UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
| x | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 2012
OR
| ¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission file number 1-7584
TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
(Exact Name of Registrant as Specified in Its Charter)
| Delaware | 74-1079400 | |
| (State or Other Jurisdiction of Incorporation or Organization) |
(I.R.S. Employer Identification No.) | |
| 2800 Post Oak Boulevard, Houston, Texas |
77056 | |
| (Address of Principal Executive Offices) | (Zip Code) | |
713-215-2000
(Registrant’s Telephone Number, Including Area Code)
Securities registered pursuant to Section 12(b) of the Act:
None
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No x
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
| Large accelerated filer | ¨ | Accelerated filer | ¨ | |||
| Non-accelerated filer | x (Do not check if a smaller reporting company) | Smaller reporting company | ¨ | |||
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x
DOCUMENTS INCORPORATED BY REFERENCE
None
REGISTRANT MEETS THE CONDITIONS SET FORTH IN GENERAL INSTRUCTIONS (I) (1)(a) AND (b) OF FORM 10-K AND IS THEREFORE FILING THIS FORM 10-K WITH THE REDUCED DISCLOSURE FORMAT.
TRANSCONTINTENTAL GAS PIPE LINE COMPANY, LLC
FORM 10-K
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DEFINITIONS
We use the following gas measurements in this report:
Bcf – means billion cubic feet.
Mdth – means thousand dekatherms.
Mdth/d – means thousand dekatherms per day.
MMdth – means million dekatherms.
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In this report, Transcontinental Gas Pipe Line Company, LLC (Transco) is at times referred to in the first person as “we”, “us” or “our”.
Transco is owned, through Williams Partners Operating LLC (WPO), by Williams Partners L.P. (WPZ), a publicly traded Delaware limited partnership, which is consolidated by The Williams Companies, Inc. (Williams). Williams holds an approximate 70 percent interest in WPZ, comprised of an approximate 68 percent limited partner interest and all of WPZ’s 2 percent general partner interest.
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, Delaware, 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 is regulated by the Federal Energy Regulatory Commission (FERC).
At December 31, 2012, our system had a mainline delivery capacity of approximately 5.8 MMdth of gas per day from production areas to our primary markets including delivery capacity from the mainline to locations on our Mobile Bay Lateral. Using our Leidy Line along with market-area storage and transportation capacity, we can deliver an additional 4.0 MMdth of gas per day for a system-wide delivery capacity total of approximately 9.8 MMdth of gas per day. The system is comprised of approximately 9,800 miles of mainline and branch transmission pipelines, 45 compressor stations, four underground storage fields and one 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 200 Bcf of gas. At December 31, 2012, our customers had stored in our facilities approximately 150 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.
MARKETS AND TRANSPORTATION
Our natural gas pipeline system serves customers in Texas and 12 southeast and Atlantic seaboard states including major metropolitan areas in Georgia, North Carolina, Washington, D.C., Maryland, 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 2012 were Public Service Enterprise Group and National Grid, which accounted for approximately 10.3 percent and 7.6 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 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.
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PIPELINE PROJECTS
The pipeline projects listed below were either completed during 2012 or are significant future pipeline projects for which we have customer commitments.
Mid-South
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. In August 2011, we received approval from the FERC for the project. The capital cost of the project is estimated to be approximately $200 million. We placed the first phase of the project into service in September 2012 which increased capacity by 95 Mdth/d. We plan to place the second phase of the project into service in June 2013 which will increase capacity by an additional 130 Mdth/d.
Mid-Atlantic Connector
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. In July 2011, we received approval from the FERC for the project. The capital cost of the project is estimated to be approximately $60 million. We placed the project into service in the first quarter of 2013, and it increased capacity by 142 Mdth/d.
Northeast Supply Link
The Northeast Supply Link Project involves an expansion of our existing natural gas transmission system from the Marcellus Shale production region on the Leidy Line to various delivery points in Zone 6. In November 2012, we received approval from the FERC for the project. The capital cost of the project is estimated to be approximately $390 million. We plan to place the project into service in November 2013, and it will increase capacity by 250 Mdth/d.
Rockaway Delivery Lateral
The Rockaway Delivery Lateral Project involves the construction of a three-mile offshore lateral to National Grid’s distribution system in New York. We filed an application with the FERC in January 2013. The capital cost of the project is estimated to be approximately $180 million. We plan to place the project into service during the second half of 2014, and its capacity will be 647 Mdth/d.
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. We anticipate filing an application with the FERC in the second quarter of 2013. The capital cost of the project is estimated to be approximately $50 million. We plan to place the project into service during the second half of 2014, and it will increase capacity by 100 Mdth/d.
Virginia Southside
The Virginia Southside Expansion Project involves an expansion of our existing natural gas transmission system from the Zone 6 Station 210 Pooling Point in New Jersey to Dominion Virginia Power’s proposed power station in Brunswick County, Virginia, and both our Cascade Creek interconnect with East Tennessee Natural Gas and our Pleasant Hill delivery point to Piedmont Natural Gas Company, Inc. in North Carolina. We filed an application with the FERC in December 2012 for approval of the project. The capital cost of the project is estimated to be approximately $300 million. We plan to place the project into service in September 2015, and it will increase capacity by 270 Mdth/d.
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Leidy Southeast
The Leidy Southeast Expansion Project involves an expansion of our existing natural gas transmission system from the Marcellus Shale production region on the Leidy Line in Pennsylvania to the Station 85 pooling point in Alabama. We anticipate filing an application with the FERC in the fourth quarter of 2013. The capital cost of the project is estimated to be approximately $600 million. We plan to place the project into service in December 2015, and it will increase capacity by 469 Mdth/d.
RATE 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) contract and volume throughput assumptions. The allowed rate of return is determined in each rate case. Rate design and the allocation of costs between the reservation 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 reservation 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.
General rate case (Docket No. RP12-993) On August 31, 2012, we submitted to the FERC a general rate filing principally designed to recover increased costs and to comply with the terms of the settlement in our Docket No. RP06-569 rate proceeding (see below) to file a rate case no later than August 31, 2012. On September 28, 2012, the FERC issued an order accepting and suspending our filing to be effective March 1, 2013, subject to refund and the outcome of a hearing, except that rates for certain services that were proposed as overall rate decreases were accepted, without suspension, to be effective October 1, 2012. These decreased rates will not be subject to refund, but may be subject to decrease prospectively under the Natural Gas Act of 1938, Section 5.
General rate case (Docket No. RP06-569) On August 31, 2006, we submitted to the FERC a general rate filing principally 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. Certain parties sought rehearing of the FERC’s order and, on April 2, 2012, the FERC denied the rehearing request. On June 1, 2012, one of the parties filed an appeal in the U.S. Court of Appeals for the D.C. Circuit (D.C. Circuit). If the D.C. Circuit were to overturn the FERC’s order, we believe any refunds would not be material to our results of operations.
REGULATION
FERC Regulation.
Our interstate transmission and storage activities are subject to regulation by the FERC under the Natural Gas Act of 1938 (NGA), as amended, and under the Natural Gas Policy Act of 1978 (NGPA), as amended, 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. The FERC’s Standards of Conduct govern the relationship
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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 Matters.
Our operations are subject to federal environmental laws and regulations as well as the state and local laws and regulations adopted by the jurisdictions in which we operate. We could incur liability to governments or third parties for any unlawful discharge of pollutants into the air, soil, or water, as well as liability for cleanup costs. Materials could be released into the environment in several ways including, but not limited to:
| • | Leakage from gathering systems, underground gas storage caverns, pipelines, transportation facilities and storage tanks; |
| • | Damage to facilities resulting from accidents during normal operations; |
| • | Damages to onshore and offshore equipment and facilities resulting from storm events or natural disasters; |
| • | Blowouts, cratering and explosions. |
In addition, we may be liable for environmental damage caused by former operators of our properties.
We believe compliance with current environmental laws and regulations will not have a material adverse effect on our capital expenditures, earnings or competitive position. However, environmental laws and regulations could affect our business in various ways from time to time, including incurring capital and maintenance expenditures, fines and penalties, and creating the need to seek relief from the FERC for rate increases to recover the costs of certain capital expenditures and operation and maintenance expenses.
For additional information regarding the potential impact of federal, state or local regulatory measures on our business and specific environmental issues, please refer to “Risk Factors – We are subject to risks associated with climate change and – Our operations are subject to governmental laws and regulations relating to the protection of the environment, which may expose us to significant costs, liabilities and expenditures and could exceed current expectations,” and “Environmental Matters” in Note 2 of our Notes to Consolidated Financial Statements.
Safety and Maintenance.
Our operations are subject to the Natural Gas Pipeline Safety Act of 1968, as amended, the Pipeline Safety Improvement Act of 2002, and the Pipeline Safety, Regulatory Certainty, and Jobs Creation Act of 2011 (Pipeline Safety Act), which regulates safety requirements in the design, construction, operation and maintenance of interstate natural gas transmission facilities. The U.S. Department of Transportation (USDOT) administers federal pipeline safety laws.
Federal pipeline safety laws authorize USDOT to establish minimum safety standards for pipeline facilities and persons engaged in the transportation of gas or hazardous liquids by pipeline. These safety standards apply to the design, construction, testing, operation, and maintenance of gas and hazardous liquids pipeline facilities affecting interstate or foreign commerce. USDOT has also established reporting requirements for operators of gas and hazardous liquid pipeline facilities, as well as provisions for establishing the qualification of pipeline personnel and requirements for managing the integrity of gas transmission and distribution lines and certain hazardous liquid pipelines. To ensure compliance with these provisions, USDOT performs pipeline safety inspections and has the authority to initiate enforcement actions.
On January 3, 2012, the Pipeline Safety Act was enacted. The Pipeline Safety Act requires USDOT to complete a number of reports in preparation for potential rulemakings. The issues addressed in these rulemaking provisions include, but are not limited to, the use of automatic or remotely-controlled shut-off valves on new or replaced transmission line facilities, modifying the requirements for pipeline leak detection systems, and expanding the scope of the pipeline integrity management requirements. USDOT is considering these and other provisions in the Pipeline Safety Act and has sought public comment on changes to the standards in its pipeline safety regulations.
Pipeline Integrity Regulations We have developed an Integrity Management Plan that we believe complies with the United States Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA) final rule that was issued pursuant to the requirements of the Pipeline Safety Improvement Act of 2002. The rule requires gas pipeline operators to develop an integrity management program for transmission pipelines that could affect high consequence areas in the event of pipeline failure. The Integrity Management program includes a baseline assessment plan to be completed in 2012 along with periodic reassessments to be completed within required timeframes. In meeting the integrity regulations, we have identified high consequence areas and developed our baseline assessment plan. The required pipeline segments originally identified for assessment were completed within the required timeframe, with one exception which was reported to PHMSA. We estimate that the cost to complete the remediation associated with the 2012 assessments will be approximately $20 million, most of which we expect to be 2013 capital expenditures.
Reassessments of the original segments have begun as required by regulations. As new pipelines are constructed and new high consequence areas are created, additional pipeline segments are required to be added to the baseline assessment plan. These segments are also on schedule as required. 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.
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EMPLOYEES
Transco has no employees. Operations, management and certain administrative services are provided by Williams and its affiliates.
TRANSACTIONS WITH AFFILIATES
We engage in transactions with WPZ, Williams and other Williams’ subsidiaries. (See Note 1 and Note 7 of Notes to Consolidated Financial Statements.)
FORWARD-LOOKING STATEMENTS 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,” “assumes,” “forecasts,” “intends,” “might,” “goals,” “objectives,” “targets,” “planned,” “potential,” “projects,” “scheduled,” “will,” “guidance,” “outlook,” “in service date” or other similar expressions. These statements are based on management’s beliefs and assumptions and on information currently available to management and include, among others, statements regarding:
| • | Amounts and nature of future capital expenditures; |
| • | Expansion and growth of our business and operations; |
| • | Financial condition and liquidity; |
| • | Business strategy; |
| • | Cash flow from operations or results of operations; |
| • | Rate case filings; and |
| • | 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 that could cause actual results to differ from results contemplated by the forward-looking statements include, among others, the following:
| • | Availability of supplies, 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); |
| • | The strength and financial resources of our competitors; |
| • | Development of alternative energy sources; |
| • | The impact of operational and development hazards; |
| • | Costs of, changes in, or the results of laws, government regulations (including safety and climate change regulation and changes in natural gas production from exploration and production areas that we serve), environmental liabilities, litigation, and rate proceedings; |
| • | Our allocated costs for defined benefit pension plans and other postretirement benefit plans sponsored by our affiliates; |
| • | Changes in maintenance and construction costs; |
| • | Changes in the current geopolitical situation; |
| • | Our exposure to the credit risks of our customers and counterparties; |
| • | Risks related to strategy and financing, including restrictions stemming from our debt agreements, future changes in our credit ratings, and the availability and cost of credit; |
| • | Risks associated with future weather conditions; |
| • | Acts of terrorism, including cybersecurity threats and related disruptions; and |
| • | 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.
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Risks Inherent to Our Industry and Business
Our natural gas transportation and storage 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:
| • | fires, blowouts, cratering, and explosions; |
| • | uncontrolled releases of natural gas; |
| • | pollution and other environmental risks; |
| • | natural disasters; |
| • | aging infrastructure and mechanical problems; |
| • | damages to pipelines and pipeline blockages or other pipeline interruptions; |
| • | operator error; |
| • | damage caused by third party activity, such as operation of construction equipment; and |
| • | 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 our 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.
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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. The FERC’s policies promoting competition in natural gas markets are having the effect of increasing the natural gas transportation and storage options for our traditional customer base. Similarly, 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. 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 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. All of these competitive pressures 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 the 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 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. 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:
| • | the level of existing and new competition to deliver natural gas to our markets; |
| • | the growth in demand for natural gas in our markets; |
| • | whether the market will continue to support long-term firm contracts; |
| • | whether our business strategy continues to be successful; |
| • | the level of competition for natural gas supplies in the production basins serving us; and |
| • | 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.
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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 interstate 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 transportation, and import and export of natural gas supplies, adversely impacting our ability to fill the capacities of our transportation 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 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. In addition, if natural gas prices in the supply basins connected to our pipeline systems are higher than prices in other natural gas producing regions, our ability to compete with other transporters may be negatively impacted on a short-term basis, as well as with respect to our long-term recontracting activities.
If new supplies of natural gas are not obtained to replace the natural decline in volumes from existing supply basins, if natural gas supplies are diverted to serve other markets, if development in new supply basins where we do not have significant gathering or pipeline systems reduces demand for our services 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.
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Significant prolonged changes in natural gas prices could affect supply and demand and cause a reduction in or termination of our long-term transportation and storage contracts or 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.
Our costs of testing, maintaining or repairing our facilities may exceed our expectations, and the FERC or competition in our markets may not allow us to recover such costs in the rates we charge for our services.
We have experienced leaks and ruptures on our gas pipeline system, including a rupture near Appomattox, Virginia in 2008 and a rupture near Sweet Water, Alabama in 2011. We could experience additional unexpected leaks or ruptures on our gas pipeline system, or be required by regulatory authorities to test or undertake modifications to our systems that could result in a material adverse impact on our business, financial condition and results of operations if the cost of testing, maintaining or repairing our facilities exceed current expectations and the FERC or competition in our markets do not allow us to recover such costs in the rates we charge for our service. For example, in response to a recent third party pipeline rupture, PHMSA issued an Advisory Bulletin which, among other things, advises pipeline operators that if they are relying on design, construction, inspection, testing, or other data to determine the pressures at which their pipelines should operate, the records of that data must be traceable, verifiable and complete. More recently, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 became law and under this statute PHMSA may issue additional regulations addressing such records. Locating such records and, in the absence of any such records, verifying maximum pressures through physical testing or modifying or replacing facilities to meet the demands of such pressures, could significantly increase our costs. Additionally, failure to locate such records or verify maximum pressures could result in reductions of allowable operating pressures, which would reduce available capacity on our pipeline.
Legal and regulatory proceedings and investigations relating to the energy industry have adversely affected our business and may continue to do so. The operation of our businesses might also be adversely affected by changes in government regulations or in their interpretation or implementation, or the introduction of new laws or regulations applicable to our businesses or our customers.
Public and regulatory scrutiny of the energy industry has resulted in increased regulations being either proposed or implemented. Such scrutiny has also resulted in various inquiries, investigations and court proceedings. 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. Adverse effects may continue as a result of the uncertainty of these ongoing inquiries, investigations and court 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.
In addition, existing regulations might be revised or reinterpreted, new laws and regulations might be adopted or become applicable to us, our facilities or our customers, and future changes in laws and regulations could have a material adverse effect on our financial condition and results of operations. For example, various legislative and regulatory reforms associated with pipeline safety and integrity have been proposed recently, including the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 enacted on January 3, 2012. This law will result in the promulgation of new regulations to be administered by PHMSA affecting the operations of our gas pipeline system including, but not limited to, requirements relating to pipeline inspection, installation of additional valves and other equipment and records verification. These reforms and any future changes in related laws and regulations could significantly increase our costs and impact our operations. In addition, the FERC or competition in our markets may not allow us to recover such costs in the rates we charge for our services.
We are subject to risks associated with climate change and the regulation of greenhouse gas emissions.
Climate change and the costs that may be associated with its impacts and with the regulation of emissions of greenhouse gases (GHGs) 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.
In addition, legislative and regulatory responses related to GHGs and climate change create the potential for financial risk.
The U.S. Environmental Protection Agency (EPA) has issued a final determination that six GHG emissions are a threat to public safety and welfare and implemented permitting for new and/or modified large sources of GHG emissions. Increased public awareness and concern over climate change may result in additional state, regional and/or federal requirements to reduce or mitigate GHG emissions. The U.S. Congress and certain states have for some time been considering various forms of legislation related to GHG emissions and additional regulation of
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GHG emissions in our industry may be implemented under existing Clean Air Act programs. There have also been international efforts seeking legally binding reductions in emissions of GHGs.
Regulatory actions by the EPA or the passage of new climate change laws or regulations 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 and financial condition. 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. Legislation or regulations that may be adopted to address climate change could also affect the markets for our products and services by making our products and services less desirable than competing sources of energy.
Our operations are subject to governmental laws and regulations relating to the protection of the environment, which may expose us to significant costs, liabilities and expenditures that could exceed current expectations.
Substantial costs, liabilities, delays and other significant issues related to environmental laws and regulations are inherent in the gathering, transportation, and storage of natural gas, and as a result, we may be required to make substantial expenditures that could exceed current expectations. Our operations are subject to extensive federal, state and local laws and regulations governing environmental protection, endangered and threatened species, the discharge of materials into the environment and the security of chemical and industrial facilities.
Various governmental authorities, including the EPA, the U.S. Department of the Interior and analogous state agencies, 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, the issuance of injunctions limiting or preventing some or all of our operations and delays in granting permits.
There is inherent risk of the incurrence of environmental costs and liabilities in our business, some of which may be material, due to our handling of the products as they are gathered, transported, and stored, air emissions related to our operations, historical industry operations, waste and waste disposal practices, and the prior use of flow meters containing mercury. Joint and several, strict liability may be incurred without regard to fault under certain environmental laws and regulations, for the remediation of contaminated areas and in connection with spills or releases of materials associated with natural gas, oil and wastes on, under or from our properties and facilities. Private parties, including the owners of properties through which our pipeline system 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 noncompliance with environmental laws and regulations or for personal injury or property damage arising from our operations. Some sites at which we operate are located near current or former third-party hydrocarbon storage and processing or oil and natural gas operations or facilities, and there is a risk that contamination has migrated from those sites to ours. 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 changed regulations and increased costs due to stricter pollution control requirements or liabilities resulting from noncompliance with required operating or other regulatory permits. We make assumptions and develop expectations about possible expenditures related to environmental conditions based on current laws and regulations and current interpretation of those laws and regulations. If the interpretation of the laws and regulations themselves change, our assumptions and expectations may also 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. 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 or construction 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 are generally responsible for all liabilities associated with the environmental condition of our facilities and assets, whether acquired or developed, regardless of when the liabilities arose and whether they are known or
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unknown. In connection with certain acquisitions and divestitures, we could acquire, or be required to provide indemnification against, environmental liabilities that could expose us to material losses, which may not be covered by insurance. In addition, the steps we could be required to take to bring certain facilities into compliance could be prohibitively expensive, and we might be required to shut down, divest or alter the operation of those facilities, which might cause us to incur losses.
Increased regulation of energy extraction activities, including hydraulic fracturing, could result in reductions or delays in drilling and completing new oil and natural gas wells, which could decrease the volumes of natural gas that we transport.
Hydraulic fracturing, a practice involving the injection of water, sand and chemicals under pressure into tight geologic formations to stimulate oil and natural gas production, is currently exempt from federal regulation pursuant to the federal Safe Drinking Water Act (except when the fracturing fluids or propping agents contain diesel fuels). However, public concerns have been raised related to its potential environmental impact and there have been recent initiatives at the federal, state and local levels to regulate or otherwise restrict the use of hydraulic fracturing. Several states have adopted regulations that impose permitting, disclosure and well-completion requirements on hydraulic fracturing operations. The EPA has also announced regulatory and enforcement initiatives related to hydraulic fracturing and other natural gas extraction and production activities. We cannot predict whether any additional federal, state or local laws or regulations will be enacted in this area and if so, what their provisions would be. If new regulations are imposed related to oil and gas extraction, or if additional levels of reporting, regulation or permitting moratoria are required or imposed related to hydraulic fracturing, the volumes of natural gas that we transport could decline and our results of operations could be adversely affected.
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. Although some of these customers are subject to long-term contracts, we may be unable to negotiate extensions or replacements of these contracts on favorable terms, if at all. For the year ended December 31, 2012, our two largest customers were Public Service Enterprise Group and National Grid. These customers accounted for approximately 10.3 percent and 7.6 percent, respectively, of our operating revenues for the year ended December 31, 2012. The loss of all, or even a portion of, the revenues from contracted volumes supplied by these customers, 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, results of operations, financial condition, 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 our 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.
The failure of counterparties to perform their contractual obligations could adversely affect our operating results and financial condition.
Despite performing credit analysis prior to extending credit, we are exposed to the credit risk of our contractual counterparties in the ordinary course of business even though we monitor these situations and attempt to take appropriate measures to protect ourselves. In addition to credit risk, counterparties to our commercial agreements,
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such as transportation and storage agreements, may fail to perform their other contractual obligations. A failure of counterparties to perform their contractual obligations could cause us to write down or write off doubtful accounts, which could materially adversely affect our operating results 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 for the benefit of our customers. Because we do not own these third-party pipelines or facilities, their continuing operation is not within our control. If these pipelines or other 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 to end use markets, thereby reducing our revenues. 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. In those instances in which we do not own the land on which our facilities are located, we obtain 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, results of operations, financial condition, and cash flows.
We do not insure against all potential losses and could be seriously harmed by unexpected liabilities or by the inability of our insurers to satisfy our claims.
We are not fully insured against all risks inherent to our business, including environmental accidents. We do not maintain 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 annual aggregate with a $2 million per occurrence deductible. This insurance covers Williams, its subsidiaries, and certain of its affiliates, including us, for legal and contractual liabilities arising out of bodily 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.
Although we maintain property insurance on certain physical assets that we own, lease, or are responsible to insure, the policy may not cover the full replacement cost of all damaged assets or the entire amount of business interruption loss we may experience. In addition, certain perils may be excluded from coverage or sub-limited. We may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. We may elect to self insure a portion of our risks. We do not insure our onshore underground pipelines for physical damage, except at certain locations such as river crossings and compressor stations. Offshore assets are covered for property damage when loss is due to a named windstorm event and coverage for loss caused by a named windstorm is significantly sub-limited and subject to a large deductible. All of our 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.
In addition to the insurance coverage described above, Williams is a member of Oil Insurance Limited (OIL), an energy industry mutual insurance company, which provides coverage for damage to our property. As an insured member of OIL, Williams shares in the losses among other OIL members even if our property is not damaged. As a result, we may share in any losses incurred by Williams.
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Furthermore, any insurance company that provides coverage to us may experience negative developments that could impair their ability to pay any of our claims. As a result, we could be exposed to greater losses than anticipated and may have to obtain replacement insurance, if available, at a greater cost.
The occurrence of any risks not fully covered by insurance could have a material adverse effect on our business, financial condition, results of operations and cash flows, and our ability to repay our debt.
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.
Our growth may be dependent upon the construction of new transportation and storage facilities as well as the expansion of existing facilities. Construction or expansion of these facilities is subject to various regulatory, development and operational risks, including:
| • | the ability to obtain necessary approvals and permits by regulatory agencies on a timely basis and on acceptable terms; |
| • | the availability of skilled labor, equipment, and materials to complete expansion projects; |
| • | 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; |
| • | impediments on our ability to acquire rights-of-way or land rights on a timely basis and on acceptable terms; |
| • | 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 |
| • | 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 our 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, and companies’ relationships with their independent public accounting firms. It remains unclear what new laws or regulations will be adopted, and we cannot predict the ultimate impact that any such new laws or regulations could have. In addition, the Financial Accounting Standards Board (FASB), the SEC or the FERC could issue new rules that might impact how we are required to record revenues, expenses, assets, and liabilities. Any significant change in accounting standards or disclosure requirements could have a material adverse effect on our business, results of operations, and financial condition.
Failure of our service providers or disruptions to outsourcing relationships might negatively impact our ability to conduct our business.
We rely on Williams and other third parties for certain services necessary for us to be able to conduct our business. We have a limited ability to control these operations and the associated costs. Certain of Williams’ accounting and information technology functions that we rely on are currently provided by third party vendors, and sometimes from service centers outside of the United States. Services provided pursuant to these agreements could be disrupted. Similarly, the expiration of such agreements or the transition of services between providers could lead
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to loss of institutional knowledge or service disruptions. Our reliance on Williams and others as service providers and on Williams’ outsourcing relationships, and our limited ability to control certain costs, could have a material adverse effect on our business, results of operations and financial condition.
Risks Related to Strategy and Financing
Restrictions in our debt agreements and our leverage may affect our future financial and operating flexibility.
Our total outstanding long-term debt (including current portion) as of December 31, 2012, was $1,428.3 million.
The agreements governing our indebtedness contain covenants that restrict our ability to incur certain liens to support indebtedness and our ability to merge or consolidate or sell all or substantially all of our assets. In addition, certain of our debt agreements contain various covenants that restrict or limit, among other things, our ability to make certain distributions during the continuation of an event of default and our ability to enter into certain affiliate transactions and certain restrictive agreements and to change the nature of our business. Certain of our debt agreements also contain, and those we enter into in the future may contain, financial covenants and other limitations with which we will need to comply. Williams’ and WPZ’s debt agreements contain similar covenants with respect to such entities and their respective subsidiaries, including us.
Our debt service obligations and the covenants described above could have important consequences. For example, they could:
| • | Make it more difficult for us to satisfy our obligations with respect to our indebtedness, which could in turn result in an event of default on such indebtedness; |
| • | Impair our ability to obtain additional financing in the future for working capital, capital expenditures, general corporate purposes or other purposes; |
| • | Diminish our ability to withstand a continued or future downturn in our business or the economy generally; |
| • | Require us to dedicate a substantial portion of our cash flow from operations to debt service payments, thereby reducing the availability of cash for working capital, capital expenditures, general corporate purposes or other purposes; |
| • | Limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate, including limiting our ability to expand or pursue our business activities and preventing us from engaging in certain transactions that might otherwise be considered beneficial to us; |
| • | Place us at a competitive disadvantage compared to our competitors that have proportionately less debt. |
Our ability to comply with our debt covenants, to repay, extend or refinance our existing debt obligations and to obtain future credit will depend primarily on our operating performance, which will be affected by general economic, financial, competitive, legislative, regulatory, business and other factors, many of which are beyond our control and may differ materially from our current assumptions. Our ability to refinance existing debt obligations or obtain future credit will also depend upon the current conditions in the credit markets and the availability of credit generally. If we are unable to comply with these covenants, meet our debt service obligations or obtain future credit on favorable terms, or at all, we could be forced to restructure or refinance our indebtedness, seek additional equity capital or sell assets. We may be unable to obtain financing or sell assets on satisfactory terms, or at all.
Our failure to comply with the covenants in the documents governing our indebtedness could result in events of default, which could render such indebtedness due and payable. We may not have sufficient liquidity to repay our indebtedness in such circumstances. In addition, cross-default or cross-acceleration provisions in our debt agreements could cause a default or acceleration to have a wider impact on our liquidity than might otherwise arise from a default or acceleration of a single debt instrument. For more information regarding our debt agreements, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity”.
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We are not prohibited under our indentures from incurring additional indebtedness. Our incurrence of significant additional indebtedness would exacerbate the negative consequences mentioned above, and could adversely affect our ability to repay our existing indebtedness.
Our ability to obtain credit in the future will be affected by Williams’ and WPZ’s credit ratings.
Substantially all of Williams’ and WPZ’s operations are conducted through their respective subsidiaries. Each of Williams’ and WPZ’s cash flows are substantially derived from loans, dividends and distributions paid to them by their subsidiaries. Their 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 relationships with each of 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 a 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 credit rating could likely also result in a downgrading of our credit rating. A downgrading of a Williams or WPZ credit rating could limit our ability to obtain financing in the future upon favorable terms, if at all.
Difficult conditions in the global capital markets, the credit markets and the economy in general could negatively affect our business and results of operations.
Our business may be negatively impacted by adverse economic conditions or future disruptions in the global financial markets. Included among these potential negative impacts are reduced energy 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 reduce our access to credit markets, raise the cost of such access or require us, WPZ or Williams to provide additional collateral to our counterparties. We have availability under the 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. If financing is not available when needed, or is available only on unfavorable terms, we may be unable to implement our business plans or otherwise take advantage of business opportunities or respond to competitive pressures. In addition, financial markets have recently been affected by concerns over U.S. fiscal policy, including uncertainty regarding federal spending and tax policy, as well as the U.S. federal government’s debt ceiling and the federal deficit. These concerns, as well as actions taken by the U.S. federal government in response to these concerns, could significantly and adversely impact the global and U.S. economies and financial markets, which could negatively impact us in the manners described above.
A downgrade of our credit ratings could impact our liquidity, access to capital and our costs of doing business, and independent third parties outside of our control determine our credit ratings.
A downgrade of our credit ratings might increase our cost of borrowing and could require us to post collateral with third parties, negatively impacting our available liquidity. Our ability to access capital markets could also be limited by a downgrade of our credit ratings and other disruptions. Such disruptions could include:
| • | economic downturns; |
| • | deteriorating capital market conditions; |
| • | declining market prices for natural gas; |
| • | terrorist attacks or threatened attacks on our facilities or those of other energy companies; and |
| • | 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. Credit ratings are not recommendations to buy,
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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 we will maintain our current credit ratings.
WPZ 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.
Because we are an indirect wholly-owned subsidiary of WPZ, WPZ exercises substantial control over our business and operations and makes determinations with respect to, among other things, the following:
| • | payment of distributions and repayment of advances; |
| • | decisions on financings and our capital raising activities; |
| • | mergers or other business combinations; and |
| • | acquisition or disposition of assets. |
WPZ could decide to increase distributions or advances to our member consistent with existing debt covenants. This could adversely affect our liquidity.
Risks Related to Regulations That Affect Our Industry
Our natural gas transportation 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 natural gas transportation and storage operations are subject to 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:
| • | transportation of natural gas in interstate commerce; |
| • | rates, operating terms, and conditions of service, including initiation and discontinuation of services; |
| • | the types of services we may offer to our customers; |
| • | certification and construction of new interstate pipelines and storage facilities; |
| • | acquisition, extension, disposition, or abandonment of existing interstate pipelines and storage facilities; |
| • | accounts and records; |
| • | depreciation and amortization policies; |
| • | relationships with affiliated companies who are involved in marketing functions of the natural gas business; and |
| • | market manipulation in connection with interstate sales, purchases, or transportation of natural gas. |
Under the NGA, the FERC has authority to regulate providers of natural gas pipeline transportation and storage services in interstate commerce, and such providers may only charge rates that have been determined to be just and reasonable by the FERC. In addition, the FERC prohibits providers from unduly preferring or unreasonably discriminating against any person with respect to pipeline rates or terms and conditions of service.
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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.
Unlike other interstate 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 is referred to as an “IT feeder” charge. The “IT feeder” rate is charged only when gas is actually transported on the facilities and typically it is paid by producers or marketers. Because the “IT feeder” rate 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. This rate design disparity can result in producers bypassing our offshore facilities in favor of alternative transportation facilities.
The rates, terms and conditions for our interstate pipeline and storage services are set forth in our FERC-approved tariff. 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 laws governing our business.
Our operations are regulated by numerous governmental agencies including the FERC, the EPA and PHMSA. Should we fail to comply with applicable statutes, rules, regulations and orders, we could be subject to substantial penalties and fines. For example, under the Energy Policy Act of 2005, the 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 and under the recently enacted Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, PHMSA has civil penalty authority up to $200,000 per day, with a maximum of $2 million for any related series of violations. Any material penalties or fines under these or other statutes, rules, regulations or orders could have a material adverse impact on our business, financial condition, results of operations and cash flows.
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.
The outcome of future rate cases will determine the amount of income taxes that 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 the FERC on a case-by-case basis in rate cases where the amounts of the allowances will be established.
Risks Related to Employees, Outsourcing of Non-Core Support Activities, and Technology.
Institutional knowledge residing with current employees nearing retirement eligibility or, with former employees 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, or their service is no longer available, Williams may not be able to replace them with employees of comparable knowledge and experience. In addition, Williams may not be able to retain or recruit other qualified individuals, and Williams’ 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.
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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 we have no employees, 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, including those located offshore, can be adversely affected by hurricanes, floods, earthquakes, landslides, tornadoes and other natural phenomena and weather conditions, including extreme or unseasonable 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 has not been available at all. 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.
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 transport 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 operations, and cash flows.
Our business could be negatively impacted by security threats, including cybersecurity threats, and related disruptions.
We rely on our information technology infrastructure to process, transmit and store electronic information, including information we use to safely operate our assets. While we believe that we maintain appropriate information security policies and protocols, we face cybersecurity and other security threats to our information technology infrastructure, which could include threats to our operational and safety systems that operate our pipelines, plants and assets. We could face unlawful attempts to gain access to our information technology infrastructure, including coordinated attacks from hackers, whether state-sponsored groups, “hacktivists,” or private individuals. The age, operating systems or condition of our current information technology infrastructure and software assets and our ability to maintain and upgrade such assets could affect our ability to resist cybersecurity threats. We could also face attempts to gain access to information related to our assets through attempts to obtain unauthorized access by targeting acts of deception against individuals with legitimate access to physical locations, or information.
Our information technology infrastructure is critical to the efficient operation of our business and essential to our ability to perform day-to-day operations. Breaches in our information technology infrastructure or physical facilities, or other disruptions, could result in damage to our assets, safety incidents, damage to the environment, potential liability or the loss of contracts, and have a material adverse effect on our operations, financial position and results of operations.
21
Item 1B. Unresolved Staff Comments
None.
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. We lease our company offices in Houston, Texas.
The information called for by this item is provided in “Item 8. Financial Statements and Supplementary Data – Notes to Consolidated Financial Statements – Note 2. Contingent Liabilities and Commitments”.
Item 4. Mine Safety Disclosures
Not applicable.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
We are owned, through WPO, by WPZ, and Williams holds an approximate 70 percent interest in WPZ, comprised of an approximate 68 percent limited partner interest and all of WPZ’s 2 percent general partner interest.
Distributions totaling $246 million were declared and paid to our parent during the year ended December 31, 2012. An additional distribution of $65 million was declared and paid to our parent in January 2013. Distributions totaling $219 million were declared and paid to our parent during the year ended December 31, 2011.
In the year ended December 31, 2012, WPO made contributions totaling $150 million to us to fund a portion of our expenditures for additions to property, plant and equipment. In January 2013, WPO made an additional $55 million contribution. In the year ended December 31, 2011, WPO made contributions totaling $115 million. In 2012, we received a non-cash contribution of approximately $1.5 million related to the transfer of certain property, plant and equipment and other assets. In 2011, we made a non-cash return of capital of approximately $0.5 million related to the transfer of certain property, plant and equipment and other assets.
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. Management’s Discussion and Analysis of Financial Condition and Results of Operations
General
The following discussion and analysis of critical accounting estimates, results of operations and capital resources and liquidity should be read in conjunction with the financial statements and notes thereto included within Item 8.
22
Critical Accounting Estimates
Our financial statements reflect the selection and application of accounting policies that require management to make significant estimates and assumptions. We believe that the following are the most critical judgment areas in the application of accounting policies that currently affect our financial condition and results of operations.
Regulatory Accounting
We are regulated by the FERC. The Accounting Standards Codification (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’s assessment of the probability of recovery or pass through of regulatory assets and liabilities requires judgment and interpretation of laws and regulatory commission orders. If, for any reason, we cease to meet the criteria for application of regulatory accounting treatment for all or part of our operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the Balance Sheet and included in the Statement of Income for the period in which the discontinuance of regulatory accounting treatment occurs, unless otherwise required to be recorded under other provisions of U.S. GAAP. The aggregate amounts of regulatory assets reflected in the Balance Sheet are $251.6 million and $245.8 million at December 31, 2012 and 2011, respectively. The aggregate amounts of regulatory liabilities reflected in the Balance Sheet are $247.5 million and $184.8 million at December 31, 2012 and 2011, respectively. A summary of regulatory assets and liabilities is included in Note 9 of Notes to Consolidated Financial Statements.
Eminence Storage Field
We evaluate our long lived assets 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 performed an assessment of our Eminence storage field for impairment as of December 31, 2012. The carrying value at that date was $168 million, which includes $91 million of capitalized abandonment costs. Judgments and assumptions are inherent in our estimate of future cash flows used to evaluate Eminence, particularly the recoverability of abandonment costs in our future rates. In our evaluation, our estimate of the undiscounted cash flows of Eminence exceeded its carrying value, and thus no impairment loss was recognized in 2012. If the carrying value of Eminence had exceeded the undiscounted cash flows, an impairment loss would have been recognized to the extent that the carrying value exceeded the estimated fair value of the assets.
Results of Operations
Analysis of Financial Results
This analysis discusses financial results of our operations for the years 2012 and 2011. Variances due to changes in natural gas prices and transportation volumes have little impact on revenues, because under our rate design methodology, the majority of overall cost of service is recovered through firm capacity reservation charges in our transportation rates.
23
2012 COMPARED TO 2011
Operating Income and Net Income Operating income for 2012 was $330.1 million compared to $354.6 million for 2011. Net income for 2012 was $272.5 million compared to $279.7 million for 2011. The decrease in Operating income of $24.5 million (6.9 percent) was primarily due to an increase in Operating Costs and Expenses, partially offset by higher Natural gas transportation revenues in 2012 compared to 2011, as discussed below. The decrease in Net income of $7.2 million (2.6 percent) was mostly attributable to the decrease in Operating income, offset by a favorable change in net deductions in Other (Income) and Other Deductions, as discussed below.
Sales Revenues We 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 $43.3 million (39.9 percent) to $65.1 million for 2012 when compared to 2011. The decrease was primarily due to a $28.8 million decrease in system management gas sales, the absence of Hester base gas sales of $4.4 million, recorded in 2011, and lower cash-out sales of $9.8 million. System management gas sales and cash out sales are 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 2012 was $1,023.0 million compared to $983.6 million for 2011. The $39.4 million (4.0 percent) increase was primarily due to higher transportation reservation revenues of $39.6 million, ($15.5 million from our 85 North Phase II project placed in service in May 2011, $10.0 million from the Mid South project placed in service in September 2012, $10.0 million from the Pascagoula project placed in service in September 2011, and $4.1 million from the Mobile Bay South Phase II project placed in service in May 2011), partially offset by $2.6 million lower demand rates billed for some services due to lower filed rates, effective October 1, 2012.
Other Revenues Operating Revenues: Other decreased $2.4 million (30.0 percent) to $5.6 million for 2012, when compared to 2011, primarily due to a $1.5 million decrease in liquids revenues and royalties and a $1.0 million decrease in revenues from the Park and Loan Service.
Operating Costs and Expenses Excluding the Cost of natural gas sales which is directly offset in revenues, our operating expenses were approximately $59.3 million (7.6 percent) higher than 2011. This increase was primarily attributable to:
| • | An increase in Administrative and general expense of $26.5 million (17.9 percent), primarily resulting from a $21.8 million increase in allocated corporate expenses due to a higher proportionate share of these costs as a result of Williams’ spin off of WPX Energy, Inc. (WPX), which was completed on December 31, 2011 and Williams organizational restructuring related costs, a $2.9 million increase in information technology services, and a $1.8 million increase in rental costs; |
| • | An increase in Operation and maintenance expense of $17.9 million (6.5 percent), primarily resulting from $16.5 million higher labor related costs, a $11.6 million increase primarily related to compressor and pipeline repairs, and $1.9 million associated with the Alabama pipeline rupture, partially offset by a $12.1 million decrease in costs incurred to ensure the safety of the surrounding area associated with our Eminence storage field leak. (See further discussion below); |
| • | An increase in Depreciation and amortization costs of $6.7 million (2.6 percent) primarily resulting from an increase in the depreciation base due to additional plant placed in-service; |
| • | An unfavorable change in Other expense, net of $8.2 million (63.1 percent) primarily due to the absence of the $3.8 million gain on Hester base gas sales recorded in 2011, a $5.0 million accrual for a certain |
24
litigation matter, a $1.7 million increase in accretion expense, and a $1.7 million net increase in other project development related costs (reflective of a $2.7 million overall increase in such costs partially offset by the benefit of an overall increase of $1.0 million in the amount of such costs reversed from expense to capital upon determining that certain projects were probable of development and thus the costs are probable of recovery through project rates). Partially offsetting these unfavorable changes was a $5.4 million favorable change related to regulatory charges associated with recovery of postretirement benefits;
| • | An increase in Taxes – other than income taxes of $3.8 million (7.9 percent) primarily resulting from increases in property taxes, and; |
| • | Partially offset by a decrease in Cost of natural gas transportation of $3.9 million (10.9 percent) primarily resulting from a $2.0 million decrease due to lower electric power costs and a $1.4 million decrease in fuel costs. 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 2012 had a favorable change of $17.3 million (23.1 percent) over 2011 primarily due to $6.1 million in lower interest expense due to lower rates on our long-term debt, a $4.8 million favorable change primarily due to a higher amount of reimbursements for tax gross-up related to reimbursable projects, and a $4.0 million increase in allowance for equity and borrowed funds used during construction due to increased capital spending.
Eminence Storage Field Leak
On December 28, 2010, we detected a leak in one of the seven underground natural gas storage caverns at our Eminence Storage Field in Covington County, Mississippi. We have reduced the pressure in the cavern by safely venting and flaring gas, and by flowing gas into our pipeline. Due to the leak at this cavern and damage to the well at an adjacent cavern, both caverns are out of service. The event has not affected the performance of our obligations under our service agreements with our customers.
As a result of these occurrences, we have determined that these two caverns cannot be returned to service. In addition, two other caverns at the field, which were constructed at or about the same time as those caverns, have experienced operating problems, and we have determined that they should be retired. In September 2011 we filed an application with the FERC seeking authorization to abandon these four caverns. In February 2013, the FERC issued an order approving the abandonment. We estimate the cost to abandon the caverns, which will be capital in nature, will be approximately $92 million, which is expected to be spent through the end of 2013. This estimate is subject to change as work progresses and additional information becomes known. To the extent available, the abandonment costs will be funded from the ARO Trust. As of December 31, 2012, we have incurred approximately $69 million of abandonment costs. Management considers these costs to be prudent costs incurred in the abandonment of these caverns and expects to recover these costs, net of insurance proceeds, in future rate filings.
During 2012 and 2011, we incurred $2.5 million and $14.6 million, respectively, of expense related primarily to costs to ensure the safety of the surrounding area. We anticipate incurring additional expense of approximately $5 million in 2013.
Sweet Water, Alabama Pipeline Rupture
On December 3, 2011, we experienced a rupture of our 36-inch diameter Main Line C pipeline near Sweet Water, Alabama, in a mostly unpopulated area. The rupture resulted in an explosion and fire which caused timber damage to adjacent landowners. There were no injuries as a result of the rupture. On December 6, 2011, PHMSA issued a Corrective Action Order (CAO) outlining the steps required to ensure the safety of Main Line C before its return to service. In March 2012, we submitted our plan to PHMSA to place Main Line C back in service and in June 2012, we received temporary authorization from PHMSA to do so. In December 2012, PHMSA issued authorization to return the Main Line C to full pressure without restrictions. The adjacent B Line was exposed by the rupture and had coating damage due to the fire. We replaced that section of B Line. Mainlines A, D and E were not damaged and were quickly returned to full service. There was no impact to our customers.
25
Filing of Rate Case.
On August 31, 2012, we filed a general rate case with the FERC for an overall increase in rates. In September 2012, with the exception of certain rates that reflected a rate decrease, the FERC accepted and suspended our general rate filing to be effective March 1, 2013, subject to refund and the outcome of a hearing. We expect that our new rates, although still subject to refund until the rate case is resolved, will contribute to a modest increase in revenues in 2013. The specific rates that reflected a rate decrease were accepted, without suspension, to be effective October 1, 2012 and will not be subject to refund. The impact of these specific new rates that became effective October 1, 2012 is expected to reduce revenues by approximately $1.6 million for the period from January 1, 2013 until the remaining rates that are currently suspended become effective on March 1, 2013.
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, equity contributions from WPZ, collection of advances to WPZ, accessing capital markets, and, if required, borrowings under the Credit Facility described below and advances from WPZ.
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. We anticipate that we will be able to access public and private markets on terms commensurate with our credit ratings to finance our capital requirements.
In September 2012, WPZ amended its existing $2 billion senior unsecured revolving credit facility agreement to increase the aggregate commitments by $400 million. This facility was also amended to provide an additional $400 million increase to be available under certain conditions in the future. We may borrow up to $400 million under the credit facility to the extent not otherwise utilized by WPZ and Northwest Pipeline GP. See Note 3 of Notes to Consolidated Financial Statements for further discussion of the credit facility.
Through wholly-owned subsidiaries, we hold a 35 percent interest in Pine Needle and approximately a 45 percent interest in Cardinal, which have interest rate swap agreements that qualify as cash flow hedge transactions 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 and Cardinal’s hedge are recognized in other comprehensive income.
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 existing assets, extend useful lives, increase transmission or storage capacities from existing levels, reduce costs or enhance revenues. We anticipate
26
2013 capital expenditures will be between $590 million to $650 million. Of this total, $490 million to $570 million is considered nondiscretionary due to legal, regulatory, and/or contractual requirements, primarily due to expansion projects and mandatory pipeline integrity costs and U. S. Department of Transportation requirements.
Property, plant and equipment additions were $475 million, $386 million and $377 million for 2012, 2011 and 2010, respectively. The $89 million increase in 2012 compared to 2011 is primarily related to expansion projects. The $9 million increase in 2011 compared to 2010 is mostly related to the maintenance of existing facilities, primarily due to pipeline integrity costs.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
At December 31, 2012, 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, 2012. The table presents principal cash flows and weighted-average interest rates by expected maturity dates.
| December 31, 2012 |
Expected Maturity Date | |||||||||||||||
| 2013 | 2014 | 2015 | 2016 | |||||||||||||
| (Dollars in millions) | ||||||||||||||||
| Long-term debt: |
||||||||||||||||
| Fixed rate |
$ | — | $ | — | $ | — | $ | 200 | ||||||||
| Interest rate |
5.65 | % | 5.65 | % | 5.65 | % | 5.57 | % | ||||||||
| December 31, 2012 |
Expected Maturity Date | |||||||||||||||
| 2017 | Thereafter | Total | Fair Value | |||||||||||||
| (Dollars in millions) | ||||||||||||||||
| Long-term debt: |
||||||||||||||||
| Fixed rate |
$ | — | $ | 1,233 | $ | 1,433 | $ | 1,704 | ||||||||
| Interest rate |
5.53 | % | 5.12 | % | ||||||||||||
27
Item 8. Financial Statements and Supplementary Data
| Page | ||
| Management’s Annual Report on Internal Control over Financial Reporting |
29 | |
| 30 | ||
| 31 | ||
| 32-33 | ||
| 34 | ||
| 35-36 | ||
| 37-52 | ||
28
MANAGEMENT’S ANNUAL 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 – Atlantic-Gulf and our Vice President and Chief Accounting Officer, we assessed the effectiveness of our internal control over financial reporting as of December 31, 2012, based on the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework. Based on our assessment, we concluded that, as of December 31, 2012, our internal control over financial reporting was effective.
This annual report does not include a report of the company’s registered public accounting firm regarding internal control over financial reporting. A report by the company’s registered public accounting firm is not required pursuant to rules of the Securities and Exchange Commission that permit the company to provide only management’s report in this annual report.
29
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, 2012 and 2011, and the related consolidated statements of comprehensive income, owner’s equity, and cash flows for each of the three years in the period ended December 31, 2012. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public 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, 2012 and 2011, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2012, in conformity with U.S. generally accepted accounting principles.
/S/ ERNST & YOUNG LLP
Houston, Texas
February 27, 2013
30
TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
(Thousands of Dollars)
| Years Ended December 31, | ||||||||||||
| 2012 | 2011 | 2010 | ||||||||||
| Operating Revenues: |
||||||||||||
| Natural gas sales |
$ | 65,120 | $ | 108,359 | $ | 99,346 | ||||||
| Natural gas transportation |
1,022,990 | 983,554 | 930,704 | |||||||||
| Natural gas storage |
140,390 | 142,556 | 146,820 | |||||||||
| Other |
5,601 | 8,045 | 5,125 | |||||||||
|
|
|
|
|
|
|
|||||||
| Total operating revenues |
1,234,101 | 1,242,514 | 1,181,995 | |||||||||
|
|
|
|
|
|
|
|||||||
| Operating Costs and Expenses: |
||||||||||||
| Cost of natural gas sales |
65,120 | 108,359 | 99,346 | |||||||||
| Cost of natural gas transportation |
31,815 | 35,674 | 32,231 | |||||||||
| Operation and maintenance |
292,610 | 274,735 | 249,060 | |||||||||
| Administrative and general |
174,610 | 148,113 | 148,589 | |||||||||
| Depreciation and amortization |
266,445 | 259,660 | 252,049 | |||||||||
| Taxes - other than income taxes |
52,210 | 48,434 | 46,064 | |||||||||
| Other expense, net |
21,230 | 12,988 | 15,189 | |||||||||
|
|
|
|
|
|
|
|||||||
| Total operating costs and expenses |
904,040 | 887,963 | 842,528 | |||||||||
|
|
|
|
|
|
|
|||||||
| Operating Income |
330,061 | 354,551 | 339,467 | |||||||||
|
|
|
|
|
|
|
|||||||
| Other (Income) and Other Deductions: |
||||||||||||
| Interest expense - affiliate |
309 | 262 | 353 | |||||||||
|
- other |
88,766 | 94,920 | 94,620 | |||||||||
| Interest income - affiliates |
(35 | ) | (29 | ) | (2,231 | ) | ||||||
|
- other |
(2,351 | ) | (2,119 | ) | (882 | ) | ||||||
| Allowance for equity and borrowed funds used during construction (AFUDC) |
(19,257 | ) | (15,339 | ) | (12,349 | ) | ||||||
| Equity in earnings of unconsolidated affiliates |
(7,458 | ) | (5,164 | ) | (5,805 | ) | ||||||
| Miscellaneous other (income) deductions, net |
(2,379 | ) | 2,362 | (5,015 | ) | |||||||
|
|
|
|
|
|
|
|||||||
| Total other (income) and other deductions |
57,595 | 74,893 | 68,691 | |||||||||
|
|
|
|
|
|
|
|||||||
| Net Income |
272,466 | 279,658 | 270,776 | |||||||||
| Equity interest in unrealized gain (loss) on interest hedge |
(376 | ) | (519 | ) | 891 | |||||||
|
|
|
|
|
|
|
|||||||
| Comprehensive Income |
$ | 272,090 | $ | 279,139 | $ | 271,667 | ||||||
|
|
|
|
|
|
|
|||||||
See accompanying notes.
31
TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
(Thousands of Dollars)
| December 31, | ||||||||
| 2012 | 2011 | |||||||
| ASSETS |
||||||||
| Current Assets: |
||||||||
| Cash |
$ | 185 | $ | 164 | ||||
| Receivables: |
||||||||
| Trade less allowance of $0 ($407 in 2011) |
116,847 | 107,585 | ||||||
| Affiliates |
2,656 | 5,903 | ||||||
| Advances to affiliate |
312,165 | 253,611 | ||||||
| Other |
8,928 | 14,004 | ||||||
| Transportation and exchange gas receivables |
2,876 | 4,914 | ||||||
| Inventories: |
||||||||
| Gas in storage, at original cost |
812 | 822 | ||||||
| Gas available for customer nomination, at average cost |
8,600 | 349 | ||||||
| Material and supplies, at lower of average cost or market |
36,506 | 34,437 | ||||||
| Regulatory assets |
36,706 | 37,877 | ||||||
| Other |
14,342 | 12,973 | ||||||
|
|
|
|
|
|||||
| Total current assets |
540,623 | 472,639 | ||||||
|
|
|
|
|
|||||
| Investments, at cost plus equity in undistributed earnings |
55,603 | 56,994 | ||||||
|
|
|
|
|
|||||
| Property, Plant and Equipment: |
||||||||
| Natural gas transmission plant |
8,506,189 | 8,089,338 | ||||||
| Less-Accumulated depreciation and amortization |
2,954,276 | 2,801,104 | ||||||
|
|
|
|
|
|||||
| Total property, plant and equipment, net |
5,551,913 | 5,288,234 | ||||||
|
|
|
|
|
|||||
| Other Assets: |
||||||||
| Regulatory assets |
214,912 | 207,945 | ||||||
| Other |
47,764 | 50,471 | ||||||
|
|
|
|
|
|||||
| Total other assets |
262,676 | 258,416 | ||||||
|
|
|
|
|
|||||
| Total assets |
$ | 6,410,815 | $ | 6,076,283 | ||||
|
|
|
|
|
|||||
(continued)
See accompanying notes.
32
TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
| December 31, | ||||||||
| 2012 | 2011 | |||||||
| LIABILITIES AND OWNER’S EQUITY |
||||||||
| Current Liabilities: |
||||||||
| Payables: |
||||||||
| Trade |
$ | 107,795 | $ | 93,862 | ||||
| Affiliates |
32,006 | 16,937 | ||||||
| Cash overdrafts |
11,512 | 14,844 | ||||||
| Transportation and exchange gas payables |
3,513 | 2,784 | ||||||
| Accrued liabilities: |
||||||||
| Property and other taxes |
13,326 | 11,672 | ||||||
| Interest |
20,784 | 25,947 | ||||||
| Regulatory liabilities |
14,624 | 1,958 | ||||||
| Customer advances |
11,020 | 20,221 | ||||||
| Asset retirement obligations |
43,472 | 57,403 | ||||||
| Other |
36,107 | 23,189 | ||||||
| Current maturities of long-term debt |
— | 324,321 | ||||||
|
|
|
|
|
|||||
| Total current liabilities |
294,159 | 593,138 | ||||||
|
|
|
|
|
|||||
| Long-Term Debt |
1,428,323 | 1,029,397 | ||||||
|
|
|
|
|
|||||
| Other Long-Term Liabilities: |
||||||||
| Asset retirement obligations |
253,398 | 245,365 | ||||||
| Regulatory liabilities |
232,888 | 182,848 | ||||||
| Other |
5,339 | 6,182 | ||||||
|
|
|
|
|
|||||
| Total other long-term liabilities |
491,625 | 434,395 | ||||||
|
|
|
|
|
|||||
| Contingent Liabilities and Commitments (Note 2) |
||||||||
| Owner’s Equity: |
||||||||
| Member’s capital |
1,993,412 | 1,841,888 | ||||||
| Retained earnings |
2,204,018 | 2,177,811 | ||||||
| Accumulated other comprehensive income (loss) |
(722 | ) | (346 | ) | ||||
|
|
|
|
|
|||||
| Total owner’s equity |
4,196,708 | 4,019,353 | ||||||
|
|
|
|
|
|||||
| Total liabilities and owner’s equity |
$ | 6,410,815 | $ | 6,076,283 | ||||
|
|
|
|
|
|||||
See accompanying notes.
33
TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
CONSOLIDATED STATEMENT OF OWNER’S EQUITY
(Thousands of Dollars)
| Years Ended December 31, | ||||||||||||
| 2012 | 2011 | 2010 | ||||||||||
| Member’s Capital: |
||||||||||||
| Balance at beginning of period |
$ | 1,841,888 | $ | 1,727,434 | $ | 1,652,434 | ||||||
| Cash contributions from parent |
150,000 | 115,000 | 75,000 | |||||||||
| Non-cash contributions from parent |
1,524 | — | — | |||||||||
| Non-cash return of capital |
— | (546 | ) | — | ||||||||
|
|
|
|
|
|
|
|||||||
| Balance at end of period |
1,993,412 | 1,841,888 | 1,727,434 | |||||||||
|
|
|
|
|
|
|
|||||||
| Loans to Parent: |
||||||||||||
| Balance at beginning of period |
— | — | (237,526 | ) | ||||||||
| Loans to parent, net |
— | — | 237,526 | |||||||||
|
|
|
|
|
|
|
|||||||
| Balance at end of period |
— | — | — | |||||||||
|
|
|
|
|
|
|
|||||||
| Retained Earnings: |
||||||||||||
| Balance at beginning of period |
2,177,811 | 2,117,153 | 2,180,367 | |||||||||
| Net income |
272,466 | 279,658 | 270,776 | |||||||||
| Cash distributions |
(246,259 | ) | (219,000 | ) | (333,791 | ) | ||||||
| Non-cash distributions |
— | — | (199 | ) | ||||||||
|
|
|
|
|
|
|
|||||||
| Balance at end of period |
2,204,018 | 2,177,811 | 2,117,153 | |||||||||
|
|
|
|
|
|
|
|||||||
| Accumulated Other Comprehensive Income (Loss): |
||||||||||||
| Balance at beginning of period |
(346 | ) | 173 | (718 | ) | |||||||
| Equity interest in unrealized gain (loss) on interest rate hedge |
(376 | ) | (519 | ) | 891 | |||||||
|
|
|
|
|
|
|
|||||||
| Balance at end of period |
(722 | ) | (346 | ) | 173 | |||||||
|
|
|
|
|
|
|
|||||||
| Total Owner’s Equity |
$ | 4,196,708 | $ | 4,019,353 | $ | 3,844,760 | ||||||
|
|
|
|
|
|
|
|||||||
See accompanying notes.
34
TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
CONSOLIDATED STATEMENT OF CASH FLOWS
(Thousands of Dollars)
| Years Ended December 31, | ||||||||||||
| 2012 | 2011 | 2010 | ||||||||||
| Cash flows from operating activities: |
||||||||||||
| Net income |
$ | 272,466 | $ | 279,658 | $ | 270,776 | ||||||
| Adjustments to reconcile net income to net cash provided by operating activities: |
||||||||||||
| Depreciation and amortization |
266,981 | 260,069 | 252,131 | |||||||||
| Allowance for equity funds used during construction (Equity AFUDC) |
(13,222 | ) | (10,588 | ) | (8,539 | ) | ||||||
| Changes in operating assets and liabilities: |
||||||||||||
| Receivables - affiliates |
3,247 | (982 | ) | 1,702 | ||||||||
| - others |
(4,186 | ) | (11,155 | ) | 6,714 | |||||||
| Transportation and exchange gas receivable |
2,038 | (2,497 | ) | 4,833 | ||||||||
| Inventories |
673 | 50,295 | (46,261 | ) | ||||||||
| Payables - affiliates |
15,069 | (1,832 | ) | (23,485 | ) | |||||||
| - others |
3,727 | 14,577 | 15,888 | |||||||||
| Accrued liabilities |
8,256 | 27,775 | 617 | |||||||||
| Asset retirement obligation removal costs |
(41,052 | ) | (43,666 | ) | (6,990 | ) | ||||||
| Reserve for rate refunds |
— | — | (564 | ) | ||||||||
| Other, net |
27,452 | 9,990 | 42,661 | |||||||||
|
|
|
|
|
|
|
|||||||
| Net cash provided by operating activities |
541,449 | 571,644 | 509,483 | |||||||||
|
|
|
|
|
|
|
|||||||
| Cash flows from financing activities: |
||||||||||||
| Additions to long-term debt |
398,804 | 372,518 | — | |||||||||
| Retirement of long-term debt |
(325,000 | ) | (300,000 | ) | — | |||||||
| Debt issue costs |
(4,403 | ) | (3,846 | ) | — | |||||||
| Cash distributions |
(246,259 | ) | (219,000 | ) | (333,791 | ) | ||||||
| Cash contributions from parent |
150,000 | 115,000 | 75,000 | |||||||||
| Other |
(3,333 | ) | (4,681 | ) | 1,146 | |||||||
|
|
|
|
|
|
|
|||||||
| Net cash used in financing activities |
(30,191 | ) | (40,009 | ) | (257,645 | ) | ||||||
|
|
|
|
|
|
|
|||||||
(continued)
See accompanying notes.
35
TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
CONSOLIDATED STATEMENT OF CASH FLOWS
(Thousands of Dollars)
| Years Ended December 31, | ||||||||||||
| 2012 | 2011 | 2010 | ||||||||||
| Cash flows from investing activities: |
||||||||||||
| Property, plant and equipment additions, net of equity AFUDC* |
$ | (475,450 | ) | $ | (385,671 | ) | $ | (376,502 | ) | |||
| Disposal of property, plant and equipment, net |
7,157 | 2,698 | 13,959 | |||||||||
| Advances to affiliates, net |
(58,554 | ) | (144,773 | ) | 126,999 | |||||||
| Return of capital from unconsolidated affiliates |
11,327 | 1,925 | — | |||||||||
| Contributions to unconsolidated affiliates |
(5,806 | ) | (14,834 | ) | — | |||||||
| Purchase of ARO Trust investments |
(34,430 | ) | (41,310 | ) | (46,952 | ) | ||||||
| Proceeds from sale of ARO Trust investments |
43,205 | 56,576 | 31,001 | |||||||||
| Other, net |
1,314 | (6,230 | ) | (303 | ) | |||||||
|
|
|
|
|
|
|
|||||||
| Net cash used in investing activities |
(511,237 | ) | (531,619 | ) | (251,798 | ) | ||||||
|
|
|
|
|
|
|
|||||||
| Increase in cash |
21 | 16 | 40 | |||||||||
| Cash at beginning of period |
164 | 148 | 108 | |||||||||
|
|
|
|
|
|
|
|||||||
| Cash at end of period |
$ | 185 | $ | 164 | $ | 148 | ||||||
|
|
|
|
|
|
|
|||||||
|
|
||||||||||||
| * Increase to property, plant and equipment |
$ | (466,115 | ) | $ | (386,462 | ) | $ | (352,674 | ) | |||
| Changes in related accounts payable and accrued liabilities |
(9,335 | ) | 791 | (23,828 | ) | |||||||
|
|
|
|
|
|
|
|||||||
| Property, plant and equipment additions, net of equity AFUDC |
$ | (475,450 | ) | $ | (385,671 | ) | $ | (376,502 | ) | |||
|
|
|
|
|
|
|
|||||||
| Supplemental disclosures of cash flow information: |
||||||||||||
| Cash paid during the year for: |
||||||||||||
| Interest (exclusive of amount capitalized) |
$ | 86,586 | $ | 88,357 | $ | 89,342 | ||||||
| Income taxes |
254 | 728 | 31 | |||||||||
See accompanying notes.
36
TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES.
Corporate Structure and Control.
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.”
Transco is owned, through Williams Partners Operating LLC (WPO), by Williams Partners L.P. (WPZ), a publicly traded Delaware limited partnership, which is consolidated by The Williams Companies, Inc. (Williams). Williams holds an approximate 70 percent interest in WPZ, comprised of an approximate 68 percent limited partner interest and all of WPZ’s 2 percent general partner interest.
Transco is a single member limited liability company, and as such, single member losses are limited to the amount of their investment.
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, Delaware, Pennsylvania and New Jersey to the New York City metropolitan area. The system serves customers in Texas and the 12 southeast and Atlantic seaboard states mentioned above, including major metropolitan areas in Georgia, Washington D.C., Maryland, North Carolina, New York, New Jersey and Pennsylvania.
Regulatory Accounting.
We are regulated by the Federal Energy Regulatory Commission (FERC). The Accounting Standards Codification (ASC) 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, 2012, the remaining property, plant and equipment allocation was approximately $0.8 billion. Current FERC policy does not permit us to recover through rates amounts in excess of original cost.
37
We are a participant in WPZ’s cash management program. We make advances to and receive advances from WPZ. The advances are represented by demand notes. The interest rate on these intercompany demand notes is based upon the daily overnight investment rate paid on WPZ’s excess cash at the end of each month.
Certain prior period amounts reported within Total operating costs and expenses in the Consolidated Statement of Comprehensive Income have been reclassified to conform to the current presentation. The effect of the correction increased Operation and maintenance costs and decreased Administrative and general expenses, with no net impact on Total operating costs and expenses, Operating Income or Net Income. The adjustments were $10.4 million and $9.4 million in 2011 and 2010, respectively.
Principles of Consolidation.
The consolidated financial statements include our accounts and the accounts of the subsidiaries we control. 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, 2012 and December 31, 2011 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 $14.3 million, $6.2 million, and $8.4 million in 2012, 2011 and 2010, respectively. Included in the distributions are $11.3 million return of capital from Cardinal in 2012 and $1.9 million return of capital from Pine Needle in 2011. We made capital contributions to Cardinal related to Cardinal’s expansion project totaling $5.8 million and $14.8 million in 2012 and 2011, respectively.
Use of Estimates.
The preparation of financial statements in conformity with U.S. generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the amounts reported in the consolidated 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 reservation and commodity charges. Reservation 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 reservation, capacity, and injection and withdrawal charges. Reservation 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).
38
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 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. 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. 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, 2012, 2011 and 2010 are as follows:
| Category of Property |
||||
| Gathering facilities |
0.18% - 1.66% | |||
| Storage facilities |
2.10% - 3.70% | |||
| Onshore transmission facilities |
2.79% - 5.71% | |||
| Offshore transmission facilities |
1.01% - 1.01% | |||
We record an asset and a liability equal to the present value of each expected future asset retirement obligation (ARO). Measurements of asset retirement obligations include, as a component of future expected costs, an estimate of the price that a third party would demand, and could expect to receive, for bearing the uncertainties inherent in the obligations, sometimes referred to as a market-risk premium. The ARO asset is depreciated in a manner consistent with the expected timing of the future abandonment of the underlying physical assets. 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 these 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
39
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.
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.
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 $6.0 million, $4.7 million and $3.8 million, for 2012, 2011 and 2010, respectively. The allowance for equity funds was $13.2 million, $10.6 million, and $8.5 million, for 2012, 2011 and 2010, respectively.
Income Taxes.
We generally are not a taxable entity for federal or state and local income tax purposes. The tax on net income is generally borne by unitholders of our ultimate parent, WPZ. Net income for financial statement purposes may differ significantly from taxable income of WPZ’s unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under the WPZ partnership agreement. The aggregated difference in the basis of our assets for financial and tax reporting purposes cannot be readily determined because information regarding each of WPZ’s unitholder’s tax attributes in WPZ is not available to us.
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
40
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, 2012 and 2011. 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. At December 31, 2012 and 2011, physical withdrawals from the Eminence Storage facility exceeded the customer nominations for withdrawals, resulting in a liability. 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.
Materials and Supplies Inventory.
All inventories are stated at lower of average cost or market. 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, 2012 and at December 31, 2011.
Contingent Liabilities
We record liabilities for estimated loss contingencies, including environmental matters, when we assess that a loss is probable and the amount of the loss can be reasonably estimated. These liabilities are calculated based upon our assumptions and estimates with respect to the likelihood or amount of loss and upon advice of legal counsel, engineers, or other third parties regarding the probable outcomes of the matters. These calculations are made without consideration of any potential recovery from third-parties. We recognize insurance recoveries or reimbursements from others when realizable. Revisions to these liabilities are generally reflected in income when new or different facts or information become known or circumstances change that affect the previous assumptions or estimates.
Pension and Other Postretirement Benefits.
We do not have employees. Certain of the costs charged to us by Williams associated with employees who directly support us include costs related to Williams’ pension and other postretirement benefit plans. (See Note 6.) Although the underlying benefit plans of Williams are single-employer plans, we follow multiemployer plan accounting whereby the amount charged to us and thus paid by us, is based on our share of net periodic benefit cost.
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.
41
2. CONTINGENT LIABILITIES AND COMMITMENTS.
Rate Matters.
General rate case (Docket No. RP12-993) On August 31, 2012, we submitted to the FERC a general rate filing principally designed to recover increased costs and to comply with the terms of the settlement in our Docket No. RP06-569 rate proceeding (see below) to file a rate case no later than August 31, 2012. On September 28, 2012, the FERC issued an order accepting and suspending our filing to be effective March 1, 2013, subject to refund and the outcome of a hearing, except that rates for certain services that were proposed as overall rate decreases were accepted, without suspension, to be effective October 1, 2012. These decreased rates will not be subject to refund, but may be subject to decrease prospectively under the Natural Gas Act of 1938, Section 5.
General rate case (Docket No. RP06-569) On August 31, 2006, we submitted to the FERC a general rate filing principally 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. Certain parties sought rehearing of the FERC’s order and, on April 2, 2012, the FERC denied the rehearing request. On June 1, 2012, one of the parties filed an appeal in the U.S. Court of Appeals for the D.C. Circuit (D.C. Circuit). If the D.C. Circuit were to overturn the FERC’s order, we believe any refunds would not be material to our results of operations.
Environmental Matters.
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 $5 million to $7 million (including both expense and capital expenditures), measured on an undiscounted basis, and will be spent over the next three to five 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, 2012, we had a balance of approximately $3.3 million for the expense portion of these estimated costs recorded in current liabilities ($1.1 million) and other long-term liabilities ($2.2 million) in the accompanying Consolidated Balance Sheet. At December 31, 2011, we had a balance of approximately $3.5 million for the expense portion of these estimated costs recorded in current liabilities ($0.8 million) and other long-term liabilities ($2.7 million) in the accompanying Consolidated Balance Sheet.
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 $5 million to $7 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 $5 million to $7 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
42
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.
In March 2008, the EPA promulgated a new, lower National Ambient Air Quality Standard (NAAQS) for ground-level ozone. 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. In September 2011, the EPA announced that it was proceeding with required actions to implement the 2008 ozone standard and area designations. In May 2012, the EPA completed designation of new eight-hour ozone non-attainment areas. Several Transco facilities are located in 2008 ozone non-attainment areas; however, each facility has been previously subjected to federal and/or state emission control requirements implemented to address preceding ozone standards. To date, no new federal or state actions have been proposed to mandate additional emission controls at these facilities. At this time, it is unknown whether future federal or state regulatory actions associated with implementation of the 2008 ozone standard will impact our operations and increase the cost of additions to property, plant and equipment. Until any additional federal or state regulatory actions are proposed, we are unable to estimate the cost of additions that may be required to meet this new regulation.
Additionally, in August 2010, the EPA promulgated National Emission Standards for Hazardous Air Pollutants (NESHAP) regulations that will impact our operations. The remaining emission control additions required to comply with the hazardous air pollutant regulations are estimated to include capital costs in the range of $10 million to $12 million through 2013, the compliance date.
On January 22, 2010, the EPA set a new one-hour nitrogen dioxide (NO2) NAAQS. The effective date of the new NO2 standard was April 12, 2010. This standard is subject to challenges in federal court. On January 20, 2012, the EPA determined pursuant to available information that no area in the country is violating the 2010 NO2 NAAQS and thus designated all areas of the country as “unclassifiable/attainment.” Also, at that time, the EPA noted its plan to deploy an expanded NO2 monitoring network beginning in 2013. However, on October 5, 2012, the EPA proposed a graduated implementation of the monitoring network between January 1, 2014 and January 1, 2017. Once three years of data is collected from the new monitoring network, the EPA will reassess attainment status with the one-hour NO2 NAAQS. Until that time, the EPA or states may require ambient air quality modeling on a case by case basis to demonstrate compliance with the NO2 standard. Because we are unable to predict the outcome of the EPA’s or states’ future assessment using the new monitoring network, we are unable to estimate the cost of additions that may be required to meet this regulation.
We consider prudently incurred environmental assessment and remediation costs and the 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. As a result, as estimated costs of environmental assessment and remediation are incurred, they are recorded as regulatory assets in the Condensed Consolidated Balance Sheet until collected through rates. However, we had no uncollected environmental related regulatory assets at December 31, 2012 or December 31, 2011.
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 Federal Clean Air Act (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. The EPA has requested additional information pertaining to these compressor stations and in May 2011, we submitted information in response to the EPA’s latest request. In August, 2010, the EPA requested, and we provided, similar information for a compressor station in Maryland.
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Safety Matters.
Pipeline Integrity Regulations We have developed an Integrity Management Plan that we believe meets the United States Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA) final rule that was issued pursuant to the requirements of the Pipeline Safety Improvement Act of 2002. The rule requires gas pipeline operators to develop an integrity management program for transmission pipelines that could affect high consequence areas in the event of pipeline failure. The Integrity Management Program includes a baseline assessment plan to be completed in 2012 along with periodic reassessments to be completed within required timeframes. In meeting the integrity regulations, we have identified high consequence areas and developed our baseline assessment plan. The required pipeline segments originally identified for assessment were completed within the required timeframe, with one exception which was reported to PHMSA. We estimate that the cost to complete the remediation associated with the 2012 assessments will be approximately $20 million, most of which we expect to be 2013 capital expenditures.
Reassessments of the original segments have begun as required by regulations. As new pipelines are constructed and new high consequence areas are created, additional pipeline segments are required to be added to the baseline assessment plan. These segments are also on schedule as required. 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.
Other Matters.
Various other proceedings are pending against us and are considered incidental to our operations.
Summary.
We estimate that for all matters for which we are able to reasonably estimate a range of loss, including those noted above and others that are not individually significant, our aggregate reasonably possible losses beyond amounts accrued for all of our contingent liabilities are immaterial to our expected future annual results of operations, liquidity and financial position. These calculations have been made without consideration of any potential recovery from third parties. We have disclosed all significant matters for which we are unable to reasonably estimate a range of possible loss.
Other Commitments.
Commitments for construction We have commitments for construction and acquisition of property, plant and equipment of approximately $225 million at December 31, 2012.
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3. DEBT, FINANCING ARRANGEMENTS AND LEASES.
Long-Term Debt.
At December 31, 2012 and 2011, long-term debt issues were outstanding as follows (in thousands):
| 2012 | 2011 | |||||||
| Debentures: |
||||||||
| 7.08% due 2026 |
$ | 7,500 | $ | 7,500 | ||||
| 7.25% due 2026 |
200,000 | 200,000 | ||||||
|
|
|
|
|
|||||
| Total debentures |
207,500 | 207,500 | ||||||
|
|
|
|
|
|||||
| Notes: |
||||||||
| 8.875% due 2012 |
— | 325,000 | ||||||
| 6.4% due 2016 |
200,000 | 200,000 | ||||||
| 6.05% due 2018 |
250,000 | 250,000 | ||||||
| 5.4% due 2041 |
375,000 | 375,000 | ||||||
| 4.45% due 2042 |
400,000 | — | ||||||
|
|
|
|
|
|||||
| Total notes |
1,225,000 | 1,150,000 | ||||||
|
|
|
|
|
|||||
| Total long-term debt issues |
1,432,500 | 1,357,500 | ||||||
| Unamortized debt premium and discount |
(4,177 | ) | (3,103 | ) | ||||
| Current maturities |
— | (325,000 | ) | |||||
|
|
|
|
|
|||||
| Total long-term debt, less current maturities |
$ | 1,428,323 | $ | 1,029,397 | ||||
|
|
|
|
|
|||||
Aggregate minimum maturities (face value) applicable to long-term debt outstanding at December 31, 2012, for the next five years, are as follows (in thousands):
| 2016: 6.4% Notes |
$ | 200,000 |
There are no maturities applicable to long-term debt outstanding for the years 2013, 2014, 2015 and 2017.
No property is pledged as collateral under any of our long-term debt issues.
Restrictive Debt Covenants.
At December 31, 2012, none of our debt instruments restrict the amount of distributions to our parent. Our debt agreements contain restrictions on our ability to incur secured debt beyond certain levels.
Credit Facility.
In September 2012, WPZ amended its existing $2 billion senior unsecured revolving credit facility agreement to increase the aggregate commitments by $400 million. This facility was also amended to provide an additional $400 million increase to be available under certain conditions in the future. We may borrow up to $400 million under the credit facility to the extent not otherwise utilized by WPZ and Northwest Pipeline GP.
Under the Credit Facility, WPZ is required to maintain a ratio of debt to EBITDA (each as defined in the Credit Facility) that must be no greater than 5.0 to 1.0. For the fiscal quarter and the two following fiscal quarters in which one or more acquisitions for a total aggregate purchase price equal to or greater than $50 million has been executed, WPZ is required to maintain a ratio of debt to EBITDA of no greater than 5.5 to 1.00. For us and our consolidated subsidiaries, the ratio of debt to capitalization (defined as net worth plus debt) must be no greater than 65 percent. At December 31, 2012, we are in compliance with these financial covenants.
45
Each time funds are borrowed, the borrower may choose from two methods of calculating interest: a fluctuating base rate equal to Citibank N.A.’s alternate base rate plus an applicable margin, or a periodic fixed rate equal to London Interbank Offered Rate (LIBOR) plus an applicable margin. The borrower is required to pay a commitment fee (currently 0.20 percent) based on the unused portion of the Credit Facility. The applicable margin and the commitment fee are determined for each borrower by reference to a pricing schedule based on such borrower’s senior unsecured long-term debt ratings. The Credit Facility contains various covenants that limit, among other things, a borrower’s and its respective material subsidiaries’ ability to grant certain liens supporting indebtedness, a borrower’s ability to merge or consolidate, sell all or substantially all of its assets, enter into certain affiliate transactions, make certain distributions during an event of default, make investments and allow any material change in the nature of its business.
The Credit Facility includes customary events of default. If an event of default with respect to a borrower occurs under the Credit Facility, the lenders will be able to terminate the commitments for all borrowers and accelerate the maturity of any loans of the defaulting borrower and exercise other rights and remedies.
Letter of credit capacity under the $2.4 billion credit facility is $1.3 billion. At December 31, 2012, no letters of credit have been issued and $375 million of loans, none by us, were outstanding under the credit facility. At December 31, 2012, the full $400 million under the credit facility was available to us.
Issuance and Retirement of Long-Term Debt.
In August 2011, we issued $375 million of 5.4 percent senior unsecured notes due 2041 to investors in a private debt placement. As part of the new issuance, we entered into a registration rights agreement with the initial purchasers of the notes. An offer to exchange these unregistered notes for substantially identical new notes that are registered under the Securities Act of 1933, as amended, was commenced in February 2012 and completed in March 2012.
On July 13, 2012, we issued $400 million aggregate principal amount of 4.45 percent senior unsecured notes due 2042 (4.45 percent Notes) to certain institutional investors pursuant to certain exemptions from registration under the Securities Act of 1933, as amended. Interest is payable on February 1 and August 1 of each year, beginning February 1, 2013. A portion of these proceeds was used to repay our $325 million 8.875 percent notes that matured on July 15, 2012. We used the remainder for general corporate purposes, including the funding of capital expenditures.
As part of the new issuance, we entered into a registration rights agreement with the initial purchasers of the 4.45 percent Notes. An offer to exchange these unregistered notes for substantially identical new notes that are registered under the Securities Act of 1933, as amended, was commenced in November 2012 and completed in December 2012.
Lease Obligations
The future minimum lease payments under our various operating leases are as follows (in thousands):
| 2013 |
$ | 9,658 | ||
| 2014 |
9,654 | |||
| 2015 |
9,524 | |||
| 2016 |
9,524 | |||
| 2017 |
9,523 | |||
| Thereafter |
30,758 | |||
|
|
|
|||
| Total net minimum obligations |
$ | 78,641 | ||
|
|
|
Our lease expense was $10.9 million in 2012, $9.1 million in 2011, and $9.3 million in 2010.
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4. INVESTMENTS.
Available-for-Sale Investments.
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.
Investments in available-for-sale securities within the ARO Trust at fair value were as follows (in millions):
| December 31, 2012 | December 31, 2011 | |||||||||||||||
| Amortized Cost Basis |
Fair Value |
Amortized Cost Basis |
Fair Value |
|||||||||||||
| Money Market Funds |
$ | 1.3 | $ | 1.3 | $ | 1.4 | $ | 1.4 | ||||||||
| U.S. Equity Funds |
5.4 | 7.4 | 7.1 | 9.5 | ||||||||||||
| International Equity Funds |
3.4 | 3.8 | 5.4 | 5.3 | ||||||||||||
| Municipal Bond Funds |
4.9 | 5.3 | 7.9 | 8.3 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total |
$ | 15.0 | $ | 17.8 | $ | 21.8 | $ | 24.5 | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
5. FAIR VALUE MEASUREMENTS.
The following table presents, by level within the fair value hierarchy, certain of our financial assets and liabilities.
| Fair Value Measurements Using | ||||||||||||||||||||
| Carrying Amount |
Fair Value |
Quoted Prices In Active Markets for Identical Assets (Level 1) |
Significant Other Observable Inputs (Level 2) |
Significant Unobservable Inputs (Level 3) |
||||||||||||||||
| (Millions) | ||||||||||||||||||||
| Assets (liabilities) at December 31, 2012: |
||||||||||||||||||||
| Measured on a recurring basis: |
||||||||||||||||||||
| ARO Trust investments |
$ | 17.8 | $ | 17.8 | $ | 17.8 | $ | — | $ | — | ||||||||||
| Additional disclosures: |
||||||||||||||||||||
| Notes receivable |
8.2 | 8.2 | — | 8.2 | — | |||||||||||||||
| Long-term debt |
(1,428.3 | ) | (1,704.5 | ) | — | (1,704.5 | ) | — | ||||||||||||
| Assets (liabilities) at December 31, 2011: |
||||||||||||||||||||
| Measured on a recurring basis: |
||||||||||||||||||||
| ARO Trust investments |
$ | 24.5 | $ | 24.5 | $ | 24.5 | $ | — | $ | — | ||||||||||
| Additional disclosures: |
||||||||||||||||||||
| Notes receivable |
9.5 | 9.5 | N/A | N/A | N/A | |||||||||||||||
| Long-term debt, including current portion |
(1,353.7 | ) | (1,539.2 | ) | N/A | N/A | N/A | |||||||||||||
47
Fair Value of Methods.
The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value:
Cash and short-term financial assets (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.
ARO Trust investments - We deposit a portion of our collected rates, pursuant to our 2008 rate case settlement, into an external trust (ARO Trust) that is specifically designated to fund future asset retirement obligations. The ARO Trust invests in a portfolio of actively traded mutual funds that are measured at fair value on a recurring basis based on quoted net asset values, are classified as available-for-sale, and are reported in Other Assets-Other in the Condensed Consolidated Balance Sheet. However, both realized and unrealized gains and losses are ultimately recorded as regulatory assets or liabilities. See Note 4 for more information regarding the ARO Trust.
Notes receivable - The carrying value of our notes receivable are considered to approximate the fair value generally due to the nature of the related interest rates and our assessment of our ability to recover these amounts using an income approach.
Long-term debt - The disclosed fair value of our long-term debt is determined by a market approach using broker quoted indicative period-end bond prices. The quoted prices are based on observable transactions in less active markets for our debt or similar instruments.
Reclassifications of fair value between Level 1, Level 2, and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. No transfers between Level 1 and Level 2 occurred during the year ended December 31, 2012 or 2011.
6. BENEFIT PLANS.
Certain of the benefit costs charged to us by Williams associated with employees who directly support us are described below. Additionally, allocated corporate expenses from Williams to us also include amounts related to these same employee benefits, which are not included in the amounts presented below.
Pension and Other Postretirement Benefit Plans.
Williams has noncontributory defined benefit pension plans (Williams Pension Plan, Williams Inactive Employees Pension Plan and The Williams Companies Retirement Restoration Plan) that provide pension benefits for its eligible employees. Pension cost charged to us by Williams was $20.3 million, $16.4 million and $16.7 million for 2012, 2011, and 2010, respectively.
Williams provides certain retiree health care and life insurance benefits for eligible participants that generally were employed by Williams on or before December 31, 1991 or December 31, 1995, if they were employees or retirees of Transco Energy Company and its subsidiaries. We recognized other postretirement benefit cost of $2.5 million for 2012 and income of $3.0 million and $4.5 million for 2011 and 2010, 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 other postretirement benefits costs deferred as a regulatory liability at December 31, 2012 and 2011 are $24.7 million and $22.0 million, respectively, and are expected to be refunded through future rates. The amounts of other postretirement benefits costs deferred as regulatory assets at December 31, 2012 and 2011 are $4.6 million and $5.7 million, respectively, and are currently being recovered over a ten year period beginning March 1, 2007.
48
Defined Contribution Plan.
Williams charged us compensation expense of $7.1 million in 2012, $6.8 million in 2011, and $6.7 million in 2010 for Williams’ company matching contributions to this plan.
Employee Stock-Based Compensation Plan Information.
The Williams Companies, Inc. 2007 Incentive Plan, as amended and restated on February 23, 2010, (Plan) was approved by stockholders on May 20, 2010. 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 achieved.
Williams currently bills us directly for compensation expense related to stock-based compensation awards based on the fair value of the awards. We are also billed for our proportionate share of Williams’ and other affiliates’ stock-based compensation expense through various allocation processes.
Total stock-based compensation expense, included in administrative and general expenses, for the years ended December 31, 2012, 2011 and 2010 was $2.8 million, $2.4 million and $3.1 million, respectively, excluding amounts allocated from WPZ and Williams.
7. TRANSACTIONS WITH MAJOR CUSTOMERS AND AFFILIATES.
Major Customers.
Operating revenues received from our two major customers in 2012, 2011 and 2010 are as follows (in millions):
| 2012 | 2011 | 2010 | ||||||||||
| Public Service Enterprise Group |
$ | 127.4 | $ | 136.7 | $ | 130.0 | ||||||
| National Grid |
93.5 | 98.2 | 115.1 | |||||||||
Affiliates.
We are a participant in WPZ’s cash management program, and we make advances to and receive advances from WPZ. At December 31, 2012 and 2011, the advances due us by WPZ totaled approximately $312.2 million and $253.6 million, respectively. These advances are represented by demand notes. Advances are stated at the historical carrying amounts. Interest income is recognized when chargeable and collectability is reasonably assured. The interest rate on these intercompany demand notes is based upon the daily overnight investment rate paid on WPZ’s excess cash at the end of each month. At December 31, 2012, the interest rate was 0.01 percent.
On December 31, 2011, Williams completed the spin-off of its former exploration and production business, WPX, by means of a special stock dividend to its shareholders. Included in our operating revenues and cost of sales listed below for the years 2011 and 2010 are amounts related to activity with WPX.
Included in our operating revenues for 2012, 2011 and 2010 are revenues received from affiliates of $17.0 million, $18.5 million, and $23.4 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.
Included in our cost of sales for 2012, 2011 and 2010 is purchased gas cost from affiliates of $3.9 million, $8.8 million, and $4.8 million, respectively. All gas purchases are made at market or contract prices.
We have no employees. Services necessary to operate our business are provided to us by Williams and certain affiliates of Williams. We reimburse Williams for all direct and indirect expenses it incurs or payments it makes (including salary, bonus, incentive compensation and benefits) in connection with these services. We were billed $206.1 million, $191.1 million and $170.7 million during 2012, 2011 and 2010, respectively, for these services.
49
Such expenses are primarily included in Administrative and general and Operation and maintenance expenses in the accompanying Consolidated Statement of Comprehensive Income.
Employees of Williams also provide general and administrative services to us, and we are charged for certain administrative expenses incurred by Williams. These charges are either directly identifiable or allocated to our assets. Direct charges are for goods and services provided by Williams at our request. Allocated charges are based on a three-factor formula, which considers revenues; property, plant and equipment; and payroll. Our share of direct and allocated administrative expenses is reflected in general and administrative expenses in the Consolidated Statement of Comprehensive Income. In management’s estimation, the allocation methodologies used are reasonable and result in a reasonable allocation to us of our costs of doing business incurred by Williams. Included in our administrative and general expenses for 2012, 2011 and 2010 were $75.6 million, $52.6 million, and $54.7 million, respectively, for management services charged by Williams and other affiliated companies.
Pursuant to an operating agreement, we serve as contract operator on certain Williams Field Services (WFS) facilities. We recorded reductions in operating expenses for services provided to and reimbursed by WFS of $4.5 million, $6.4 million, and $8.7 million in 2012, 2011 and 2010, respectively, under terms of the operating agreement. Pursuant to construction agreements, we received pre-payments from WFS of $2.3 million, $4.5 million and $13.5 million during 2012, 2011 and 2010, respectively, associated with capital projects. We received reimbursements totaling $3.1 million from Williams Gas Processing – Gulf Coast Company, L.P. in 2012 associated with costs related to a transfer and assignment agreement.
We made equity distributions of $246 million, $219 million and $334 million during 2012, 2011 and 2010, respectively. In January 2013, an additional distribution of $65 million was declared and paid.
During 2012, 2011 and 2010, WPO made contributions totaling $150 million, $115 million and $75 million, respectively, to us to fund a portion of our expenditures for additions to property, plant and equipment. In January 2013, WPO made an additional $55 million contribution. During 2012, we received a non-cash contribution of $1.5 million from WPO. During 2011, we made a non-cash return of capital to WPO of approximately $0.5 million.
8. ASSET RETIREMENT OBLIGATIONS.
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.
During 2012 and 2011, our overall asset retirement obligation changed as follows (in thousands):
| 2012 | 2011 | |||||||
| Beginning balance |
$ | 302,768 | $ | 251,644 | ||||
| Accretion |
23,052 | 19,866 | ||||||
| New obligations |
2,556 | 530 | ||||||
| Changes in estimates of existing obligations (1) |
10,895 | 74,039 | ||||||
| Property dispositions/obligations settled |
(42,401 | ) | (43,311 | ) | ||||
|
|
|
|
|
|||||
| Ending balance |
$ | 296,870 | $ | 302,768 | ||||
|
|
|
|
|
|||||
| (1) | The change in estimates of existing obligations in 2012 are primarily due to an increase of $13 million related to changes in the timing and method of abandonment of our Eminence natural gas storage caverns that were associated with a leak in 2010. The 2011 change in estimates of existing obligations included revisions of $35 million primarily due to increases in the inflation rate and estimated removal costs, which are among several factors considered for revision in the annual review process. The 2011 revision also included an increase of $39 million related to changes in the timing and method of abandonment of our Eminence natural gas storage caverns. |
50
We are entitled to collect in rates the amounts necessary to fund our ARO. All funds received for such retirements are deposited into an external trust account dedicated to funding our ARO. Under our current rate settlement our annual funding obligation is approximately $16.7 million, with installments to be deposited monthly.
9. 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, 2012 and December 31, 2011 are as follows (in millions):
| Regulatory Assets |
2012 | 2011 | ||||||
| Grossed-up deferred taxes on equity funds used |
||||||||
| during construction |
$ | 83.5 | $ | 85.6 | ||||
| Asset retirement obligations |
125.1 | 114.4 | ||||||
| Deferred taxes |
9.1 | 10.2 | ||||||
| Postretirement benefits other than pension |
4.6 | 5.7 | ||||||
| Fuel cost |
29.3 | 26.2 | ||||||
| Electric power cost |
— | 3.3 | ||||||
| Other |
— | 0.4 | ||||||
|
|
|
|
|
|||||
| Total Regulatory Assets |
$ | 251.6 | $ | 245.8 | ||||
|
|
|
|
|
|||||
| Regulatory Liabilities |
2012 | 2011 | ||||||
| Negative salvage |
$ | 203.8 | $ | 158.1 | ||||
| Deferred cash out |
6.2 | 1.2 | ||||||
| Sentinel meter station depreciation |
3.9 | 2.8 | ||||||
| Postretirement benefits other than pension |
24.7 | 22.0 | ||||||
| Electric power cost |
7.7 | — | ||||||
| Other |
1.2 | 0.7 | ||||||
|
|
|
|
|
|||||
| Total Regulatory Liabilities |
$ | 247.5 | $ | 184.8 | ||||
|
|
|
|
|
|||||
The significant regulatory assets and liabilities include:
Grossed-up deferred taxes on equity funds used during construction: Regulatory asset balance established to offset the deferred tax for the equity component of the allowance for funds used during the construction of long-lived assets. All amounts were generated during the period that we were a taxable entity. Taxes on capitalized funds used during construction and the offsetting deferred income taxes are included in the rate base and are recovered over the depreciable lives of the long-lived asset to which they relate.
Asset Retirement Obligations: Regulatory asset balance established to offset depreciation of the ARO asset and changes in the ARO liability due to the passage of time. The regulatory asset is being recovered through our rates, and is being amortized to expense consistent with the amounts collected in rates.
Deferred Taxes: Regulatory asset balance was established as a result of an increase to rate base deferred taxes due to an increase to the effective state income tax rate. The regulatory asset is being collected from rate payers over the remaining depreciable lives of the long-lived asset to which they relate.
Postretirement benefits: We recover the actuarially determined cost of postretirement benefits through rates that are set through periodic general rate filings. Any differences between the annual actuarially determined cost and amounts currently being recovered in rates are recorded as regulatory assets or liabilities and collected or refunded through future rate adjustments. These amounts are not included in the rate base.
51
Fuel cost: This amount represents the difference between the gas retained from our customers and the gas consumed in operations. These amounts are not included in the rate base but are expected to be recovered/refunded in subsequent annual fuel tracker filing periods.
Electric power cost: This amount represents the difference between the electric power costs recovered from our customers and the electric power costs incurred in operations. These amounts are not included in the rate base but are expected to be recovered/refunded in subsequent annual electric power tracker filing periods.
Negative Salvage: Our rates include a component designed to recover certain future retirement costs for which we are not required to record an asset retirement obligation. We record a regulatory liability representing the cumulative residual amount of recoveries through rates, net of expenditures associated with these retirement costs.
Deferred cash out: This amount represents the deferral of gains or losses on the purchases and sales of gas imbalances with shippers. These amounts are not included in the rate base but are expected to be recovered/refunded in subsequent annual cash out filing periods.
Sentinel meter station depreciation: This amount reflects the incremental depreciation being recorded related to the meter station modifications made for three of the Sentinel shippers. These modifications will be recovered through a surcharge over a defined period of time as stated in the Sentinel FERC order. The incremental depreciation represents the difference between the FERC granted depreciation rate for such facilities in the last rate case as compared to the depreciation rates in the Sentinel order which are based on the contractual terms in the surcharge agreements. The incremental depreciation will be recorded through the end of the contractual term and then will be amortized.
10. OTHER INCOME AND EXPENSES.
During 2012, we capitalized $8.7 million and $2.4 million, respectively, of project feasibility costs associated with the Rockaway Delivery Lateral Project and the Northeast Connector Project, which had been expensed in prior periods in Other (income) expenses, net, upon determining that the projects were probable of development. During 2011, we capitalized $10.1 million of project feasibility costs associated with the Northeast Supply Link Expansion Project, which had been expensed in prior periods in Other (income) expenses, net, upon determining that the project was probable of development. These costs will be included in the capital costs of the projects, which we believe are probable of recovery through the projects’ rates.
We detected a leak in an underground cavern at our Eminence Storage Field in Mississippi on December 28, 2010. During 2012, 2011 and 2010, we recorded $2.5 million, $14.6 million and $2.0 million, respectively, of charges to Operation and maintenance expenses primarily related to costs to ensure the safety of the surrounding area. In 2010, we also recorded $2.5 million related to gas loss in Cost of natural gas transportation.
52
TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
QUARTERLY FINANCIAL DATA (UNAUDITED)
Summarized quarterly financial data are as follows (in thousands):
| 2012 |
First | Second | Third | Fourth (1) | ||||||||||||
| Operating revenues |
$ | 309,879 | $ | 293,764 | $ | 302,957 | $ | 327,501 | ||||||||
| Operating expenses |
216,421 | 230,274 | 231,945 | 225,400 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Operating income |
93,458 | 63,490 | 71,012 | 102,101 | ||||||||||||
| Interest expense |
23,718 | 23,668 | 21,132 | 20,557 | ||||||||||||
| Other (income) and deductions, net |
(5,043 | ) | (8,859 | ) | (10,082 | ) | (7,496 | ) | ||||||||
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|
|
|
|
|
|
|
|||||||||
| Net income |
74,783 | 48,681 | 59,962 | 89,040 | ||||||||||||
| Equity interest in unrealized gain (loss) on interest rate hedge |
(25 | ) | (133 | ) | (283 | ) | 65 | |||||||||
|
|
|
|
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|
|
|
|
|||||||||
| Comprehensive income |
$ | 74,758 | $ | 48,548 | $ | 59,679 | $ | 89,105 | ||||||||
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|
|||||||||
| 2011 |
First (2) | Second (3) | Third (4) | Fourth (5) | ||||||||||||
| Operating revenues |
$ | 305,356 | $ | 300,851 | $ | 321,694 | $ | 314,613 | ||||||||
| Operating expenses |
208,555 | 223,730 | 232,435 | 223,243 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Operating income |
96,801 | 77,121 | 89,259 | 91,370 | ||||||||||||
| Interest expense |
23,822 | 23,873 | 23,887 | 23,600 | ||||||||||||
| Other (income) and deductions, net |
(8,707 | ) | (2,216 | ) | (3,702 | ) | (5,664 | ) | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Net income |
81,686 | 55,464 | 69,074 | 73,434 | ||||||||||||
| Equity interest in unrealized gain (loss) on interest rate hedge |
31 | (271 | ) | (316 | ) | 37 | ||||||||||
|
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|||||||||
| Comprehensive income |
$ | 81,717 | $ | 55,193 | $ | 68,758 | $ | 73,471 | ||||||||
|
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|
|||||||||
| (1) | Includes a $15.9 million decrease to operating expenses, of this amount, $4.8 million was expensed in the first three quarters of 2012, resulting from the reversal of project feasibility costs from expense to capital associated with Leidy Southeast, Rockaway Lateral and Northeast Connector Expansion projects. |
| (2) | Includes a $3.8 million increase to income before income taxes resulting from a gain on the sale of base gas from the Hester storage facility, a $3.6 million increase to operating expenses resulting from a gas leak at our Eminence storage facility and a $10.1 million decrease to operating expenses resulting from the reversal of project feasibility costs from expense to capital associated with the Northeast Supply Link Expansion Project. |
| (3) | Includes a $3.0 million increase to operating expenses resulting from a gas leak at our Eminence storage facility. |
| (4) | Includes a $6.7 million increase to operating expenses resulting from a gas leak at our Eminence storage facility. |
| (5) | Includes a $6.3 million increase to operating expenses resulting from project feasibility costs associated with the Atlantic Access Project and a $1.3 million increase to operating expenses resulting from a gas leak at our Eminence storage facility. |
53
Item 9. Changes In and Disagreements With Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
Disclosure Controls and Procedures
Our management, including our Senior Vice President – Atlantic-Gulf and our Vice President and Chief Accounting Officer, 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 the company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple 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.
Evaluation of Disclosure Controls and Procedures
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 – Atlantic-Gulf and our Vice President and Chief Accounting Officer. Based upon that evaluation, our Senior Vice President – Atlantic-Gulf and our Vice President and Chief Accounting Officer concluded that these Disclosure Controls are effective at a reasonable assurance level.
Management’s Annual Report on Internal Control over Financial Reporting
See report set forth in Item 8, “Financial Statements and Supplementary Data.”
Fourth Quarter 2012 Changes in Internal Controls
Except as described below, there have been no changes during the fourth quarter of 2012 that have materially affected, or are reasonably likely to materially affect, our Internal Controls over financial reporting.
None.
54
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.
Items 14. Principal Accounting 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):
| 2012 | 2011 | |||||||
| Audit fees |
$ | 1,879 | $ | 1,835 | ||||
| Audit-related fees |
— | — | ||||||
| Tax fees |
— | — | ||||||
| All other fees |
— | — | ||||||
|
|
|
|
|
|||||
| Total fees |
$ | 1,879 | $ | 1,835 | ||||
|
|
|
|
|
|||||
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.
As a wholly owned subsidiary of WPZ, we do not have a separate audit committee. The policies and procedures for pre-approving audit and non-audit services of the Audit Committee of the Board of Directors of WPZ’s general partner have been set forth in WPZ’s 2012 annual report on Form 10-K, which is available on the SEC’s website at http://www.sec.gov and on WPZ’s website at http://www.williamslp.com under the heading “Investors-SEC Filings”.
55
Item 15. Exhibits and Financial Statement Schedules
| Page Reference | ||||
| A. 1 and 2. Transcontinental Gas Pipe Line Company, LLC financials | ||||
| Index | ||||
| Covered by Report of Independent Registered Public Accounting Firm: |
||||
| Consolidated Statement of Comprehensive Income for the Years Ended December 31, 2012, 2011 and 2010 | 31 | |||
| Consolidated Balance Sheet as of December 31, 2012 and 2011 | 32-33 | |||
| Consolidated Statement of Owner’s Equity for the Years Ended December 31, 2012, 2011 and 2010 | 34 | |||
| Consolidated Statement of Cash Flows for the Years Ended December 31, 2012, 2011 and 2010 | 35-36 | |||
| Notes to Consolidated Financial Statements | 37-52 | |||
| Not covered by Report of Independent Registered Public Accounting Firm : |
||||
| Quarterly Financial Data (Unaudited) | 53 | |||
| The following schedules are omitted because of the absence of the conditions under which they are required: I, II, III, IV, and V. |
||||
56
3. Exhibits:
| Exhibit No. |
Description | |
| 2.1 | Certificate of Conversion dated December 22, 2008 and effective December 31, 2008 (filed on February 24, 2011 as Exhibit 2.1 to our report Form 10-K and incorporated herein by reference). | |
| 3.1 | Certificate of Formation dated December 22, 2008 and effective December 31, 2008 (filed on February 24, 2011 as Exhibit 3.1 to our report Form 10-K and incorporated herein by reference). | |
| 3.2 | Amended and Restated Operating Agreement of Transcontinental Gas Pipe Line Company, LLC dated February 17, 2010 (filed on October 28, 2010 as Exhibit 3.2 to our Form 10-Q and incorporated herein by reference). | |
| 4.1 | Senior Indenture dated July 15, 1996 between Transco and Citibank, N.A., as Trustee (filed on April 2, 1996 as Exhibit 4.1 to our Form S-3 (File No. 333-02155) and incorporated herein by reference). | |
| 4.2 | Indenture dated April 11, 2006 between Transco and JP Morgan Chase Bank, N.A., as Trustee (filed on April 11, 2006 as Exhibit 4.1 to our Form 8-K (File No. 001-07584) and incorporated herein by reference). | |
| 4.3 | Indenture, dated as of May 22, 2008 between Transco and The Bank of New York Trust Company, N.A., as Trustee (filed on May 23, 2008 as Exhibit 4.1 to our Form 8-K (File No. 001-07584) and incorporated herein by reference). | |
| 4.4 | Indenture, dated as of August 12, 2011 between Transco and The Bank of New York Mellon Trust Company, N.A., as Trustee (filed on August 12, 2011 as Exhibit 4.1 to our Form 8-K (File No. 001-07584) and incorporated herein by reference). | |
| 4.5 | Indenture, dated as of July 13, 2012, between Transco and The Bank of New York Mellon Trust Company, N.A., as trustee. (filed on July 16, 2012 as Exhibit 4.1 to our Form 8-K (File No. 001-07584) and incorporated herein by reference). | |
| 10.1 | Administrative Services Agreement, dated as of February 17, 2010, by and between Transco Pipeline Services LLC and Transco (filed on February 22, 2010 as Exhibit 10.3 to Williams Partners L.P.’s, Form 8-K (File No. 001-32599) and incorporated herein by reference). | |
| 10.2* | Assignment Agreement dated February 13, 2013 by and between Transco Pipeline Services LLC and Williams WPC-I, LLC, effective January 1, 2013. | |
| 10.3 | Credit Agreement, dated as of June 3, 2011, by and among Williams Partners L.P., Northwest Pipeline GP and Transco, as co-borrowers, the lenders named therein, and Citibank N.A., as Administrative Agent (filed on August 4, 2011 as Exhibit 10.1 to Williams Partners L.P.’s quarterly report on Form 10-Q (File No. 001-32599) and incorporated herein by reference). | |
| 10.4 | Commitment Increase and First Amendment Agreement, dated as of September 25, 2012, by and among Williams Partners L.P., Northwest Pipeline GP and Transco, as co-borrowers, the lenders named therein, the Issuing Banks, and Citibank N.A., as administrative agent (filed on September 27, 2012 as Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599) and incorporated herein by reference). | |
| 31.1* | Certification of Principal Executive Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |
57
| 31.2* | Certification of Principal Financial Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |
| 32 ** | 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. | |
| 101.INS**
101.I SCH **
101.CAL**
101.DEF**
101.LAB** |
XBRL Instance Document.
XBRL Taxonomy Extension Schema.
XBRL Taxonomy Extension Calculation Linkbase.
XBRL Taxonomy Extension Definition Linkbase.
XBRL Taxonomy Extension Label Linkbase. | |
| 101.PRE** | XBRL Taxonomy Extension Presentation Linkbase. | |
* Filed herewith.
** Furnished herewith.
58
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 | ||
Date: February 27, 2013
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:
| Signature |
Title | |
| /s/ RORY L. MILLER Rory L. Miller |
Management Committee Member and Senior Vice President – Atlantic-Gulf (Principal Executive Officer) | |
| /s/ TED T. TIMMERMANS Ted T. Timmermans |
Vice President and Chief Accounting Officer (Principal Financial Officer) | |
| /s/ JEFFREY P. HEINRICHS Jeffrey P. Heinrichs |
Controller (Principal Accounting Officer) | |
| /s/ FRANK J. FERAZZI Frank J. Ferazzi |
Management Committee Member and Vice President | |
Date: February 27, 2013
INDEX OF EXHIBITS
| Exhibit No. |
Description | |
| 2.1 | Certificate of Conversion dated December 22, 2008 and effective December 31, 2008 (filed on February 24, 2011 as Exhibit 2.1 to our report Form 10-K and incorporated herein by reference). | |
| 3.1 | Certificate of Formation dated December 22, 2008 and effective December 31, 2008 (filed on February 24, 2011 as Exhibit 3.1 to our report Form 10-K and incorporated herein by reference). | |
| 3.2 | Amended and Restated Operating Agreement of Transcontinental Gas Pipe Line Company, LLC dated February 17, 2010 (filed on October 28, 2010 as Exhibit 3.2 to our Form 10-Q and incorporated herein by reference). | |
| 4.1 | Senior Indenture dated July 15, 1996 between Transco and Citibank, N.A., as Trustee (filed on April 2, 1996 as Exhibit 4.1 to our Form S-3 (File No. 333-02155) and incorporated herein by reference). | |
| 4.2 | Indenture dated April 11, 2006 between Transco and JP Morgan Chase Bank, N.A., as Trustee (filed on April 11, 2006 as Exhibit 4.1 to our Form 8-K (File No. 001-07584) and incorporated herein by reference). | |
| 4.3 | Indenture, dated as of May 22, 2008 between Transco and The Bank of New York Trust Company, N.A., as Trustee (filed on May 23, 2008 as Exhibit 4.1 to our Form 8-K (File No. 001-07584) and incorporated herein by reference). | |
| 4.4 | Indenture, dated as of August 12, 2011 between Transco and The Bank of New York Mellon Trust Company, N.A., as Trustee (filed on August 12, 2011 as Exhibit 4.1 to our Form 8-K (File No. 001-07584) and incorporated herein by reference). | |
| 4.5 | Indenture, dated as of July 13, 2012, between Transco and The Bank of New York Mellon Trust Company, N.A., as trustee. (filed on July 16, 2012 as Exhibit 4.1 to our Form 8-K (File No. 001-07584) and incorporated herein by reference). | |
| 10.1 | Administrative Services Agreement, dated as of February 17, 2010, by and between Transco Pipeline Services LLC and Transco (filed on February 22, 2010 as Exhibit 10.3 to Williams Partners L.P.’s, Form 8-K (File No. 001-32599) and incorporated herein by reference). | |
| 10.2* | Assignment Agreement dated February 13, 2013 by and between Transco Pipeline Services LLC and Williams WPC-I, LLC, effective January 1, 2013. | |
| 10.3 | Credit Agreement, dated as of June 3, 2011, by and among Williams Partners L.P., Northwest Pipeline GP and Transco, as co-borrowers, the lenders named therein, and Citibank N.A., as Administrative Agent (filed on August 4, 2011 as Exhibit 10.1 to Williams Partners L.P.’s quarterly report on Form 10-Q (File No. 001-32599) and incorporated herein by reference). | |
| 10.4 | Commitment Increase and First Amendment Agreement, dated as of September 25, 2012, by and among Williams Partners L.P., Northwest Pipeline GP and Transco, as co-borrowers, the lenders named therein, the Issuing Banks, and Citibank N.A., as administrative agent (filed on September 27, 2012 as Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599) and incorporated herein by reference). | |
| 31.1* | Certification of Principal Executive Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |
| 31.2* | Certification of Principal Financial Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |
| 32 ** | 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. | |
| 101.INS** | XBRL Instance Document. | |
| 101.I SCH ** | XBRL Taxonomy Extension Schema. | |
| 101.CAL** | XBRL Taxonomy Extension Calculation Linkbase. | |
| 101.DEF** | XBRL Taxonomy Extension Definition Linkbase. | |
| 101.LAB** | XBRL Taxonomy Extension Label Linkbase. | |
| 101.PRE** | XBRL Taxonomy Extension Presentation Linkbase. | |
* Filed herewith.
** Furnished herewith.
Exhibit 10.2
ASSIGNMENT AGREEMENT
This Assignment Agreement (“Assignment”), entered into by and among Transco Pipeline Services LLC, a Delaware limited liability company (“Assignor”), and Williams WPC-I, LLC, a Delaware limited liability company (“Assignee”), is effective as of January 1, 2013 (the “Effective Date”).
RECITALS
A. WHEREAS, Transcontinental Gas Pipe Line Company, LLC, a Delaware limited liability company, and Assignor are parties to an Administrative Services Agreement dated February 16, 2010 (the “Agreement”).
B. WHEREAS, pursuant to an organizational restructuring of The Williams Companies, Inc. and its affiliates, employees of Assignor ceased to be employees of Assignor and became employees solely of Assignee on the Effective Date.
Assignor and Assignee hereto agree as follows:
ASSIGNMENT AND ASSUMPTION
1. Assignment. Assignor hereby assigns to Assignee all rights, obligations, and other interests in and under the Agreement.
2. Assumption. Assignee shall assume and be responsible for all of Assignor’s rights, obligations, and other interests in and under the Agreement, including, but not limited to, any rights or obligations arising before the Effective Date.
IN WITNESS WHEREOF, the parties hereto have caused this Assignment to be executed by their duly authorized representatives on February 13, 2013.
| ASSIGNOR:
Transco Pipeline Services LLC |
ASSIGNEE:
Williams WPC-I, LLC | |||||||
| By: | /s/ Frank J. Ferazzi | By: | /s/ Stephanie C. Cipolla | |||||
| Frank J. Ferazzi | Stephanie C. Cipolla | |||||||
| Vice President |
President | |||||||
Exhibit 31.1
SECTION 302 CERTIFICATION
I, Rory L. Miller, certify that:
1. I have reviewed this annual report on Form 10-K of Transcontinental Gas Pipe Line Company, LLC;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
| Date: February 27, 2013 | ||
| By: | /s/ Rory L. Miller | |
| Rory L. Miller Senior Vice President – Atlantic-Gulf (Principal Executive Officer) | ||
Exhibit 31.2
SECTION 302 CERTIFICATION
I, Ted T. Timmermans, certify that:
| 1. | I have reviewed this annual report on Form 10-K of Transcontinental Gas Pipe Line Company, LLC; |
| 2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
| 3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
| 4. | The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
| (a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
| (b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
| (c) | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
| (d) | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
| 5. | The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): |
| (a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
| (b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
| Date: February 27, 2013 |
| /s/ Ted T. Timmermans |
| Ted T. Timmermans Vice President and Chief Accounting Officer (Principal Financial Officer) |
Exhibit 32
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Annual Report of Transcontinental Gas Pipe Line Company, LLC (the “Company”) on Form 10-K for the period ending December 31, 2012 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), each of the undersigned hereby certifies, in his capacity as an officer of the Company, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that to his knowledge:
(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
| /s/ Rory L. Miller |
| Rory L. Miller Senior Vice President – Atlantic-Gulf February 27, 2013 |
| /s/ Ted T. Timmermans |
| Ted T. Timmermans Vice President and Chief Accounting Officer February 27, 2013 |
A signed original of this written statement required by Section 906 has been provided to, and will be retained by, the Company and furnished to the Securities and Exchange Commission or its staff upon request.
The foregoing certification is being furnished to the Securities and Exchange Commission as an exhibit to the Report and shall not be considered filed as part of the Report.
|
Asset Retirement Obligations (Details Textual) (USD $)
In Millions, unless otherwise specified |
12 Months Ended | |
|---|---|---|
|
Dec. 31, 2012
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Dec. 31, 2011
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| AssetRetirementObligationDisclosureAbstract | ||
| Asset Retirement Obligations Significant Changes Due To Changes In The Timing And Method Of Abandonment | $ 13 | $ 39 |
| Asset Retirement Obligation Annual Funding | 16.7 | |
| Asset Retirement Obligations Significant Changes Annual Review Process | $ 35 |
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Fair Value Measurements (Details Textual) (USD $)
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Dec. 31, 2012
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Dec. 31, 2011
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|---|---|---|
| Fair Value Measurements [Abstract] | ||
| FairValueAssetsLevel1ToLevel2TransfersAmount | $ 0 | $ 0 |
| FairValueAssetsLevel2ToLevel1TransfersAmount | 0 | 0 |
| FairValueLiabilitiesLevel1ToLevel2TransfersAmount | 0 | 0 |
| FairValueLiabilitiesLevel2ToLevel1TransfersAmount | $ 0 | $ 0 |
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Regulatory Assets and Liabilities (Tables)
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Dec. 31, 2012
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| RegulatoryAssetsAndLiabilitiesDisclosureAbstract | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Regulatory Assets And Liabilities Disclosure [Table Text Block] |
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Transactions with Major Customers and Affiliates (Details Textual) (USD $)
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1 Months Ended | 12 Months Ended | ||
|---|---|---|---|---|
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Jan. 31, 2013
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Dec. 31, 2012
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Dec. 31, 2011
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Dec. 31, 2010
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| Related Party Transaction [Line Items] | ||||
| Advances to affiliate | $ 312,165,000 | $ 253,611,000 | ||
| Related Party Transaction, Rate | 0.01% | |||
| Total operating revenues | 1,234,101,000 | 1,242,514,000 | 1,181,995,000 | |
| Cost of natural gas sales | 65,120,000 | 108,359,000 | 99,346,000 | |
| Entity Number of Employees | 0 | |||
| Administrative and general | 174,610,000 | 148,113,000 | 148,589,000 | |
| Total operating costs and expenses | 904,040,000 | 887,963,000 | 842,528,000 | |
| Cash distributions | 246,259,000 | 219,000,000 | 333,791,000 | |
| Cash contributions from parent | 150,000,000 | 115,000,000 | 75,000,000 | |
| Non-cash contributions from parent | 1,524,000 | 0 | 0 | |
| Non-cash return of capital | 0 | (546,000) | 0 | |
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Affiliated Entity [Member]
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| Related Party Transaction [Line Items] | ||||
| Total operating revenues | 17,000,000 | 18,500,000 | 23,400,000 | |
| Cost of natural gas sales | 3,900,000 | 8,800,000 | 4,800,000 | |
| Administrative and general | 75,600,000 | 52,600,000 | 54,700,000 | |
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Williams Partners L.P. [Member]
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| Related Party Transaction [Line Items] | ||||
| Advances to affiliate | 312,200,000 | 253,600,000 | ||
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Williams Field Services Company [Member]
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| Related Party Transaction [Line Items] | ||||
| Total operating costs and expenses | (4,500,000) | (6,400,000) | (8,700,000) | |
| ContributionsInAidOfConstruction | 2,300,000 | 4,500,000 | 13,500,000 | |
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Williams Partners Operating LLC [Member]
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| Related Party Transaction [Line Items] | ||||
| Cash distributions | 65,000,000 | 246,000,000 | 219,000,000 | 334,000,000 |
| Cash contributions from parent | 55,000,000 | 150,000,000 | 115,000,000 | 75,000,000 |
| Non-cash contributions from parent | 1,500,000 | |||
| Non-cash return of capital | 500,000 | |||
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The Williams Companies, Inc.[Member]
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| Related Party Transaction [Line Items] | ||||
| Labor And Related Expense | 206,100,000 | 191,100,000 | 170,700,000 | |
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Williams Gas Processing - Gulf Coast Company, L.P. [Member]
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| Related Party Transaction [Line Items] | ||||
| Reimbursement Revenue | $ 3,100,000 | |||
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Contingent Liabilities and Commitments
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12 Months Ended |
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Dec. 31, 2012
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| Contingent Liabilities and Commitments [Abstract] | |
| CONTINGENT LIABILITIES AND COMMITMENTS | 2. CONTINGENT LIABILITIES AND COMMITMENTS.
Rate Matters.
General rate case (Docket No. RP12-993) On August 31, 2012, we submitted to the FERC a general rate filing principally designed to recover increased costs and to comply with the terms of the settlement in our Docket No. RP06-569 rate proceeding (see below) to file a rate case no later than August 31, 2012. On September 28, 2012, the FERC issued an order accepting and suspending our filing to be effective March 1, 2013, subject to refund and the outcome of a hearing, except that rates for certain services that were proposed as overall rate decreases were accepted, without suspension, to be effective October 1, 2012. These decreased rates will not be subject to refund, but may be subject to decrease prospectively under the Natural Gas Act of 1938, Section 5.
General rate case (Docket No. RP06-569) On August 31, 2006, we submitted to the FERC a general rate filing principally 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. Certain parties sought rehearing of the FERC's order and, on April 2, 2012, the FERC denied the rehearing request. On June 1, 2012, one of the parties filed an appeal in the U.S. Court of Appeals for the D.C. Circuit (D.C. Circuit). If the D.C. Circuit were to overturn the FERC's order, we believe any refunds would not be material to our results of operations.
Environmental Matters.
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 $5 million to $7 million (including both expense and capital expenditures), measured on an undiscounted basis, and will be spent over the next three to five 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, 2012, we had a balance of approximately $3.3 million for the expense portion of these estimated costs recorded in current liabilities ($1.1 million) and other long-term liabilities ($2.2 million) in the accompanying Consolidated Balance Sheet. At December 31, 2011, we had a balance of approximately $3.5 million for the expense portion of these estimated costs recorded in current liabilities ($0.8 million) and other long-term liabilities ($2.7 million) in the accompanying Consolidated Balance Sheet.
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 $5 million to $7 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 $5 million to $7 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.
In March 2008, the EPA promulgated a new, lower National Ambient Air Quality Standard (NAAQS) for ground-level ozone. 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. In September 2011, the EPA announced that it was proceeding with required actions to implement the 2008 ozone standard and area designations. In May 2012, the EPA completed designation of new eight-hour ozone non-attainment areas. Several Transco facilities are located in 2008 ozone non-attainment areas; however, each facility has been previously subjected to federal and/or state emission control requirements implemented to address preceding ozone standards. To date, no new federal or state actions have been proposed to mandate additional emission controls at these facilities. At this time, it is unknown whether future federal or state regulatory actions associated with implementation of the 2008 ozone standard will impact our operations and increase the cost of additions to property, plant and equipment. Until any additional federal or state regulatory actions are proposed, we are unable to estimate the cost of additions that may be required to meet this new regulation.
Additionally, in August 2010, the EPA promulgated National Emission Standards for Hazardous Air Pollutants (NESHAP) regulations that will impact our operations. The remaining emission control additions required to comply with the hazardous air pollutant regulations are estimated to include capital costs in the range of $10 million to $12 million through 2013, the compliance date.
On January 22, 2010, the EPA set a new one-hour nitrogen dioxide (NO2) NAAQS. The effective date of the new NO2 standard was April 12, 2010. This standard is subject to challenges in federal court. On January 20, 2012, the EPA determined pursuant to available information that no area in the country is violating the 2010 NO2 NAAQS and thus designated all areas of the country as “unclassifiable/attainment.” Also, at that time, the EPA noted its plan to deploy an expanded NO2 monitoring network beginning in 2013. However, on October 5, 2012, the EPA proposed a graduated implementation of the monitoring network between January 1, 2014 and January 1, 2017. Once three years of data is collected from the new monitoring network, the EPA will reassess attainment status with the one-hour NO2 NAAQS. Until that time, the EPA or states may require ambient air quality modeling on a case by case basis to demonstrate compliance with the NO2 standard. Because we are unable to predict the outcome of the EPA's or states' future assessment using the new monitoring network, we are unable to estimate the cost of additions that may be required to meet this regulation.
We consider prudently incurred environmental assessment and remediation costs and the 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. As a result, as estimated costs of environmental assessment and remediation are incurred, they are recorded as regulatory assets in the Condensed Consolidated Balance Sheet until collected through rates. However, we had no uncollected environmental related regulatory assets at December 31, 2012 or December 31, 2011.
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 Federal Clean Air Act (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. The EPA has requested additional information pertaining to these compressor stations and in May 2011, we submitted information in response to the EPA's latest request. In August, 2010, the EPA requested, and we provided, similar information for a compressor station in Maryland.
Safety Matters.
Pipeline Integrity Regulations We have developed an Integrity Management Plan that we believe meets the United States Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA) final rule that was issued pursuant to the requirements of the Pipeline Safety Improvement Act of 2002. The rule requires gas pipeline operators to develop an integrity management program for transmission pipelines that could affect high consequence areas in the event of pipeline failure. The Integrity Management Program includes a baseline assessment plan to be completed in 2012 along with periodic reassessments to be completed within required timeframes. In meeting the integrity regulations, we have identified high consequence areas and developed our baseline assessment plan. The required pipeline segments originally identified for assessment were completed within the required timeframe, with one exception which was reported to PHMSA. We estimate that the cost to complete the remediation associated with the 2012 assessments will be approximately $20 million, most of which we expect to be 2013 capital expenditures.
Reassessments of the original segments have begun as required by regulations. As new pipelines are constructed and new high consequence areas are created, additional pipeline segments are required to be added to the baseline assessment plan. These segments are also on schedule as required. 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.
Other Matters.
Various other proceedings are pending against us and are considered incidental to our operations.
Summary.
We estimate that for all matters for which we are able to reasonably estimate a range of loss, including those noted above and others that are not individually significant, our aggregate reasonably possible losses beyond amounts accrued for all of our contingent liabilities are immaterial to our expected future annual results of operations, liquidity and financial position. These calculations have been made without consideration of any potential recovery from third parties. We have disclosed all significant matters for which we are unable to reasonably estimate a range of possible loss.
Other Commitments.
Commitments for construction We have commitments for construction and acquisition of property, plant and equipment of approximately $225 million at December 31, 2012. |
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