change over time; however, business or financial alternatives may be available to allow financial commitments to be met. Fitch may add a “+” or a “-” sign to show the obligor’s relative standing within a major rating category.
Credit rating agencies perform independent analyses when assigning credit ratings. No assurance can be given that the credit rating agencies will continue to assign us investment grade ratings even if we meet or exceed their current criteria for investment grade ratios. A downgrade of our credit rating might increase our future cost of borrowing and might require us to post collateral with third parties.
Capital Expenditures
We categorize our capital expenditures as either maintenance capital expenditures or expansion capital expenditures. Maintenance capital expenditures are those expenditures required to maintain the existing operating capacity and service capability of our assets, including replacement of system components and equipment that are worn, obsolete, completing their useful life, or necessary to remain in compliance with environmental laws and regulations. Expansion capital expenditures improve the service capability of the existing assets, extend useful lives, increase transmission or storage capacities from existing levels, reduce costs or enhance revenues. As shown in the table below, our capital expenditures for 2009 included $174 million for expansion projects, primarily for Sentinel and 85 North and $129 million for maintenance of existing facilities and other projects including expenditures required under the Pipeline Safety Improvement Act of 2002. We are estimating approximately $400 million to $450 million of capital expenditures in the year 2010 related to the maintenance of existing facilities, including pipeline safety expenditures, and expansion projects, primarily the 85 North Expansion project. Of this total, $375 million to $425 million is considered nondiscretionary due to legal, regulatory, and/or contractual requirements.
Other Capital Requirements, Contractual Obligations and Contingencies
Contractual obligations The table below summarizes the maturity dates of our contractual obligations as of December 31, 2009 (in millions).
(1)
Obligations primarily associated with Property, Plant and Equipment expenditures.
Regulatory and legal proceedings As discussed in Note 3 of Notes to Consolidated Financial Statements included in Item 8 herein, we are involved in several pending regulatory and legal proceedings. Because of the complexities of the issues involved in these proceedings, we cannot predict the actual timing of resolution or the ultimate amounts, which might have to be refunded or paid in connection with the resolution of these pending regulatory and legal proceedings.
Environmental matters As discussed in Note 3 of Notes to Consolidated Financial Statements, we are subject to extensive federal, state and local environmental laws and regulations which affect our operations related to the construction and operation of our pipeline facilities. We consider environmental assessment and remediation costs and costs associated with compliance with environmental standards to be recoverable through rates, as they are prudent costs incurred in the ordinary course of business. To date, we have been permitted recovery of environmental costs incurred, and it is our intent to continue seeking recovery of such costs, as incurred, through rate filings.
Long-term gas purchase contracts We have long-term gas purchase contracts containing variable prices that are currently in the range of estimated market prices. However, due to contract expirations and estimated deliverability declines, our estimated purchase commitments under such gas purchase contracts are not material to our total gas purchases.
CONCLUSION
Although no assurances can be given, we currently believe that the aggregate of cash flows from Operating activities, supplemented, when necessary, by advances or capital contributions from our parent and borrowings under our New Credit Facility will provide us with sufficient liquidity to meet our capital requirements. Historically, we have been able to access public and private markets on terms commensurate with our credit ratings to finance our capital requirements, when needed.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
At December 31, 2009, our debt portfolio included only fixed rate issues. The following table provides information about our long-term debt, including current maturities, as of December 31, 2009. The table presents principal cash flows and weighted-average interest rates by expected maturity dates.
Item 8.
Item 8. Financial Statements and Supplementary Data
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER
FINANCIAL REPORTING
Management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a - 15(f) and 15d - 15(f) under the Securities Exchange Act of 1934). Our internal controls over financial reporting are designed to provide reasonable assurance to our management regarding the preparation and fair presentation of financial statements in accordance with accounting principles generally accepted in the United States. Our 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 our assets; (ii) provide reasonable assurance that transactions are recorded as to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorization of our management; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.
All internal control systems, no matter how well designed, have inherent limitations including the possibility of human error and the circumvention or overriding of controls. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
Under the supervision and with the participation of our management, including our Senior Vice President and our Vice President and Treasurer, we assessed the effectiveness of our internal control over financial reporting as of December 31, 2009, based on the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework. Previously, our management had concluded that our internal control over financial reporting was effective for the period ended December 31, 2008. In the first quarter of 2010, we identified a material weakness related to the manner in which we presented and recognized certain pension and post retirement obligations in certain benefit plans for which our parent is the plan sponsor.
A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis.
As discussed further in Note 2 of the Notes to Consolidated Financial Statements, we have previously recorded parent-allocated amounts related to these plans on a single-employer basis rather than a multi-employer accounting model. As the plan assets are not legally segregated and we are not contractually required to assume these obligations upon withdrawal, we have now concluded that the appropriate accounting model for these historical financial statements is a multi-employer model. The error was significant to the Consolidated Statement of Comprehensive Income for the period ended December 31, 2008. The impact of the correction also increased Owner’s Equity and reduced non-current assets and liabilities. It did not have an impact on our 2008 Consolidated Net Income, nor did it have any impact on our 2008 Consolidated Statement of Cash Flows.
Based upon our current assessment, which considered the material weakness described above, our management concluded that our internal control over financial reporting was not effective at December 31, 2008. Our management also concluded that our internal control over financial reporting was not effective at December 31, 2009.
We have corrected our method of accounting to the multi-employer model, and this change is reflected in our financial statements for the period ended December 31, 2009. We have also enhanced our controls that ensure proper selection and application of generally accepted accounting principles.
This annual report does not include an attestation report of Transco’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by Transco’s registered public accounting firm pursuant to temporary rules of the SEC that permit Transco to provide only management’s report in this annual report.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Management Committee of Transcontinental Gas Pipe Line Company, LLC
We have audited the accompanying consolidated balance sheets of Transcontinental Gas Pipe Line Company, LLC as of December 31, 2009 and 2008, and the related consolidated statements of income, comprehensive income, owner’s equity, and cash flows for each of the three years in the period ended December 31, 2009. Our audits also included the financial statement schedule listed in the Index at Item 15(a). These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our 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 audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Transcontinental Gas Pipe Line Company, LLC at December 31, 2009 and 2008, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2009, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
As discussed in Note 2 to the consolidated financial statements, the Company restated its consolidated balance sheet as of December 31, 2008 and the related consolidated statements of comprehensive income, and owner’s equity for each of the two years then ended, as a result of the correction of an error related to pension and other postretirement benefit obligations in certain benefit plans for which their parent, The Williams Companies, Inc. is the plan sponsor.
/S/ ERNST & YOUNG LLP
Houston, Texas
February 22, 2010
TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
CONSOLIDATED STATEMENT OF INCOME
(Thousands of Dollars)
See accompanying notes.
TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
See accompanying notes.
TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
See accompanying notes.
TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
CONSOLIDATED STATEMENT OF OWNER’S EQUITY
(Thousands of Dollars)
See accompanying notes.
TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
(Thousands of Dollars)
See accompanying notes.
TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
CONSOLIDATED STATEMENT OF CASH FLOWS
(Thousands of Dollars)
(continued)
TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
CONSOLIDATED STATEMENT OF CASH FLOWS (continued)
(Thousands of Dollars)
See accompanying notes.
TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Summary of Significant Accounting Policies
2. Restatement and Change in Reporting Entity
3. Contingent Liabilities and Commitments
4. Debt, Financing Arrangements and Leases
5. Fair Value Measurements
6. Employee Benefit Plans
7. Income Taxes
8. Financial Instruments and Guarantees
9. Transactions with Major Customers and Affiliates
10. Asset Retirement Obligations
11. Regulatory Assets and Liabilities
12. Quarterly Information (Unaudited)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Corporate structure and control On December 31, 2008, Transcontinental Gas Pipe Line Corporation was converted from a corporation to a limited liability company and thereafter is known as Transcontinental Gas Pipe Line Company, LLC (Transco). On December 31, 2009, we were a wholly-owned subsidiary of Williams Gas Pipeline Company, LLC (WGP). WGP is a wholly-owned subsidiary of The Williams Companies, Inc. (Williams). Effective December 31, 2008, we distributed our ownership interest in all of our wholly-owned subsidiaries to WGP and adjusted financial and operating information retrospectively to reflect the effects of this transaction.
Effective September 2009, WGP contributed its ownership interests in certain entities to us as follows: TransCardinal Company, LLC (TransCardinal) and Cardinal Operating Company, LLC (Cardinal Operating); TransCarolina LNG Company, LLC (TransCarolina) and Pine Needle Operating Company, LLC (Pine Needle Operating). Accordingly, we have adjusted financial and operating information retrospectively to reflect the effects of this transaction.
On February 17, 2010, Williams completed a strategic restructuring, which involved contributing substantially all of its domestic midstream and pipeline businesses, which includes us, into Williams Partners L.P. (WPZ). WPZ is a master limited partnership with publicly traded units. It is controlled by and consolidated with Williams. Effective February 17, 2010, we are a wholly owned subsidiary of WPZ, approximately 82 percent of whose limited partnership interests as of such date are owned by Williams.
In this report, Transco (which includes Transcontinental Gas Pipe Line Company, LLC and unless the context otherwise requires, all of our majority-owned subsidiaries) is at times referred to in the first person as “we” “us” or “our.”
Nature of operations We are an interstate natural gas transmission company that owns a natural gas pipeline system extending from Texas, Louisiana, Mississippi and the Gulf of Mexico through Alabama, Georgia, South Carolina, North Carolina, Virginia, Maryland, Pennsylvania and New Jersey to the New York City metropolitan area. The system serves customers in Texas and the 11 southeast and Atlantic seaboard
states mentioned above, including major metropolitan areas in Georgia, Washington D.C., North Carolina, New York, New Jersey and Pennsylvania.
Regulatory accounting We are regulated by the Federal Energy Regulatory Commission (FERC). The Accounting Standards Codification Regulated Operations (Topic 980), provides that rate-regulated public utilities account for and report regulatory assets and liabilities consistent with the economic effect of the way in which regulators establish rates if the rates established are designed to recover the costs of providing the regulated service and if the competitive environment makes it probable that such rates can be charged and collected. Accounting for businesses that are regulated and apply the provisions of Topic 980 can differ from the accounting requirements for non-regulated businesses. Transactions that are recorded differently as a result of regulatory accounting requirements include the capitalization of an equity return component on regulated capital projects, capitalization of other project costs, retirements of general plant assets, employee related benefits, environmental costs, negative salvage, asset retirement obligations, and other costs and taxes included in, or expected to be included in, future rates. As a rate-regulated entity, our management has determined that it is appropriate to apply the accounting prescribed by Topic 980 and, accordingly, the accompanying consolidated financial statements include the effects of the types of transactions described above that result from regulatory accounting requirements.
Basis of presentation Williams’ acquisition of Transco Energy Company and its subsidiaries, including us, in 1995 was accounted for using the purchase method of accounting. Accordingly, an allocation of the purchase price was assigned to our assets and liabilities based on their estimated fair values. The purchase price allocation to us primarily consisted of a $1.5 billion allocation to property, plant and equipment and adjustments to deferred taxes based upon the book basis of the net assets recorded as a result of the acquisition. The amount allocated to property, plant and equipment is being depreciated on a straight-line basis over 40 years, the estimated useful lives of these assets at the date of acquisition, at approximately $36 million per year. At December 31, 2009, the remaining property, plant and equipment allocation was approximately $0.9 billion. Current FERC policy does not permit us to recover through rates amounts in excess of original cost.
As a participant in Williams’ cash management program, we make advances to and receive advances from Williams. These advances are represented by demand notes. The interest rate on intercompany demand notes is based upon the weighted average cost of Williams’ debt outstanding at the end of each quarter. At December 31, 2009, the interest rate was 8.02 percent. In accordance with Williams’ restructuring of its business, our participation in the Williams’ cash management program will be terminated. On January 31, 2010 our Management Committee authorized a cash distribution which included the amount of our outstanding advances and associated interest receivable which was paid February 16, 2010. Accordingly, the balance and related interest outstanding at December 31, 2009 were reflected as a reduction of our Owner’s Equity. As a result of the restructuring, we will become a participant of the WPZ cash management program.
Through an agency agreement, Williams Gas Marketing, Inc. (WGM), an affiliate of ours, manages all jurisdictional merchant gas sales for us, receives all margins associated with such business and, as our agent, assumes all market and credit risk associated with our jurisdictional merchant gas sales. Consequently, our merchant gas sales have no impact on our operating income or results of operations.
We made equity distributions to WGP of $145 million in 2009 and $55 million for the fourth quarter of 2008. Our Board of Directors declared and we paid cash dividends on common stock in the amounts of $165 million and $110 million for the first three quarters of 2008 and full year of 2007, respectively. In January 2010, we distributed $50 million to WGP. In association with Williams’ restructuring of its gas pipeline and
domestic midstream businesses, our Management Committee authorized a cash distribution of approximately $153.8 million on January 31, 2010, which we paid on February 16, 2010.
Principles of consolidation The consolidated financial statements include our accounts and the accounts of our majority-owned subsidiaries. Companies in which we and our subsidiaries own 20 percent to 50 percent of the voting common stock or otherwise exercise significant influence over operating and financial policies of the company are accounted for under the equity method. The equity method investments as of December 31, 2009 and December 31, 2008 consist of Cardinal Pipeline Company, LLC (Cardinal) with ownership interest of approximately 45 percent and Pine Needle LNG Company, LLC (Pine Needle) with ownership interest of 35 percent. We received distributions associated with our equity method investments totaling $1.4 million, $5.9 million, and $5.8 million in 2009, 2008, and 2007, respectively. In addition, distributions totaling $3.7 million were received by WGP during the first nine months of 2009 in which it owned the equity method investments.
Use of estimates The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates. Estimates and assumptions which, in the opinion of management, are significant to the underlying amounts included in the financial statements and for which it would be reasonably possible that future events or information could change those estimates include: 1) revenues subject to refund; 2) litigation-related contingencies; 3) environmental remediation obligations; 4) impairment assessments of long-lived assets; 5) depreciation; and 6) asset retirement obligations.
Revenue recognition Revenues for transportation of gas under long-term firm agreements are recognized considering separately the demand and commodity charges. Demand revenues are recognized monthly over the term of the agreement regardless of the volume of natural gas transported. Commodity revenues from both firm and interruptible transportation are recognized in the period transportation services are provided based on volumes of natural gas physically delivered at the agreed upon delivery point. Revenues for the storage of gas under firm agreements are recognized considering separately the demand, capacity, and injection and withdrawal charges. Demand and capacity revenues are recognized monthly over the term of the agreement regardless of the volume of storage service actually utilized. Injection and withdrawal revenues are recognized in the period when volumes of natural gas are physically injected into or withdrawn from storage.
In the course of providing transportation services to customers, we may receive different quantities of gas from shippers than the quantities delivered on behalf of those shippers. The resulting imbalances are primarily settled through the purchase and sale of gas with our customers under terms provided for in our FERC tariff. Revenue is recognized from the sale of gas upon settlement of the transportation and exchange imbalances (See Gas imbalances in this Note).
As a result of the ratemaking process, certain revenues collected by us may be subject to possible refunds upon the issuance of final orders by the FERC in pending rate proceedings. We record estimates of rate refund liabilities considering our and other third-party regulatory proceedings, advice of counsel and other risks.
Environmental Matters We are subject to federal, state, and local environmental laws and regulations. Environmental expenditures are expensed or capitalized depending on their economic benefit and potential for rate recovery. We believe that any expenditures required to meet applicable environmental laws and regulations are prudently incurred in the ordinary course of business and that substantially all of such expenditures would be permitted to be recovered through rates.
Property, plant and equipment Property, plant and equipment is recorded at cost. The carrying values of these assets are also based on estimates, assumptions and judgments relative to capitalized costs, useful lives and salvage values. These estimates, assumptions and judgments reflect FERC regulations, as well as historical experience and expectations regarding future industry conditions and operations. Gains or losses from the ordinary sale or retirement of property, plant and equipment are credited or charged to accumulated depreciation; certain other gains or losses are recorded in operating income.
We provide for depreciation using the straight-line method at FERC prescribed rates, including negative salvage (cost of removal) for transmission facilities, production and gathering facilities and LNG storage facilities. Depreciation of general plant is provided on a group basis at straight-line rates. Included in our depreciation rates is a negative salvage component that we currently collect in rates. Depreciation rates used for major regulated gas plant facilities at December 31, 2009, 2008 and 2007 are as follows:
We record an asset and a liability equal to the present value of each expected future asset retirement obligation (ARO). The ARO asset is depreciated in a manner consistent with the depreciation of the underlying physical asset. We measure changes in the liability due to passage of time by applying an interest method of allocation. The depreciation of the ARO asset and accretion of the ARO liability are recognized as an increase to a regulatory asset, as management expects to recover such amounts in future rates. The regulatory asset is amortized commensurate with our collection of those costs in rates.
Impairment of long-lived assets We evaluate the long-lived assets of identifiable business activities for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable. When an indicator of impairment has occurred, we compare our management’s estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has occurred. We apply a probability-weighted approach to consider the likelihood of different cash flow assumptions and possible outcomes including selling in the near term or holding for the remaining estimated useful life. If an impairment of the carrying value has occurred, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value.
For assets identified to be disposed of in the future and considered held for sale in accordance with the ASC Property, Plant, and Equipment (Topic 360), we compare the carrying value to the estimated fair value less the cost to sell to determine if recognition of an impairment is required. Until the assets are disposed of, the estimated fair value, which includes estimated cash flows from operations until the assumed date of sale, is recalculated when related events or circumstances change. We had no impairments during the years ended December 31, 2009, 2008 and 2007.
Judgments and assumptions are inherent in our management’s estimate of undiscounted future cash flows used to determine recoverability of an asset and the estimate of an asset’s fair value used to calculate the amount of impairment to recognize. The use of alternate judgments and/or assumptions could result in the recognition of different levels of impairment charges in the financial statements.
Accounting for repair and maintenance costs We account for repair and maintenance costs under the guidance of FERC regulations. The FERC identifies installation, construction and replacement costs that are to be capitalized. All other costs are expensed as incurred.
Allowance for funds used during construction Allowance for funds used during construction (AFUDC) represents the estimated cost of borrowed and equity funds applicable to utility plant in process of construction and are included as a cost of property, plant and equipment because it constitutes an actual cost of construction under established regulatory practices. The FERC has prescribed a formula to be used in computing separate allowances for borrowed and equity AFUDC. The allowance for borrowed funds used during construction was $4.2 million, $2.0 million and $3.5 million, for 2009, 2008 and 2007, respectively. The allowance for equity funds was $7.8 million, $4.4 million, and $9.4 million, for 2009, 2008 and 2007, respectively.
Accounting for income taxes Williams and its wholly-owned subsidiaries, which includes us, file a consolidated federal income tax return. It is Williams’ policy to charge or credit its taxable subsidiaries with an amount equivalent to their federal income tax expense or benefit computed as if each subsidiary had filed a separate return.
We use the assets and liability method of accounting for income taxes, as required by the Accounting Standards Codification Income Taxes (Topic 740), which requires, among other things, provisions for all temporary differences between the financial basis and the tax basis in our assets and liabilities and adjustments to the existing deferred tax balances for changes in tax rates. Following our conversion from a corporation to a limited liability company on December 31, 2008, we are no longer subject to income tax, except for the Texas Gross Margin tax. (See Note 7 of Notes to the Consolidated Financial Statements.)
Accounts receivable and allowance for doubtful receivables Accounts receivable are stated at the historical carrying amount net of reserves or write-offs. Our credit risk exposure in the event of nonperformance by the other parties is limited to the face value of the receivables. We perform ongoing credit evaluations of our customers’ financial condition and require collateral from our customers, if necessary. Due to our customer base, we have not historically experienced recurring credit losses in connection with our receivables. Receivables determined to be uncollectible are reserved or written off in the period of determination.
Gas imbalances In the course of providing transportation services to customers, we may receive different quantities of gas from shippers than the quantities delivered on behalf of those shippers. Additionally, we transport gas on various pipeline systems which may deliver different quantities of gas on behalf of us than the quantities of gas received from us. These transactions result in gas transportation and exchange imbalance receivables and payables which are recovered or repaid in cash or through the receipt or delivery of gas in the future and are recorded in the accompanying Consolidated Balance Sheet. Settlement of imbalances requires agreement between the pipelines and shippers as to allocations of volumes to specific transportation contracts and timing of delivery of gas based on operational conditions. Our tariff includes a method whereby most transportation imbalances are settled on a monthly basis. Each month a portion of the imbalances are not identified to specific parties and remain unsettled. These are generally identified to specific parties and settled in subsequent periods. We believe that amounts that remain unidentified to specific parties and unsettled at year end are valid balances that will be settled with no material adverse effect upon our financial position, results of operations or cash flows. Management has implemented a policy of continuing to carry any unidentified transportation and exchange imbalances on the books for a three-year period. At the
end of the three year period a final assessment will be made of their continued validity. Absent a valid reason for maintaining the imbalance, any remaining balance will be recognized in income. Certain imbalances are being recovered or repaid in cash or through the receipt or delivery of gas upon agreement of the parties as to the allocation of the gas volumes, and as permitted by pipeline operating conditions. These imbalances have been classified as current assets and current liabilities at December 31, 2009 and 2008. We utilize the average cost method of accounting for gas imbalances.
Deferred cash out Most transportation imbalances are settled in cash on a monthly basis (cash out). We are required by our tariff to refund revenues received from the cash out of transportation imbalances in excess of costs incurred during the annual August through July reporting period. Revenues received in excess of costs incurred are deferred until refunded in accordance with the tariff.
Gas inventory We utilize the last-in, first-out (LIFO) method of accounting for inventory gas in storage. If inventories valued using the LIFO cost method were valued at current replacement cost, the amounts would decrease by $1.1 million at December 31, 2009 and decrease $0.8 million at December 31, 2008. The basis for determining current cost at the end of each year is the December monthly average gas price delivered to pipelines in Texas and Louisiana. We utilize the average cost method of accounting for gas available for customer nomination. Liquefied natural gas in storage is valued at original cost.
Reserve for Inventory Obsolescence We perform an annual review of Materials and Supplies inventories, including a quarterly analysis of parts that may no longer be useful due to planned replacements of compressor engines and other components on our system. Based on this assessment, we record a reserve for the value of the inventory which can no longer be used for maintenance and repairs on our pipeline. There was a minimal reserve at December 31, 2009 and at December 31, 2008.
Cash flows from operating activities and cash equivalents We use the indirect method to report cash flows from operating activities, which requires adjustments to net income to reconcile to net cash flows provided by operating activities. We include short-term, highly-liquid investments that have an original maturity of three months or less as cash equivalents.
Subsequent Events We have evaluated our disclosure of subsequent events through the time of filing this Form 10-K with the SEC on February 22, 2010.
Recent Accounting Standards In January 2010, the FASB issued Accounting Standards Update No. 2010-06, “Fair Value Measurements and Disclosures (Topic 820) - Improving Disclosures about Fair Value Measurements”. This Update requires new disclosures regarding the amount of transfers in or out of levels 1 and 2 along with the reason for such transfers and also requires a greater level of disaggregation when disclosing valuation techniques and inputs used in estimating level 2 and level 3 fair value measurements. The disclosures will be required for reporting beginning in the first quarter 2010. Also, beginning with the first quarter 2011, the Standard requires additional categorization of items included in the rollforward of activity for level 3 inputs on a gross basis. We are assessing the application of this Standard to disclosures in our Consolidated Financial Statements.
2. RESTATEMENT AND CHANGE IN REPORTING ENTITY
On January 20, 2010, we concluded that our financial statements for the year ended December 31, 2008 should be restated due to the manner in which we have presented and recognized pension and postretirement obligations in certain benefit plans for which our parent, Williams, is the plan sponsor. We have previously recorded parent-allocated amounts related to these plans on a single-employer basis rather than a multi-employer accounting model. As the plan assets are not legally segregated and we are not contractually required to assume these obligations upon withdrawal, we have now concluded that the appropriate accounting model for these historical financial statements is a multi-employer model.
We participate in pension and postretirement benefit plans sponsored by Williams. However, we have historically accounted for these plans as if they were our own. We have now determined that ASC 715-30-55-63 requires us to account for the plans as if we are a participant in a multi-employer plan. This error in methodology had the most significant impact to our financial statements for the year ended December 31, 2008. In that year, we recognized a significant parent-allocated actuarial loss on our Consolidated Balance Sheet, Consolidated Statement of Owner’s Equity and Consolidated Statement of Comprehensive Income. We have determined that the error was significant to the Statement of Comprehensive Income for the year ended December 31, 2008. For this period, Comprehensive Income should have approximated Net Income. The impact of this error correction also increased Owner’s Equity and reduced non-current assets and liabilities at December 31, 2008 with an offsetting impact to Loan to Parent, which is presented as a reduction to Owner’s Equity (See Note 1). The impact of the error correction did not have an impact on our 2008 or 2007 Net Income as our expense recognized approximated our contributions to the parent-sponsored plans, nor did it have any impact on our 2008 or 2007 Consolidated Statement of Cash Flows.
On December 31, 2008 Transco distributed its ownership interest in the following companies to WGP: Marsh Resources, LLC; TransCarolina; Pine Needle Operating; TransCardinal and Cardinal Operating. TransCarolina owns a 35 percent interest in Pine Needle, a LNG storage Facility. TransCardinal owns a 45 percent interest in Cardinal, a North Carolina intrastate natural gas pipeline company. These assets were transferred at historical cost, as the entities are under common control. No gains or losses were recorded as a result of the distribution, and financial and operating information were adjusted retrospectively to reflect this transaction.
Effective September 2009, WGP contributed its ownership interests in certain of the entities, listed above, to us as follows: TransCardinal and Cardinal Operating; TransCarolina and Pine Needle Operating. These entities were transferred at historical cost, as the entities are under common control. No gains or losses were recorded as a result of the contribution.
Following the guidance of the FASB for when a change in the reporting entity occurs, the change shall be retrospectively applied to the financial statements of all prior periods to show financial information for the new reporting entity. Accordingly, we have adjusted financial and operating information retrospectively for prior periods included in this document to reflect the September 2009 transaction. The impact of the retrospective adjustments to our net income for the years 2008 and 2007 was an increase of $17.9 million and $4.1 million, respectively. The impact of these retrospective adjustments to our comprehensive income for the years 2008 and 2007 was an increase of $17.2 million and $3.9 million, respectively.
The following schedules reconcile the amounts previously reported in our Consolidated Financial Statements as of December 31, 2008 and for the years ended December 31, 2008 and 2007:
TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
CONSOLIDATED STATEMENT OF INCOME
(Thousands of Dollars)
TRANSCONTINENTAL GAS PIPE COMPANY, LLC
CONSOLIDATED STATEMENT OF INCOME
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TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
CONSOLIDATED BALANCE SHEET
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TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
CONSOLIDATED BALANCE SHEET
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TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
CONSOLIDATED STATEMENT OF OWNER’S EQUITY
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TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
CONSOLIDATED STATEMENT OF OWNER’S EQUITY
(Thousands of Dollars)
TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
(Thousands of Dollars)
TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
(Thousands of Dollars)
TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
CONSOLIDATED STATEMENT OF CASH FLOWS
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TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
CONSOLIDATED STATEMENT OF CASH FLOWS
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TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
CONSOLIDATED STATEMENT OF CASH FLOWS
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TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
CONSOLIDATED STATEMENT OF CASH FLOWS
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3. CONTINGENT LIABILITIES AND COMMITMENTS
Rate Matters
On March 1, 2001, we submitted to the FERC a general rate filing (Docket No. RP01-245) to recover increased costs. All cost of service, throughput and throughput mix, cost allocation and rate design issues in this rate proceeding have been resolved by settlement or litigation. The resulting rates were effective from September 1, 2001 to March 1, 2007. A tariff matter in this proceeding has not yet been resolved.
On August 31, 2006, we submitted to the FERC a general rate filing (Docket No. RP06-569) designed to recover increased costs. The rates became effective March 1, 2007, subject to refund and the outcome of a hearing. All issues in this proceeding except one have been resolved by settlement.
The one issue reserved for litigation or further settlement relates to our proposal to change the design of the rates for service under one of our storage rate schedules, which was implemented subject to refund on March 1, 2007. A hearing on that issue was held before a FERC Administrative Law Judge (ALJ) in July 2008. In November 2008, the ALJ issued an initial decision in which he determined that our proposed incremental rate design is unjust and unreasonable. On January 21, 2010, the FERC reversed the ALJ’s initial decision, and approved our proposed incremental rate design. Parties may seek rehearing of the FERC’s order.
Environmental Matters
Since 1989, we have had studies underway to test some of our facilities for the presence of toxic and hazardous substances to determine to what extent, if any, remediation may be necessary. We have responded to data requests from the U.S. Environmental Protection Agency (EPA) and state agencies regarding such potential contamination of certain of our sites. On the basis of the findings to date, we estimate that environmental assessment and remediation costs under various federal and state statutes will total approximately $8 million to $10 million (including both expense and capital expenditures), measured on an undiscounted basis, and will be spent over the next four to six years. This estimate depends on a number of assumptions concerning the scope of remediation that will be required at certain locations and the cost of the remedial measures. We are conducting environmental assessments and implementing a variety of remedial measures that may result in increases or decreases in the total estimated costs. At December 31, 2009, we had a balance of approximately $4.7 million for the expense portion of these estimated costs recorded in current liabilities ($0.8 million) and other long-term liabilities ($3.9 million) in the accompanying Consolidated Balance Sheet. At December 31, 2008, we had a balance of approximately $4.7 million for the expense portion of these estimated costs recorded in current liabilities ($0.9 million) and other long-term liabilities ($3.8 million) in the accompanying Consolidated Balance Sheet.
We consider prudently incurred environmental assessment and remediation costs and costs associated with compliance with environmental standards to be recoverable through rates. To date, we have been permitted recovery of environmental costs, and it is our intent to continue seeking recovery of such costs through future rate filings. Therefore, these estimated costs of environmental assessment and remediation, less amounts collected, have been recorded as regulatory assets in Current Assets, in the accompanying Consolidated Balance Sheet. At December 31, 2009 and 2008, we had recorded approximately $0.6 million and $1.8 million, respectively, of environmental related regulatory assets.
Although we discontinued the use of lubricating oils containing polychlorinated biphenyls (PCBs) in the
1970s, we have discovered residual PCB contamination in equipment and soils at certain gas compressor station sites. We have worked closely with the EPA and state regulatory authorities regarding PCB issues, and we have a program to assess and remediate such conditions where they exist. In addition, we commenced negotiations with certain environmental authorities and other parties concerning investigative and remedial actions relative to potential mercury contamination at certain gas metering sites. All such costs are included in the $8 million to $10 million range discussed above.
We have been identified as a potentially responsible party (PRP) at various Superfund and state waste disposal sites. Based on present volumetric estimates and other factors, our estimated aggregate exposure for remediation of these sites is less than $0.5 million. The estimated remediation costs for all of these sites are included in the $8 million to $10 million range discussed above. Liability under The Comprehensive Environmental Response, Compensation and Liability Act (and applicable state law) can be joint and several with other PRPs. Although volumetric allocation is a factor in assessing liability, it is not necessarily determinative; thus, the ultimate liability could be substantially greater than the amounts described above.
We are also subject to the Federal Clean Air Act (Act) and to the Federal Clean Air Act Amendments of 1990 (1990 Amendments), which added significantly to the existing requirements established by the Act. Pursuant to requirements of the 1990 Amendments and EPA rules designed to mitigate the migration of ground-level ozone (NOx), we are planning installation of air pollution controls on existing sources at certain facilities in order to reduce NOx emissions. We anticipate that additional facilities may be subject to increased controls within three years. For many of these facilities, we are developing more cost effective and innovative compressor engine control designs. Due to the developing nature of federal and state emission regulations, it is not possible to precisely determine the ultimate emission control costs. However, the emission control additions required to comply with current Act requirements, the 1990 Amendments, the hazardous air pollutant regulations and the individual state implementation plans for NOx reductions are estimated to include costs in the range of $5 million to $10 million for the period 2010 through 2013. In March 2008, the EPA promulgated a new, lower National Ambient Air Quality Standard (NAAQS) for ground-level ozone. Within two years, the EPA was expected to designate new eight-hour ozone non-attainment areas. However, in September 2009, the EPA announced it would reconsider the 2008 NAAQS for ground level ozone to ensure that the standards were clearly grounded in science, and were protective of both public health and the environment. As a result, the EPA delayed designation of new eight-hour ozone non-attainment areas under the 2008 standards until the reconsideration is complete. In January 2010, the EPA proposed to further reduce the ground-level ozone NAAQS from the March 2008 levels. The EPA currently anticipates finalization of the new ground-level ozone standard in August 2010 and anticipates designation of new eight-hour ozone non-attainment areas under the new August 2010 ozone NAAQS standards in July 2011. Designation of new eight-hour ozone non-attainment areas would result in additional federal and state regulatory actions that would likely impact our operations and increase the cost of additions to property, plant and equipment. Additionally, the EPA is expected to promulgate additional hazardous air pollutant regulations in 2010 that will likely impact our operations. We are unable at this time to estimate with any certainty the cost of additions that may be required to meet new regulations, although we believe that some of those costs are included in the range discussed above. Management considers costs associated with compliance with the environmental laws and regulations described above to be prudent costs incurred in the ordinary course of business and, therefore, recoverable through our rates.
By letter dated September 20, 2007, the EPA required us to provide information regarding natural gas compressor stations in the states of Mississippi and Alabama as part of the EPA’s investigation of our compliance with the Act. By January 2008, we responded with the requested information. By Notices of Violation (NOVs) dated March 28, 2008, the EPA found us to be in violation of the requirements of the Act
with respect to these compressor stations. We met with the EPA in May 2008 to discuss the allegations contained in the NOVs; in June 2008, we submitted to the EPA a written response denying the allegations. In July 2009, the EPA requested additional information pertaining to these compressor stations; in August 2009, we submitted the requested information.
Safety Matters
Pipeline Integrity Regulations. We have developed an Integrity Management Plan that meets the United States Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA) final rule pursuant to the requirements of the Pipeline Safety Improvement Act of 2002. In meeting the integrity regulations, we have identified high consequence areas and completed our baseline assessment plan. We are on schedule to complete the required assessments within specified timeframes. Currently, we estimate that the cost to perform required assessments and remediation will be between $150 million and $220 million over the remaining assessment period of 2010 through 2012, the majority of which are capital expenditures. Management considers the costs associated with compliance with the rule to be prudent costs incurred in the ordinary course of business and, therefore, recoverable through our rates.
Appomattox, Virginia Pipeline Rupture. On September 14, 2008, we experienced a rupture of our 30-inch diameter mainline B pipeline near Appomattox, Virginia. The rupture resulted in an explosion and fire which caused several minor injuries and property damage to several nearby residences. On September 25, 2008, PHMSA issued a Corrective Action Order (CAO) which required that we operate three of our mainlines in a portion of Virginia at reduced operating pressure and prescribes various remedial actions that must be undertaken before the lines can be restored to normal operating pressure. On October 6, 2008, we filed a request for hearing with PHMSA to challenge the CAO but asked that the hearing be stayed pending discussions with PHMSA to modify certain aspects of the order. PHMSA approved the request for stay. On November 7, 2008, PHMSA approved our request to restore the first of the three affected pipelines to normal operating pressure. On December 24, 2008, PHMSA approved our request to restore the second of the three affected pipelines to normal operating pressure. On May 6, 2009, PHMSA approved our request to restore the last of the three affected pipelines to normal operating pressure. In August 2009, PHMSA issued to us a Notice of Probable Violation and Proposed Civil Penalty of $1.0 million as a result of the incident. In September 2009, we paid the penalty.
Other Matters
Various other proceedings are pending against us incidental to our operations.
Summary
Litigation, arbitration, regulatory matters, environmental matters and safety matters are subject to inherent uncertainties. Were an unfavorable ruling to occur, there exists the possibility of a material adverse impact on the results of operations in the period in which the ruling occurs. Management, including internal counsel, currently believes that the ultimate resolution of the foregoing matters, taken as a whole and after consideration of amounts accrued, insurance coverage, recovery from customers or other indemnification arrangements will not have a material adverse effect upon our future liquidity or financial position.
Other Commitments
Commitments for construction and gas purchases. We have commitments for construction and
acquisition of property, plant and equipment of approximately $155 million at December 31, 2009. We have commitments for gas purchases of approximately $61 million at December 31, 2009. See Note 1 of Notes to Consolidated Financial Statements for our discussion of our agency agreement with WGM.
4. DEBT, FINANCING ARRANGEMENTS AND LEASES
Long-term debt At December 31, 2009 and 2008, long-term debt issues were outstanding as follows (in thousands):
Aggregate minimum maturities (face value) applicable to long-term debt outstanding at December 31, 2009 are as follows (in thousands):
There are no maturities applicable to long-term debt outstanding for the years 2010, 2013 and 2014.
No property is pledged as collateral under any of our long-term debt issues.
Revolving Credit and Letter of Credit Facility
As of December 31, 2009, Williams had an unsecured, $1.5 billion revolving credit facility (Credit Facility) with a maturity date of May 1, 2012. Prior to the restructuring, we had access to $400 million under the Credit Facility to the extent not otherwise utilized by Williams. A participating bank, which is committed to fund up to $70 million of the Credit Facility, has filed for bankruptcy. Williams expects that its ability to borrow under this facility is reduced by this committed amount. Consequently, we expect our ability to borrow under the Credit Facility is reduced by approximately $18.7 million. The committed amounts of other participating banks under this
agreement remain in effect and are not impacted by the above. As of December 31, 2009, no letters of credit have been issued by the participating institutions. There were no revolving credit loans outstanding as of December 31, 2009.
Interest under the Credit Facility is calculated based on a choice of two methods: a fluctuating rate equal to the lender’s base rate plus an applicable margin or a periodic fixed rate equal to the London Interbank Offered Rate plus an applicable margin. Williams is required to pay a commitment fee (currently 0.125 percent) based on the unused portion of the Credit Facility. The margins and commitment fee are generally based on the specific borrower’s senior unsecured long-term debt ratings.
The Credit Facility contains certain affirmative covenants and a number of restrictions on the business of the borrowers, including us. These restrictions include restrictions on the borrowers’ ability to grant liens securing indebtedness, merge or sell all or substantially all of our assets and incurrence of indebtedness. Significant financial covenants under the Credit Facility include the following:
The Credit Facility also contains events of default tied to all borrowers which in certain circumstances would cause all lending under the Credit Facility to terminate and all indebtedness outstanding under the Credit Facility to be accelerated.
On February 17, 2010, Williams completed a strategic restructuring which involved contributing substantially all of its domestic midstream and pipeline businesses, which includes us, into WPZ. We are now a wholly-owned subsidiary of WPZ.
As part of the restructuring, we were removed as borrowers under the Credit Facility and on February 17, 2010, we entered into a new $1.75 billion three-year senior unsecured revolving credit facility (the “New Credit Facility”) with WPZ and Northwest Pipeline GP (“Northwest”), as co-borrowers, and Citibank N.A., as administrative agent, and certain other lenders named therein. The full amount of the New Credit Facility is available to WPZ, and may be increased by up to an additional $250 million. We may borrow up to $400 million under the New Credit Facility to the extent not otherwise utilized by WPZ and Northwest. At closing, WPZ borrowed $250 million under the New Credit Facility to repay the term loan outstanding under its existing senior unsecured credit agreement.
Interest on borrowings under the New Credit Facility is payable at rates per annum equal to, at the option of the borrower: (1) a fluctuating base rate equal to Citibank, N.A.’s adjusted base rate plus the applicable margin, or (2) a periodic fixed rate equal to LIBOR plus the applicable margin. The adjusted base rate will be the highest of (i) the federal funds rate plus 0.5 percent, (ii) Citibank N.A.’s publicly announced base rate, and (iii) one-month LIBOR plus 1.0 percent. WPZ pays a commitment fee (currently 0.5 percent) based on the unused portion of the New Credit Facility. The application margin and the commitment fee are determined by reference to a pricing schedule based on a borrower’s senior unsecured debt ratings.
The New Credit Facility contains various covenants that limit, among other things, the borrower’s and its respective subsidiaries’ ability to incur indebtedness, grant certain liens supporting indebtedness, merge or consolidate, sell all or substantially all of its assets, enter into certain affiliate transactions, make certain distributions during an event of default, and allow any material change in the nature of their business.
Under the New Credit Facility, WPZ is required to maintain a ratio of debt to Earnings Before Income Taxes, Interest, Depreciation and Amortization (EBITDA) (each as defined in the New Credit Facility) of no greater than 5.00 to 1.00 for itself and its consolidated subsidiaries. For us and our consolidated subsidiaries, the ratio of debt to capitalization (defined as net worth plus debt) is not permitted to be greater than 55%. Each of the above ratios will be tested, beginning June 30, 2010, at the end of each fiscal quarter, and the debt to EBITDA ratio is measured on a rolling four-quarter basis.
The New Credit Facility includes customary events of default, including events of default relating to non-payment of principal, interest or fees, inaccuracy of representations and warranties in any material respect when made or when deemed made, violation of covenants, cross-payment defaults, cross acceleration, bankruptcy and insolvency events, certain unsatisfied judgments and a change of control. If an event of default with respect to a borrower occurs under the New Credit Facility, the lenders will be able to terminate the commitments for all borrowers and accelerate the maturity of the loans of the defaulting borrower under the New Credit Facility and exercise other rights and remedies.
Issuance and Retirement of Long-Term Debt
In January 2008, we borrowed $100 million under the Credit Facility to retire $100 million of 6.25 percent senior unsecured notes that matured on January 15, 2008. In April 2008, we borrowed $75 million under the Credit Facility to retire $75 million of adjustable rate unsecured notes that matured on April 15, 2008.
On May 22, 2008, we issued $250 million aggregate principal amount of 6.05 percent senior unsecured notes due 2018 to certain institutional investors in a Rule 144A private debt placement. We used $175 million of the net proceeds to repay our borrowings under the Credit Facility. In September 2008, we completed an exchange of these notes for new notes that are registered under the Securities Act of 1933, as amended.
Restrictive covenants At December 31, 2009, none of our debt instruments restrict the amount of dividends distributable to WGP. Effective February 17, 2010, the New Credit Facility restricts certain payments that we can make following an event of default.
Lease obligations On October 23, 2003, we entered into a lease agreement for space in the Williams Tower in Houston, Texas (Williams Tower). The lease term runs through March 31, 2014.
On July 1, 2006, we entered into a sublease agreement with our affiliate, Williams Field Services Company, for space in the Williams Tower. The lease term runs through March 31, 2014. On May 1, 2007, we entered into an agreement to sublease space in the Williams Tower to our affiliate, Williams Field Services Company. The lease term runs through March 29, 2014.
The future minimum lease payments under our various operating leases, including the Williams Tower leases are as follows (in thousands):
Our lease expense was $9.8 million in 2009, $9.1 million in 2008, and $9.5 million in 2007.
5. FAIR VALUE MEASUREMENTS
We are entitled to collect in rates the amounts necessary to fund our asset retirement obligations (ARO). We deposit monthly, into an external trust account, the revenues specifically designated for ARO. We established the ARO trust account (ARO Trust) on June 30, 2008. The ARO Trust carries a moderate risk portfolio. We measure the financial instruments held in our ARO Trust at fair value. However, in accordance with the ASC Topic 980, Regulated Operations, both realized and unrealized gains and losses of the ARO Trust are recorded as regulatory assets or liabilities.
The fair value hierarchy prioritizes the inputs used to measure fair value, giving the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). We classify fair value balances based on the observability of those inputs. The three levels of the fair value hierarchy are as follows:
•
Level 1 - Quoted prices in active markets for identical assets or liabilities that we have the ability to access. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 consists of financial instruments in our ARO Trust totaling $22.0 million at December 31, 2009. These financial instruments include money market funds, U.S. equity funds, international equity funds and municipal bond funds.
•
Level 2 - Inputs are other than quoted prices in active markets included in Level 1, that are either directly or indirectly observable. These inputs are either directly observable in the marketplace or indirectly observable through corroboration with market data for substantially the full contractual term of the asset or liability being measured. We do not have any Level 2 measurements.
•
Level 3 - Includes inputs that are not observable for which there is little, if any, market activity for the asset or liability being measured. These inputs reflect management’s best estimate of the assumptions market participants would use in determining fair value. We do not have any Level 3 measurements.
6. EMPLOYEE BENEFIT PLANS
Pension and other postretirement benefit plans We participate in pension and other postretirement benefit plans sponsored by Williams. We account for these plans on the multi-employer accounting model in which we expense the amounts billed to us by Williams or other Williams’ affiliates for our participation in these plans. We recognized pension expense of $20.3 million, $5.2 million and $6.4 million for 2009, 2008 and 2007, respectively. We recognized other postretirement benefit expense of $3.3 million, $3.6 million and $4.3 million for 2009, 2008 and 2007, respectively.
We have been allowed by rate case settlements to collect or refund in future rates any differences between the actuarially determined costs and amounts currently being recovered in rates related to other postretirement benefits. Any differences between the annual actuarially determined cost and amounts currently being recovered in rates are recorded as an adjustment to revenues or expense and collected or refunded through future rate adjustments. The amounts of postretirement benefits costs deferred as a regulatory liability at December 31, 2009 and 2008 are $4.7 million and $2.7 million, respectively, and are expected to be refunded through future rates. The amounts of postretirement benefits costs deferred as regulatory assets at December 31, 2009 and 2008 are $7.9 million and $10.7 million respectively, and are currently being recovered over a ten year period beginning March 1, 2007.
Defined contribution plan Our employees participate in a Williams defined contribution plan. We recognized compensation expense of $6.7 million, $6.3 million and $6.0 million in 2009, 2008 and 2007, respectively, for Williams’ company matching contributions to this plan.
Employee Stock-Based Compensation Plan Information The Williams Companies, Inc. 2007 Incentive Plan (Plan) was approved by stockholders on May 17, 2007. The Plan provides for Williams common-stock-based awards to both employees and nonmanagement directors. The Plan permits the granting of various types of awards including, but not limited to, restricted stock units and stock options. Awards may be granted for no consideration other than prior and future services or based on certain financial performance targets being achieved.
Williams currently bills us directly for compensation expense related to stock-based compensation awards granted directly to our employees based on the fair value of the options. We are also billed for our proportionate share of both WGP’s and Williams’ stock-based compensation expense though various allocation processes.
Accounting for Stock-Based Compensation Compensation cost for share-based awards is based on the grant date fair value. The performance targets for certain performance based restricted stock units have not been established and therefore expense is not currently recognized. Expense associated with these performance-based awards will be recognized in future periods when performance targets are established.
Total stock-based compensation expense, included in administrative and general expenses, for the years ended December 31, 2009, 2008 and 2007 was $3.2 million, $2.4 million and $2.1 million, respectively, excluding amounts allocated from WGP and Williams.
Business Restructuring In connection with Williams’ recent restructuring, all of our employees were transferred to another Williams’ affiliate effective as of February 16, 2010. This affiliate will provide the personnel to perform the services previously conducted by our employees and will charge us for these services according to a new service agreement. (See Note 9.)
7. INCOME TAXES
Following is a summary of the (benefit) provision for income taxes for 2009, 2008, and 2007 (in thousands):
Following is a reconciliation of the (benefit) provision for income taxes at the federal statutory rate to the (benefit) provision for income taxes (in thousands):
Following our conversion on December 31, 2008 to a single member limited liability company, for which an election was made to be treated as a disregarded entity, we are no longer subject to income tax, except for the Texas Gross Margin tax. Subsequent to the conversion, all deferred income taxes were eliminated.
In 2009, the state income taxes reflect a current benefit for the Texas Gross Margin tax. Since we are considered a Service business for Texas tax purposes, we are not allowed a cost of goods sold deduction for book to tax differences and therefore there is no deferred Texas Gross Margin tax.
As of December 31, 2009, the Internal Revenue Service (IRS) examinations of Williams’ consolidated U.S. income tax returns for 2008 is in process. IRS examinations for 1997 through 2007 have been completed at the field level but the years remain open for certain disagreed issues. The statute of limitations for most states expires one year after IRS audit settlement.
8. FINANCIAL INSTRUMENTS AND GUARANTEES
Fair value of financial instruments The carrying amount and estimated fair values of our financial instruments as of December 31, 2009 and 2008 are as follows (in thousands):
For cash and short-term financial assets (third-party notes receivable and advances to affiliates) that have variable interest rates, the carrying amount is a reasonable estimate of fair value due to the short maturity of those instruments. For long-term financial assets (long-term receivables), the carrying amount is a reasonable estimate of fair value because the interest rate is a variable rate.
The fair value of our publicly traded long-term debt is valued using year-end traded bond market prices. Private debt is valued based on the prices of similar securities with similar terms and credit ratings. At December 31, 2009 and 2008, 100 percent of long-term debt was publicly traded. As a participant in Williams’ cash management program, we make advances to and receive advances from Williams. Advances are stated at the historical carrying amounts. At December 31, 2009, the advances due to us by Williams totaled $186.1 million and are reflected as a reduction of owner's equity. At December 31, 2008, the advances due to us by Williams totaled $186.2 million and are reflected in current assets. Advances to affiliates are due on demand. However, in accordance with the restructuring of Williams’ business in February 2010, our Management Committee authorized a distribution which included an amount equivalent to our advance balance and related interest outstanding. Accordingly, our advance balance and related interest receivable at December 31, 2009 are reflected as a reduction of owner’s equity as the advances will not be available to us as working capital.
9. TRANSACTIONS WITH MAJOR CUSTOMERS AND AFFILIATES
Major Customers In 2009, operating revenues received from National Grid (formerly known as KeySpan Corporation), Public Service Enterprise Group, and Piedmont Natural Gas Company, our three major customers, were $120.3 million, $111.4 million, and $78.4 million, respectively. In 2008, operating revenues received from Public Service Enterprise Group, National Grid, and Piedmont Natural Gas Company, our three major customers, were $132.3 million, $120.4 million, and $81.8 million, respectively. In 2007, operating revenues received from Public Service Enterprise Group, KeySpan Corporation, and Piedmont Natural Gas Company, our three major customers, were $141.9 million, $86.1 million, and $84.4 million, respectively.
Affiliates As a participant in Williams’ cash management program, we make advances to and receive advances from Williams. At December 31, 2009, the advances due to us by Williams totaled $186.1 million and are reflected as a reduction of owner’s equity. At December 31, 2008, the advances due to us by Williams totaled approximately $186.2 million and are reflected in current assets. The advances are represented by demand notes. The interest rate on intercompany demand notes is based upon the weighted average cost of Williams’ debt outstanding at the end of each quarter. At December 31, 2009, the interest rate was 8.02
percent. We received interest income from advances to Williams of $19.1 million, $22.0 million, and $14.9 million during 2009, 2008 and 2007, respectively. Such interest income is included in Other Income - affiliates on the accompanying Consolidated Statement of Income. However, in connection with Williams’ restructuring in February 2010, our Management Committee authorized a distribution which included an amount equivalent to our advance balance and related interest outstanding. Accordingly, our advance balance and related interest receivable at December 31, 2009 are reflected as a reduction of owner’s equity as the advances will not be available to us as working capital.
Included in our operating revenues for 2009, 2008 and 2007 are revenues received from affiliates of $21.9 million, $35.8 million, and $42.8 million, respectively. The rates charged to provide sales and services to affiliates are the same as those that are charged to similarly-situated nonaffiliated customers.
Through an agency agreement with us, WGM manages our jurisdictional merchant gas sales. The agency fees billed by WGM for 2007 through 2009 were not significant.
Included in our cost of sales for 2009, 2008 and 2007 is purchased gas cost from affiliates, excluding the agency fees discussed above, of $5.2 million, $14.3 million, and $9.7 million, respectively. All gas purchases are made at market or contract prices.
We have long-term gas purchase contracts containing variable prices that are currently in the range of estimated market prices. Our estimated purchase commitments under such gas purchase contracts are not material to our total gas purchases. Furthermore, through the agency agreement with us, WGM has assumed management of our merchant sales service and, as our agent, is at risk for any above-spot-market gas costs that it may incur.
Williams has a policy of charging subsidiary companies for management services provided by the parent company and other affiliated companies. Included in our administrative and general expenses for 2009, 2008 and 2007 were $50.7 million, $44.9 million, and $53.2 million, respectively, for such corporate expenses charged by Williams and other affiliated companies. Management considers the cost of these services to be reasonable.
Pursuant to an operating agreement, we serve as contract operator on certain Williams Field Services (WFS) facilities. Transco recorded reductions in operating expenses for services provided to and reimbursed by WFS of $9.1 million, $7.8 million, and $5.8 million in 2009, 2008 and 2007 respectively, under terms of the operating agreement.
As a result of Williams’ restructuring of its business units, effective as of February 16, 2010, all of our former employees were transferred to our affiliate, Transco Pipeline Services LLC (TPS), a Delaware limited liability company. On February 17, 2010, we entered into an administrative services agreement pursuant to which TPS will provide personnel, facilities, goods and equipment not otherwise provided by us that are necessary to operate our business. In return, we will reimburse TPS for all direct and indirect expenses it incurs or payments it makes (including salary, bonus, incentive compensation and benefits) in connection with these services.
10. ASSET RETIREMENT OBLIGATIONS
We record an asset and a liability equal to the present value of each expected future ARO. The ARO asset is depreciated in a manner consistent with the depreciation of the underlying physical asset. We measure changes in the liability due to passage of time by applying an interest method of allocation. The depreciation of the ARO asset and accretion of the ARO liability are recognized as an increase to a regulatory asset which will be amortized commensurate with our collection of those costs in rates.
The asset retirement obligation at December 31, 2009 and 2008 was $229.4 million. During 2009 and 2008, our overall asset retirement obligation changed as follows (in thousands):
The accrued obligations relate to underground storage caverns, offshore platforms, pipelines, and gas transmission facilities. At the end of the useful life of each respective asset, we are legally obligated to plug storage caverns and remove any related surface equipment, to dismantle offshore platforms, to cap certain gathering pipelines at the wellhead connection and remove any related surface equipment, and to remove certain components of gas transmission facilities from the ground.
We are entitled to collect in rates the amounts necessary to fund our ARO. All funds received for such retirements shall be deposited into an external trust account dedicated to funding our ARO. On June 30, 2008, we deposited the initial funding of $11.2 million, which included an adjustment for the total spending on ARO requirements as of May 31, 2008. We have an annual funding obligation of approximately $16.7 million, with installments to be deposited monthly.
11. REGULATORY ASSETS AND LIABILITIES
The regulatory assets and regulatory liabilities resulting from our application of the provisions of ASC Topic 980, Regulated Operations, included in the accompanying Consolidated Balance Sheet at December 31, 2009 and December 31, 2008 are as follows (in millions):
12. QUARTERLY INFORMATION (UNAUDITED)
The following summarizes selected quarterly financial data for 2009 and 2008 (in thousands):
(1) Includes a $10.5 million decrease to operating expenses resulting from state franchise tax reductions and a $2.5 million increase to operating expenses resulting from an accrued obligation associated with an unclaimed property audit.
(2) Includes a $2.4 million increase to operating revenues resulting from an adjustment to the reserve for rate refunds.
(3) Includes a $9.5 million decrease to operating expenses resulting from a gain on the sale of top gas from the Eminence storage facility and a $3.4 million decrease to operating expenses resulting from recording the difference between amounts accrued and amounts collected in rates for Asset Retirements Obligations.
(4) Includes a $10.4 million decrease to operating expenses resulting from a gain on the sale of South Texas assets and a $4.0 million increase to operating expenses resulting from an accrual for a pipeline rupture near Appomattox, Virginia. The accrual was subsequently increased to $4.5 million in the fourth quarter.
(5) Includes a $2.1 million decrease to operating expenses resulting from the reversal of a liability associated with unidentified transportation and exchange gas for a prior year.
TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
(In thousands)
(1) Rate refunds were paid in the Third Quarter of 2008.
(2) Additions to reserve for rate refunds primarily due to placing into effect, subject to refund, the rates in Docket No. RP06-569 March 1, 2007.
Item 9.
Item 9. Changes In and Disagreements With Accountants on Accounting and Financial Disclosure
None.
Item 9A(T).
Item 9A(T). Controls and Procedures
Disclosure Controls and Procedures
Our management, including our Senior Vice President and our Vice President and Treasurer, does not expect that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act) (Disclosure Controls) will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within Transco have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our Disclosure Controls and make modifications as necessary; our intent in this regard is that the Disclosure Controls will be modified as systems change and conditions warrant.
An evaluation of the effectiveness of the design and operation of our Disclosure Controls was performed as of the end of the period covered by this report. This evaluation was performed under the supervision and with the participation of our management, including our Senior Vice President and our Vice President and
Treasurer. Previously, our management had concluded that our Disclosure Controls were effective at a reasonable assurance level at December 31, 2008. Based upon our current evaluation, which considered the material weakness described in Management’s Report on Internal Control Over Financial Reporting, our Senior Vice President and our Vice President and Treasurer concluded that these Disclosure Controls were not effective at a reasonable assurance level at December 31, 2008. Our management also concluded that these Disclosure Controls were not effective at a reasonable assurance level at December 31, 2009.
As discussed in Item 8. Financial Statements and Supplementary Data-Management’s Report on Internal Control Over Financial Reporting and Note 2 of the Notes to Consolidated Financial Statements, in the first quarter of 2010, we identified a material weakness related to the manner in which we presented and recognized certain pension and post retirement obligations in certain benefit plans for which our parent is the plan sponsor. We have corrected our method of accounting for the parent-allocated amounts related to certain pension and post retirement plans to the multi-employer model. We have also enhanced our controls that ensure proper selection and application of generally accepted accounting principles.
Management’s Annual Report on Internal Control over Financial Reporting
See report set forth above in Item 8, “Financial Statements and Supplementary Data.”
Changes in Internal Controls Over Financial Reporting
There have been no changes during the fourth quarter of 2009 that have materially affected, or are reasonably likely to materially affect, our Internal Controls over financial reporting. However, in the first quarter of 2010, we enhanced our controls that ensure proper selection and application of generally accepted accounting principles. We also made the change described above in our method of accounting for parent-allocated amounts related to certain pension and post retirement plans and that change is reflected in our financial statements for the period ended December 31, 2009.
Item 9B.
Item 9B. Other Information
None
PART III
Since we meet the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K, the information required by Items 10, 11, 12, and 13 is omitted.
Item 14.
Item 14. Principal Accountant Fees and Services
Fees for professional services provided by our independent registered public accounting firm in each of the last two fiscal years in each of the following categories are (in thousands):
Fees for audit services include fees associated with the annual audit, the reviews for our quarterly reports on Form 10-Q, the reviews for other SEC filings and accounting consultation. Audit-related fees include other attestation services.
As a wholly owned subsidiary of Williams, we do not have a separate Audit Committee. The Williams Audit Committee policies and procedures for pre-approving audit and non-audit services will be set forth in the proxy statement for Williams’ 2010 annual meeting of stockholders which will be available upon its filing on the SEC’s website at http://www.sec.gov and on the Williams website at http://www.williams.com under the heading “Investors-SEC Filings”.
PART IV
Item 15.
Item 15. Exhibits and Financial Statement Schedules
The following schedules are omitted because of the absence of the conditions under which they are required:
I, III, IV, and V.
3.
Exhibits:
The following instruments are included as exhibits to this report. Those exhibits below incorporated by reference herein are indicated as such by the information supplied in the parenthetical thereafter. If no parenthetical appears after an exhibit, copies of the instrument have been included herewith.
(3)
Articles of incorporation and by-laws
(4)
Instruments defining the rights of security holders, including indentures
-
Certification of Principal Executive Officer and Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
TRANSCONTINENTAL GAS PIPE
LINE COMPANY, LLC
(Registrant)
By:
/s/ Jeffrey P. Heinrichs
Jeffrey P. Heinrichs
Controller and Assistant Treasurer
Date: February 22, 2010
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Date: February 22, 2010
INDEX OF EXHIBITS