UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
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þ[x] | | ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 20062008
OR
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o[ ] | | TRANSITION REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from _______ to __________________to ____________
Commission File Number 1-7584
TRANSCONTINENTAL GAS PIPE LINE CORPORATIONCOMPANY, LLC
(Exact name of Registrant as specified in its charter)
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| DELAWARE | | 74-1079400 |
(State or other jurisdiction of incorporation or organization) | | 74-1079400
(I.R.S. Employer |
incorporation or organization) | | Identification No.) |
| | | |
2800 Post Oak Blvd., P. O. Box 1396, Houston, Texas
| | 77251 |
| (Address of principal executive offices) | | 77251
Zip Code |
Registrant’s telephone number, including area code (713) | | |
| Registrant’s telephone number, including area code | | (713) 215-2000 |
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
Yeso [ ] No [þÖ]
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 orSection 15(d) of the Act.
Yes[ ].YesoNo [þÖ]
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or15(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 [þÖ] Noo [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to thisForm 10-K. [þÖ]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a non-accelerated filer.smaller reporting company. See definition of “large accelerated filer,” “accelerated filer,” and large accelerated filer”“smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filero Accelerated fileroNon-accelerated filerþ | | | | | | |
| Large accelerated filer [ ] | | Accelerated filer [ ] | | Non-accelerated filer [Ö] | | Smaller reporting company [ ] |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).
Yeso [ ] No [þÖ
No voting or non-voting common equity of registrant is held by non-affiliates.
The number of shares of Common Stock, par value $1.00 per share, outstanding at January 31, 2007 was 100.]
Documents Incorporated by Reference: None
The registrant meets the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K and is therefore filing thisForm 10-K with the reduced disclosure format.
TRANSCONTINENTAL GAS PIPE LINE CORPORATION
COMPANY, LLC
FORM 10-K
TABLE OF CONTENTS
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PART I
In this report, Transco (which includes Transcontinental Gas Pipe Line Corporation and unless the context otherwise requires, all of our consolidated subsidiaries)Company, LLC (Transco) is at times referred to in the first person as “we,” “us” or “our.”
GENERAL
Since we meet the conditions set forth in General Instruction (I) (1) (a) and (b) of Form 10-K, the information in this Item 1 is in a reduced disclosure format.
Transco is a wholly-owned subsidiary of Williams Gas Pipeline Company, LLC (WGP). WGP is a wholly-owned subsidiary of The Williams Companies, Inc. (Williams). For 2006 WilliamsOn December 31, 2008, Transcontinental Gas Pipe Line Corporation was converted from a corporation to a limited liability company and thereafter is a reporting entity underknown as Transcontinental Gas Pipe Line Company, LLC. Effective December 31, 2008, we distributed our ownership interest in our wholly-owned subsidiaries to WGP. Accordingly, we have adjusted financial and operating information retrospectively to remove the Sarbanes-Oxley Acteffects of 2002. Transco is not an accelerated filer and therefore not required in 2006 to report under Section 404 of the Sarbanes-Oxley Act of 2002.our former subsidiaries.
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 the states of Alabama, Georgia, South Carolina, North Carolina, Virginia, Maryland, Pennsylvania and New Jersey to the New York City metropolitan area. We also hold a minority interest in Cardinal Pipeline Company, LLC, an intrastate natural gas pipeline located in North Carolina. Our principal business is the interstate transportation of natural gas, which the Federal Energy Regulatory Commission (FERC) regulates.
As of December 31, 2006, we had 1,272 full time employees.
At December 31, 2006,2008, our system had a mainline delivery capacity of approximately 4.7 MMdt1 of gas per day from production areas to our primary markets. Using our Leidy Line andalong with market-area storage and transportation capacity, we can deliver an additional 3.53.8 MMdt of gas per day for a system-wide delivery capacity total of approximately 8.28.5 MMdt of gas per day. The system is comprised of approximately 10,50010,100 miles of mainline and branch transmission pipelines, 4445 compressor stations, fivefour underground storage fields and twoa liquefied natural gas (LNG) storage facilities.facility. Compression facilities at sea level rated capacity total approximately 1.5 million horsepower.
We have natural gas storage capacity in fivefour underground storage fields located on or near our pipeline system and/or market areas and we operate threetwo of these storage fields. We also have storage capacity in aan LNG storage facility that we 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 216204 Bcf of gas. In addition, through wholly-owned subsidiaries we operate and own a 35 percent interest in Pine Needle LNG Company, LLC, a LNGOctober 2008, the FERC approved Transco’s request to abandon our Hester storage facility, with 4 Bcf ofwhich is not in operation. Hester is not included in the gas storage capacity.capacity described above. Storage capacity permits our customers to inject gas into storage during the summer and off-peak periods for delivery during peak winter demand periods.
Our gas pipeline facilities are generally owned in fee. However, a substantial portion of such facilities
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| 1 | | As used in this report, the term “Mcf” means thousand cubic feet, the term “MMcf” means million cubic feet, the term “Bcf” means billion cubic feet, the term “Tcf” means trillion cubic feet, the term “Mcf/d” means thousand cubic feet per day, the term “MMcf/d” means million cubic feet per day, the term “Bcf/d” means billion cubic feet per day, the term “MMBtu” means million British Thermal Units, the term “TBtu” means trillion British Thermal Units, the term “dt” means dekatherm, the term “Mdt” means thousand dekatherms, the term “Mdt/d” means thousand dekatherms per day and theterm “MMdt” means million dekatherms. |
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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.
Through an agency agreement, one of our affiliates, Williams Power Company (WPC),Gas Marketing, Inc. (WGM) manages our jurisdictional merchant gas sales.
Over the past several years, we filed applications with the FERC seeking authorization to abandon certain facilities located onshore and offshore in Texas, Louisiana and Mississippi by conveyance to an affiliate, Williams Gas Processing — Gulf Coast Company. The net book value of these facilities at December 31, 2006, was approximately $277 million. Because of the various challenges to our applications and numerous outstanding regulatory issues affecting the transfer of these facilities, to date we have transferred only a small offshore system with a net book value of $3.3 million, and we have no immediate plans to transfer the remaining facilities.
MARKETS AND TRANSPORTATION
Our natural gas pipeline system serves customers in Texas and eleven11 southeast and Atlantic seaboard states including major metropolitan areas in Georgia, North Carolina, Washington, D.C., New York, New Jersey and Pennsylvania.
Our major customers are public utilities and municipalities that provide service to residential, commercial, industrial and electric generation end users. Shippers on our pipeline system include public utilities, municipalities, intrastate pipelines, direct industrial users, electrical generators, gas marketers and producers. Our two largest customers in 20062008 were Public Service Enterprise Group, and Keyspan Corporation,National Grid (formerly known as KeySpan Corporation), which accounted for approximately 10.2%11.0 percent and 7.1%,10.0 percent, respectively, of our total operating revenues. Our firm transportation agreements are generally long-term agreements with various expiration dates and account for the major portion of our business. Additionally, we offer interruptible transportation services under shorter-term agreements.
Our total system deliveries for the years 2006, 20052008, 2007 and 20042006 are shown below.
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| Transco System Deliveries (TBtu) | | 2006 | | 2005 | | 2004 | | | 2008 | | 2007 | | 2006 |
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| Market-area deliveries | | |
| Long-haul transportation | | 795.1 | | 754.9 | | 781.6 | | | 752.8 | | 838.6 | | 795.1 | |
| Market-area transportation | | 816.5 | | 852.5 | | 817.1 | | | 969.2 | | 874.9 | | 816.5 | |
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| Total market-area deliveries | | 1,611.6 | | 1,607.4 | | 1,598.7 | | | 1,722.0 | | 1,713.5 | | 1,611.6 | |
| Production-area transportation | | 247.2 | | 278.4 | | 317.7 | | | 188.4 | | 189.9 | | 247.2 | |
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| Total system deliveries | | 1,858.8 | | 1,885.8 | | 1,916.4 | | | 1,910.4 | | 1,903.4 | | 1,858.8 | |
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| Average Daily Transportation Volumes (TBtu) | | 5.1 | | 5.2 | | 5.2 | | |
| Average Daily Firm Reserved Capacity (TBtu) | | 6.6 | | 6.6 | | 6.6 | | |
| Average Daily Transportation Volumes | | | 5.2 | | 5.2 | | 5.1 | |
| Average Daily Firm Reserved Capacity | | | 6.8 | | 6.6 | | 6.6 | |
Our total market-area deliveries for 20062008 increased 4.28.5 TBtu (0.3%(0.5%) when compared to 2005.2007. The increased deliveries are primarily the result of our Potomac and Leidy to Long Island expansions placed in service in November 2007 and December 2007, respectively, partially offset by the reduction of volumes available from producers beginning in the third quarter of 2008 as a result of gas wells shut-in/or damages to gathering lines in the Gulf of Mexico caused by Hurricanes Ike and Gustav. Our production area deliveries decreased 31.21.5 TBtu (11.2%(0.8%) when compared to 2005.2007. The reductiondecrease in production area deliveries is primarily due to decreased requests for deliveriesvolumes beginning in the third quarter of 2008 due to production-area interconnects.gas wells shut-in and/or damages to gathering lines in the Gulf of Mexico caused by Hurricanes Ike and Gustav. This decrease was partially offset by the increase in volumes from offshore Texas as a result of new wells drilled and producing.
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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
Leidy to Long Island Expansion ProjectThe Leidy to Long Island Expansion Project will involve an expansion of our existing natural gas transmission system in Zone 6 from the Leidy Hub in Pennsylvania to Long Island, New York. The project will provide 100,000 dekatherms per day (dt/d) of incremental firm transportation capacity,pipeline projects listed below are significant future pipeline projects for which has been fully subscribed by one shipper for a twenty-year primary term. The project facilities will include pipeline looping in Pennsylvania, pipeline looping, pipeline replacement and a natural gas compressor facility in New Jersey and appurtenant facilities in New York. We expect that over three-quarters of the project expenditures will occur in 2007. We filed an application for FERC authorization of the project in December 2005, which the FERC approved by order issued on May 18, 2006. On October 20, 2006, we filed an application to amend the FERC authorizations to reflect our ownership of certain appurtenant facilities as part of the project and to adjust the cost of facilities and rates, which the FERC approved by order issued on January 11, 2007. The estimated capital cost of the project is approximately $141 million. The target in-service date for the project is November 1, 2007.
Potomac Expansion ProjectThe Potomac Expansion Project will involve an expansion of our existing natural gas transmission system from receipt points in North Carolina to delivery points in the greater Baltimore and Washington, D.C. metropolitan areas. The project will provide 165,000 dt/d of incremental firm transportation capacity, which has been fully subscribed by shippers under long-term firm arrangements. The estimated capital cost of the project is approximately $74 million. We filed an application for FERC approval of the project on July 17, 2006. The target in-service date for the project is November 1, 2007.have customer commitments.
Sentinel Expansion ProjectThe Sentinel Expansion Project will involveinvolves an expansion of our existing natural gas transmission system from the Leidy Hub in Clinton County, Pennsylvania and from the Pleasant Valley interconnection with Cove Point LNG in Fairfax County, Virginia to various delivery points requested by the shippers under the project. The project will provide 142,000 dt/d of incremental firm transportation capacity, which has been fully subscribed by the shippers under long-term firm arrangements. The project facilities will include pipeline looping in Pennsylvania and New Jersey and minor compressor station modifications. The estimated capital cost of the project excluding any customer meter station upgrades is estimated to be up to approximately $140$200 million. In orderPhase 1 was placed into service in December 2008. Phase II is expected to accommodate certain shippers, we are planningbe placed into service by November 2009.
Pascagoula Expansion ProjectThe Pascagoula Expansion Project involves the construction of a new pipeline to be jointly owned with Florida Gas Transmission connecting Transco’s existing Mobile Bay Lateral to the outlet pipeline of a proposed LNG import terminal in Mississippi. Transco’s share of the capital cost of the project is estimated to be up to approximately $37 million. Transco plans to place the incremental firm transportation capacityproject into service in two phases,September 2011.
Mobile Bay South Expansion ProjectThe Mobile Bay South Expansion Project involves the first phase commencingaddition of compression at Transco’s Station 85 in Choctaw County, Alabama to allow Transco to provide firm transportation service southbound on November 1, 2008 for 67,000 dt/d of service and the second phase commencing on November 1, 2009 for an additional 75,000 dt/d of service.Mobile Bay line from Station 85 to various delivery points. The FERC has granted our request for a pre-application environmental reviewcapital cost of the project soliciting early inputis estimated to be up to approximately $37 million. Transco plans to place the project into service by May 2010.
85 North Expansion ProjectThe 85 North Expansion Project involves an expansion of our existing natural gas transmission system from citizens, governmental entitiesStation 85 in Choctaw County, Alabama to various delivery points as far north as North Carolina. The capital cost of the project is estimated to be $248 million. Transco plans to place the project into service in phases, in July 2010 and other interested parties. We expect to file a formal application with the FERC in the second quarter of 2007.May 2011.
REGULATORY MATTERS
Our transportation rates are established through the FERC ratemaking process. Key determinants in the ratemaking process are (1) costs of providing service, including depreciation expense, (2) allowed rate of return, including the equity component of the capital structure and related income taxes, and (3) volume
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throughput assumptions. The allowed rate of return is determined in each rate case. Rate design and the allocation of costs between the demand and commodity rates also impact profitability. As a result of these proceedings, certain revenues may be collected subject to refund. We record estimates of rate refund liabilities considering outcomes of our regulatory proceedings, advice of counsel and estimated total exposure, as discounted and risk weighted, as well as collection and other risks.
Since September 1, 1992, we have designed our rates using the straight fixed-variable (SFV) method of rate design. Under the SFV method of rate design, substantially all fixed costs, including return on equity and income taxes, are included in a demand charge to customers and all variable costs are recovered through a commodity charge to customers. While the use of SFV rate design limits our opportunity to earn incremental revenues through increased throughput, it also limits our risk associated with fluctuations in throughput.
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On March 1, 2001, we submitted to the FERC a general rate filing (Docket No. RP01-245) to recover increased costs. All cost of service, throughput and throughput mix, cost allocation and rate design issues in this rate proceeding have been resolved by settlement or litigation. The resulting rates becamewere effective onfrom September 1, 2001. Certain cost allocation, rate design and2001 to March 1, 2007. A tariff mattersmatter in this proceeding havehas not yet been finally resolved. We believe the resolution of these matters will not have a materially adverse effect upon our future financial position.
On August 31, 2006, we submitted to the FERC a general rate filing (Docket No. RP06-569) principally designed to recover costs associated with (a) an increase in operation and maintenance expenses and administrative and general expenses; (b) an increase in depreciation expense; (c) the inclusion of costs for asset retirement obligations; (d) an increase in rate base resulting from additional plant; and (e) an increase in rate of return and related taxes. The filing reflected an increase in annual revenues from jurisdictional service of approximately $281 million over the cost of service underlying the rates reflected in the settlement of our Docket No. RP01-245 rate proceeding, as adjusted to include the cost of service and rate base amounts for expansion projects placed in service after the September 1, 2001 effective date of the Docket No. RP01-245 rates. The filing also reflected changes to our tariff, cost allocation and rate design methods, including the refunctionalization of certain facilities from transmission plant accounts to jurisdictional gathering plant accounts consistent with various FERC orders (including the facilities addressed in the FERC’s various spin-down orders). On September 29, 2006, the FERC issued an order accepting and suspending our August 31, 2006 general rate filing to bebecame effective March 1, 2007, subject to refund and the outcome of a hearing. On November 28, 2007, we filed with the FERC a Stipulation and Agreement (Agreement) resolving all but one issue in the rate case. On March 7, 2008, the FERC issued an order approving the Agreement without modifications. Pursuant to its terms, the Agreement became effective on June 1, 2008, and refunds of approximately $144 million were issued on July 17, 2008. We had previously provided a reserve for the refunds.
The one issue reserved for litigation or further settlement relates to our proposal to change the design of the rates for service under one of our storage rate schedules, which was implemented subject to refund on March 1, 2007. A hearing on that issue was held before a FERC Administrative Law Judge (ALJ) in July 2008. In November 2008, the ALJ issued an initial decision in which he determined that Transco’s proposed incremental rate design is unjust and unreasonable. The ALJ’s decision is subject to review by the FERC.
SALES SERVICE
As discussed above, WPCWGM manages our jurisdictional merchant gas sales, which are made to customers pursuant to a blanket sales certificate issued by the FERC. Most of these sales were previously made through a Firm Sales (FS) program which gave customers the option to purchase daily quantities of gas from us at market-responsive prices in exchange for a demand charge payment. Pursuant to the terms of an agreement with the FERC, we terminated our remaining FS agreements effective April 1, 2005. Through an agency agreement, WPCWGM is still authorized to make gas sales on our behalf in order to manage our remaining gas purchase obligations. WPCWGM receives all margins associated with jurisdictional merchant gas sales business and, as our agent, assumes all market and credit risk associated with our jurisdictional merchant gas sales. Consequently, our merchant gas sales service and the termination of the FS agreements in April 2005, havehas no impact on our operating income or results of operations.
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Our gas sales volumes managed by WPCWGM for the years 2008, 2007 and 2006 2005in TBtus were 0.3, 2.0 and 2004 are shown below.
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| Gas Sales Volumes (TBtu) | | 2006 | | 2005 | | 2004 |
| Long-term sales | | | — | | | | 7.8 | | | | 30.3 | |
| Short-term sales | | | 3.6 | | | | 6.7 | | | | 13.8 | |
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| Total gas sales | | | 3.6 | | | | 14.5 | | | | 44.1 | |
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TRANSACTIONS WITH AFFILIATES
We engage in transactions with Williams and other Williams subsidiaries. See “Item 8. Financial Statements(See Note 1 and Supplementary Data —Note 9 of Notes to Consolidated Financial Statements — 1. Summary of Significant Accounting Policies, 2. Rate and Regulatory Matters, 3. Contingent Liabilities and Commitments and 8. Transactions with Major Customers and Affiliates.”Statements.)
REGULATION
Interstate gas pipeline operationsOur interstate transmission and storage activities are subject to regulation by the FERC under the Natural Gas Act of 1938 (NGA) and under the Natural Gas Policy Act of 1978 (NGPA), and, as such, our rates and charges for the transportation of natural gas in interstate commerce, the extension, enlargement or abandonment of jurisdictional facilities, and accounting, among other things, are subject to regulation. We hold certificates of public convenience and necessity issued by the FERC authorizing ownership and operation of pipelines, facilities and properties under the NGA. We are also subject to the Natural Gas Pipeline Safety Act of 1968, as amended by Title I of the Pipeline Safety Act of 1979, andthe Pipeline Safety Improvement Act of 2002 which regulate safety requirements in the design, construction, operation and maintenance of interstate gas transmission facilities. The FERC’s Standards of Conduct govern the relationship
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between natural gas transmission providers and their “marketing affiliates”marketing function employees as defined by the rule. The standards of conduct are intended to prevent natural gas transmission providers from preferentially benefiting theirgas marketing affiliatesfunctions by requiring the employees of a transmission provider that perform transmission functions to function independently from employees ofgas marketing affiliatesemployees and by restricting the information that transmission providers may provide to gas marketing affiliates.
Intrastate gas pipeline operationsCardinal Pipeline Company, LLC, a North Carolina natural gas pipeline company, is subject to the jurisdiction of the North Carolina Utilities Commission. Through wholly-owned subsidiaries, we operate and own a 45 percent interest in Cardinal Pipeline.employees.
EnvironmentalWe are subject to the National Environmental Policy Act and federal, state and local laws and regulations relating to environmental quality control. Management believes that, capital expenditures and operation and maintenance expenses required to meet applicable environmental standards and regulations are generally recoverable in rates. For these reasons, management believes that compliance with applicable environmental requirements is not likely to have a material effect upon our competitive position or earnings. See “Item 8. Financial Statements and Supplementary Data —(See Note 3 of Notes to Consolidated Financial Statements — 3. Contingent Liabilities and Commitments — Environmental Matters.”Statements.)
COMPETITION
The natural gas industry has undergone tremendoussignificant change sinceover the issuance of FERC Order 636 in 1992. Order 636 required that the natural gas sales, transportation, and other services that were formerly
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provided in bundled form by pipelines be separated, resulting in non-discriminatory open access transportation services, and encouraged the establishment of market hubs. These and other factors have led to apast two decades. A highly-liquid competitive commodity market in natural gas and to increasingly competitive markets infor natural gas services, including competitive secondary markets in pipeline capacity.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. These factors have increased the risk for pipelines that customers will turn back or substantially reduce their contractual commitments. Future utilization of pipeline capacity will depend on competition from other pipeline and LNG facilities, use of alternative fuels, the general level of natural gas demand, and weather conditions.
At the state level, both localLocal distribution company (LDC) and electric industry restructuring by states have affected pipeline markets. Several states have implemented changes similar to the federal changes under Order 636. New York, New Jersey, Pennsylvania, Maryland, Delaware, Georgia, Virginia and the District of Columbia have established regulations for LDC unbundling. Although pipeline operators are increasingly challenged to accommodate the flexibility demanded by customers and allowed under tariffs, the changes implemented at the state level have not thus far, required renegotiation of` LDC contracts. The state plans have in some cases discouraged LDCs from signing long-term contracts for new capacity.
States are in the process of developing new energy plans that will encourage utilities to develop energy saving measures and diversify their energy supplies to include renewable sources. This could lower the growth of gas demand. Resistance to coal-fired electricity generation could increase it. These factors have increased the risk that customers will reduce their contractual commitments for pipeline capacity. Future utilization of pipeline capacity will depend on competition from LNG imported into markets, as well as the growth of natural gas demand.
EMPLOYEES
As of February 1, 2009, we had 1,300 full time employees.
FORWARD LOOKING STATEMENTS/RISK FACTORS AND CAUTIONARY
STATEMENT FOR PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF
THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
Certain matters contained in this report include “forward-looking statements” within the meaning of section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. These statements discuss our expected future results based on current and pending business operations. We make thosethese forward-looking statements in reliance on the safe harbor protections provided under the Private
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Securities Litigation Reform Act of 1995.
All statements, other than statements of historical facts, included in this report whichthat 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,” “could,” “may,” “should,” “continues,” “estimates,” “expects,” “forecasts,” “might,” “planned,” “potential,” “projects,” “scheduled” or similar expressions. These forward-looking statements include, among others, statements regarding:
| | • | | amounts and nature of future capital expenditures; |
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| | • | | expansion and growth of our business and operations; |
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| | • | | financial condition and liquidity; |
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| • | | business strategy; |
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| | • | | cash flow from operations or results of operations; |
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| | • | | rate case filing;filings; and |
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| | • | | powernatural gas and natural gas liquids prices and demand. |
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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 document.report. Many of the factors that will determine these results are beyond our ability to control or project. Specific factors which could cause actual results to differ from those in the forward-looking statements include:
| | • | | availability of supplies (including the uncertainties inherent in assessing and estimating future natural gas reserves), market demand, volatility of prices, and increasedthe availability and costs of capital; |
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| | • | | inflation, interest rates and general economic conditions;conditions (including the recent economic slowdown and the disruption of global credit markets and the impact of these events on our customers and suppliers; |
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| | • | | the strength and financial resources of our competitors; |
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| | • | | development of alternative energy sources; |
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| | • | | the impact of operational and development hazards; |
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| | • | | costs of, changes in, or the results of laws, government regulations (including proposed climate change legislation), environmental liabilities, litigation, and rate proceedings; |
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| | • | | our costs and funding obligations for defined benefit pension plans and other postretirement benefit plans; |
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| • | | increasing maintenance and construction costs; |
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| | • | | changes in the current geopolitical situation; |
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| • | | our exposure to the credit risk of our customers; |
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| | • | | risks related to strategy and financing, including restrictions stemming from our debt agreements, future changes in our credit rating and our lackthe availability and cost of investment grade credit ratings;credit; |
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| • | | risks associated with future weather conditions; |
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| • | | acts of terrorism; and |
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| | • | | risk associatedadditional risks described in our filings with future weather conditions and acts of terrorism.the 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 includeare described in the following:following section:
RISK FACTORS
You should carefully consider the following risk factors in addition to the other information in this
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report. Each of these factors could adversely affect our business, operating results, and financial condition as well as adversely affect the value of an investment in our securities.
Risks Inherent to our Industry and Business
DecreasesOur natural gas transportation, storage and gathering activities involve numerous risks that might result in accidents and other operating risks and hazards.
Our operations are subject to all the risks and hazards typically associated with the transportation and storage of natural gas. These operating risks include, but are not limited to:
| • | | fires, blowouts, cratering and explosions; |
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| • | | uncontrollable releases of natural gas; |
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| • | | pollution and other environmental risks; |
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| • | | natural disasters; |
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| • | | aging pipeline infrastructure and mechanical problems; |
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| • | | damage inadvertently caused by third party activity, such as operation of construction equipment; and |
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| • | | terrorist attacks or threatened attacks on our facilities or those of other energy companies. |
These risks could result in loss of human life, personal injuries, significant damage to property, environmental pollution, impairment of our operations and substantial losses to us. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses, and only at levels we believe to be appropriate. The location of certain segments of our pipeline in or near populated areas, including residential areas, commercial business centers and industrial sites, could increase the level of damages resulting from these risks. In spite of our precautions, 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 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, Williams and its other affiliates, including Williams Partners, are not limited in their ability to compete with us. Further, natural gas also competes with other forms of energy available to our customers, including electricity, coal, fuel oils and other alternative energy sources.
The principal elements of competition among natural gas transportation and storage assets are rates, terms of service, access to natural gas supplies, flexibility and reliability. FERC’s policies promoting competition in natural gas markets could have the effect of increasing the natural gas transportation and storage options for our traditional customer base. As a result, we could experience some “turnback” of firm capacity as the primary terms of existing agreements expire. If we are unable to remarket this capacity or can remarket it only at substantially discounted rates compared to previous contracts, we or our remaining customers may have to bear the costs associated with the turned back capacity. Increased competition could reduce the amount of transportation or storage capacity contracted on our system or, in cases where we do not have long-term fixed rate contracts, could force us to lower our transportation or storage rates. Competition could intensify the negative impact of factors that significantly decrease demand for natural gas or increase the price of natural gas in the markets served by our pipeline system, such as competing or alternative forms of energy, a regional or national recession or other adverse economic conditions, weather, higher fuel costs and taxes or other governmental or regulatory actions that directly or indirectly increase the price of natural gas or limit the use of, or increase the demand for, natural gas. Our ability to renew or replace existing contracts at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of our competitors. Please read “Competition”. All of these competitive pressures could have a material adverse effect on our business, financial condition, results of operations and cash flows.
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We may not be able to maintain or replace expiring natural gas transportation and storage contracts at favorable rates or on a long-term basis.
Our primary exposure to market risk occurs at the time the terms of existing transportation and storage contracts expire and are subject to termination. Although none of our material contracts are terminable in 2009, upon expiration of the terms we may not be able to extend contracts with existing customers to 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; |
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| • | | the growth in demand for natural gas in our markets; |
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| • | | whether the market will continue to support long-term firm contracts; |
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| • | | whether our business strategy continues to be successful; |
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| • | | the level of competition for natural gas supplies in the production basins serving us; and |
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| • | | the effects of state regulation on customer contracting practices. |
Any failure to extend or replace a significant portion of our existing contracts may have a material adverse effect on our business, financial condition, results of operations and cash flows.
Competitive pressures could lead to decreases in the volume of natural gas contracted or transported through our pipeline system for any of the reasons described below will adversely affect our business.
Expiration of firm transportation agreements.A substantial portion of our operating revenues is generated through firm transportation agreements that expire periodically and must be renegotiated and extended or replaced. We cannot give any assurance as to whether any of these agreements will be extended or replaced or that the terms of any renegotiated agreements will be as favorable as the existing agreements. Upon the expiration of these agreements, should customers turn back or substantially reduce their commitments, we could experience a negative effect to our results of operations.
Decreases in natural gas production.The development of the additional natural gas reserves that are essential for our gas transmission business to thrive 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, or the lack of available capital for these projects could adversely affect the development and production of additional reserves, as well as gathering, storage, pipeline transmission and import and export of natural gas supplies, adversely impacting our ability to fill the capacities of our gathering, transmission and processing facilities. Additionally, in some cases, new liquefied natural gas (LNG) import facilities built near our markets could result in less demand for our gathering and transmission facilities.
Decreases in demand for natural gas.Demand 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.
Competitive pressures.Although most of our pipeline system’s current capacity is fully contracted, the FERC has taken certain actions to strengthen market forces in the natural gas pipeline industry that have led to increased competition throughout the industry. In a number of key markets, interstate pipelines are now facing competitive pressure from other major pipeline systems, enabling local distribution companies and end users to choose a transmission provider based on considerations other than location. Other entities could construct new pipelines or expand existing pipelines that could potentially serve the same markets as our pipeline system. Any such new pipelines could offer transportation services that are more desirable to shippers because of locations, facilities, or other factors. These new pipelines could charge rates or provide service to locations that would result in greater net profit for shippers and producers and thereby force us to lower the rates charged for service on our pipeline in order to extend our existing transportation service agreements or to attract new customerscustomers. 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.
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Our gatheringAny significant decrease in supplies of natural gas in our areas of operation could adversely affect our business and transporting activities involve numerous risks that might result in accidents and other operating risks and hazards.results.
Our operations are subjectbusiness 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 allbe produced and delivered to our pipeline system. Low prices for natural gas, regulatory limitations, or the riskslack of available capital for these projects could adversely affect the development and hazards typicallyproduction of additional reserves, as well as gathering, storage, pipeline transmission and import and export of natural gas supplies, adversely impacting our ability to fill the capacities of our gathering, transmission and processing facilities.
Production from existing wells and natural gas supply basins with access to our pipeline will naturally decline over time. The amount of natural gas reserves underlying these wells may also be less than anticipated, and the rate at which production from these reserves declines may be greater than anticipated. Additionally, the competition for natural gas supplies to serve other markets could reduce the amount of natural gas supply for our customers. Accordingly, to maintain or increase the contracted capacity or the volume of natural gas transported, or throughput, on our pipeline and cash flows associated with the transportation of natural gas, our customers must compete with others to obtain adequate supplies of natural gas. These operating risks include, but
If new supplies of natural gas are not limited to:
| • | | blowouts, cratering and explosions; |
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| • | | uncontrollable flows of natural gas; |
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| • | | fires; |
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| • | | pollution and other environmental risks; |
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| • | | natural disasters; |
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| • | | aging pipeline infrastructure; and |
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| • | | terrorists attacks or threatened attacks on our facilities or those of other energy companies. |
In addition, thereobtained to replace the natural decline in volumes from existing supply area, or if natural gas supplies are inherent indiverted to serve other markets, the overall volume of natural gas transported and stored on our gas gathering and transporting properties a variety of hazards and operating risks, such as leaks, explosions and mechanical problems that could cause substantial financial losses. 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, an event could cause considerable harm to people or property, andsystem would decline, which could have a material adverse effect on our business, financial condition and results of operations.
Decreases in demand for natural gas could adversely affect our business.
Demand for our transportation services depends on the ability and willingness of shippers with access to our facilities to satisfy their demand by deliveries through our system. Any decrease in this demand could adversely affect our business. Demand for natural gas is also affected by weather, future industrial and economic conditions, fuel conservation measures, alternative fuel requirements, governmental regulation, or technological advances in fuel economy and energy generation devices, all of which are matters beyond our control. Additionally, in some cases, new LNG import facilities built near our markets could result in less demand for our gathering and transmission facilities.
Significant prolonged changes in natural gas prices could affect supply and demand and cause a termination of the our transportation and storage contracts or a reduction in throughput on our system.
Higher natural gas prices over the long term could result in a decline in the demand for natural gas and, therefore, in our long-term transportation and storage contracts or throughput on our system. Also, lower natural gas prices over the long term could result in a decline in the production of natural gas resulting in reduced contracts or throughput on our system. As a result, significant prolonged changes in natural gas prices could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Our current pipeline infrastructure is aging, which may adversely affect our business.
Some portions of our pipeline infrastructure are approximately 50 years old. The current age and condition of this pipeline infrastructure could result in a material adverse impact on our business, financial condition and results of operations particularly if the event is not fully covered by insurance. Accidents or other operating riskscosts of maintaining our facilities exceed current expectations.
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Our operations are subject to governmental laws and regulations relating to the protection of the environment, which could further result in loss of service availableexpose us to our customers. Such circumstances could adversely impact our ability to meet contractual obligationssignificant costs and retain customers, with a resulting impact on our results of operations.
Costs of environmental liabilities and complying with existing and future environmental regulations could exceed our current expectations.
Our natural gas transportation and storage operations are subject to extensive environmental regulation pursuant to a variety of federal, state and municipal laws and regulations. Suchlocal environmental laws and regulations governing environmental protection, the discharge of materials into the environment and the security of chemical and industrial facilities. These laws include:
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| § | | the Federal Clean Air Act and analogous state laws, which impose obligations related to air emissions; |
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| § | | the Federal Water Pollution Control Act of 1972, as renamed and amended as the Clean Water Act (CWA) and analogous state laws, which regulate discharge of wastewaters from our facilities to state and federal waters; |
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| § | | the Federal Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), and analogous state laws that regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or locations to which we have sent wastes for disposal; and |
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| § | | the Federal Resource Conservation and Recovery Act (RCRA), and analogous state laws that impose requirements for the handling and discharge of solid and hazardous waste from our facilities. |
These laws and regulations may impose among other things, restrictions, liabilitiesnumerous obligations that are applicable to our operations including the acquisition of permits to conduct regulated activities, the incurrence of capital expenditures to limit or prevent releases of materials from our pipeline and obligations in connection withfacilities, and the generation, handling, use, storage, transportation, treatmentimposition of substantial costs and disposal of hazardous substances and wastes, in connection withpenalties for spills, releases and emissions of various regulated substances into the environment resulting from those operations. Various governmental authorities, including the U.S. Environmental Protection Agency and analogous state agencies, and the United States Department of Homeland Security have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly actions. Failure to comply with these laws, regulations, and permits may result in the assessment of administrative, civil, and criminal penalties, the imposition of remedial obligations, and the issuance of injunctions limiting or preventing some or all of our operations.
There is inherent risk of incurring significant environmental costs and liabilities in the operation of natural gas transportation and storage facilities due to the handling of petroleum hydrocarbons and wastes, the occurrence of air emissions and water discharges related to the operations, and historical industry operations and waste disposal practices. Joint and several, strict liability may be incurred without regard to fault under certain environmental laws and regulations, including CERCLA, RCRA and analogous state laws, in connection with spills or releases of natural gas and wastes on, under, or from our properties and facilities. Private parties, including the operation, maintenance, abandonmentowners of properties through which our pipeline passes and facilities where our wastes are taken for reclamation of our facilities.
Compliance with environmental laws requires significant expenditures including thoseor disposal, may have the right to pursue legal actions to enforce compliance as well as to seek damages for clean up costs and damages arising out of contaminated properties. In addition, the possible failure to complynon-compliance with environmental laws and regulations mightor for personal injury or property damage.. In addition, changes in environmental laws and regulations occur frequently, and any such changes that result in the imposition of finesmore stringent and penalties. We are generally
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responsible for all liabilities associated with the environmental condition of our facilitiescostly regulated substance and assets, whether acquiredwaste handling, storage, transport, disposal, or developed, regardless of when the liabilities arose and whether they are known or unknown. In connection with certain acquisitions and divestitures, weremedial requirements 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. Although we do not expect that the costs of complying with current environmental laws will have a material adverse effect on our business, financial condition, or results of operations no assurance canand cash flows.
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 given that theadversely affected by increased costs of complyingdue to stricter pollution control requirements or liabilities resulting from non-compliance with environmental laws in the future will not have such an effect.required operating or other regulatory permits.
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We make assumptions and develop expectations about possible expenditures related to environmental conditions based on current laws and regulations and current interpretations of those laws and regulations. If the interpretation of laws or regulations, or the laws and regulations themselves, change, our assumptions may change. Our regulatory rate structure and our contracts with customers might not necessarily allow us to recover capital costs we incur to comply with the new environmental regulations. Also, we might not be able to obtain or maintain from time to time all required environmental regulatory approvals for certain development projects. If there is a delay in obtaining any required environmental regulatory approvals or if we fail to obtain and comply with them, the operation of our facilities could be prevented or become subject to additional costs, resulting in potentially material adverse consequences to our business, financial condition, results of operations and cash flows.
We may be subject to legislative and regulatory responses to climate change with which compliance may be costly.
Legislative and regulatory responses related to climate change create financial risk. The United States Congress and certain states have for some time been considering various forms of legislation related to greenhouse gas emissions. Increased public awareness and concern may result in more state, regional and/or federal requirements to reduce or mitigate the emission of greenhouse gases. Numerous states have announced or adopted programs to stabilize and reduce greenhouse gases and similar federal legislation has been introduced in both houses of Congress. Our pipeline may be subject to regulation under climate change policies introduced at either the state or federal level within the next few years. There is a possibility that, when and if enacted, the final form of such legislation could increase our costs of compliance with environmental laws. If we are unable to recover all costs related to complying with climate change regulatory requirements imposed on us, it could have a material adverse effect on our results of operations. To the extent financial markets view climate change
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and emissions of greenhouse gases as a financial risk, this could negatively impact our cost of and access to capital.
The failure of new sources of natural gas production or LNG import terminals to be successfully developed in North America could increase natural gas prices and reduce the demand for our services.
New sources of natural gas production in the United States and Canada, particularly in areas of shale development are expected to become an increasingly significant component of future U.S. natural gas supply in North America. Additionally, increases in LNG supplies are expected to be imported through new LNG import terminals, particularly in the Gulf Coast region. If these additional sources of supply are not developed, natural gas prices could increase and cause consumers of natural gas to turn to alternative energy sources, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Certain of our services are subject to long-term, fixed-price contracts that are not subject to adjustment, even if our cost to perform such services exceeds the revenues received from such contracts.
We provide some services pursuant to long-term, fixed price contracts. It is possible that costs to perform services under such contracts will exceed the revenues we collect for our services. Although most of the services are priced at cost-based rates that are subject to adjustment in rate cases, under FERC policy, a regulated service provider and a customer may mutually agree to sign a contract for service at a “negotiated rate” that may be above or below the FERC regulated cost-based rate for that service. These “negotiated rate” contracts are not generally subject to adjustment for increased costs that could be produced by inflation or other factors relating to the specific facilities being used to perform the services.
We depend on certain key customers for a significant portion of our revenues. The loss of any of these key customers or the loss of any contracted volumes could result in a decline in our business.
We rely on a limited number of customers for a significant portion of our revenues. Our largest customers, Public Service Enterprise Group and National Grid accounted for approximately 11.0 percent and 10.0 percent, respectively, of our operating revenues for the year ended December 31, 2008. The loss of even a portion of our key 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, financial condition, results of operations and cash flows.
We are exposed to the credit risk of our customers.
We are exposed to the credit risk of 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, we cannot predict to what extent our business would be impacted by deteriorating conditions in the economy, including declines in our customers’ creditworthiness. While we monitor these situations carefully and attempt to take appropriate measures to protect ourselves, it is possible that we may have 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 operating results and financial condition.
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If third-party pipelines and other facilities interconnected to our pipeline and facilities become unavailable to transport natural gas, our revenues could be adversely affected.
We depend upon third-party pipelines and other facilities that provide delivery options to and from our pipeline and storage facilities. Because we do not own these third-party pipelines or facilities, their continuing operation is not within our control. If these pipelines or other facilities were to become unavailable due to repairs, damage to the facility, lack of capacity, increased credit requirements or rates charged by such pipelines or facilities or for any other reason, our ability to operate efficiently and continue shipping natural gas to end-use markets could be restricted, thereby reducing our revenues. Further, although there are laws and regulations designed to encourage competition in wholesale market transactions, some companies may fail to provide fair and equal access to their transportation systems or may not provide sufficient transportation capacity for other market participants. Any temporary or permanent interruption at any key pipeline interconnect causing a material reduction in volumes transported on our pipeline or stored at our facilities could have a material adverse effect on our business, financial condition, results of operations and cash flows.
We do not own all of the land on which our pipeline and facilities are located, which could disrupt our operations.
We do not own all of the land on which our pipeline and facilities have been constructed. As such, we are subject to the possibility of increased costs to retain necessary land use. We obtain, in certain instances, the rights to construct and operate our pipeline on land owned by third parties and governmental agencies for a specific period of time. Our loss of any of these rights, through our inability to renew right of way contracts or otherwise could have a material adverse effect on our business, financial condition, results of operations and cash flows.
We do not insure against all potential losses and could be seriously harmed by unexpected liabilities or by the inability of the insurers we do use to satisfy our claims.
We are not fully insured against all risks inherent to our business, including environmental accidents that might occur. In addition, we do not maintain business interruption insurance in the type and amount to cover all possible risks of loss. Williams currently maintains excess liability insurance with limits of $610 million per occurrence and in the aggregate annually and a deductible of $2 million per occurrence. This insurance covers Williams and its affiliates, including our legal and contractual liabilities arising out of bodily injury, personal injury or property damage, including resulting loss of use, to third parties. This excess liability insurance includes coverage for sudden and accidental pollution liability for full limits, with the first $135 million of insurance also providing gradual pollution liability coverage for natural gas and natural gas liquids operations. Pollution liability coverage excludes: release of pollutants subsequent to their disposal; release of substances arising from the combustion of fuels that result in acidic deposition, and testing, monitoring, clean-up, containment, treatment or removal of pollutants from property owned, occupied by, rented to, used by or in the care, custody or control of Williams and its affiliates.
Williams does not insure onshore underground pipelines for physical damage, except at river crossings and at certain locations such as compressor stations. Williams maintains coverage of $300 million per occurrence for physical damage to assets and resulting business interruption caused by terrorist acts committed by a U.S. person or interest. Also, all of Williams’ insurance is subject to deductibles. If a significant accident or event occurs for which we are not fully insured, it could adversely affect our operations and financial condition. We may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. Changes in the insurance markets subsequent to the September 11, 2001 terrorist attacks and hurricanes Katrina, Rita, Gustav and Ike have impacted the availability of certain types of coverage at reasonable rates, and we may elect to self
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insure a portion of our asset portfolio. We cannot assure you that we will in the future be able to obtain the levels or types of insurance we would otherwise have obtained prior to these market changes or that the insurance coverage we do obtain will not contain large deductibles or fail to cover certain hazards or cover all potential losses. The occurrence of any operating risks not fully covered by insurance could have a material adverse effect on our business, financial condition, results of operations and cash flows.
In addition, certain insurance companies that provide coverage to us, including American International Group, Inc., have experienced negative developments that could impair their ability to pay any of our potential claims. As a result, we could be exposed to greater losses than anticipated and may have to obtain replacement insurance, if available, at a greater cost.
Execution of our capital projects subjects us to construction risks, increases in labor costs and materials, and other risks that may adversely affect financial results.
A significant portion of our growth is accomplished through the construction of new transportation and storage facilities as well as the expansion of existing facilities. Construction of these facilities is subject to various regulatory, development and operational risks, including:
| • | | the ability to obtain necessary approvals and permits by regulatory agencies on a timely basis and on acceptable terms; |
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| • | | the availability of skilled labor, equipment, and materials to complete expansion projects; |
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| • | | potential changes in federal, state and local statutes and regulations, including environmental requirements, that prevent a project from proceeding or increase the anticipated cost of the project; |
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| • | | impediments on our ability to acquire rights-of-way or land rights on a timely basis and on acceptable terms; |
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| • | | the ability to construct projects within estimated costs, including the risk of cost overruns resulting from inflation or increased costs of equipment, materials, labor or other factors beyond our control, that may be material; and |
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| • | | the ability to access capital markets to fund construction projects. |
Any of these risks could prevent a project from proceeding, delay its completion or increase its anticipated costs. As a result, new facilities may not achieve expected investment return, which could adversely affect results of operations, financial position or cash flows.
Potential changes in accounting standards might cause us to revise our financial results and disclosures in the future, which might change the way analysts measure our business or financial performance.
Regulators and legislators continue to take a renewed look at accounting practices, financial disclosures, companies’ relationships with their independent registered public accounting firms, and retirement plan practices. We cannot predict the ultimate impact of any future changes in accounting regulations or practices in general with respect to public companies or the energy industry or in our operations specifically. In addition, the Financial Accounting Standards Board (FASB), the SEC or the FERC could enact new accounting standards or FERC orders, as the case may be, that might impact how we are required to record revenues, expenses, assets, liabilities and equity.
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Risks Related to Strategy and Financing
Our debt agreements impose restrictions on us that may adversely affect our ability to operate our business.
Certain of our debt agreements contain covenants that restrict or limit, among other things, our ability to create liens supporting indebtedness, sell assets, make certain distributions and incur additional debt. In addition, our debt agreements contain, and those we enter into in the future may contain, financial covenants and other limitations with which we will need to comply. Our ability to comply with these covenants may be affected by many events beyond our control, and we cannot assure you that our future operating results will be sufficient to comply with the covenants or, in the event of a default under any of our debt agreements, to remedy that default.
Our failure to comply with the covenants in our debt agreements and other related transactional documents could result in events of default. Upon the occurrence of such an event of default, the lenders could elect to declare all amounts outstanding under a particular facility to be immediately due and payable and terminate all commitments, if any, to extend further credit. An event of default or an acceleration under one debt agreement could cause a cross-default or cross-acceleration of another debt agreement. Such a cross-default or cross-acceleration could have a wider impact on our liquidity than might otherwise arise from a default or acceleration of a single debt instrument. If an event of default occurs, or if other debt agreements cross-default, and the lenders under the affected debt agreements accelerate the maturity of any loans or other debt outstanding to us, we may not have sufficient liquidity to repay amounts outstanding under such debt agreements.
Our ability 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. 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 meet our debt service obligations or obtain future credit on favorable terms, if 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 lackEvents in the global credit markets created a shortage in the availability of investment gradecredit and have led to credit market volatility.
In 2008, global credit markets experienced a shortage in overall liquidity and a resulting disruption in the availability of credit. While we cannot predict the occurrence of future disruptions or the duration of current volatility in the credit markets, we believe cash on hand and cash provided by operating activities, as well as availability under our existing financing agreements will provide us with adequate liquidity for the foreseeable future. However, our ability to borrow under our existing financing agreements, including our bank credit facilities, could be negatively impacted if one or more of our lenders fail to honor its contractual obligation to lend to us. Continuing volatility or additional disruptions, including the bankruptcy or restructuring of certain financial institutions, may adversely affect the availability of credit already arranged and the availability and cost of credit in the future.
The continuation of recent economic conditions, including disruptions in the global credit markets, could adversely affect our results of operations.
The slowdown in the economy and the significant disruptions and volatility in global credit markets have the potential to negatively impact our business in many ways. Included among these potential negative impacts are reduced demand and lower prices for our products and services, increased difficulty in collecting amounts
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owed to us by our customers and a reduction in our credit ratings increases(either due to tighter rating standards or the negative impacts described above), which could result in reducing our access to credit markets, raising the cost of such access or requiring us or Williams to provide additional collateral to third parties.
A downgrade of our credit ratings could impact our liquidity, access to capital, and our costs of doing business in manycertain ways and increases our risks from market disruptions and furthermaintaining current credit downgrades.ratings is within the control of independent third parties.
Because we do not have an investment gradeA downgrade of our credit rating from allratings might increase our cost of the major credit rating agencies,
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our transactions require greater credit assurances, both to be given fromborrowing and received bycould cause us to satisfy credit support requirements. In addition, we are more vulnerablepost collateral with third parties, thereby negatively impacting our available liquidity. Our ability to the impact of market disruptions oraccess capital markets could also be limited by a further downgrade of our credit rating that might further increase our cost of borrowing or further impair our ability to access capital markets.and other disruptions. Such disruptions could include:
| | • | | economic downturns; |
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| | • | | deteriorating capital market conditions generally; |
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| | • | | declining market prices for electricitynatural gas, natural gas liquids and natural gas;other commodities; |
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| • | | terrorist attacks or threatened attacks on our facilities or those of other energy companies; and |
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| | • | | the overall health of the energy industry, including the bankruptcy or insolvency of other energy companies. |
Credit rating agencies perform independent analysis when assigning credit ratings. Given the significant changes in capital marketsThe analysis includes a number of criteria including, but not limited to, business composition, market and the energy industry over the last few years, creditoperational risks, as well as various financial tests. Credit rating agencies continue to review the criteria for attaining investment gradeindustry sectors and various debt ratings and may make changes to those criteria from time to time. Our goal is to attainWe are currently rated investment grade ratios from allby three of the major credit rating agencies. However, there is no guaranteeassurance can be given that the credit rating agencies will continue to assign us investment grade ratings even if we meet or exceed their criteria for investment grade ratios.
Williams can exercise substantial control over our dividenddistribution policy and our business and operations and may do so in a manner that is adverse to our interests.
We are an indirect wholly-owned subsidiary of Williams. Our board of directors,management committee, which is electedappointed by WGP, which in turn is controlled by Williams, exercises substantial control over our business and operations and makes determinations with respect to, among other things, the following:
| | • | | payment of dividendsdistributions and repayment of advances; |
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| | • | | decisions on financings and our capital raising activities; |
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| | • | | mergers or other business combinations; and |
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| | • | | acquisition or disposition of assets. |
Our board of directorsmanagement committee could decide to increase dividendsdistributions or advances to our parent entities consistent with existing debt covenants. This could adversely affect our liquidity. Moreover, various WilliamsWilliams’ credit facilities include covenants restricting the ability of WilliamsWilliams’ entities, including us, to make advances to Williams and its other subsidiaries, which could make the terms on which we may be able to secure additional future financing less favorable.
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The financial condition and liquidity of Williams affects our access to capital, our credit standing and our financial condition.
Substantially all of Williams’ operations are conducted through its subsidiaries. Williams’ cash flows are substantially derived from loans and dividends paid to it by its subsidiaries, including WGP, our parent
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company under which Williams’ interstate natural gas pipelines and gas pipeline joint venture investments are grouped. Williams’ cash flows are typically utilized to service debt and pay dividends on the common stock of Williams, with the balance, if any, reinvested in its subsidiaries as contributions to capital.
Our ratings and credit are impacted by Williams’ credit standing. If Williams were to experience deterioration in its credit standing or liquidity difficulties, our access to credit and our ratings could be adversely affected.
We are exposed to the credit risk of our customers in the ordinary course of our business
We are exposed to the credit risk of our customers in the ordinary course of our business. Generally our customers are rated investment grade or are required to make pre-payments or provide security to satisfy credit concerns. However, we cannot predict to what extent our business would be impacted by deteriorating conditions in the energy sector, including declines in our customers’ creditworthiness.
Risks Related to Regulations that Affect our Industry
Our gas sales, natural gas transmission, and storage operations are subject to government regulations and rate proceedings thatregulation 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 profitabilityfull cost of these operations.operating our pipeline, including a reasonable rate of return.
Our interstate gas sales, transmission,transportation, and storage operations are subject to the FERC’s rulesfederal, state and regulations in accordance withlocal regulatory authorities. Specifically, our interstate pipeline transportation and storage services and related assets are subject to regulation by the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978.FERC. The FERC’s regulatory authorityfederal regulation extends to:to such matters as:
| | • | | transportation and sale for resale of natural gas in interstate commerce; |
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| | • | | rates, operating terms and charges;conditions of service, including initiation and discontinuation of service; |
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| | • | | construction;the types of services we may offer to our customers; |
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| • | | certification and construction of new facilities; |
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| | • | | acquisition, extension, disposition or abandonment of services or facilities; |
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| | • | | accounts and records; |
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| | • | | depreciation and amortization policies; |
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| • | | relationships with marketing functions within Williams involved in certain aspects of the natural gas business; and |
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| | • | | operatingmarket manipulation in connection with interstate sales, purchases or transportation of natural gas. |
Under the Natural Gas Act, FERC has authority to regulate providers of natural gas pipeline transportation and storage services, and such providers may only charge rates that have been determined to be just and
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reasonable by FERC. In addition, FERC prohibits providers from unduly preferring or unreasonably discriminating against any person with respect to pipeline rates or terms and conditions of service.
Regulatory actions in these areas can affect our business in many ways, including decreasing tariff rates and revenues, decreasing volumes in our pipelines, increasing our costs and otherwise altering the profitability of our business.
The FERC’s Standards of Conduct govern the relationship between natural gas transmission providers and their “marketing affiliates”marketing function employees as defined by the rule. The standards of conduct are intended to prevent natural gas transmission providers from preferentially benefiting theirgas marketing affiliatesfunctions by requiring the employees of a transmission provider that perform transmission functions to function independently from employees of marketing affiliatesfunction employees and by restricting the information that transmission providers may provide to gas marketing affiliates.employees. The
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inefficiencies created by the restrictions on the sharing of employees and information may increase our costs, and the restrictions on the sharing of information may have an adverse impact on our senior management’s ability to effectively obtain important information about our business. Violators of the rules are subject to potentially substantial civil penalty assessments.
Unlike other pipelines that own facilities in the offshore Gulf of Mexico, we charge our transportation customers a separate fee to access our offshore facilities. The separate charge that we assess, which we refer to as an “IT feeder” charge, is charged only when the facilities are used, and typically is paid by producers or marketers. This means that we recover the costs included in the “IT feeder” charge only if our facilities are used, and because it is typically paid by producers and marketers it generally results in netback prices to producers that are slightly lower than the netbacks realized by producers transporting on other interstate pipelines. Longer term, this rate design disparity could result in producers bypassing our offshore facilities in favor of alternative transportation facilities. We have asked the FERC to allow us to eliminate the IT feeder charge and charge for transportation on our offshore facilities in the same manner as the other pipelines. Our requests have been denied.
We could be subject to penalties and fines if we fail to comply with FERC regulations.
Our transportation and storage operations are regulated by FERC. Should we fail to comply with all applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines. Under the Energy Policy Act of 2005, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1,000,000 per day for each violation. Any material penalties or fines imposed by FERC could have a material adverse impact on our business, financial condition, results of operations and cash flows.
The outcome of pendingcertain FERC proceedings regarding income tax allowances in rate calculations is uncertain and could affect our ability to include an income tax allowance in our cost-of-service based rates.
In May 2005, FERC issued a statement of general policy, permitting a pipeline to include in 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. Whether a pipeline’s owners have such actual or potential income tax liability will be reviewed by FERC on a case-by-case basis. The new policy entails rate risk due to the case-by-case review requirement. In June 2005 FERC applied its new policy and granted a partnership owning an oil pipeline an income tax allowance when establishing rates. That decision, applying the new policy to the particular oil pipeline, was appealed to the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit). The D.C. Circuit, by order issued May 29, 2007, denied the appeal and upheld FERC’s new tax allowance policy as applied in the decision involving the oil pipeline on all points subject to the appeal. On August 20, 2007, the D.C. Circuit denied rehearing of its decision.
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On December 8, 2006, FERC issued an order in an interstate oil pipeline proceeding addressing its income tax allowance policy, noting that the tax deferral features of a publicly traded partnership may cause some investors to receive, for some indeterminate duration, cash distributions in excess of their taxable income, which FERC characterized as a “tax savings.” FERC stated that it is concerned that this creates an opportunity for those investors to earn an additional return, funded by ratepayers. Responding to this concern, FERC chose to adjust the pipeline’s equity rate of return downward based on the percentage by which the publicly traded partnership’s cash flow exceeded taxable income. On February 7, 2007, the pipeline asked FERC to reconsider this ruling. On December 26, 2007, FERC issued an order on rehearing affirming its prior ruling. FERC indicated that it will continue to review on a case-by-case basis whether a pipeline’s owners have an actual or potential income tax liability and may utilize a normalization approach to reduce a pipeline’s income tax allowance as appropriate. On January 25, 2008, shippers on the pipeline asked FERC to reconsider its income tax allowance policy, including whether such allowance should be permitted at all. On February 15, 2008, FERC responded that the shipper’s income tax allowance issues were complex and will be addressed at a later time.
The ultimate outcome of these proceedings is not certain and could result in changes to FERC’s treatment of income tax allowances in cost of service. As a consequence of our conversion to a general partnership, if FERC were to disallow a substantial portion of our income tax allowance, it may be more difficult for us to justify our rates in future proceedings. If we are unable to satisfy the requirements necessary to qualify for a full income tax allowance in calculating our cost of service in future rate cases, FERC could disallow a substantial portion of our income tax allowance, and our maximum lawful rates could decrease from current levels.
The outcome of certain FERC proceedings involving FERC policy statements is uncertain and could affect the level of return on equity that Transco may be able to achieve in any future rate proceeding.
In an effort to provide some guidance and to obtain further public comment on FERC’s policies concerning return on equity determinations, on July 19, 2007, FERC issued its Proposed Proxy Policy Statement, “Composition of Proxy Groups for Determining Gas and Oil Pipeline Return on Equity.” In the Proposed Proxy Policy Statement, FERC proposes to permit inclusion of publicly traded partnerships in the proxy group analysis relating to return on equity determinations in rate proceedings, provided that the analysis be limited to actual publicly traded partnership distributions capped at the level of the pipeline’s earnings.
After receiving public comment on the proposed policy statement, on April 17, 2008, FERC issued a final policy statement rejecting the concept of capping distributions in favor of an adjustment to the long-term growth rate used to calculate the equity cost of capital for publicly traded partnerships which are included in the proxy group.
On January 19, 2009, the FERC applied the policy statement to a pipeline rate case and determined that the pipeline’s return on equity should be 11.55 percent. It is difficult to know how instructive this case is for purposes of anticipating rates of return in future rate cases, because the FERC determined the composition of the proxy group using data from 2004 when the case was filed.
The effect of the application of FERC’s policy to our future rate proceedings is not certain and we cannot ensure that such application would not adversely affect our ability to achieve a reasonable level of return on equity.
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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.
On August 31, 2006, we filed a rate case with the FERC to request changes to the rates we charge. The outcome of the rate case is uncertain. There is a risk that rates set by the FERC will lower our return on the capital we have invested in our assets or might notfuture rate cases will be adequateinadequate to recover increases in operating costs.costs or to sustain an adequate return on capital investments. There is also the risk that higher rates will cause us to discount our services or result in our customers seekingto look for alternative ways to transport their natural gas.
Legal and regulatory proceedings and investigations relating to the energy industry and capital markets have adversely affected our business and may continue to do so.
Public and regulatory scrutiny of the energy industry and of the capital markets has resulted in increased regulation being either proposed or implemented. Such scrutiny has also resulted in various inquiries, investigations and court proceedings in which we or our affiliates are named as defendants. Both the shippers on our pipeline and regulators have rights to challenge the rates we charge under certain circumstances. Any successful challenge could materially affect our results of operations.
Certain inquiries, investigations and court proceedings are ongoing. We might see adverse effects continue as a result of the uncertainty of these ongoing inquiries and proceedings, or additional inquiries and proceedings by federal or state regulatory agencies or private plaintiffs. In addition, we cannot predict the outcome of any of these inquiries or whether these inquiries will lead to additional legal proceedings against us, civil or criminal fines or penalties, or other regulatory action, including legislation, which might be materially adverse to the operation of our business and our revenues and net income or increase our operating costs in other ways. Current legal proceedings or other matters against us including environmental matters, disputes over gas measurement and royalty payments, 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.
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Risks Related to Accounting Standards
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.
Accounting irregularities discovered in the past few years across various industries have forced regulators and legislators to take a renewed look at accounting practices, financial disclosures, companies’ relationships with their independent registered public accounting firm and retirement plan practices. We cannot predict the ultimate impact of any future changes in accounting regulations or practices in general with respect to public companies or the energy industry or in our operations specifically.
In addition, the Financial Accounting Standards Board (FASB), the Securities and Exchange Commission (SEC) or the FERC could enact new accounting standards or FERC orders that might impact how we are required to record revenues, expenses, assets, liabilities and equity.
Risks Related to Employees, Outsourcing of Non-Core Support Activities, and Technology
Institutional knowledge residing with current employees nearing retirement eligibility might not be adequately preserved.
In our business, institutional knowledge resides with employees who have many years of service. As these employees reach retirement age, we may not be able to replace them with employees of comparable knowledge and experience. In addition, we may not be able to retain or recruit other qualified individuals and our efforts at knowledge transfer could be inadequate. If knowledge transfer, recruiting and retention efforts are inadequate, access to significant amounts of internal historical knowledge and expertise could become unavailable to us.
Failure of theor disruptions to our outsourcing relationshiprelationships might negatively impact our ability to conduct our business.
Some studies indicate a high failure rate of outsourcing relationships. Although Williams has taken steps to build a cooperative and mutually beneficial relationship with its outsourcing providers and to closely monitor their performance, a deterioration in the timeliness or quality of the services performed by the outsourcing providers or a failure of all or part of these relationships could lead to loss of institutional knowledge and interruption of services necessary for us to be able to conduct our business.
Williams’ ability The expiration of such agreements or the transition of services between providers could lead to receive services from outsourcing provider locations outsidesimilar losses of the United States might be impacted by cultural differences, political instability,institutional knowledge or unanticipated regulatory requirements in jurisdictions outside the United States.disruptions.
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Certain of our accounting, information technology, application development, and help desk services are currently provided by Williams’ outsourcing provider from service centers outside of the United States. The economic and political conditions in certain countries from which Williams’ outsourcing providers may provide services to us present similar risks of business operations located outside of the United States, including risks of interruption of business, war, expropriation, nationalization, renegotiation, trade sanctions or nullification of existing contracts and changes in law or tax policy, that are greater than in the United States.
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Our current information technology infrastructure is agingcosts and may adversely affectfunding obligations for defined benefit pension plans and costs for other postretirement benefit plans, in which we participate, are affected by factors beyond our ability to conduct our business.control.
Limited capital spending for information technology infrastructure during 2001-2003 resultedWe are a participating employer in an aging server environment that may be less efficient and may require more personnel and capital resources to maintain and upgrade than more current systems, and may not be adequate fordefined benefit pension plans covering substantially all of our current business needs. While efforts are ongoing to update the environment, the current age and condition of equipment could result in loss of internal and external communications, loss of data, inability to access data when needed, excessive software downtime (including downtime for critical software applications),employees and other disruptionspostretirement benefit plans covering certain eligible participants. The timing and amount of our funding allocation requirements under the defined benefit pension plans in which we participate depend upon a number of factors Williams controls, including changes to pension plan benefits as well as factors outside of our control, such as asset returns, interest rates and changes in pension laws. Changes to these and other factors that can significantly increase our funding allocation requirements could have a materialsignificant adverse impacteffect on our businessfinancial condition. The amount of expenses recorded for the defined benefit pension plans and other postretirement benefit plans, in which we participate, is also dependent on changes in several factors, including market interest rates and the returns on plan assets. Significant changes in any of these factors may adversely impact our future 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, especially those located offshore, can be adversely affected by hurricanes, earthquakes, tornadoes and other natural phenomena and weather conditions including extreme temperatures, making it more difficult for us to realize the historic rates of return associated with these assets and operations.
Our current pipeline infrastructure is aging Insurance may be inadequate, and in some instances, we may adversely affect our abilitybe unable to conduct our business.
Some portions of our pipeline infrastructure are more than 40 yearsobtain insurance on commercially reasonable terms, if at all. A significant disruption in ageoperations or a significant liability for which may impact our ability to provide reliable service. While efforts are ongoing to maintain equipment and pipeline facilities, the current age and condition of this pipeline infrastructurewe were not fully insured could result inhave a material adverse impacteffect on our business.business, results of operations and financial condition.
In addition, there is a growing belief that emissions of greenhouse gases may be linked to global climate change. Climate change creates physical and financial risk. Our customers’ energy needs vary with weather conditions. To the extent weather conditions are affected by climate change or demand is impacted by regulations associated with climate change, customers’ energy use could increase or decrease depending on the duration and magnitude of the changes leading either to increased investment or decreased revenues.
Acts of terrorism could have a material adverse effect on our financial condition, results of operations and cash flows.
Our assets and the assets of our customers and others may be targets of terrorist activities that could disrupt our business or cause significant harm to our operations, such as full or partial disruption to our ability to transmit natural gas. Acts of terrorism as well as events occurring in response to or in connection with acts of terrorism could cause environmental repercussions that could result in a significant decrease in revenues or significant reconstruction or remediation costs, which could have a material adverse effect on our financial condition, results of operation and cash flows.
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None.
See “Item 1. Business.”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.
The information called for by this item is provided in “Item 8. Financial Statements and Supplementary Data – Notes to Consolidated Financial Statements —– Note 3. Contingent Liabilities and Commitments —- - Legal Proceedings”, which information is incorporated by reference into this item..
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Since we meet the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K, this information is omitted.
PART II
We are an indirect wholly-owned subsidiary of Williams; therefore,Williams. Prior to our conversion to a limited liability company on December 31, 2008, we issued common stock iswhich was not publicly traded. Upon conversion, we distributed our entire membership interest in Marsh Resources, LLC, Cardinal Operating Company, LLC, Pine Needle Operating Company, LLC, TransCardinal Company, LLC and TransCarolina LNG Company, LLC to WGP. Accordingly, we have adjusted financial and operating information retrospectively to remove the effects of our former subsidiaries.
Prior to our conversion to a limited liability company our Board of Directors declared and we paid cash dividends on common stock in the amounts of $50 million on March 31, 2008, $60 million on June 30, 2008, and $55 million on September 30, 2008. After the conversion, we distributed $55 million on December 31, 2008 to WGP.
Our Board of Directors declared and we paid cash dividends on common stock in the amounts of $40 million on March 31, 2006, $40 million on June 30, 2006, $15 million on September 29, 2006 and $10 million on December 29, 2006.
Our Board of Directors declared cash dividends on common stock in the amounts of $20 million on March 31, 2005, $2530, 2007, $20 million on June 30, 2005, $3529, 2007, $40 million on September 30, 200528, 2007 and $45$30 million on December 30, 2005.31, 2007.
Since we meet the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K, this information is omitted.
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ITEM 7. Management’s NarrativeDiscussion and Analysis of theFinancial Condition and Results of Operations.
GENERAL
The following discussion and analysis of results of operations and capital resources and liquidity should be read in conjunction with the consolidated financial statements and notes thereto included within Item 8.
RECENT MARKET EVENTS
During the latter part of 2008, global credit markets experienced significant instability and energy commodity prices experienced significant and rapid declines. Changes in commodity prices and volumes transported have little near-term impact on our revenues because the majority of cost of service is recovered through firm capacity reservation charges in transportation rates. As a result, the recent decline in energy commodity prices has not significantly impacted our results of operations.
The 2008 economic downturn resulted in a significant decrease in the funded status of the Williams’ sponsored tax-qualified pension plans. As a result, we anticipate that future contributions to the pension plans may vary significantly from recent historical contributions if investment returns do not return to expected levels. Future contributions may also be impacted if actual results differ significantly from estimated results for assumptions such as interest rates, retirement rates, mortality and other significant assumptions or by changes to current legislation and regulations.
The overall decline in equity markets in 2008 negatively impacted our employee benefit plan assets and will increase our net periodic benefit expense in future periods. (See Note 6 of Notes to Financial Statements.)
CRITICAL ACCOUNTING POLICIESESTIMATES
Use of estimatesThe preparation of financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.
Regulatory AccountingWe are regulated by the FERC. Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation,” 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 SFAS No. 71 can differ from the accounting requirements for non-regulated businesses. Transactions that are recorded
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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 SFAS No. 71 and, accordingly, the accompanying consolidated financial statements include the effects of the types of transactions described above that result from regulatory accounting requirements. A summary of regulatory assets and liabilities is included in Item 8. Financial Statements and Supplementary Data —Note 10 of Notes to Consolidated Financial Statements - 10. Regulatory Assets and Liabilities.Statements.
Revenue subject to refundFERC regulations promulgate policies and procedures which govern a process to establish the rates that we are permitted to charge customers for natural gas sales and services, including the
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transportation and storage of natural gas. Key determinants in the ratemaking process are (1) costs of providing service, including depreciation expense, (2) allowed rate of return, including the equity component of the capital structure and related taxes, and (3) volume throughput assumptions.
As a result of the ratemaking process, certain revenues collected by us may be subject to possible refunds upon final orders in pending rate proceedings with the FERC. We record estimates of rate refund liabilities considering our and other third party regulatory proceedings, advice of counsel and estimated total exposure, as discounted and risk weighted, as well as collection and other risks. Depending on the results of these proceedings, the actual amounts allowed to be collected from customers could differ from management’s estimate. In addition, as a result of rate orders, tariff provisions or regulations, we are required to refund or credit certain revenues to our customers. At December 31, 2006,2008, we had accrued approximately $2$14 million for potential amounts to be refunded or credited.
Contingent liabilitiesWe record liabilities for estimated loss contingencies when we assess that a loss is probable and the amount of the loss can be reasonably estimated. Revisions to contingent liabilities are reflected in income in the period in which new or different facts or information become known or circumstances change that affect the previous assumptions with respect to the likelihood or amount of loss. Liabilities for contingent losses are based upon our assumptions and estimates, and advice of legal counsel or other third parties regarding the probable outcomes of the matter. As new developments occur or more information becomes available, our assumptions and estimates of these liabilities may change. Changes in our assumptions and estimates or outcomes different from our current assumptions and estimates could materially affect future results of operations for any particular quarterly or annual period.
Impairment of long-lived assetsWe evaluate long-lived assets for impairment when events or changes in circumstances indicate, in management’s judgment, that the carrying value of such assets may not be recoverable. When such a determination has been made, management’s estimate of undiscounted future cash flows attributable to the assets is compared to the carrying value of the assets to determine whether an impairment has occurred. If an impairment of the carrying value has occurred, the amount of the impairment recognized in the consolidated financial statements is determined by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value.
Judgments and assumptions are inherent in 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 consolidated financial statements.
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Asset Retirement ObligationsWe record an asset and a liability equal to the present value of each expected future asset retirement obligation (ARO). The ARO asset is depreciated in a manner consistent with the depreciation of the underlying physical asset. We measure changes in the liability due to passage of time by applying an interest method of allocation. This amount is recognized as an increase in the carrying amount of the liability and offset by a regulatory asset.asset, as such amounts are expected to be recovered in future rates.
Pension and Postretirement ObligationsWe participate in employee benefit plans with Williams and its subsidiaries that include pension and other postretirement benefits. Pension and other postretirement benefitsbenefit plan expense and obligations are calculated by a third-party actuary and are impacted by various estimates and assumptions. These estimates and assumptions include the expected long-term rates of return on plan assets, discount rates, expected rate of compensation increase, health care trend rates, and employee demographics, including retirement age and mortality. These assumptions are reviewed annually and adjustments are made as needed.
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FERC Accounting GuidanceOn June 30, 2005, the FERC issued an order, “Accounting for Pipeline Assessment Costs,” to be applied prospectively effective January 1, 2006. The order requires companies to expense certain assessment costs that we have historically capitalized. During 2006, we expensed approximately $8 million that previously would have been capitalized.
RESULTS OF OPERATIONS
20062008 COMPARED TO 20052007
Operating Income and Net IncomeOur operatingOperating incomefor 20062008 was $250.0$393.6 million compared tooperating incomeof $327.7 million for 2007.Net incomefor 2008 was $1,281.0 million compared tonet incomeof $168.1 million for 2007. The increase in operating income of $342.1$65.9 million for 2005. Net income for 2006(20.1%) was $117.3 million compareddue primarily to net income of $185.3 million for 2005.
The lower operating income of $92.1 million was primarily the result of increasesan increase in cost of natural gas transportation operation and maintenance expenses, administrative and general expenses, depreciation and amortization expenses and taxes other than income taxes,revenues, partially offset by a decreasedecreases in other revenues and operating costs and expenses as discussed below. The decreaseincrease innet incomeof $68.0$1,112.9 million (662.0%) was mostly attributable to the decreaseddecrease in provision for income taxes primarily due to the reversal of Transco’s deferred taxes upon the conversion from a corporation to a limited liability company on December 31, 2008 and the higher operating income, partially offset by lower net expenses as discussed below in Other Income and Other Deductions.income.
Transportation RevenuesOur operating revenues relatedOperating Revenues: Natural gas transportationincreased $48.4 million (5.7%) to transportation services increased $3.9 million to $771.9$897.6 million for 20062008 when compared to 2005.2007. The higher transportation revenues were primarily due to an increasethe effects of $9.3placing into effect the rates in Docket No. RP06-569 on March 1, 2007, additional revenues in 2008 of $39.9 million forfrom the portion of a changePotomac and Leidy to Long Island expansion projects placed in service in the effective state income tax ratefourth quarter of 2007 and $6.4 million related to higher electric power costs recognized in 2008, which is recoverableare recovered from customers. The recoverable portion is more thancustomers through transportation rates resulting in no impact to net income. This was partly offset by a $15.9lower interruptible revenues of $7.4 million net increase in tax expense included in Provision for Income Taxes. This increase in transportation revenues is partially offset by a $4.0 million decrease of reimbursable costs that are offset in operating expenses and recovered in our rates.production area.
Sales RevenuesWe make jurisdictional merchant gas sales pursuant to a blanket sales certificate issued by the FERC, with most of those sales previously having been made through a Firm Sales (FS) program which gave customers the option to purchase daily quantities of gas from us at market-responsive prices in exchange for a demand charge payment. Pursuant to the terms of an agreement with the FERC, we terminated our remaining FS agreements effective April 1, 2005.FERC.
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Through an agency agreement, WPCWGM manages our long-term purchase agreements and our remaining jurisdictional merchant gas sales, which excludes our cash out sales in settlement of gas imbalances. The long-term purchase agreements managed by WPCWGM remain in our name, as do the corresponding sales of such purchased gas. Therefore, we continue to record natural gas sales revenues and the related accounts receivable and cost of natural gas sales and the related accounts payable for the jurisdictional merchant sales that are managed by WPC. WPCWGM. WGM receives all margins associated with jurisdictional merchant gas sales business and, as our agent, assumes all market and credit risk associated with our jurisdictional merchant gas sales. Consequently, our merchant gas sales service and the termination of the FS agreements in April 2005 havehas no impact on our operating income or results of operations.
In addition to our merchant gas sales, we also have cash out sales, which settle gas imbalances with shippers. In the course of providing transportation services to customers, we may receive different quantities of gas from shippers than the quantities delivered on behalf of those shippers. Additionally, we transport gas on various pipeline systems, which may deliver different quantities of gas on our behalf than the quantities of gas received from us. These transactions result in gas transportation and exchange imbalance receivables and payables. Our tariff includes a method whereby the majority of transportation imbalances are settled on a monthly basis through cash out sales or purchases. The cash out sales have no impact on our operating income or results of operations.
Operating revenues related to ourRevenues: Natural gas sales services decreased $146.0$41.9 million to $142.3$150.1 million for 20062008 when compared to 2005.2007. The 21.8% decrease was primarily due to the sale of $59.2 million of excess top gas from our Eminence storage field in 2007, and a lower volume ofin merchant sales because of the termination of the FS agreements during 2005. There were also lower$11.1 million, partially offset by an increase in cash out sales volumesof $28.4 million related to the monthly settlementsettlements of imbalances. These sales were offset in our costs of natural gas sold and therefore had no impact on our operating income or results of operations.
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Storage RevenuesOur operating revenues related toOperating Revenues: Natural gas storage services of $119.8were $145.7 million for 2006 were comparable2008 compared to revenues of $122.1$141.1 million for 2005.2007. The increase of $4.6 million (3.3%) was primarily due to the effects of placing into effect, subject to refund, the rates in Docket No. RP06-569, on March 1, 2007.
Other RevenuesOur other operating revenues increased $6.5Operating Revenues: Otherdecreased $10.4 million (56.8%) to $14.5$7.9 million for 2006,2008, when compared to 2005,2007, primarily due to an increasea decrease in environmental mitigation credit sales.revenues from the Park and Loan service of $10.5 million as a result of lower volumes parked and/or loaned by customers in 2008 due to unfavorable market conditions.
Operating Costs and ExpensesExcluding thecost of natural gas salesof $142.2$150.1 million for 20062008 and $288.3$191.8 million for 2005,2007, our operating expenses were approximately $100.0$23.6 million higher(3.5%) lower than the comparable period in 2005.2007. This increasedecrease was primarily attributable to higher cost of natural gas transportation, operation and maintenance expenses, administrative and general expenses, depreciation and amortization expense and taxes other than income taxes, partially offset by lower other expenses. The higher cost of natural gas transportation of $17.2to:
| • | | Lowerother (income) expense, netof $23.8 million, is primarily due to the absence of a 2005 positive adjustment of $14.2 million associated with the resolution of our 1999 Fuel Tracker filing. Additionally, there was a $3.5 million decrease in 2006 of reimbursable costs that are recovered in our rates. The increase in operation and maintenance expense of $32.0 million is due primarily to higher outside services of $7.3 million and higher material and supplies expenses of $5.1 million due primarily to integrity management assessment costs, and higher contract labor and services of $10.8 million. The 2005 hurricanes in the Gulf of Mexico caused a shortage of contractors resulting in a large premium for offshore services. The increase in administrative and general expense of $44.9 million is mostly due to higher employee labor and benefits costs of $16.3 million, increased information systems costs of $10.9 million and higher property insurance of $12.8 million due to increased premiums on offshore facilities. The increase in depreciation and amortization of $10.1 million was primarily due to higher expense associated with asset retirement obligations. The increase in taxes other than income taxes of $7.5 million is due to higher property taxes resulting from increased property values and additional capital spending and increased franchise taxes resulting from settlements of prior years state audits. The lower other operating costs and expenses of $11.7 million were primarily resulting from: |
| ° | | $10.4 million gain related to the sale of our South Texas assets. |
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| ° | | $9.5 million gain recognized in the second quarter of 2008 related to the 2007 sale of Eminence top gas. In 2007, the gain was deferred pending final approval of the Agreement. (See Note 1 of Notes to Financial Statements.) |
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| ° | | $4.9 million net decrease in expense associated with our asset retirement obligations (ARO) due to the new rates in Docket No. RP06-569, effective March 1, 2007. (See Note 3 of Notes to Financial Statements.) Any differences between the recovery of ARO costs in rates and the depreciation, accretion, and amortization of the recovery of ARO costs in rates and the depreciation, accretion, and amortization of the regulatory asset from March 1, 2007 forward are being deferred as a regulatory asset for collection/refund in a future rate case. |
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| ° | | Partially offset by a $2.1 million increase in expense associated with project development costs. |
| • | | Loweradministrative and generalexpense of $11.6 million, primarily resulting from: |
| ° | | $6.9 million decrease in labor and benefits mostly attributable to lower group insurance, retirement plan expense and employee bonuses. |
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| ° | | $6.4 million decrease in specific and allocated corporate expense from Williams. |
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| ° | | Partially offset by a $4.5 million charge associated with a third quarter 2008 pipeline rupture. |
| • | | Lowertaxes-other than income taxesof $5.2 million, primarily resulting from: |
| ° | | $3.0 million decease related to the State of Pennsylvania gross receipt tax due to a favorable ruling and a subsequent refund. |
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| ° | | $1.3 million decrease related to the reversal of a prior year accrual for franchise taxes due to the conversion to a limited liability company. |
|
| ° | | $1.3 million sales and use tax refund from the State of Texas applicable to prior years. |
| • | | An increase indepreciation and amortizationof $8.5 million, primarily due to higher expense associated with negative salvage, partly offset by lower depreciation related to transmission assets. |
2129
regulatory credit associated with asset retirement obligation depreciation expense of $7.8 million and a $2.0 million reduction of accrued liabilities for royalty claims associated with certain producer indemnities. See “Item 1. Financial Statements – Notes to Consolidated Financial Statements – 3. Contingent Liabilities and Commitments.” | • | | An increase inoperation and maintenance expenseof $6.9 million, primarily due to an increase in miscellaneous contractual services mostly for work related to Hurricane Ike. |
Other Income(Income) and Other DeductionsOther income(income) and other deductionsresulted in $1.9$2.9 million lower(5.0%) higher net expense in 20062008 compared to 2005. A $5.02007. This was primarily due to:
| • | | Lowerallowance for equity and borrowed funds used during construction (AFUDC)of $6.7 million due to lower construction spending in 2008, primarily due to the completion of our Leidy to Long Island and Potomac expansions placed in service in the fourth quarter of 2007. |
|
| • | | Lowermiscellaneous other (income) deductions, netof $2.1 million, primarily due to lower equity AFUDC gross-up in 2008 as compared to 2007. |
|
| • | | An increase ininterest income-affiliatesof $7.1 million, primarily due to higher average daily cash advance balances in 2008 as compared to 2007. |
(Benefit) Provision for Income Taxes(Benefit) Provision for Income Taxesdecreased $1,049.9 million decrease in interest expense resulted from the reduction(1,038.5%), which includes a reversal of accrued liabilities for royalty claims associated with certain producer indemnities. (See “Item 1. Financial Statements – Notes to Consolidated Financial Statements – 3. Contingent Liabilities and Commitments.”) The increase in interest income – affiliates$1,072.6 million of $4.1 million was mostlydeferred taxes, due to an increase in intercompany demand notes resultingour conversion from a lower amount of dividends paidcorporation to WGP in 2006 compareda single member limited liability company on December 31, 2008. The provision for income taxes for 2008 reflects the provision through December 31, 2008. Subsequent to 2005. These amountsthe conversion to a single member limited liability company, all deferred income taxes were offset by increased interest expense primarily associated with the issuance of the 6.4 % notes.eliminated and we no longer provide for income tax.
EFFECT OF INFLATION
We generally have experienced increased costs due to the effect of inflation on the cost of labor, materials and supplies, and property, plant and equipment. A portion of the increased labor and materials and supplies cost can directly affect income through increased operation and maintenance expenses. The cumulative impact of inflation over a number of years has resulted in increased costs for current replacement of productive facilities. The majority of our property, plant and equipment and material and supplies inventory is subject to ratemaking treatment, and under current FERC practices, recovery is limited to historical costs. We believe that we will be allowed to recover and earn a return based on increased actual costs incurred when existing facilities are replaced. Cost based regulation along with competition and other market factors limit our ability to price services or products based upon inflation’s effect on costs.
CAPITAL RESOURCES AND LIQUIDITY
METHOD OF FINANCING
We fund our capital requirements with cash flows from operating activities, repayments of advances to Williams, accessing capital markets, and, if required, borrowings under the credit agreement described below and advances from Williams.
We have an effective shelf registration statement on file with the Securities and Exchange Commission. At December 31, 2006, $200 million of availability remained under this registration statement. While our credit ratings from certain credit rating agencies remain below investment grade, the shelf registration may only be utilized to issue debt securities if such securities are guaranteed by Williams. However, we can raise capital through private debt offerings, as well as offerings registered pursuant to offering-specific registration statements, without a guaranty from Williams.statements. Interest rates, market conditions, and industry conditions will affect amounts raised, if any, in the capital markets. We believe any additional financing arrangements, if required, can be obtained from the capitalHistorically, we have been able to access public and private markets on terms that are commensurate with our current credit ratings.ratings to finance our capital requirements, when needed. However, as a result of credit market conditions, this source of funding is considered economically unfavorable at December 31, 2008.
30
In May 2006, Williams obtainedhas an unsecured, three-year, $1.5 billion revolving credit facility replacing the $1.275 billion secured revolving credit facility. The new unsecured facility contains similar terms and financial covenants as the secured facility but contains additional restrictions on asset sales, certain
22
subsidiary debt and sale-leaseback transactions. The facility is guaranteed by WGP, and Williams guarantees obligations(Credit Facility) with a maturity date of Williams Partners L.P. for up to $75 million.May 1, 2012. We have access to $400 million under the facilityCredit Facility to the extent not otherwise utilized by Williams. Lehman Commercial Paper Inc., which is committed to fund up to $70 million of the Credit Facility, has filed for bankruptcy. Williams expects that its ability to borrow under this facility is reduced by this committed amount. Consequently, we expect our ability to borrow under the Credit Facility is reduced by approximately $18.7 million. The committed amounts of other participating banks under this agreement remain in effect and are not impacted by the above. As of December 31, 2008, letters of credit totaling $71 million, none of which are associated with us, have been issued by the participating institutions. There were no revolving credit loans outstanding as of December 31, 2008.
Interest is calculated based on a choice of two methods: a fluctuating rate equal to the lender’s base rateplus an applicable margin, or a periodic fixed rate equal to LIBORthe London Interbank Offered Rate plus an applicable margin. Williams is required to pay a commitment fee (currently 0.25 % annually)0.125 percent) based on the unused portion of the facility.Credit Facility. The margins and commitment fee are generally based on the specific borrower’s senior unsecured long-term debt ratings. Letters
The Credit Facility contains certain affirmative covenants and a number of credit totaling approximately $29 million, nonerestrictions on the business of which are associated with us, have been issued by the participating institutionsborrowers, including us. These restrictions include restrictions on the borrowers’ ability to grant liens securing indebtedness, merge or sell all or substantially all of our assets and no revolving credit loans were outstanding at December 31, 2006. Transco did not access this facility during 2006.incurrence of indebtedness. Significant financial covenants under the credit agreementCredit Facility include the following:
| | • | | Williams’ ratio of debt to capitalization must be no greater than 65 percent. At December 31, 2008, Williams was in compliance with this covenant. |
| |
| | • | | Our ratio of debt to capitalization must be no greater than 55 percent. At December 31, 2006,2008, we are in compliance with this covenant as our ratio of debt to capitalization, as calculated under this covenant is approximately 32 percent. |
|
| • | | Williams’ ratio of EBITDA to interest, on a rolling four quarter basis, must be no less than 2.5 for the period ending December 31, 2007 and 3.0 for the remaining term of the agreement.covenant. |
The Credit Facility also contains events of default tied to all borrowers which in certain circumstances would cause all lending under the Credit Facility to terminate and all indebtedness outstanding under the Credit Facility to be accelerated.
In January 2008, we borrowed $100 million under the Credit Facility to retire $100 million of 6.25 percent senior unsecured notes that matured on January 15, 2008. In April 2008, we borrowed $75 million under the Credit Facility to retire $75 million of adjustable rate unsecured notes that matured on April 15, 2008.
On April 11, 2006,May 22, 2008, we issued $200$250 million aggregate principal amount of 6.05 percent senior unsecured notes due 2018 to certain institutional investors in a Rule 144A private debt placement which pay interest at 6.4% per annum on April 15 and October 15 each year, beginning October 15, 2006 (6.4% Notes). The 6.4% Notes mature on April 15, 2016, but are subject to redemption at any time, at our option, in whole or part, at a specified redemption price, plus accrued and unpaid interest toplacement. We used $175 million of the date of redemption. The net proceeds ofto repay our borrowings under the sale are being used for general corporate purposes, including the funding of capital expenditures.Credit Facility. In October 2006,September 2008, we completed thean exchange of the 6.4% Notesthese notes for substantially identical new notes that are registered under the Securities Act of 1933, as amended.
As a participant in Williams’ cash management program, we have advances to and from Williams. At December 31, 2006,2008, the advances due to us by Williams totaled $190.4$186.2 million. The advances are represented by demand notes. In July 2008, a large portion of these advances were called upon in order to pay rate refunds to our customers after final approval of the Agreement in Docket No. RP06-569. The interest rate on intercompany
31
demand notes is based upon the weighted average cost of Williams’ debt outstanding at the end of each quarter. At December 31, 2006,2008, the interest rate was 7.81%.
Through a wholly-owned subsidiary, we hold a 35% interest in Pine Needle LNG Company, LLC (Pine Needle). On March 20, 1998, Pine Needle executed an interest rate swap agreement with a bank, which swapped floating rate debt into 6.58% fixed rate debt. This interest rate swap qualifies as a cash flow hedge transaction under7.87 percent. Williams has indicated that it currently believes that it will continue to have the accountingfinancial resources and reporting standards established by SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” as amended by SFAS No. 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities.” As such, our equity interest in the changes in fair value of Pine Needle’s hedge is recognized in other comprehensive income. For the years ended December 31, 2006 and 2005, our cumulative equity interest in an unrealized loss on Pine Needle’s hedge was $0.2 million and $0.4 million, respectively. The swap agreement initially had a notional amount of $53.5 million of debt, of which $37.5 million was still outstanding at December 31, 2006. The interest rate swap is settled quarterly. The swap agreement was effective March 31, 1999 and terminates on December 31, 2013, which is also the date of the last principal payment on this long-term debt.liquidity to repay these advances.
23
Credit Ratings
We have no guarantees of off-balance sheet debt to third parties and maintain no debt obligations that contain provisions requiring accelerated payment of the related obligations in the event of specified levels of declines in Williams’ or our credit ratings given by Moody’s Investors Service, Standard & Poor’s and Fitch Ratings (rating agencies).
During 2006, the rating agencies raised2008, the credit ratings on our senior unsecured long-term debt remained unchanged with investment grade ratings from all three agencies, as shown below. While the Moody’s Investor Services and Standard & Poor’s credit ratings remain below investment grade, the rise in the Fitch Ratings credit rating moves us to investment grade.
| | | | |
| Moody’s Investors Services | | Ba2 to Ba1Baa2 | | |
| Standard & Poor’s | | B+ to BB-BBB- | | |
| Fitch Ratings | | BB+ to BBB-BBB | | |
Currently,At December 31, 2008, the Standard and Poor’s evaluation of our credit rating is “positive“stable outlook” from Standard and the Fitch andPoor’s. On November 6, 2008, Moody’s Investors Services evaluationsService changed the ratings outlook for Williams, and each of Williams’ rated subsidiaries, including us, to “negative”. In addition, Fitch Ratings changed its rating outlook for Williams and two of its rated subsidiaries, including us, to “evolving”. On February 23, 2009, Moody’s changed its ratings outlook for Williams and two of its rated subsidiaries, including us, from negative to stable. On February 24, 2009, Fitch changed its ratings outlook for Williams and two of its rated subsidiaries, including us, from evolving to stable.
With respect to Moody’s, a rating of “Baa” or above indicates an investment grade rating. A rating below “Baa” is considered to have speculative elements. A “Ba” rating indicates an obligation that is judged to have speculative elements and is subject to substantial credit risk. The “1”, “2” and “3” modifiers show the relative standing within a major category. A “1” indicates that an obligation ranks in the higher end of the broad rating category, “2” indicates a mid-range ranking, and “3” ranking at the lower end of the category.
With respect to Standard & Poor’s, a rating of “BBB” or above indicates an investment grade rating. A rating below “BBB” indicates that the security has significant speculative characteristics. A “BB” rating indicates that Standard & Poor’s believes the issuer has the capacity to meet its financial commitment on the obligation, but adverse business conditions could lead to insufficient ability to meet financial commitments. Standard & Poor’s may modify its ratings with a “+” or a “-” sign to show the obligor’s relative standing within a major rating category.
With respect to Fitch, a rating of “BBB” or above indicates an investment grade rating. A rating below “BBB” is considered speculative grade. A “BB” rating from Fitch indicates that there is a possibility of credit risk developing, particularly as the result of adverse economic change over time; however, business or financial alternatives may be available to allow financial commitments to be met. Fitch may add a “+” or a “-” sign to show the obligor’s relative standing within a major rating category.
Credit rating agencies perform independent analyses when assigning credit ratings. No assurance can be given that the credit rating agencies will continue to assign us investment grade ratings even if we meet or exceed their current criteria for investment grade ratios. A downgrade of our credit rating are “stable outlook.”might increase our future cost of borrowing and might require us to post collateral with third parties.
32
CAPITAL EXPENDITURES
We categorize our capital expenditures as either maintenance capital expenditures or expansion capital expenditures. Maintenance capital expenditures are those expenditures required to maintain the existing operating capacity and service capability of our assets, including replacement of system components and equipment that are worn, obsolete, completing their useful life, or necessary to remain in compliance with environmental laws and regulations. Expansion capital expenditures improve the service capability of the existing assets, extend useful lives, increase transmission or storage capacities from existing levels, reduce costs or enhance revenues. As shown in the table below, our capital expenditures for 20062008 included $29$95 million for expansion projects, primarily for Sentinel, Leidy to Long Island, Sentinel and Potomac and $301$107 million for maintenance of existing facilities and other projects including expenditures required under the Federal Clean Air Act and Clean Air Act Amendments of 1990 and the Pipeline Safety Improvement Act of 2002. We are estimating approximately $310$370 million to $390$430 million of capital expenditures in the year 20072009 related to the maintenance of existing facilities, including pipeline safety expenditures, and expansion projects, primarily the LeidySentinel and 85 North Expansion projects. Of this total, $310 million to Long Island and Potomac projects.$370 million is considered nondiscretionary due to legal, regulatory, and/or contractual requirements.
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Capital Expenditures | | 2006 | | 2005 | | 2004 | | | 2008 | | 2007 | | 2006 |
| | | | (In millions) | |
| | | (In millions) | | |
| Expansion Projects | | $ | 29.4 | | $ | 22.0 | | $ | 10.1 | | | $ | 95.8 | | $ | 201.0 | | $ | 33.7 | |
| Maintenance of Existing Facilities and Other Projects | | 300.5 | | 222.9 | | 143.5 | | | 107.8 | | 174.4 | | 309.1 | |
| | | | | | | | | | | | | | |
| | | |
| Total Capital Expenditures | | $ | 329.9 | | $ | 244.9 | | $ | 153.6 | | | $ | 203.6 | | $ | 375.4 | | $ | 342.8 | |
| | | | | | | | | | | | | | |
2433
OTHER CAPITAL REQUIREMENTS, CONTRACTUAL OBLIGATIONS AND CONTINGENCIES
Contractual obligationsThe table below summarizes the maturity dates of our contractual obligations by periodas of December 31, 2008 (in millions).
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | 2010- | | 2012- | | There- | | | |
| | | 2008- | | 2010- | | There- | | | | | 2009 | | 2011 | | 2013 | | after | | Total |
| | | 2007 | | 2009 | | 2011 | | after | | Total | | |
| Long-term debt, including current portion: | | |
| | | |
| Principal | | $ | — | | $ | 175 | | $ | 300 | | $ | 733 | | $ | 1,208 | | | $ | — | | $ | 300 | | $ | 325 | | $ | 658 | | $ | 1,283 | |
| | |
| Interest | | 89 | | 161 | | 155 | | 312 | | 717 | | | 93 | | 186 | | 115 | | 287 | | 681 | |
| | |
| Capital leases | | — | | — | | — | | — | | — | | | — | | — | | — | | — | | — | |
| | |
| Operating leases | | 6 | | 12 | | 13 | | 15 | | 46 | | | 7 | | 14 | | 15 | | 2 | | 38 | |
| | | |
| Purchase obligations: | | |
| Natural gas purchase, storage and transportation | | 99 | | 151 | | 88 | | 76 | | 414 | | | 76 | | 83 | | 48 | | 17 | | 224 | |
| | |
| Other | | | 139 | (1) | | 7 | | 5 | | 2 | | 153 | | |
| | |
| Other long-term liabilities, including current portion: | | |
| FERC penalty | | 4 | | — | | — | | — | | 4 | | |
| Other (1) | | | 110 | | 11 | | 4 | | 2 | | 127 | |
| | | | | | | | | | | | | | | | | | | | | | |
| | | |
| Total | | $ | 337 | | $ | 506 | | $ | 561 | | $ | 1,138 | | $ | 2,542 | | | $ | 286 | | $ | 594 | | $ | 507 | | $ | 966 | | $ | 2,353 | |
| | | | | | | | | | | | | | | | | | | | | | |
| | |
| (1) | | Obligations primarily associated with Property, Plant and Equipment expenditures. Does not include estimated contributions to the Williams’ sponsored pension and other postretirement benefit plans. We made contributions to the pension and other postretirement benefit plans of $16.4 million in 2008, $16.2 million in 2007, and $14.7 million in 2006. (See Note 6 of Notes to Financial Statements.) |
Regulatory and legal proceedingsAs discussed in Notes 2 andNote 3 of the Notes to Consolidated Financial Statements, included in Item 8 herein, we are involved in several pending regulatory and legal proceedings. Because of the complexities of the issues involved in these proceedings, we cannot predict the actual timing of resolution or the ultimate amounts, which might have to be refunded or paid in connection with the resolution of these pending regulatory and legal proceedings.
Environmental mattersAs discussed in Note 3 of the Notes to Consolidated Financial Statements, included in Item 8 herein, we are subject to extensive federal, state and local environmental laws and regulations which affect our operations related to the construction and operation of our pipeline facilities. We consider environmental assessment and remediation costs and costs associated with compliance with environmental standards to be recoverable through rates, as they are prudent costs incurred in the ordinary course of business. To date, we have been permitted recovery of environmental costs incurred, and it is our intent to continue seeking recovery of such costs, as incurred, through rate filings.
Long-term gas purchase contractsWe have long-term gas purchase contracts containing variable prices that are currently in the range of estimated market prices. However, due to contract expirations and estimated deliverability declines, our estimated purchase commitments under such gas purchase contracts are not material to our total gas purchases.
CONCLUSION
Although no assurances can be given, we currently believe that the aggregate of cash flows from operatingOperating activities, supplemented, when necessary, by repayments of funds advanced to Williams, advances or capital
34
contributions from Williams and borrowings under the Credit AgreementFacility will provide us with sufficient liquidity to meet our capital requirements. In addition,Historically, we have been able to access public and private markets on terms commensurate with our current credit ratings to finance our capital requirements.requirements, when needed. However, as a result of credit market conditions, this source of funding is considered economically unfavorable at December 31, 2008.
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ITEM 7A. Qualitative and Quantitative Disclosures About Market Risk
Due to variable rate issues inAt December 31, 2008, our debt portfolio our interest rate risk exposure is influenced by short-term rates, primarily London Interbank Offered Rate (LIBOR) on borrowings from commercial banks. To mitigate the impact of fluctuations in short-term interest rates, we maintain a significant portion of our debt portfolio inincluded only fixed rate debt.
issues. The following tables providetable provides information about our long-term debt, including current maturities, as of December 31, 2006.2008. The tables presenttable presents principal cash flows and weighted-average interest rates by expected maturity dates.
| | | | | | | | | | | | | | | | | |
| December 31, 2006 | | Expected Maturity Date |
| | | 2007 | | 2008 | | 2009 | | 2010 |
| | | (Dollars in millions) |
| Long-term debt: | | | | | | | | | | | | | | | | |
| Fixed rate | | $ | — | | | $ | 100 | | | $ | — | | | $ | — | |
| Interest rate | | | 7.23 | % | | | 7.45 | % | | | 7.53 | % | | | 7.53 | % |
| Variable rate | | $ | — | | | $ | 75 | | | $ | — | | | $ | — | |
| Interest rate (5.43% to 6.79% for 2006) | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2006 | | Expected Maturity Date | |
| December 31, 2008 | | | Expected Maturity Date |
| | | 2011 | | Thereafter | | Total | | Fair Value | | 2009 | | 2010 | | 2011 | | 2012 |
| | | (Dollars in millions) | | (Dollars in millions) | |
| Long-term debt: | | |
| Fixed rate | | $ | 300 | | $ | 733 | | $ | 1,133 | | $ | 1,195 | | | $ | - | | $ | - | | $ | 300 | | $ | 325 | |
| Interest rate | | | 7.60 | % | | | 7.14 | % | | | | 7.24 | % | | | 7.24 | % | | | 7.26 | % | | | 7.03 | % |
| Variable rate | | $ | — | | $ | — | | $ | 75 | | $ | 75 | | |
| Interest rate (5.43% to 6.79% for 2006) | | |
| | |
| December 31, 2008 | | | Expected Maturity Date |
| | | | 2013 | | Thereafter | | Total | | Fair Value |
| | | | (Dollars in millions) | |
| Long-term debt: | | |
| Fixed rate | | | $ | - | | $ | 658 | | $ | 1,283 | | $ | 1,155 | |
| Interest rate | | | | 6.53 | % | | | 6.81 | % | |
2635
ITEM 8. Financial Statements and Supplementary Data
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| | | 37 | |
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| | 28 | 38 | |
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| | 29 | 39 | |
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| | 30-31 | 40-41 | |
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| | 32 | 42 | |
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| | 33 | 43 | |
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| | 34-35 | 44-45 | |
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| | 36-57 | 46-68 | |
2736
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER
FINANCIAL REPORTING
Management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a – 15(f) and 15d – 15(f) under the Securities Exchange Act of 1934). Our internal controls over financial reporting are designed to provide reasonable assurance to our management regarding the preparation and fair presentation of financial statements in accordance with accounting principles generally accepted in the United States. Our internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorization of our management; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.
All internal control systems, no matter how well designed, have inherent limitations including the possibility of human error and the circumvention or overriding of controls. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
Under the supervision and with the participation of our management, including our Senior Vice President and our Vice President and Treasurer, we assessed the effectiveness of our internal control over financial reporting as of December 31, 2008, based on the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) inInternal Control — Integrated Framework.Based on our assessment we believe that, as of December 31, 2008, our internal control over financial reporting was effective.
This annual report does not include an attestation report of Transco’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by Transco’s registered public accounting firm pursuant to temporary rules of the SEC that permit Transco to provide only management’s report in this annual report.
37
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of DirectorsManagement Committee of Transcontinental Gas Pipe Line CorporationCompany, LLC
We have audited the accompanying consolidated balance sheets of Transcontinental Gas Pipe Line CorporationCompany, LLC as of December 31, 20062008 and 2005,2007, and the related consolidated statements of income, comprehensive income, common stockholder’sowner’s equity, and cash flows for each of the three years in the period ended December 31, 2006.2008. Our audits also included the financial statement schedule listed in the Index at Item 15(a). These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our auditaudits 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 CorporationCompany, LLC at December 31, 20062008 and 2005,2007, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2006,2008, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
As discussed in Note 5 to the financial statements, in 2006 the Company adopted Statement of Financial Accounting Standards No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans -An Amendment of FASB Statements No. 87, 88, 106, and 132(R), and Statement of Financial Accounting Standards No. 123(R), Share-Based Payment – a revision of FASB Statement No. 123, Accounting for Stock-Based Compensation. As discussed in Note 1 to the financial statements, in 2006 the Company adopted the Federal Energy Regulatory Commission order on Accounting for Pipeline Assessment Costs.
/s/ ERNST & YOUNG LLP
Houston, Texas
February 27, 200723, 2009
2838
TRANSCONTINENTAL GAS PIPE LINE CORPORATIONCOMPANY, LLC
CONSOLIDATED STATEMENT OF INCOME
(Thousands of Dollars)
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | Years Ended December 31, |
| | | Years Ended December 31, | | | 2008 | | 2007 | | 2006 |
| | | 2006 | | 2005 | | 2004 | | | (Restated) | | (Restated) | |
| Operating Revenues: | | |
| Natural gas sales | | $ | 142,252 | | $ | 288,294 | | $ | 403,181 | | | $ | 150,056 | | $ | 192,006 | | $ | 142,252 | |
| Natural gas transportation | | 771,855 | | 767,919 | | 784,605 | | | 897,569 | | 849,246 | | 771,855 | |
| Natural gas storage | | 119,750 | | 122,117 | | 122,951 | | | 145,711 | | 141,098 | | 119,750 | |
| Other | | 14,534 | | 8,083 | | 9,079 | | | 7,876 | | 18,251 | | 7,590 | |
| | | | | | | | | | | | | | |
| Total operating revenues | | 1,048,391 | | 1,186,413 | | 1,319,816 | | | 1,201,212 | | 1,200,601 | | 1,041,447 | |
| | | | | | | | | | | | | | |
| | | |
| Operating Costs and Expenses: | | |
| Cost of natural gas sales | | 142,248 | | 288,256 | | 401,632 | | | 150,129 | | 191,841 | | 142,248 | |
| Cost of natural gas transportation | | 11,414 | | | (5,815 | ) | | 20,883 | | | 7,043 | | 5,518 | | 11,414 | |
| Operation and maintenance | | 232,002 | | 200,030 | | 191,200 | | | 232,390 | | 225,504 | | 231,830 | |
| Administrative and general | | 165,367 | | 120,471 | | 118,719 | | | 153,271 | | 164,896 | | 165,326 | |
| Depreciation and amortization | | 205,860 | | 195,744 | | 196,021 | | | 233,516 | | 225,010 | | 202,848 | |
| Taxes – other than income taxes | | 51,146 | | 43,669 | | 42,077 | | | 46,148 | | 51,265 | | 51,094 | |
| Other (income) expense, net | | | (9,679 | ) | | 1,973 | | 3,182 | | | | (14,882 | ) | | 8,915 | | | (9,679 | ) |
| | | | | | | | | | | | | | |
| Total operating costs and expenses | | 798,358 | | 844,328 | | 973,714 | | | 807,615 | | 872,949 | | 795,081 | |
| | | | | | | | | | | | | | |
| | | |
| Operating Income | | 250,033 | | 342,085 | | 346,102 | | | 393,597 | | 327,652 | | 246,366 | |
| | | | | | | | | | | | | | |
| | | |
| Other (Income) and Other Deductions: | | |
| Interest expense — affiliates | | 942 | | — | | — | | |
| — other | | 85,064 | | 79,661 | | 88,742 | | |
| Interest income — affiliates | | | (14,310 | ) | | | (10,172 | ) | | | (12,555 | ) | |
| — other | | | (762 | ) | | | (851 | ) | | | (1,192 | ) | |
| Interest expense – affiliates | | | 437 | | 463 | | 559 | |
| – other | | | 95,802 | | 94,641 | | 85,064 | |
| Interest income – affiliates | | | | (21,967 | ) | | | (14,947 | ) | | | (13,600 | ) |
| – other | | | | (631 | ) | | | (748 | ) | | | (762 | ) |
| Allowance for equity and borrowed funds used during construction (AFUDC) | | | (11,148 | ) | | | (9,270 | ) | | | (8,327 | ) | | | (6,324 | ) | | | (12,951 | ) | | | (11,148 | ) |
| Equity in earnings of unconsolidated affiliates | | | (7,498 | ) | | | (7,185 | ) | | | (7,073 | ) | |
| Miscellaneous other (income) deductions, net | | | (7,382 | ) | | | (5,352 | ) | | | (4,868 | ) | | | (5,908 | ) | | | (8,008 | ) | | | (7,382 | ) |
| | | | | | | | | | | | | | |
| Total other (income) and other deductions | | 44,906 | | 46,831 | | 54,727 | | | 61,409 | | 58,450 | | 52,731 | |
| | | | | | | | | | | | | | |
| | | |
| Income before Income Taxes | | 205,127 | | 295,254 | | 291,375 | | | 332,188 | | 269,202 | | 193,635 | |
| Provision for Income Taxes | | 87,876 | | 109,939 | | 111,921 | | |
| (Benefit) Provision for Income Taxes | | | | (948,780 | ) | | 101,116 | | 83,298 | |
| | | | | | | | | | | | | | |
| | | |
| Net Income | | $ | 117,251 | | $ | 185,315 | | $ | 179,454 | | | $ | 1,280,968 | | $ | 168,086 | | $ | 110,337 | |
| | | | | | | | | | | | | | |
See accompanying notes.
2939
TRANSCONTINENTAL GAS PIPE LINE CORPORATIONCOMPANY, LLC
CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
| | | | | | | | | | |
| | | | | | | | | | | December 31, |
| | | December 31, | | | 2008 | | 2007 |
| | | 2006 | | 2005 | | | (Restated) | |
| ASSETS | | |
| | | |
| Current Assets: | | |
| Cash | | $ | 315 | | $ | 362 | | | $ | 428 | | $ | 119 | |
| Receivables: | | |
| Trade less allowance of $503 ($509 in 2005) | | 73,378 | | 87,348 | | |
| Trade less allowance of $424 ($462 in 2007) | | | 87,278 | | 105,427 | |
| Affiliates | | 7,814 | | 4,374 | | | 3,419 | | 6,171 | |
| Advances to affiliates | | 190,399 | | 130,307 | | |
| Advances to affiliate | | | 186,249 | | 213,915 | |
| Other | | 11,067 | | 6,479 | | | 4,031 | | 9,444 | |
| Transportation and exchange gas receivables | | 7,075 | | 9,906 | | | 10,649 | | 10,724 | |
| Inventories: | | |
| Gas in storage, at LIFO | | 26,172 | | 25,289 | | | 10,616 | | 55 | |
| Gas in storage, at original cost | | | 764 | | 809 | |
| Gas available for customer nomination, at average cost | | 10,901 | | 29,617 | | | 46,087 | | 25,686 | |
| Materials and supplies, at lower of average cost or market | | 27,748 | | 27,774 | | | 30,424 | | 28,570 | |
| Deferred income taxes | | 17,414 | | 15,283 | | | — | | 38,588 | |
| Regulatory assets | | | 86,361 | | 21,934 | |
| Other | | 28,557 | | 17,825 | | | 10,253 | | 11,685 | |
| | | | | | | | | | |
| Total current assets | | 400,840 | | 354,564 | | | 476,559 | | 473,127 | |
| | | | | | | |
| | | |
| Investments, at cost plus equity in undistributed earnings | | 44,820 | | 44,108 | | |
| | | | | | | | | | |
| | | |
| Property, Plant and Equipment: | | |
| Natural gas transmission plant | | 6,475,172 | | 6,134,951 | | | 7,071,491 | | 6,840,377 | |
| Less – Accumulated depreciation and amortization | | 1,939,430 | | 1,776,946 | | | 2,294,112 | | 2,113,561 | |
| | | | | | | | | | |
| Total property, plant and equipment, net | | 4,535,742 | | 4,358,005 | | | 4,777,379 | | 4,726,816 | |
| | | | | | | | | | |
| Other Assets: | | |
| Regulatory assets | | | 219,472 | | 157,110 | |
| Other | | | 46,306 | | 95,450 | |
| | | | | | |
| Other Assets | | 300,587 | | 251,969 | | |
| Total other assets | | | 265,778 | | 252,560 | |
| | | | | | | | | | |
| | | |
| | | $ | 5,281,989 | | $ | 5,008,646 | | | $ | 5,519,716 | | | $ | 5,452,503 | |
| | | | | | | | | | |
See accompanying notes.
3040
TRANSCONTINENTAL GAS PIPE LINE CORPORATIONCOMPANY, LLC
CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
| | | | | | | | | | | | | | | | | |
| | | December 31, | | | December 31, | |
| | | 2006 | | 2005 | | | 2008 | | 2007 | |
| LIABILITIES AND STOCKHOLDER’S EQUITY | | |
| | | | (Restated) | |
| LIABILITIES AND OWNER’S EQUITY | | |
| | |
| Current Liabilities: | | |
| Payables: | | |
| Trade | | $ | 83,517 | | $ | 52,415 | | | $ | 112,388 | | $ | 74,026 | |
| Affiliates | | 23,007 | | 27,812 | | | 25,708 | | 21,389 | |
| Cash Overdrafts | | 29,901 | | 28,461 | | |
| Cash overdrafts | | | 14,279 | | 12,242 | |
| Transportation and exchange gas payables | | 14,693 | | 49,657 | | | 2,851 | | 7,245 | |
| Accrued liabilities: | | |
| Federal income taxes payable to affiliate | | — | | 18,425 | | | 19,704 | | 53,003 | |
| State income taxes | | — | | 4,356 | | | - | | 5,382 | |
| Other taxes | | 15,038 | | 15,365 | | | 11,809 | | 15,256 | |
| Interest | | 29,338 | | 26,428 | | | 26,061 | | 29,331 | |
| Deferred cash out | | 15,823 | | 39,842 | | | 9,778 | | 7,648 | |
| Employee benefits | | 32,494 | | 42,459 | | | 35,687 | | 36,197 | |
| Other | | 17,137 | | 20,080 | | | 41,408 | | 56,928 | |
| Reserve for rate refunds | | 2,232 | | 3,763 | | | 14,362 | | 98,035 | |
| Current maturities of long-term debt | | — | | — | | | - | | 75,000 | |
| | | | | | | | | | |
| Total current liabilities | | 263,180 | | 329,063 | | | 314,035 | | 491,682 | |
| | | | | | | | | | |
| | |
| Long-Term Debt | | 1,201,458 | | 1,000,623 | | | 1,277,679 | | 1,127,370 | |
| | | | | | | | | | |
| | | |
| Other Long-Term Liabilities: | | |
| Deferred income taxes | | 1,013,282 | | 955,503 | | | - | | 1,015,992 | |
| Asset retirement obligations | | 136,171 | | 53,596 | | | 229,360 | | 141,416 | |
| Regulatory liabilities | | | 49,808 | | 38,500 | |
| Accrued employee benefits | | | 164,799 | | 44,093 | |
| Other | | 129,462 | | 115,239 | | | 13,487 | | 29,021 | |
| | | | | | | | | | |
| Total other long-term liabilities | | 1,278,915 | | 1,124,338 | | | 457,454 | | 1,269,022 | |
| | | | | | | | | | |
| | | |
| Contingent liabilities and commitments (Note 3) | | |
| | | |
| Cumulative Redeemable Preferred Stock, without par value: | | |
| Authorized 10,000,000 shares: none issued or outstanding | | — | | — | | |
| Authorized 10,000,000 shares in 2007: none issued or outstanding. | | | - | | - | |
| | | | | | | | | | |
| Cumulative Redeemable Second Preferred Stock, without par value: | | |
| Authorized 2,000,000 shares: none issued or outstanding | | — | | — | | |
| Authorized 2,000,000 shares in 2007: none issued or outstanding | | | - | | - | |
| | | | | | | | | | |
| | | |
| Common Stockholder’s Equity: | | |
| Owner’s Equity: | | |
| Common Stock $1.00 par value: | | |
| 100 shares authorized, issued and outstanding | | — | | — | | |
| 100 shares authorized, issued and outstanding in 2007 | | | - | | - | |
| Premium on capital stock and other paid-in capital | | 1,652,430 | | 1,652,430 | | | - | | 1,652,430 | |
| Member’s capital | | | 1,652,430 | | - | |
| Retained earnings | | 914,851 | | 902,600 | | | 1,987,932 | | 926,964 | |
| Accumulated other comprehensive loss | | | (28,845 | ) | | | (408 | ) | | | (169,814 | ) | | | (14,965 | ) |
| | | | | | | | | | |
| Total common stockholder’s equity | | 2,538,436 | | 2,554,622 | | |
| Total owner’s equity | | | 3,470,548 | | 2,564,429 | |
| | | | | | | | | | |
| | |
| | | $ | 5,281,989 | | $ | 5,008,646 | | | $ | 5,519,716 | | $ | 5,452,503 | |
| | | | | | | | | | |
See accompanying notes.
3141
TRANSCONTINENTAL GAS PIPE LINE CORPORATIONCOMPANY, LLC
CONSOLIDATED STATEMENT OF COMMON STOCKHOLDER’SOWNER’S EQUITY
(Thousands of Dollars)
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | Years Ended December 31, |
| | | Years Ended December 31, | | | 2008 | | 2007 | | 2006 |
| | | 2006 | | 2005 | | 2004 | | | (Restated) | | (Restated) |
| Common Stock: | | |
| Balance at beginning and end of period | | $ | — | | $ | — | | $ | — | | | $ | - | | $ | - | | $ | - | |
| | | | | | | | | | | | | | |
| Premium on Capital Stock and Other Paid-in Capital: | | |
| Balance at beginning of period | | | 1,652,430 | | 1,652,430 | | 1,652,430 | |
| Conversion to LLC | | | | (1,652,430 | ) | | - | | - | |
| | | | | | | | |
| Premium on Capital Stock and Other Paid-in Capital: | | |
| Balance at beginning and end of period | | 1,652,430 | | 1,652,430 | | 1,652,430 | | |
| Balance at end of period | | | - | | 1,652,430 | | 1,652,430 | |
| | | | | | | | | | | | | | |
| Owner’s capital: | | |
| Balance at beginning of period | | | - | | - | | - | |
| Conversion to LLC | | | 1,652,430 | | - | | - | |
| | | | | | | | |
| Balance at end of period | | | 1,652,430 | | - | | - | |
| | | | | | | | |
| Retained Earnings: | | |
| Balance at beginning of period | | 902,600 | | 842,285 | | 787,831 | | | 926,964 | | 868,878 | | 863,541 | |
| Add (deduct): | | |
| Net income | | 117,251 | | 185,315 | | 179,454 | | | 1,280,968 | | 168,086 | | 110,337 | |
| Cash dividends on common stock | | | (105,000 | ) | | | (125,000 | ) | | | (125,000 | ) | |
| | | | | | | | | |
| Cash dividends and distributions | | | | (220,000 | ) | | | (110,000 | ) | | | (105,000 | ) |
| | | | | | | | |
| Balance at end of period | | 914,851 | | 902,600 | | 842,285 | | | 1,987,932 | | 926,964 | | 868,878 | |
| | | | | | | | | | | | | | |
| | | |
| Accumulated Other Comprehensive Income/(Loss): | | |
| Interest Rate Hedge: | | |
| Pension Benefits: | | |
| Balance at beginning of period | | | (408 | ) | | | (920 | ) | | | (1,144 | ) | | | (14,965 | ) | | | (28,596 | ) | | - | |
| Add (deduct): | | |
| Net gain/(loss) | | 159 | | 512 | | 224 | | |
| Prior service credit, net of taxes of $303 in 2008 and $633 in 2007 | | | | (489 | ) | | | (1,023 | ) | | - | |
| Net actuarial (loss)/gain, net of taxes of $55,381 in 2008 and $(9,076) in 2007 | | | | (89,407 | ) | | 14,654 | | - | |
| Adjustment to initially apply SFAS No. 158: | | |
| Prior service credit, net of taxes of $(917) in 2006 | | | - | | - | | 1,480 | |
| Net actuarial loss, net of taxes of $18,629 in 2006 | | | - | | - | | | (30,076 | ) |
| Elimination of deferred income taxes | | | | (64,953 | ) | | - | | - | |
| | | | | | | | | | | | | | |
| Balance at end of period | | | (249 | ) | | | (408 | ) | | | (920 | ) | | | (169,814 | ) | | | (14,965 | ) | | | (28,596 | ) |
| | | | | | | | | | | | | | |
| Pension Benefit Obligation: | | |
| Balance at beginning of period | | — | | — | | — | | |
| Add (deduct): | | |
| Adjustment to initially apply SFAS No. 158, net of tax | | | (28,596 | ) | | — | | — | | |
| Total Owner’s Equity | | | $ | 3,470,548 | | $ | 2,564,429 | | $ | 2,492,712 | |
| | | | | | | | | | | | | | |
| Balance at end of period | | | (28,596 | ) | | — | | — | | |
| | | | | | | | | |
| Balance at end of period | | | (28,845 | ) | | | (408 | ) | | | (920 | ) | |
| | | | | | | | | |
| Total Common Stockholder’s Equity | | $ | 2,538,436 | | $ | 2,554,622 | | $ | 2,493,795 | | |
| | | | | | | | | |
See accompanying notes.
3242
TRANSCONTINENTAL GAS PIPE LINE CORPORATIONCOMPANY, LLC
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
(Thousands of Dollars)
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | Years Ended December 31, |
| | | Years Ended December 31, | | | 2008 | | 2007 | | 2006 |
| | | 2006 | | 2005 | | 2004 | | | (Restated) | | (Restated) | |
| Net Income | | $ | 117,251 | | $ | 185,315 | | $ | 179,454 | | | $ | 1,280,968 | | $ | 168,086 | | $ | 110,337 | |
| | | |
| Equity interest in unrealized gain/(loss) on interest rate hedge, net of tax of $102 in 2006, $305 in 2005, $137 in 2004 | | 159 | | 512 | | 224 | | |
| Pension Benefits: | | |
| Amortization of prior service credit, net of taxes of $303 in 2008 and $633 in 2007 | | | | (489 | ) | | | (1,023 | ) | | - | |
| Amortization of net actuarial loss, net of taxes of $(1,060) in 2008 and $(1,490) in 2007 | | | 1,710 | | 2,407 | | - | |
| Net actuarial (loss)/gain arising during the period, net of taxes of $56,441 in 2008 and $(7,586) in 2007 | | | | (91,117 | ) | | 12,247 | | - | |
| Elimination of deferred income taxes | | | | (64,953 | ) | | - | | - | |
| | | | | | | | |
| | | | | | | | |
| Total Comprehensive Income | | $ | 117,410 | | $ | 185,827 | | $ | 179,678 | | | $ | 1,126,119 | | $ | 181,717 | | $ | 110,337 | |
| | | | | | | | | | | | | | |
See accompanying notes.
3343
TRANSCONTINENTAL GAS PIPE LINE CORPORATIONCOMPANY, LLC
CONSOLIDATED STATEMENT OF CASH FLOWS
(Thousands of Dollars)
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | Years Ended December 31, |
| | | Years Ended December 31, | | | 2008 | | 2007 | | 2006 |
| | | 2006 | | 2005 | | 2004 | | | (Restated) | | (Restated) | |
| Cash flows from operating activities: | | |
| Net income | | $ | 117,251 | | $ | 185,315 | | $ | 179,454 | | | $ | 1,280,968 | | $ | 168,086 | | $ | 110,337 | |
| Adjustments to reconcile net income to net cash Provided by operating activities: | | |
| Adjustments to reconcile net income to net cash provided by operating activities: | | |
| Depreciation and amortization | | 204,508 | | 198,361 | | 198,247 | | | 235,106 | | 226,755 | | 204,508 | |
| | |
| Deferred income taxes | | 73,259 | | | (916 | ) | | 31,814 | | | | (986,674 | ) | | | (16,468 | ) | | 72,398 | |
| | |
| (Gain)/loss on sale of property, plant and equipment | | | | (11,905 | ) | | 12 | | 201 | |
| | |
| Allowance for equity funds used during construction (Equity AFUDC) | | | (8,355 | ) | | | (6,455 | ) | | | (6,091 | ) | | | (4,374 | ) | | | (9,439 | ) | | | (8,355 | ) |
| Changes in operating assets and liabilities: | | |
| Receivables — affiliates | | | (3,440 | ) | | | (2,427 | ) | | 7,413 | | |
| — other | | 6,392 | | 17,193 | | 22,794 | | |
| | |
| Receivables – affiliates | | | 2,752 | | 1,537 | | | (2,963 | ) |
| | |
| – other | | | 29,713 | | | (29,713 | ) | | 5,421 | |
| | |
| Transportation and exchange gas receivable | | 2,831 | | | (4,096 | ) | | 16,946 | | | 75 | | | (3,649 | ) | | 2,831 | |
| | |
| Inventories | | 17,859 | | | (5,108 | ) | | 4,151 | | | | (32,771 | ) | | 9,701 | | 17,859 | |
| Payables — affiliates | | | (4,805 | ) | | | (10,839 | ) | | | (23,757 | ) | |
| — other | | 21,443 | | | (6,105 | ) | | | (26,022 | ) | |
| | |
| Payables – affiliates | | | 2,103 | | | (2,801 | ) | | | (3,582 | ) |
| | |
| – other | | | | (111,154 | ) | | | (1,769 | ) | | 22,598 | |
| | |
| Transportation and exchange gas payable | | | (34,964 | ) | | 25,037 | | 7,285 | | | | (4,394 | ) | | | (7,448 | ) | | | (34,964 | ) |
| Accrued liabilities | | | (41,414 | ) | | 22,793 | | 34,264 | | | | (56,109 | ) | | 70,472 | | | (40,785 | ) |
| Reserve for rate refunds | | | (1,531 | ) | | | (5,156 | ) | | | (1,691 | ) | | 60,902 | | 95,803 | | | (1,531 | ) |
| Other, net | | | (45,722 | ) | | | (18,854 | ) | | 14,954 | | | | (75,951 | ) | | 37,680 | | | (47,462 | ) |
| | | | | | | | | | | | | | |
| Net cash provided by operating activities | | 303,312 | | 388,743 | | 459,761 | | | 328,287 | | 538,759 | | 296,511 | |
| | | | | | | | | | | | | | |
| | | |
| Cash flows from financing activities: | | |
| Additions to long-term debt | | 200,000 | | — | | 75,000 | | | 424,332 | | - | | 200,000 | |
| Retirement of long-term debt | | — | | | (200,000 | ) | | — | | | | (350,000 | ) | | - | | - | |
| Debt issue costs | | | (3,202 | ) | | | (255 | ) | | | (356 | ) | | | (2,100 | ) | | | (10 | ) | | | (3,202 | ) |
| Common stock dividends paid | | | (105,000 | ) | | | (125,000 | ) | | | (125,000 | ) | |
| Cash dividends and distributions | | | | (220,000 | ) | | | (110,000 | ) | | | (105,000 | ) |
| Change in cash overdrafts | | 1,440 | | 7,869 | | | (1,341 | ) | | 2,056 | | | (17,658 | ) | | 1,440 | |
| | | | | | | | | | | | | | |
| Net cash provided by (used in) financing activities | | 93,238 | | | (317,386 | ) | | | (51,697 | ) | | | (145,712 | ) | | | (127,668 | ) | | 93,238 | |
| | | | | | | | | | | | | | |
(continued)
3444
TRANSCONTINENTAL GAS PIPE LINE CORPORATIONCOMPANY, LLC
CONSOLIDATED STATEMENT OF CASH FLOWS
(continued)
(Thousands of Dollars)
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | Years Ended December 31, |
| | | Years Ended December 31, | | | 2008 | | 2007 | | 2006 |
| | | 2006 | | 2005 | | 2004 | | | (Restated) | | (Restated) | |
| Cash flows from investing activities: | | |
| Property, plant and equipment: | | |
| Additions, net of equity AFUDC | | | (339,522 | ) | | | (256,362 | ) | | | (150,434 | ) | | | (203,575 | ) | | | (375,447 | ) | | | (342,843 | ) |
| Changes in accounts payable | | 9,659 | | 11,497 | | | (3,156 | ) | | 988 | | | (7,493 | ) | | 8,524 | |
| Changes in accrued liabilities | | | | (3,130 | ) | | 18,609 | | 3,321 | |
| Advances to affiliates, net | | | (60,092 | ) | | 172,458 | | | (252,818 | ) | | 27,666 | | | (34,212 | ) | | | (52,156 | ) |
| Advances to others, net | | 981 | | | (428 | ) | | | (2,313 | ) | | 270 | | 835 | | 981 | |
| Purchase of ARO trust investments | | | | (31,056 | ) | | - | | - | |
| Proceeds from sale of ARO trust investments | | | 14,143 | | - | | - | |
| Other, net | | | (7,623 | ) | | 1,664 | | 533 | | | 12,428 | | | (13,579 | ) | | | (7,623 | ) |
| | | | | | | | | | | | | | |
| Net cash used in investing activities | | | (396,597 | ) | | | (71,171 | ) | | | (408,188 | ) | |
| Net cash used in investing activities. | | | | (182,266 | ) | | | (411,287 | ) | | | (389,796 | ) |
| | | | | | | | | | | | | | |
| | |
| Net increase (decrease) in cash | | | (47 | ) | | 186 | | | (124 | ) | | 309 | | | (196 | ) | | | (47 | ) |
| Cash at beginning of period | | 362 | | 176 | | 300 | | | 119 | | 315 | | 362 | |
| | | | | | | | | | | | | | |
| Cash at end of period | | $ | 315 | | $ | 362 | | $ | 176 | | | $ | 428 | | $ | 119 | | $ | 315 | |
| | | | | | | | | | | | | | |
| | | |
| Supplemental disclosures of cash flow information: | | |
| Cash paid during the year for: | | |
| Interest (exclusive of amount capitalized) | | $ | 81,063 | | $ | 77,297 | | $ | 83,334 | | | $ | 99,073 | | $ | 86,105 | | $ | 80,736 | |
| Income taxes paid | | 39,913 | | 123,797 | | 51,346 | | | 77,980 | | 55,599 | | 36,792 | |
| Income tax refunds received | | — | | | (122 | ) | | | (46 | ) | | | (570 | ) | | | (177 | ) | | - | |
See accompanying notes.
3545
TRANSCONTINENTAL GAS PIPE LINE CORPORATIONCOMPANY, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Corporate structure and controlOn December 31, 2008, Transcontinental Gas Pipe Line Corporation was converted from a corporation to a limited liability company and thereafter is known as Transcontinental Gas Pipe Line Company, LLC (Transco). Transco is a wholly-owned subsidiary of Williams Gas Pipeline Company, LLC (WGP). WGP is a wholly-owned subsidiary of The Williams Companies, Inc. (Williams). Effective December 31, 2008, we distributed our ownership interest in our wholly-owned subsidiaries to WGP. Accordingly, we have adjusted financial and operating information retrospectively to remove the effects of our former subsidiaries.
In this report, Transco (which includes Transcontinental Gas Pipe Line Corporation and unless the context otherwise requires, all of our consolidated subsidiaries) is at times referred to in the first person as “we” “us” or “our.”
Nature of operationsWe 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 the states of Alabama, Georgia, South Carolina, North Carolina, Virginia, Maryland, Pennsylvania and New Jersey to the New York City metropolitan area. The system serves customers in Texas and the eleven11 southeast and Atlantic seaboard states mentioned above, including major metropolitan areas in Georgia, Washington D.C., North Carolina, New York, New Jersey and Pennsylvania. We also hold a minority interest in an intrastate natural gas pipeline in North Carolina.
Regulatory accountingWe are regulated by the Federal Energy Regulatory Commission (FERC). Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation,” 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 SFAS No. 71 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
3646
by SFAS No. 71 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 presentationWilliams’ 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, 2006,2008, the remaining property, plant and equipment allocation was approximately $1$0.9 billion. Current FERC policy does not permit us to recover through rates amounts in excess of original cost. At December 31, 2008, the effective date of the conversion of Transcontinental Gas Pipe Line Corporation to Transco, the remaining deferred taxes adjustment was transferred to WGP.
As a participant in Williams’ cash management program, we have advances to and from Williams. These advances are represented by demand notes. We currently expect to receive payment of these advances within the next twelve months and have recorded such advances as current in the accompanying Consolidated Balance Sheet. The interest rate on intercompany demand notes is based upon the weighted average cost of Williams’ debt outstanding at the end of each quarter. At December 31, 2006,2008, the interest rate was 7.81%.7.87 percent.
Through an agency agreement, Williams Power Company (WPC)Gas Marketing, Inc. (WGM), an affiliate of ours, manages all jurisdictional merchant gas sales for us, receives all margins associated with such business and, as our agent, assumes all market and credit risk associated with our jurisdictional merchant gas sales. Consequently, our merchant gas sales have no impact on our operating income or results of operations.
Our Board of Directors declared and we paid cash dividends on common stock in the amounts of $165 million, $110 million and $105 million $125for the first three quarters of 2008, full year of 2007 and full year of 2006, respectively. For the fourth quarter of 2008 we distributed $55 million and $125 million for 2006, 2005 and 2004, respectively.
Principles of consolidationThe consolidated financial statements include our accounts and the accounts of our majority-owned subsidiaries. Companies in which we and our subsidiaries own 20 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 investments as of December 31, 2006 and 2005 primarily consist of Cardinal Pipeline Company, LLC with ownership interest of approximately 45% and Pine Needle LNG Company, LLC (Pine Needle) with ownership interest of 35%. We received distributions associated with our equity investments in the amounts of $7.0 million, $7.5 million and $7.5 million in 2006, 2005 and 2004, respectively.WGP.
Use of estimatesThe preparation of financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the amounts reported in the 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) deferred and other income taxes; 6) depreciation; 7) pensions and other post-employment benefits; and 8) asset retirement obligations.
Revenue recognitionRevenues for transportation of gas under long-term firm agreements are recognized considering separately the demand and commodity charges. Demand revenues are recognized monthly over the term of the agreement regardless of the volume of natural gas transported. Commodity revenues from both firm and interruptible transportation are recognized in the period transportation services are provided based on volumes of natural gas physically delivered at the agreed upon delivery point. Revenues for the storage of gas under firm agreements are recognized considering separately the demand, capacity, and injection and withdrawal changes. Demand and capacity revenues are recognized monthly over the term of the
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Revenue recognitionRevenues for salesagreement regardless of productsthe volume of storage service actually utilized. Injection and withdrawal revenues are recognized in the period when volumes of deliverynatural 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 revenuessale 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 storage of gas are recognizedexchange imbalances (See Gas imbalances in the period the service is provided based on contractual terms and the related volumes.this Note).
As a result of the of the ratemaking process, certain revenues collected by us may be subject to possible refunds upon final orders in pending rate proceedingsproceeding with the FERC. We record estimates of rate refund liabilities considering our and other third partythird-party regulatory proceedings, advice of counsel and estimated total exposure, as discounted and risk weighted, as well as collection and other risks.
Contingent liabilitiesWe record liabilities for estimated loss contingencies when we assess that a loss is probable and the amount of the loss can be reasonably estimated. Revisions to contingent liabilities are reflected in income in the period in which new or different facts or information become known or circumstances change that affect the previous assumptions with respect to the likelihood or amount of loss. Liabilities for contingent losses are based upon our assumptions and estimates, and advice of legal counsel or other third parties regarding the probable outcomes of the matter. As new developments occur or more information becomes available, our assumptions and estimates of these liabilities may change. Changes in our assumptions and estimates or outcomes different from our current assumptions and estimates could materially affect future results of operations for any particular quarterly or annual period.
Environmental MattersWe are subject to federal, state, and local environmental laws and regulations. Environmental expenditures are expensed or capitalized depending on their economic benefit and potential for rate recovery. We believe that any expenditures required to meet applicable environmental laws and regulations are prudently incurred in the ordinary course of business and that substantially all of such expenditures would be permitted to be recovered through rates. We believe that compliance with applicable environmental requirements is not likely to have a material effect upon our financial position or results of operations.
Property, plant and equipmentProperty, plant and equipment is recorded at cost. The carrying values of these assets are also based on estimates, assumptions and judgments relative to capitalized costs, useful lives and salvage values. These estimates, assumptions and judgments reflect FERC regulations, as well as historical experience and expectations regarding future industry conditions and operations. Gains or losses from the ordinary sale or retirement of property, plant and equipment are credited or charged to accumulated depreciation; certain other gains or losses are recorded in operating income.
We provide for depreciation using the straight-line method at FERC prescribed rates, including negative salvage (cost of removal) for offshore 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 (cost of removal) component that we currently collect in rates. Depreciation rates used for major regulated gas plant facilities at December 31, 2006, 2005,2008, 2007 and 20042006 are as follows:
| | | | | | | | | | | | | |
| Category of Property | | 2008 | | 2007 (1) | | 2006 |
| | | | | | | | | | | | | |
| Gathering facilities | | | 0.01%-0.91 | % | | | 0.01%-0.91 | % | | | 0%-3.80 | % |
| Storage facilities | | | 0.40%-3.30 | % | | | 0.40%-3.30 | % | | | 2.50 | % |
| Onshore transmission facilities | | | 0.69%-5.00 | % | | | 0.69%-5.00 | % | | | 2.35 | % |
| Offshore transmission facilities | | | 0.01%-1.00 | % | | | 0.01%-1.00 | % | | | 0.85%-1.50 | % |
| | (1) | | | |
Category of Property | | Depreciation Rates |
Gathering facilities | | | 0%-3.80 | % |
Storage facilities | | | 2.50 | % |
Onshore transmission facilities | | | 2.35 | % |
Offshore transmission facilities | | | 0.85%-1.50 | %Changes in depreciation rates in 2007 due to placing into effect, subject to refund, the rates in Docket No. RP06-569 on March 1, 2007. |
We record an asset and a liability equal to the present value of each expected future asset retirement obligation (ARO). The ARO asset is depreciated in a manner consistent with the depreciation of the
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underlying physical asset. We measure changes in the liability due to passage of time by applying an interest method of allocation. The depreciation of the ARO asset and accretion of the ARO liability are recognized as an increase to a regulatory asset.asset, as management expects to recover such amounts in future rates. The regulatory asset will beis amortized commensurate with our collection of those costs in rates.
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Impairment of long-lived assets and investmentsWe evaluate the long-lived assets of identifiable business activities for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable. When an indicator of impairment has occurred, we compare our management’s estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has occurred. We apply a probability-weighted approach to consider the likelihood of different cash flow assumptions and possible outcomes including selling in the near term or holding for the remaining estimated useful life. If an impairment of the carrying value has occurred, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value.
For assets identified to be disposed of in the future and considered held for sale in accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” we compare the carrying value to the estimated fair value less the cost to sell to determine if recognition of an impairment is required. Until the assets are disposed of, the estimated fair value, which includes estimated cash flows from operations until the assumed date of sale, is recalculated when related events or circumstances change. We had no impairments atduring the years ended December 31, 20062008, 2007 and 2005.
We evaluate our equity method investments for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such investments may have experienced an other-than-temporary decline in value. When evidence of loss in value has occurred, we compare our estimate of fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred. If the estimated fair value is less than the carrying value and we consider the decline in value to be other than temporary, the excess of the carrying value over the fair value is recognized in the financial statements as an impairment.2006.
Judgments and assumptions are inherent in our management’s estimate of undiscounted future cash flows used to determine recoverability of an asset and the estimate of an asset’s fair value used to calculate the amount of impairment to recognize. The use of alternate judgments and/or assumptions could result in the recognition of different levels of impairment charges in the financial statements.
Accounting for repair and maintenance costsWe account for repair and maintenance costs under the guidance of FERC regulations. The FERC identifies installation, construction and replacement costs that are to be capitalized. All other costs are expensed as incurred.
Allowance for funds used during constructionAllowance 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 $2.0 million, $3.5 million and $2.8 million, $2.8 millionfor 2008, 2007 and $2.2 million, for 2006, 2005 and 2004, respectively. The allowance for equity funds was $ 8.3$4.4 million, $6.5$9.4 million, and $6.1$8.3 million, for 2008, 2007 and 2006, 2005 and 2004, respectively.
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Accounting for income taxesWilliams and its wholly-owned subsidiaries, which includes us, file a consolidated federal income tax return. It is Williams’ policy to charge or credit usits taxable subsidiaries with an amount equivalent to ourtheir federal income tax expense or benefit computed as if weeach subsidiary had filed a separate return.
We use the assets and liability method of accounting for income taxes, as required by SFAS 109, “Accounting for Income Taxes”, which requires, among other things, provisions for all temporary differences between the financial basis and the tax basis in our assets and liabilities and adjustments to the existing deferred tax balances for changes in tax rates. Following our conversion from a corporation to a limited liability company on December 31, 2008, we are no longer subject to income tax. (See Note 7 of Notes to the Financial Statements.)
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Accounts receivable and allowance for doubtful receivablesAccounts 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 customer’scustomers’ 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. At December 31, 2006 and 2005, we had recorded reserves of $0.5 million and $0.5 million, respectively, for uncollectible accounts.
Gas imbalancesIn the course of providing transportation services to customers, we may receive different quantities of gas from shippers than the quantities delivered on behalf of those shippers. Additionally, we transport gas on various pipeline systems which may deliver different quantities of gas on behalf of us than the quantities of gas received from us. These transactions result in gas transportation and exchange imbalance receivables and payables which are recovered or repaid in cash or through the receipt or delivery of gas in the future and are recorded in the accompanying Consolidated Balance Sheet. Settlement of imbalances requires agreement between the pipelines and shippers as to allocations of volumes to specific transportation contracts and timing of delivery of gas based on operational conditions. Our tariff includes a method whereby most transportation imbalances are settled on a monthly basis. Each month a portion of the imbalances are not identified to specific parties and remain unsettled. These are generally identified to specific parties and settled in subsequent periods. We believe that amounts that remain unidentified to specific parties and unsettled at year end are valid balances that will be settled with no material adverse effect upon our financial position, results of operations or cash flows. Management has implemented a policy of continuing to carry any unidentified transportation and exchange imbalances on the books for a three-year period. At the end of the three year period a final assessment will be made of their continued validity. Absent a valid reason for maintaining the imbalance, any remaining balance will be recognized in income. Certain imbalances are being recovered or repaid in cash or through the receipt or delivery of gas upon agreement of the parties as to the allocation of the gas volumes, and as permitted by pipeline operating conditions. These imbalances have been classified as current assets and current liabilities at December 31, 20062008 and 2005.2007. We utilize the average cost method of accounting for gas imbalances.
Deferred cash outMost 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 requirement.tariff.
Gas inventoryWe utilize the last-in, first-out (LIFO) method of accounting for inventory gas in storage. The excess of current cost overIf inventories valued using the LIFO value oncost method were valued at current replacement cost, the Consolidated Balance Sheet datedamounts would decrease by $0.5 million at December 31, 2006 is approximately $22.1 million.2008 and increase minimally at December 31, 2007. The basis for determining current cost at the end of each year is the December 2006 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.
In 2007, Transco requested authorization from the FERC to sell our excess Eminence top gas inventory and retain any gain on the sales. The FERC authorized the top gas sales, but consolidated the issue of Transco’s request to retain the gain on the sales with Transco’s general rate case. One of the provisions of the Agreement in the Docket No. RP06-569 rate case (See Note 3 of Notes to the Financial Statements) requires that Transco share 50 percent of the gain with its customers. During 2007, approximately $59.2 million of excess top gas was sold and is reflected in operating revenues on our Statement of Income. The entire gain on the sales of the excess top gas, which was $19.0 million, was deferred in 2007 pending final approval of the
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Agreement. Upon approval of the Agreement, the deferred gain was recognized in the second quarter of 2008.
Reserve for Inventory ObsolescenceWe perform an annual review of Materials and Supplies
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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, 20062008 and $0.7 million at December 31, 2005.2007.
Cash flows from operating activities and cash equivalentsWe 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 aan original maturity of three months or less as cash equivalents.
Recent accounting standardsAccounting StandardsIn JuneSeptember 2006, the Financial Accounting Standards Board (FASB) issued FASB InterpretationSFAS No. 48, “Accounting157, “Fair Value Measurements” (SFAS No. 157). This Statement establishes a framework for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109” (FIN 48). The Interpretation clarifies the accounting for uncertainty in income taxes under FASB Statement No. 109, “Accounting for Income Taxes.” The Interpretation prescribes guidance for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. To recognize a tax position, the enterprise determines whether it is more likely than not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. A tax position that meets the more likely than not recognition threshold is measured to determine the amount of benefit to recognizefair value measurements in the financial statements. The tax position is measured atstatements by providing a definition of fair value, provides guidance on the largest amount of benefit, determined on a cumulative basis, that is greater than 50 percent likely of being realized upon ultimate settlement.
FIN 48methods used to estimate fair value and expands disclosures about fair value measurements. SFAS No. 157 is effective for fiscal years beginning after DecemberNovember 15, 2006. The cumulative effect2007. In February 2008, the FASB issued FASB Staff Position (FSP) No. FAS 157-2, permitting entities to delay application of applying the Interpretation must be reported as an adjustmentSFAS 157 to the opening balance of retained earningsfiscal years beginning after November 15, 2008, for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the year of adoption. We adopted the Interpretation beginningfinancial statements on a recurring basis (at least annually). On January 1, 2007, as required. We expect2008, we applied SFAS 157 to our assets and liabilities that are measured at fair value on a recurring basis with no material impact of the cumulative effect of adopting FIN 48 onto our Consolidated Financial Statements.
FERC Accounting GuidanceOn June 30, 2005, the FERC issued an order, “Accounting for Pipeline Assessment Costs,” to be applied prospectively effective Beginning January 1, 2006. The order requires companies2009, we will apply SFAS 157 fair value requirements to expense certain pipeline integrity-related assessment costsnonfinancial assets and nonfinancial liabilities that are not recognized or disclosed on a recurring basis. Application will be prospective when nonrecurring fair value measurements are required. (See Note 5 of Notes to the Financial Statements). Had we have historically capitalized. During 2006, the applicationnot elected to defer portions of this order resultedSFAS 157, fair value measurements for nonfinancial items occurring in $8 million of such costs being expensed. We anticipate expensing approximately $5 million to $10 million in 2007 that previously2008 where SFAS No. 157 would have been capitalized.
ReclassificationCertain reclassifications have been made inapplied include long-lived assets measured at fair value for impairment purposes and the 2005 balance sheet to conform to the 2006 presentation.initial measurement at fair value of asset retirement obligations.
2. RATECHANGE IN REPORTING ENTITIES
On December 31, 2008 Transco distributed its ownership interest in the following companies to WGP: Marsh Resources, LLC; TransCarolina LNG Company, LLC (TransCarolina); Pine Needle Operating Company, LLC; TransCardinal Company LLC (TransCardinal) and Cardinal Operating Company, LLC. TransCarolina owns a 35 percent interest in Pine Needle LNG Company, LLC an LNG storage Facility. TransCardinal owns a 45 percent interest in Cardinal Pipeline Company, LLC, a North Carolina intrastate natural gas pipeline company. These assets were transferred at historical cost, as the entities are under common control. No gains or losses were recorded as a result of the distribution.
SFAS No. 154, Accounting Changes and Error Corrections, requires that when a change in the reporting entity occurs, the change shall be retrospectively applied to the financial statements of all prior periods to show financial information for the new reporting entity.
The impact of these retrospective adjustments to our net income for the years 2007 and 2006 was a decrease of $4.5 million and $6.9 million, respectively.
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The impact of these retrospective adjustments to our comprehensive income for the years 2007 and 2006 was a decrease of $4.3 million and $7.1 million, respectively.
3. CONTINGENT LIABILITIES AND REGULATORY MATTERSCOMMITMENTS
Rate Matters
On March 1, 2001, we submitted to the FERC a general rate filing (Docket No. RP01-245) to recover increased costs. All cost of service, throughput and throughput mix, cost allocation and rate design issues in this rate proceeding have been resolved by settlement or litigation. The resulting rates becamewere effective onfrom September 1, 2001. Certain cost allocation, rate design and2001 to March 1, 2007. A tariff mattersmatter in this proceeding havehas not yet been resolved. We believe the resolution of these matters will not have a materially adverse effect upon our future financial position.
On August 31, 2006, we submitted to the FERC a general rate filing (Docket No. RP06-569) principally designed to recover costs associated with (a) an increase in operation and maintenance expenses and administrative and general expenses; (b) an increase in depreciation expense; (c) the inclusion of costs for asset retirement obligations; (d) an increase in rate base resulting from additional plant; and (e) an increase in
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rate of return and related taxes. The filing reflected an increase in annual revenues from jurisdictional service of approximately $281 million over the cost of service underlying the rates reflected in the settlement of our Docket No. RP01-245 rate proceeding, as adjusted to include the cost of service and rate base amounts for expansion projects placed in service after the September 1, 2001 effective date of the Docket No. RP01-245 rates. The filing also reflected changes to our tariff, cost allocation and rate design methods, including the refunctionalization of certain facilities from transmission plant accounts to jurisdictional gathering plant accounts consistent with various FERC orders (including the facilities addressed in the FERC’s various spin-down orders discussed below). On September 29, 2006, the FERC issued an order accepting and suspending our August 31, 2006 general rate filing to bebecame effective March 1, 2007, subject to refund and the outcome of a hearing.
Over the past several years, On November 28, 2007, we filed applications with the FERC seeking authorizationa Stipulation and Agreement (Agreement) resolving all but one issue in the rate case. On March 7, 2008, the FERC issued an order approving the Agreement without modifications. Pursuant to abandon certain facilities located onshoreits terms, the Agreement became effective on June 1, 2008, and offshore in Texas, Louisiana and Mississippi by conveyancerefunds of approximately $144 million were issued on July 17, 2008. We had previously provided a reserve for the refunds.
The one issue reserved for litigation or further settlement relates to an affiliate, Williams Gas Processing — Gulf Coast Company. The net book value of these facilities at December 31, 2006, was approximately $277 million. Becauseour proposal to change the design of the various challengesrates for service under one of our storage rate schedules, which was implemented subject to our applicationsrefund on March 1, 2007. A hearing on that issue was held before a FERC Administrative Law Judge (ALJ) in July 2008. In November 2008, the ALJ issued an initial decision in which he determined that Transco’s proposed incremental rate design is unjust and outstanding regulatory issues affectingunreasonable. The ALJ’s decision is subject to review by the transfer of these facilities, to date we have transferred only a small offshore system with a net book value of $3.3 million, and we have no immediate plans to transfer the remaining facilities. Therefore, these facilities are not considered assets held for sale.
3. CONTINGENT LIABILITIES AND COMMITMENTSFERC.
Legal Proceedings.Proceedings
By order dated March 17, 2003, the FERC approved a settlement between the FERC staff and Williams, WPC and us which resolved certain FERC staff’s allegations. As part of the settlement, WPC agreed, subject to certain exceptions, that it will not enter into new transportation agreements that would increase the transportation capacity it holds on certain affiliated interstate gas pipelines, including Transco. We also agreed to pay a civil penalty in five equal installments totaling $20 million, and the final $4 million installment will be paid in 2007.
A producer had asserted a claim for damages against us for indemnification relating to prior royalty payments. The Louisiana Court of Appeals denied the producer’s appeal and affirmed a lower court’s judgment in our favor. On March 31, 2006, the Louisiana Supreme Court denied the producer’s request for further review. Consequently, we reversed in the first quarter of 2006 a related liability which resulted in an increase to pre-tax income of approximately $7.0 million.
In 1998, the United States Department of Justice (DOJ) informed Williams that Jack Grynberg, an individual, had filed claims on behalf of himself and the federal government, in the United States District Court for the District of Colorado under the False Claims Act against Williams and certain of its wholly-owned subsidiaries including us. Mr.The claim sought an unspecified amount of royalties allegedly not paid to the federal government, treble damages, a civil penalty, attorneys’ fees, and costs. Grynberg had also filed claims against approximately 300 other energy companies and alleged that the defendants violated the False Claims Act in connection with the measurement, royalty valuation and purchase of hydrocarbons. The relief sought was an unspecified amount of royalties allegedly not paid to the federal government, treble damages, a civil penalty, attorneys’ fees, and costs. In April 1999, the DOJ declined toannounced that it would not intervene in any of the Grynberg qui tam cases, andcases. Also in October 1999, the Panel on Multi-District Litigation transferred all of the Grynberg qui tamthese cases, including those filed against Williams,us, to the United States District Court for the District offederal court in Wyoming for pre-trial purposes. In October 2002, the court granted a motion to dismiss Grynberg’s
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royalty valuation claims. Grynberg’s measurement claims remained pending against Williams, including us, and the other defendants, although the defendants have filed a number of motions to dismiss these claims on jurisdictional grounds. In May 2005, the court-appointed special master entered a report which recommended that many of the cases be dismissed, including the case pending against certain of the Williams defendants, including us. On October 20, 2006, theThe District Court dismissed all claims against Williams and its wholly-owned subsidiaries, including us. Mr. Grynberg filed a Notice of Appeal from the dismissalsThe matter is on appeal with the Tenth Circuit Court of Appeals effective November 17, 2006.
We were named as a defendant in two class action petitions for damages filed in the United States District Court for the Eastern District of Louisiana in September and October 2005 arising from hurricanes that struck Louisiana in 2005. The class plaintiffs, purporting to represent persons, businesses and entities in the State of Louisiana who suffered damage as a result of the winds and storm surge from the hurricanes, alleged that the operating activities of the two sub-classes of defendants, which included all oil and gas pipelines that dredged pipeline canals or installed pipelines in the marshes of south Louisiana (including us) and all oil and gas exploration and production companies which drilled for oil and gas or dredged canals in the marshes of south Louisiana, altered marshland ecology and caused marshland destruction which otherwise would have averted all or almost all of the destruction and loss of life caused by the hurricanes. Plaintiffs requested that the court allow the lawsuits to proceed as class actions and sought legal and equitable relief in an unspecified amount. On September 28, 2006, the court granted the defendants’ joint motion and dismissed the class action petitions against all defendants, including Transco. On November 20, 2006, in an additional class action filed in August 2006 containing substantially identical allegations against the same defendants, including Transco, the court similarly granted the defendants’ joint motion and dismissed the additional class action.Appeals.
Environmental Matters
We are subject to extensive federal, state and local environmental laws and regulations which affect our operations related to the construction and operation of pipeline facilities. Appropriate governmental authorities enforce these laws and regulations with a variety of civil and criminal enforcement measures, including monetary penalties, assessment and remediation requirements and injunctions as to future compliance. Our use and disposal of hazardous materials are subject to the requirements of the federal Toxic Substances Control Act (TSCA), the federal Resource Conservation and Recovery Act (RCRA) and comparable state statutes. The Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), also known as “Superfund,” imposes liability, without regard to fault or the legality of the original act, for release of a “hazardous substance” into the environment. Because these laws and regulations change from time to time, practices that have been acceptable to the industry and to the regulators have to be changed and assessment and monitoring have to be undertaken to determine whether those practices have damaged the environment and whether remediation is required. Since 1989, we have had studies underway to test some of our facilities for the presence of toxic and hazardous substances to determine to what extent, if any, remediation may be necessary. We have responded
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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 TSCA, RCRA, CERCLAvarious federal and comparable state statutes will total approximately $11$8 million to $13$10 million (including both expense and capital expenditures), measured on an undiscounted basis, and will be spent over the next threefour to fivesix years. This estimate depends upon 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, 2006,2008, we had a balance of approximately $4.7 million for the expense portion of these estimated costs recorded in current liabilities ($0.9 million) and other long-term liabilities ($3.8 million) in the accompanying Balance Sheet. At December 31, 2007, we had a balance of approximately $5.7 million for the expense portion of these estimated costs recorded in current liabilities ($1.20.9 million) and other long-term liabilities ($4.54.8 million) in the accompanying Consolidated Balance Sheet.
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We consider prudently incurred environmental assessment and remediation costs and costs associated with compliance with environmental standards to be recoverable through rates. To date, we have been permitted recovery of environmental costs, and it is our intent to continue seeking recovery of such costs, through future rate filings. Therefore, these estimated costs of environmental assessment and remediation, less amounts collected, have also been recorded as regulatory assets in Current Assets: OtherAssets and Other Assets, if any, in the accompanying Consolidated Balance Sheet. At December 31, 2008 and 2007, we had recorded approximately $1.8 million and $4.0 million, respectively, of environmental related regulatory assets.
We have used lubricating oils containing polychlorinated biphenyls (PCBs) and, although the use of such oils was discontinued 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 programsparties concerning investigative and remedial actions relative to potential mercury contamination at certain gas metering sites. All such costs are included in the $11$8 million to $13$10 million range discussed above.
We have been identified as a potentially responsible party (PRP) at various Superfund and state waste disposal sites. Based on present volumetric estimates and other factors, our estimated aggregate exposure for remediation of these sites is less than $500,000.$0.5 million. The estimated remediation costs for all of these sites have been included in the environmental reserve discussed above. Liability under CERCLAThe Comprehensive Environmental Response, Compensation and Liability Act (and applicable state law) can be joint and several with other PRPs. Although volumetric allocation is a factor in assessing liability, it is not necessarily determinative; thus, the ultimate liability could be substantially greater than the amounts described above.
We are also subject to the federal Clean Air Act and to the federal Clean Air Act Amendments of 1990 (1990 Amendments), which added significantly to the existing requirements established by the federal Clean Air Act. The 1990 Amendments required that the EPA issue new regulations, mainly related to stationary sources, air toxics, ozone non-attainment areas and acid rain. During the last few years we have been installing new emission control devices required for new or modified facilities in areas designated as non-attainment by EPA. We operate some of our facilities in areas of the country designated as non-attainment with the one-hour ozone standard. In April 2004, EPA designated eight-hour ozone non-attainment areas. We also operate facilities in areas of the country now designated as non-attainment with the eight-hour ozone standard. Pursuant to non-attainment area requirements of the 1990 Amendments, and EPA rules designed to mitigate the migration of ground-level ozone (NOx), we are planning installation of air pollution controls on existing sources at certain facilities in order to reduce NOx emissions. We anticipate that additional facilities may be subject to increased controls within five years. For many of these facilities, we are developing more cost effective and innovative compressor engine control designs. Due to the developing nature of federal and state emission regulations, it is not possible to precisely determine the ultimate emission control costs. However, the emission control additions required to comply with current federal Clean Air Act requirements, the 1990 Amendments, the hazardous air pollutant regulations, and the individual state implementation plans for NOx
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reductions are estimated to include costs in the range of $35$5 million to $40$10 million subsequent to 2006,for the period 2009 through 2010. EPA’s designation2012. In March 2008, the EPA promulgated a new, lower National Ambient Air Quality Standard for ground-level ozone. Within three years, the EPA will designate new eight-hour ozone non-attainment areas. Designation of new eight-hour ozone non-attainment areas will result in newadditional federal and state regulatory actionactions that maywill likely impact our operations. As a result,operations and increase the cost of additions to property, plant and equipment is expected to increase.equipment. We are unable at this time to estimate with any certainty the cost of additions that may be required to meet new regulations, although it is believed that some of those costs are included in the ranges discussed above. Management considers costs associated with compliance with the environmental laws and regulations described above to be prudent costs incurred in the ordinary course of business and, therefore, recoverable through our rates.
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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 EPA’s investigation of our compliance with the 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 and offered to hold a conference in May 2008 to discuss the NOVs. We met with the EPA in May 2008 to discuss the allegations contained in the NOVs and in June 2008 we submitted to the EPA a written response denying the allegations.
Safety Matters
Pipeline Integrity RegulationsWe have developed an Integrity Management Plan that meets the United States Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA) final rule pursuant to the requirements of the Pipeline Safety Improvement Act of 2002. In meeting the Integrity Regulations,integrity regulations, we have identified the high consequence areas including aand completed our baseline assessment and periodic reassessmentsplan. We are on schedule to be completedcomplete the required assessments within specified timeframes. Currently, we estimate that the cost to perform required assessments and remediation will be between $325$200 million and $375$250 million over the remaining assessment period of 20072009 through 2012. As a result of the June 30, 2005 FERC order described in Note 1, a portion of this amount will be expensed. Management considers the costs associated with compliance with the rule to be prudent costs incurred in the ordinary course of business and, therefore, recoverable through our rates.
Appomattox, Virginia Pipeline RuptureOn September 14, 2008, we experienced a rupture of our 30-inch diameter mainline B pipeline near Appomattox, Virginia. The rupture resulted in an explosion and fire which caused several minor injuries and property damage to several nearby residences. On September 25, 2008, PHMSA issued a Corrective Action Order (CAO) which requires that we operate three of our mainlines in a portion of Virginia at reduced operating pressure and prescribes various remedial actions that must be undertaken before the lines can be restored to normal operating pressure. On October 6, 2008, we filed a request for hearing with PHMSA to challenge the CAO but asked that the hearing be stayed pending discussions with PHMSA to modify certain aspects of the order. On November 7, 2008, PHMSA approved our request to restore the first of the three affected pipelines to normal operating pressure. On November 24, 2008, PHMSA agreed to extend the time for scheduling the hearing on the CAO until March 6, 2009. On December 24, 2008, PHMSA approved our request to restore the second of the three affected pipelines to normal operating pressure.
Other Matters
In addition to the foregoing, various other proceedings are pending against us incidental to our operations.
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Summary
Litigation, arbitration, regulatory matters, environmental matters and safety matters are subject to inherent uncertainties. Were an unfavorable ruling to occur, there exists the possibility of a material adverse impact on the results of operations in the period in which the ruling occurs. Management, including internalcounsel, currently believes that the ultimate resolution of the foregoing matters, taken as a whole and after consideration of amounts accrued, insurance coverage, recovery from customers or other indemnification arrangements, will not have a materiallymaterial adverse effect upon our future financial position.
Other Commitments
Commitments for construction and gas purchasesWe have commitments for construction and acquisition of property, plant and equipment of approximately $149$117 million at December 31, 2006.2008, most of which is expected to be spent in 2009. We have commitments for gas purchases of approximately $196$87 million at December 31, 2006.2008, which is expected to be spent over the next ten years. See Note 1 of Notes to Financial Statements for our discussion of our agency agreement with WGM.
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4. DEBT, FINANCING ARRANGEMENTS AND LEASES
Long-term debtAt December 31, 20062008 and 2005,2007, long-term debt issues were outstanding as follows (in thousands):
| | | | | | | | | | | | | | | | | |
| | | 2006 | | 2005 | | | 2008 | | 2007 |
| Debentures: | | |
| 7.08% due 2026 | | $ | 7,500 | | $ | 7,500 | | | $ | 7,500 | | | $ | 7,500 | |
| 7.25% due 2026 | | 200,000 | | 200,000 | | | 200,000 | | 200,000 | |
| | | | | | | | | | |
| Total debentures | | 207,500 | | 207,500 | | | 207,500 | | 207,500 | |
| | | | | | | | | | |
| Notes: | | |
| 6-1/4% due 2008 | | 100,000 | | 100,000 | | |
| 6.25% due 2008 | | | - | | 100,000 | |
| Floating Rate due 2008 | | 75,000 | | 75,000 | | | - | | 75,000 | |
| 7% due 2011 | | 300,000 | | 300,000 | | | 300,000 | | 300,000 | |
| 8.875% due 2012 | | 325,000 | | 325,000 | | | 325,000 | | 325,000 | |
| 6.4% due 2016 | | 200,000 | | — | | | 200,000 | | 200,000 | |
| 6.05% due 2018 | | | 250,000 | | - | |
| | | | | | | | | | |
| Total notes | | 1,000,000 | | 800,000 | | | 1,075,000 | | 1,000,000 | |
| | | | | | | | | | |
| Total long-term debt issues | | 1,207,500 | | 1,007,500 | | | 1,282,500 | | 1,207,500 | |
| Unamortized debt premium and discount | | | (6,042 | ) | | | (6,877 | ) | | | (4,821 | ) | | | (5,130 | ) |
| Current maturities | | — | | — | | | - | | | (75,000 | ) |
| | | | | | | | | | |
| | | |
| Total long-term debt, less current maturities | | $ | 1,201,458 | | $ | 1,000,623 | | | $ | 1,277,679 | | $ | 1,127,370 | |
| | | | | | | | | | |
Aggregate minimum maturities (face value) applicable to long-term debt outstanding at December 31, 20062008 are as follows (in thousands):
| | | | | |
| 2008: | | | | |
| 6-1/4% Note | | $ | 100,000 | |
| Floating Rate Note | | $ | 75,000 | |
| | | | |
| | | $ | 175,000 | |
| | | | |
| | | | | |
| 2011: | | | | |
| 7% Note | | $ | 300,000 | |
| | | | |
| 2011: | | | | |
| | | | |
| 7% Notes | | $ | 300,000 | |
| | | | |
| 2012: | | | | |
| | | | |
| 8.875% Notes | | $ | 325,000 | |
There are no maturities applicable to long-term debt outstanding for the years 2007, 2009, 2010 and 2010.2013.
No property is pledged as collateral under any of our long-term debt issues.
Revolving Credit and Letter of Credit FacilitiesFacility
In May 2006, Williams obtainedhas an unsecured, three-year, $1.5 billion revolving credit facility replacing the $1.275 billion secured revolving credit facility. The new unsecured facility contains similar terms and financial covenants as the secured facility, but contains additional restrictions on asset sales, certain subsidiary debt and sale-leaseback transactions. The facility is guaranteed by WGP, and Williams guarantees obligations(Credit Facility) with a maturity date of Williams Partners L.P. for up to $75 million.May 1, 2012. We have access to $400 million under the facilityCredit Facility to the extent not otherwise utilized by Williams. Lehman Commercial Paper Inc., which is committed to fund up to $70 million of the Credit Facility, has filed for bankruptcy. Williams expects that its ability to borrow under this facility is reduced by this committed amount. Consequently, we expect our ability to borrow under the Credit Facility is reduced by approximately $18.7 million. The committed amounts of other participating banks under this agreement remain in effect and are not impacted by the above. As of December 31, 2008, letters of credit totaling $71 million, none of which are associated with us, have been issued by the participating institutions. There were no revolving credit loans outstanding as of December 31, 2008.
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Interest is calculated based on a choice of two methods: a fluctuating rate equal to the lender’s base rate plus an applicable margin or a periodic fixed rate equal to the
46
London Interbank Offered Rate (LIBOR) plus an applicable margin. Williams is required to pay a commitment fee (currently 0.25% annually)0.125 percent) based on the unused portion of the facility.Credit Facility. The margins and commitment fee are generally based on the specific borrower’s senior unsecured long-term debt ratings. Letters
The Credit Facility contains certain affirmative covenants and a number of credit totaling approximately $29 million, nonerestrictions on the business of which are associated with us, have been issued by the participating institutionsborrowers, including us. These restrictions include restrictions on the borrowers’ ability to grant liens securing indebtedness, merge or sell all or substantially all of our assets and no revolving credit loans were outstanding at December 31, 2006. Transco did not access this facility during 2006.incurrence of indebtedness. Significant financial covenants under the credit agreementCredit Facility include the following:
| | • | | Williams’ ratio of debt to capitalization must be no greater than 65 percent. At December 31, 2008, Williams was in compliance with this covenant. |
| |
| | • | | Our ratio of debt to capitalization must be no greater than 55 percent. At December 31, 2006,2008, we are in compliance with this covenant as our ratio of debt to capitalization, as calculated under this covenant is approximately 32 percent. |
|
| • | | Williams’ ratio of EBITDA to interest, on a rolling four quarter basis, must be no less than 2.5 for the period ending December 31, 2007 and 3.0 for the remaining term of the agreement.covenant. |
The Credit Facility also contains events of default tied to all borrowers which in certain circumstances would cause all lending under the Credit Facility to terminate and all indebtedness outstanding under the Credit Facility to be accelerated.
Issuance and Retirement of Long-Term Debt
In January 2008, we borrowed $100 million under the Credit Facility to retire $100 million of 6.25 percent senior unsecured notes that matured on January 15, 2008. In April 2008, we borrowed $75 million under the Credit Facility to retire $75 million of adjustable rate unsecured notes that matured on April 15, 2008.
On April 11, 2006,May 22, 2008, we issued $200$250 million aggregate principal amount of 6.05 percent senior unsecured notes due 2018 to certain institutional investors in a Rule 144A private debt placement which pay interest at 6.4% per annum on April 15 and October 15 each year, beginning October 15, 2006 (6.4% Notes). The 6.4% Notes mature on April 15, 2016, but are subject to redemption at any time, at our option, in whole or part, at a specified redemption price, plus accrued and unpaid interest toplacement. We used $175 million of the date of redemption. The net proceeds ofto repay our borrowings under the sale are being used for general corporate purposes, including the funding of capital expenditures.Credit Facility. In October 2006,September 2008, we completed thean exchange of the 6.4% Notesthese notes for substantially identical new notes that are registered under the Securities Act of 1933, as amended.
Restrictive covenantsAt December 31, 2006,2008, none of our debt instruments restrict the amount of dividends distributable to WGP.
Lease obligationsOn October 23, 2003, we entered into a lease agreement for space in the Williams Tower in Houston, Texas.Texas (Williams Tower). The lease term runs through March 31, 2014 with a one-time right to terminate on March 29, 2009.2009, with notification due March 29, 2008. We did not terminate the lease in March 2008.
On July 1, 2006, we entered into a sublease agreement with our affiliate, Williams Field Services Company, for space in the Williams Tower. The lease term runs through March 31, 2014. On May 1, 2007,
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we entered into an agreement to sublease space in the Williams Tower to our affiliate, Williams Field Services Company. The lease term runs through March 29, 2014.
The future minimum lease payments under our various operating leases, including the Williams Tower leaseleases are as follows (in thousands):
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Operating Leases | | | Operating Leases |
| | | Williams | | Other | | | | | Williams | | Other | | |
| | | Tower | | Leases | | Total | | | Tower | | Leases | | Total |
| 2007 | | $ | 5,497 | | $ | 486 | | $ | 5,983 | | |
| 2008 | | 5,698 | | 112 | | 5,810 | | |
| 2009 | | 5,936 | | 115 | | 6,051 | | | $ | 6,777 | | $ | 148 | | $ | 6,925 | |
| 2010 | | 6,186 | | 117 | | 6,303 | | | 7,023 | | 150 | | 7,173 | |
| 2011 | | 6,258 | | 121 | | 6,379 | | | 7,095 | | 153 | | 7,248 | |
| 2012 | | | 7,278 | | 125 | | 7,403 | |
| 2013 | | | 7,386 | | 116 | | 7,502 | |
| Thereafter | | 14,553 | | 381 | | 14,934 | | | 1,848 | | 119 | | 1,967 | |
| | | | | | | | | | | | | | |
| Total net minimum obligations | | $ | 44,128 | | $ | 1,332 | | $ | 45,460 | | | $ | 37,407 | | $ | 811 | | $ | 38,218 | |
| | | | | | | | | | | | | | |
Our lease expense was $9.1 million in 2008, $9.5 million in 2007, and $12.8 million in 2006, $14.1 million in 2005, and $12.7 million in 2004.2006.
5. FAIR VALUE MEASUREMENTS
Adoption of SAS No. 157
SFAS No. 157, “Fair Value Measurements” (SFAS 157), establishes a framework for fair value measurements in the financial statements by providing a definition of fair value, provides guidance on the methods used to estimate fair value and expands disclosures about fair value measurements. On January 1, 2008, we applied SFAS 157 for our assets and liabilities that are measured at fair value on a recurring basis. The initial adoption of SFAS 157 had no material impact on our Financial Statements.
Pursuant to the terms of the Agreement (see Note 3 of Notes to Financial Statements) approved by the FERC in March 2008, we are entitled to collect in rates the amounts necessary to fund our ARO. Per the Agreement, we will deposit monthly, into an external trust account, the revenues collected specifically designated for ARO. We established the ARO trust account (ARO Trust) on June 30, 2008. The ARO Trust carries a moderate risk portfolio.
SFAS 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). We classify fair value balances based on the observability of those inputs. The three levels of the fair value hierarchy are as follows:
Level 1 – Quoted prices in active markets for identical assets or liabilities that we have the ability to access. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 consists of financial instruments in our ARO Trust, amounting to $13.5 million at December 31, 2008. These financial instruments include money market funds, U.S. equity funds, international equity funds and municipal bonds.
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| • | | Level 2 – Inputs are other than quoted prices in active markets included in Level 1, that are either directly or indirectly observable. These inputs are either directly observable in the marketplace or indirectly observable through corroboration with market data for substantially the full contractual term of the asset or liability being measured. We do not have any Level 2 measurements. |
|
| • | | Level 3 – Includes inputs that are not observable for which there is little, if any, market activity for the asset or liability being measured. These inputs reflect management’s best estimate of the assumptions market participants would use in determining fair value. We do not have any Level 3 measurements. |
6. EMPLOYEE BENEFIT PLANS
SFAS No. 158 AdoptionIn September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an amendment of FASB Statements No. 87, 88, 106 and 132(R)” (SFAS No. 158). This Statement requires sponsors ofplansWe participate in noncontributory defined benefit pension and other postretirement benefit plans to recognize the funded status of theirsponsored by Williams that provide pension and other postretirement benefit plans in the statement of financial position, measure the fair value of plan assets and benefit obligations as of the date of the fiscal year-end statement of financial position, and provide additional disclosures. On December 31, 2006, we adopted the recognition and disclosure provisions of SFAS No. 158benefits for eligible participants. Cash contributions related to our participation in Williams’ sponsored pensionthe plans totaled $9.7 million in 2008, $10.2 million in 2007, and other postretirement benefit plans, the effect of which has been reflected$10.9 million in the accompanying consolidated financial statements as of December 31,2006. Pension expense for 2008, 2007 and 2006 as described below. The adoption had no impact on the consolidated financial statements at December 31, 2005 or 2004. SFAS No. 158’s provisions regarding the change in the measurement date of postretirement benefit plans are not applicable as we already use a measurement date of December 31. There is no effect on our Consolidated Statement of Income for the year ended December 31, 2006, or for any periods presented related to the adoption of SFAS No. 158, nor will our future operating results be affected by the adoption.totaled $5.2 million, $6.4 million, and $7.3 million, respectively.
Prior to the adoption of SFAS No. 158, accounting rules allowed for the delayed recognition of certain actuarial gains and losses caused by differences between actual and assumed outcomes, as well as charges or credits caused by plan changes impacting the benefit obligations which were attributed to participants’ prior service. These unrecognized net actuarial gains or losses and unrecognized prior service costs or credits represented the difference between the plans’ funded status and the amount recognized on the Consolidated Balance Sheet. In accordance with SFAS No. 158, we recorded adjustments to accumulated other comprehensive income (loss), net of income taxes, to recognize the funded status of our pension plans on our Consolidated Balance Sheet. We recorded an adjustment to regulatory asset for our other postretirement benefit plan. Our last several rate case settlement agreements allow for the impact related to any differences between revenues and expenses related to other post retirement benefits to be refiled and collected in the next rate case. These adjustments represent the previously unrecognized net actuarial gains and losses and unrecognized prior service costs or credits. The detail of the effect of adopting SFAS No. 158 is provided in the following table.
balance sheet. The adjustments recorded to accumulated other comprehensive income (loss) and the regulatory asset will beare recognized as components of net periodic pension expense or net periodic other postretirement benefit expense and amortized over future periods in accordance with SFAS No. 87, “ Employers’“Employers’ Accounting for Pensions” and SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions” in the same manner as prior to the adoption of SFAS No. 158.. Actuarial gains and losses that arise in subsequent periods and are not recognized as net periodic pension or other postretirement benefit expense in the same
48
period will now beare recognized in other comprehensive income (loss) and regulatory assets.. These amounts will beare recognized subsequently as a component of net periodic pension or other postretirement benefit expense following the same basis as the amounts recognized in accumulated other comprehensive income (loss) and regulatory asset upon adoption of SFAS No. 158..
The effects of adopting SFAS No. 158 to our Consolidated Balance Sheet at December, 31, 2006, are as follows:
| | | | | | | | | | | | | |
| | | Prior to | | Effect of | | After |
| | | SFAS No. 158 | | SFAS No. 158 | | SFAS No. 158 |
| | | Adoption(1) | | Adoption(1) | | Adoption(1) |
| | | (Millions) |
| Balances related to pension plans within: | | | | | | | | | | | | |
| Assets: | | | | | | | | | | | | |
| Noncurrent assets | | $ | 70.2 | | | $ | (16.6 | ) | | $ | 53.6 | |
| Regulatory assets | | | 6.0 | | | | (2.1 | ) | | | 3.9 | |
| Deferred income tax assets | | | — | | | | 17.7 | | | | 17.7 | |
| Liabilities: | | | | | | | | | | | | |
| Current liabilities | | | — | | | | 0.5 | | | | 0.5 | |
| Noncurrent liabilities | | | 22.5 | | | | 27.1 | | | | 49.6 | |
| Stockholders’ equity | | | | | | | | | | | | |
| Accumulated other comprehensive income (loss) | | | — | | | | (28.6 | ) | | | (28.6 | ) |
| |
| Balances related to other postretirement benefits plans within: | | | | | | | | | | | | |
| Assets: | | | | | | | | | | | | |
| Regulatory assets | | | 22.1 | | | | (12.7 | ) | | | 9.4 | |
| Liabilities: | | | | | | | | | | | | |
| Current liabilities | | | 10.6 | | | | (9.9 | ) | | | 0.7 | |
| Noncurrent liabilities | | | 22.6 | | | | (2.8 | ) | | | 19.8 | |
| Regulatory liabilities | | | 0.9 | | | | — | | | | 0.9 | |
| | |
(1) | | Amounts in brackets represent a reduction within the line item balance included on the Consolidated Balance Sheet. |
Prior to the adoption of SFAS No. 158, we had computed an additional minimum pension liability. The effect of recognizing this additional minimum pension liability at December 31, 2006 is included in the regulatory asset amounts under the “Prior to SFAS No. 158 Adoption” column within the table above.
Accumulated other comprehensive income (loss)loss at December 31 2006 includes the following:
| | | | | | | | | |
| | | Pension Benefits |
| | | Gross | | Net of Tax |
| | | (Millions) |
| Amounts not yet recognized in net periodic benefit expense: | | | | | | | | |
| Unrecognized prior service (cost) credit | | $ | 2.4 | | | $ | 1.5 | |
| Unrecognized net actuarial gains (losses) | | | (48.7 | ) | | | (30.1 | ) |
| |
| Amounts expected to be recognized in net periodic benefit expense in 2007: | | | | | | | | |
| Prior service cost (credit) | | | (1.7 | ) | | | (1.0 | ) |
| Net actuarial (gains) losses | | | 3.2 | | | | 2.0 | |
| | | | | | | | | |
| | | Pension Benefits | |
| | | 2008 | | | 2007 | |
| | | (Millions) | |
| Amounts not yet recognized in net periodic benefit expense: | | | | | | | | |
| Prior service (credit) | | $ | (0.1 | ) | | $ | 0.7 | |
| Net actuarial losses | | | (169.7 | ) | | | (25.0 | ) |
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Regulatory asset includes unrecognized prior service credits and unrecognized netNet actuarial gainslosses of $7.8$10.7 million and $4.9 million, respectively. These amounts have not yet been recognized in net periodic other postretirement benefit expense. The prior service credit of $26 thousand related to the pension plans that are included in regulatory asset and expected to be recognized in net periodicaccumulated other postretirement benefit expense in 2007 is $2.1 million. No actuarial gains included in regulatory assetcomprehensive loss at December 31, 2008 are expected to be recognizedamortized in net periodic other postretirement benefit expense in 2007.
Pension plansWe participate in noncontributory defined benefit pension plans with Williams and its subsidiaries that provide pension benefits for eligible participants. Cash contributions related to our participation in the plans totaled $10.9 million in 2006, $14.0 million in 2005 and $11.3 million in 2004. Pension expense for 2006, 2005 and 2004 totaled $7.0 million, $1.5 million and a credit of $0.5 million, respectively.2009.
The allocation of the purchase price to the assets and liabilities of Transco based on estimated fair values resulted in the recording of an additional pension liability in 1995, for the amount that the projected benefit obligation exceeded the plan assets. The remaining amount of additional pension costs deferred at December 31, 20062008 and 2005,2007, is $3.9$3.5 million and $4.6$3.3 million, respectively, and is expected to be recovered through future rates generally over the average remaining service period for active employees.
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At December 31, 2005, we had recorded an additional minimum pension liability of $2.3 million. As required by FERC accounting guidance, this balance was recorded as a regulatory asset instead of accumulated other comprehensive income. At December 31, 2006, we had recorded an additional minimum liability of $2.1 million which was eliminated due to the adoption of SFAS No.158 as it is included in our total funded obligation.
Postretirement benefits other than pensionsWe participate in a plan withsponsored by Williams and its subsidiaries that provides certain retiree health care and life insurance benefits for eligible participants that were hired prior to January 1, 1996. The accounting for the plan anticipates future cost-sharing changes to the plan that are consistent with Williams’ expressed intent to increase the retiree contribution level, generally in line with health care cost increases. Cash contributions totaled $6.7 million in 2008, $6.0 million in 2007 and $3.8 million in 2006, $3.5 million in 2005, and $2.4 million in 2004. Postretirement2006. Net periodic postretirement benefit expense for 2008, 2007 and 2006 2005totaled $3.6 million $4.3 million and 2004 totaled $5.1 million, $5.8 millionrespectively.
In accordance with SFAS No. 158, we recorded an adjustment to regulatory assets and $4.9 million, respectively.regulatory liabilities for our other postretirement benefit plans. We recoverhave been allowed by rate case settlements to collect in future rates any differences between the actuarially determined costcosts and amounts currently being recovered in rates related to other postretirement benefits. The adjustments recorded to the regulatory assets and regulatory liabilities are recognized as components of net periodic benefit expense and amortized over future periods in accordance with SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions”. Actuarial gains and losses that arise in subsequent periods and are not recognized as net periodic benefit expense in the same period are recognized in regulatory assets and regulatory liabilities. These amounts are recognized subsequently as a component of net periodic benefit expense following the same basis as the amounts recognized in regulatory assets and regulatory liabilities.
At December 31, 2008 regulatory assets and regulatory liabilities include prior service credits and net actuarial losses related to other postretirement benefit plans of $21.3 million and $42.5 million, respectively. These amounts have not yet been recognized in net periodic benefit expense. At December 31, 2007 regulatory assets and regulatory liabilities include prior service credits and net actuarial gains related to other postretirement benefits through ratesplans of $5.7 million and $19.5 million, respectively.
Other changes in Williams plan assets and benefit obligations for our other postretirement benefits other than pension plan are recognized in net regulatory assets at December 31, 2008, and include net actuarial loss of $62.0 million, prior service credit of $17.6 million, and amortization of prior service credit of $2.1 million. At December 31, 2007, amounts recognized in net regulatory liabilities included net actuarial gain of $14.5 million and amortization of prior services credit of $2.1 million.
Net actuarial losses of $2.1 million and prior service credit of $5.1 million related to our other post retirement benefit plans that are set throughincluded in regulatory liabilities at December 31, 2008 are expected to be recognized in net periodic general rate filings. Anybenefit expense in 2009. However, any differences between the annual actuarially determined cost and amounts currently being recovered in rates are recorded as an adjustment to revenues and collected or refunded through future rate adjustments. A regulatory asset can be recorded only to the extent it is currently funded.
The amountsallocation of the purchase price to the assets and liabilities of Transco based on estimated fair values resulted in the recording of additional postretirement benefits other than pension liability in 1995, for the amount that the accumulated benefit obligation exceeded the plan assets. The remaining amount of additional postretirement benefits other than pension costs deferred at December 31, 2008 and 2007 is $1.7 million and $5.5 million, respectively, and is expected to be recovered through future rates generally over the average remaining service period for active employees.
The total deferred postretirement benefits costs deferred asresulted in a net regulatory asset of $29.2 million at December 31, 20062008 and 2005a net regulatory liability of $10.0 million at December 31, 2007. These costs are $8.5 million and $24.3 million, respectively, and are
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expected to be recovered through future rates generally over the average remaining service period for active employees.
Defined contribution planOur employees participate in a Williams defined contribution plan. We recognized compensation expense of $6.3 million, $6.0 million and $5.4 million $4.8 millionin 2008, 2007, and $4.4 million in 2006, 2005 and 2004, respectively, for companyWilliams’ matching contributions to this plan.
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Employee Stock-Based Compensation Plan InformationThe Williams Companies, Inc. 20022007 Incentive Plan (Plan) was approved by stockholders on May 16, 2002, and amended and restated on May 15, 2003, and January 23, 2004.17, 2007. The Plan provides for Williams common-stock-based awards to both employees and nonmanagement directors. The Plan permits the granting of various types of awards including, but not limited to, stock options and deferred stock. Awards may be granted for no consideration other than prior and future services or based on certain financial performance targets being achieved.
Williams currently bills us directly for compensation expense related to stock-based compensation awards granted directly to our employees.employees based on the fair value of the options. We are also billed for our proportionate share of both WGP’s and Williams’ stock-based compensation expense though various allocation processes.
Accounting for Stock-Based CompensationPrior to January 1, 2006, we accounted for the Plan under the recognition and measurement provisions of Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations, as permitted by FASB Statement No. 123, “Accounting for Stock-Based Compensation” (SFAS No. 123).Compensation cost for stock options was not recognized in the Consolidated Statement of Income for 2005, as all stock options granted under the Plan had an exercise price equal to the market value of the underlying common stock on the date of the grant. Prior to January 1, 2006, compensation cost was recognized for deferred share awards. Effective January 1, 2006, we adopted the fair value recognition provisions of FASB Statement No. 123(R), “Share-Based Payment” (SFAS No. 123(R)), using the modified-prospective method. Under this method, compensation cost recognized in 2006 includes: (1) compensation cost for all share-based payments granted through December 31, 2005, but for which the requisite service period had not been completed as of December 31, 2005,awards is based on the grant date fair value estimated in accordance with the original provisions of SFAS No. 123, and (2) compensation cost for most share-based payments granted subsequent to December 31, 2005, based on the grant date fair value estimated in accordance with the provisions of SFAS No. 123(R).value. The performance targets for certain performance based deferred sharesrestricted stock units have not been established and therefore expense is not currently recognized. Results for priorExpense associated with these performance-based awards will be recognized in future periods have not been restated.when performance targets are established.
Total stock-based compensation expense, included in administrative and general expenses, for the years ended December 31, 2008, 2007 and 2006 was $2.4 million, $2.1 million and $1.5 million, respectively, excluding amounts allocated from WGP and Williams.
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6.7. INCOME TAXES
Following our conversion on December 31, 2008 to a single member limited liability company, for which an election was made to be treated as a disregarded entity, we are no longer subject to income tax. The (benefit) provision for income taxes shown herein for 2008 reflects the (benefit) provision as of December 31, 2008. Subsequent to the conversion, all deferred taxes were eliminated and we no longer provide for income taxes.
Following is a summary of the (benefit) provision for income taxes for 2006, 2005,2008, 2007, and 20042006 (in thousands):
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2006 | | 2005 | | 2004 | | | 2008 | | 2007 | | 2006 |
| Current: | | |
| Federal | | $ | 13,183 | | $ | 96,420 | | $ | 68,707 | | | $ | 36,528 | | $ | 104,364 | | $ | 10,170 | |
| State | | 1,434 | | 14,435 | | 11,400 | | | 1,366 | | 13,220 | | 730 | |
| | | | | | | | | | | | | | |
| | | 14,617 | | 110,855 | | 80,107 | | | 37,894 | | 117,584 | | 10,900 | |
| | | | | | | | | | | | | | |
| | | |
| Deferred: | | |
| Federal | | 48,785 | | | (1,710 | ) | | 28,331 | | | | (857,697 | ) | | | (14,314 | ) | | 48,075 | |
| State | | 24,474 | | 794 | | 3,483 | | | | (128,977 | ) | | | (2,154 | ) | | 24,323 | |
| | | | | | | | | | | | | | |
| | | 73,259 | | | (916 | ) | | 31,814 | | | | (986,674 | ) | | | (16,468 | ) | | 72,398 | |
| | | | | | | | | | | | | | |
| | |
| Provision for income taxes | | $ | 87,876 | | $ | 109,939 | | $ | 111,921 | | |
| (Benefit) provision for income taxes | | | $ | (948,780 | ) | | $ | 101,116 | | $ | 83,298 | |
| | | | | | | | | | | | | | |
Following is a reconciliation of the (benefit) provision for income taxes at the federal statutory rate to the (benefit) provision for income taxes (in thousands):
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2006 | | 2005 | | 2004 | | | 2008 | | 2007 | | 2006 |
| Taxes computed by applying the federal statutory rate | | $ | 71,794 | | $ | 103,339 | | $ | 101,981 | | | $ | 116,266 | | $ | 94,221 | | $ | 67,772 | |
| State income taxes (net of federal benefit) | | 16,840 | | 9,599 | | 9,676 | | | 8,194 | | 7,192 | | 16,285 | |
| Adjustment of excess deferred taxes | | — | | | (2,996 | ) | | — | | |
| Other, net | | | (758 | ) | | | (3 | ) | | 264 | | | | (632 | ) | | | (297 | ) | | | (759 | ) |
| | | | | | | | | | | | | | |
| | |
| Provision for income taxes | | $ | 87,876 | | $ | 109,939 | | $ | 111,921 | | |
| Provision for income taxes prior to conversion from a corporation to LLC | | | 123,828 | | 101,116 | | 83,298 | |
| | | | | | | | |
| Conversion from corporation to LLC | | | | (1,072,608 | ) | | - | | - | |
| | | | | | | | |
| | |
| (Benefit) provision for income taxes | | | $ | (948,780 | ) | | $ | 101,116 | | $ | 83,298 | |
| | | | | | | | |
We providePrior to December 31, 2008, we provided for income taxes using the assets and liability method as required by SFAS No. 109, “Accounting for Income Taxes.” During 2006, we increased the effective state tax rate as the result of a rate analysis prepared in conjunction with Rate Case RP06-569 resultingthe general rate case in additional tax expense of $15.9 million.Docket No. RP06-569. In addition, we recorded a regulatory asset that partially offsets the effect of the state rate increase. The overall effect on our results of operationsincome was a decrease in net income of $5 million. During 2005, as a result of the reconciliation of our tax basis and book basis assets and liabilities, we recorded a $3.0 million tax benefit adjustment to reduce the overall deferred income tax liabilities on the Consolidated Balance Sheet.
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Significant components of deferred income tax liabilities and assets as of December 31, 20062008 and 20052007 are as follows (in thousands):
| | | | | | | | | | | | | | | | | |
| | | 2006 | | 2005 | | | 2008 | | 2007 |
| Deferred tax liabilities | | |
| Property, plant and equipment | | $ | 1,070,051 | | $ | 993,634 | | | $ | - | | | $ | 1,050,321 | |
| Deferred charges | | 34,114 | | 28,948 | | | - | | 29,259 | |
| Regulatory liabilities | | 84,125 | | 48,227 | | |
| Investments | | 6,339 | | 4,795 | | |
| Regulatory assets/liabilities, net | | | - | | 61,827 | |
| | | | | | | | | | |
| Total deferred tax liabilities | | 1,194,629 | | 1,075,604 | | | - | | 1,141,407 | |
| | | | | | | | | | |
| | | |
| Deferred tax assets | | |
| Estimated rate refund liability | | 813 | | 1,402 | | | - | | 37,498 | |
| Accrued payroll and benefits | | 59,934 | | 40,939 | | | - | | 40,863 | |
| Accrued liabilities | | | - | | 72,589 | |
| Other | | | - | | 13,053 | |
| | | | | | |
| Total deferred tax assets | | | - | | 164,003 | |
| | | | | | |
| | | |
| Overall net deferred tax liabilities | | | $ | - | | $ | 977,404 | |
| | | | | | |
|
| Deferred state income taxes | | | 45,719 | | | | 37,957 | |
| Accrued liabilities | | | 79,656 | | | | 36,099 | |
| Other | | | 12,639 | | | | 18,987 | |
| | | | | | | |
| Total deferred tax assets | | | 198,761 | | | | 135,384 | |
| | | | | | | |
| | | | | | | | | |
| Overall net deferred tax liabilities | | $ | 995,868 | | | $ | 940,220 | |
| | | | | | | |
We recognize related interest and penalties as a component of income tax expense. The amounts accrued for interest and penalties at December 31, 2008 are immaterial.
During the next twelve months, we do not expect to have a material impact on our financial position for settlement of any unrecognized tax benefit associated with domestic matters under audit.
As of December 31, 2008, the Internal Revenue Service (IRS) examinations of our consolidated U.S. income tax returns for 2006 through 2007 were in process. IRS examinations for 1997 through 2005 have been completed at the field level but the years remain open for certain disagreed issues. The statute of limitations for most states expires one year after IRS audit settlement.
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8.7. FINANCIAL INSTRUMENTS AND GUARANTEES
Fair value of financial instrumentsThe carrying amount and estimated fair values of our financial instruments as of December 31, 20062008 and 20052007 are as follows (in thousands):
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | Carrying Amount | | Fair Value |
| | | Carrying Amount | | Fair Value | | 2008 | | 2007 | | 2008 | | 2007 |
| | | 2006 | | 2005 | | 2006 | | 2005 | | (Restated) | | (Restated) | |
| Financial assets: | | |
| Cash | | $ | 315 | | $ | 362 | | $ | 315 | | $ | 362 | | | $ | 428 | | $ | 119 | | $ | 428 | | $ | 119 | |
| Short-term financial assets | | 191,380 | | 131,288 | | 191,380 | | 131,288 | | | 186,638 | | 214,632 | | 186,638 | | 214,632 | |
| Long-term financial assets | | 1,760 | | 2,741 | | 1,760 | | 2,741 | | | 655 | | 925 | | 655 | | 925 | |
| Financial liabilities: | | |
| Long-term debt, including current portion | | 1,201,458 | | 1,000,623 | | 1,270,099 | | 1,085,635 | | | 1,277,679 | | 1,202,370 | | 1,154,943 | | 1,296,482 | |
For cash and short-term financial assets (third-party notes receivable and advances to affiliates) that have variable interest rates, the carrying amount is a reasonable estimate of fair value due to the short maturity of those instruments. For long-term financial assets (long-term receivables), the carrying amount is a reasonable estimate of fair value because the interest rate is a variable rate.
The fair value of our publicly traded long-term debt is valued using year-end traded bond market prices. Private debt is valued based on the prices of similar securities with similar terms and credit ratings. At both December 31, 20062008 and 2005, approximately2007, 100 percent and 94 and 93 percent, respectively, of long-term debt was publicly traded. We use the expertise of outside investment banking firms to assist with the estimate of the fair value of our long-term debt.
As a participant in Williams’ cash management program, we make advances to and receive advances from Williams. Advances are stated at the historical carrying amounts. As of December 31, 20062008 and 2005,2007, we had advances to affiliates of $190$186.2 million and $130$213.9 million, respectively. Advances to affiliates are due on demand.
GuaranteesIn connection with our renegotiations with producers to resolve take-or-pay and other contract claims and to amend gas purchase contracts, we entered into certain settlements which may require that we indemnify producers for claims for additional royalties resulting from such settlements. Through our agent WPC,WGM, we continue to purchase gas under contracts which extend, in some cases, through the life of the associated gas reserves. Certain of these contracts contain royalty indemnification provisions, which have no carrying value. We have been made aware of demands on producers for additional royalties and such producers may receive other demands which could result in claims against us pursuant to royalty indemnification provisions. Indemnification for royalties will depend on, among other things, the specific lease provisions between the producer and the lessor and the terms of the agreement between the producer and us. Consequently, the potential maximum future payments under such indemnification provisions cannot be determined. However, we believe that the probability of material payments is remote.
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8.9. TRANSACTIONS WITH MAJOR CUSTOMERS AND AFFILIATES
Major CustomersIn 2006,2008, operating revenues received from Public Service Enterprise Group, KeyspanNational Grid (formerly known as KeySpan Corporation), and Piedmont Natural Gas Company, our three major customers, were $132.3 million, $120.4 million, and $81.8 million, respectively. In 2007, operating revenues received from Public Service Enterprise Group, KeySpan Corporation, and Piedmont Natural Gas Company, our three major customers, were $106.7$141.9 million, $74.7$86.1 million, and $66.8$84.4 million, respectively. In 2005,2006, our
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three major customers were Public Service Enterprise Group, KeySpan Corporation, and Piedmont Natural Gas Company, and Keyspan Corporation, providing operating revenues of $112.2$106.7 million, $97.1$74.7 million, and $82.8 million, respectively. In 2004, our three major customers were Piedmont Natural Gas Company, PSEG Energy Resources & Trade, LLC, and Philadelphia Gas Works providing operating revenues of $168.3 million, $115.1 million, and $92.5$66.8 million, respectively.
AffiliatesAs a participant in Williams’ cash management program, we make advances to and receive advances from Williams. At December 31, 2008 and 2007, the advances due to us by Williams totaled approximately $186.2 million and $213.9 million, respectively. The advances are represented by demand notes. The interest rate on intercompany demand notes is based upon the weighted average cost of Williams’ debt outstanding at the end of each quarter. At December 31, 2008, the interest rate was 7.87 percent. We received interest income from advances to Williams of $22.0 million, $14.9 million, and $13.6 million during 2008, 2007 and 2006, respectively. Such interest income is included in Other Income – affiliates on the accompanying Statement of Income.
Included in our operating revenues for 2006, 2005,2008, 2007 and 20042006 are revenues received from affiliates of $51.5$35.8 million, $87.1$42.8 million, and $119.3$51.5 million, respectively. The rates charged to provide sales and services to affiliates are the same as those that are charged to similarly-situated nonaffiliated customers.
Through an agency agreement with us, WPCWGM manages our jurisdictional merchant gas sales. For the years ended December 31, 2005 and 2004, included in our cost of sales is $5.5 million and $14.3 million, respectively, representing agency fees billed to us by WPC under the agency agreement. Due to the termination of our remaining Firm Sales agreements effective April 1, 2005, theThe agency fees billed by WPCWGM for 2006 through 2008 were not significant.
Included in our cost of sales for 2006, 2005,2008, 2007 and 20042006 is purchased gas cost from affiliates, excluding the agency fees discussed above, of $15.7$14.3 million, $75.7$9.7 million, and $211.2$15.7 million, respectively. All gas purchases are made at market or contract prices.
We have long-term gas purchase contracts containing variable prices that are currently in the range of estimated market prices. Our estimated purchase commitments under such gas purchase contracts are not material to our total gas purchases. Furthermore, through the agency agreement with us, WPCWGM has assumed management of our merchant sales service and, as our agent, is at risk for any above-spot-market gas costs that it may incur.
Williams has a policy of charging subsidiary companies for management services provided by the parent company and other affiliated companies. Included in our administrative and general expenses for 2008, 2007 and 2006 2005, and 2004 were $53.4$44.9 million, $50.6$53.2 million, and $45.1$53.4 million, respectively, for such corporate expenses charged by Williams and other affiliated companies. Management considers the cost of these services to be reasonable.
Beginning in May 1995, Williams Field Services Company (WFS), an affiliated company, operated our production area facilities pursuant to the terms of an operating agreement. In response to FERC Order No. 2004, we terminated the operating agreement and effective June 1, 2004 we resumed operating these facilities. Included in our operation and maintenance expenses for 2004 were $15.5 million charged by WFS to operate our gas gathering facilities.
Effective June 1, 2004 and pursuantPursuant to an operating agreement, we serve as contract operator on certain WFSWilliams Field Services (WFS) facilities. Transco recorded reductions in operating expenses for services provided to WFS forof $7.8 million, $5.8 million, and $6.9 million $7.5 millionin 2008, 2007 and $3.8 million in 2006 2005 and 2004 respectively, under terms of the operating agreement.
10. ASSET RETIREMENT OBLIGATIONS
We record an asset and a liability equal to the present value of each expected future ARO. The ARO asset is depreciated in a manner consistent with the depreciation of the underlying physical asset. We measure changes in the liability due to passage of time by applying an interest method of allocation. The depreciation of the ARO asset and accretion of the ARO liability are recognized as an increase to a regulatory asset. The regulatory asset will be amortized commensurate with our collection of those costs in rates.
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In April 2005, we sold our interest in certain gas pipeline and related facilities and equipment, located in the Ship Shoal Area, Offshore Louisiana, to Williams Mobile Bay Producer Services, L.L.C., an affiliated company, for $6.9 million. The sale of these assets was at book value, and resulted in no gain or loss.
9. ASSET RETIREMENT OBLIGATIONS
We adopted SFAS No. 143 on January 1, 2003. We previously determined that asset retirement obligations exist for our offshore transmission platforms. In 2005 we revised our estimate for offshore transmission platforms based on a change in the estimated settlement date and a change in the estimated costs of retirements, resulting in a $23.7 million increase in the asset retirement obligation in 2008 and Property, Plant and Equipment, net.
In March 2005, the FASB issued FIN No. 47, “Accounting for Conditional Asset Retirement Obligations— an interpretation of FASB Statement No.143.” The Interpretation clarifies that the term “conditional asset retirement” as used in SFAS No.143, “Accounting for Asset Retirement Obligations,” refers2007 was due primarily to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. The Interpretation also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation (ARO).
We adopted the Interpretation on December 31, 2005. In accordance with the Interpretation, we estimated future retirement obligations for certain assets previously considered to have an indeterminate life. As a result, we recorded an increase in Asset retirement obligations of $8.8 million, and an increase in property, plant and equipment, net, of $1.4 million. We also recorded a $7.4 million regulatory asset in Other Assets for retirement costs expected to be recovered through rates.
During 2006, we obtainedobtaining additional information impactingthat revised our estimation of our ARO.asset retirement obligation for certain assets and ongoing accretion of the liability. Factors affected by the additional information included estimated settlement dates, estimated settlement costs and inflation rates. We adjusted the ARO related to certain assets because the additional information results in improved and the best available estimates regarding the ARO costs, lives, and inflation rates. During 2006 we recorded an increase in Asset retirement obligations of $82.6 million.
During 20062008 and 2005,2007, our overall asset retirement obligation changed as follows (in thousands):
| | | | | | | | | | |
| | | 2006 | | 2005 | | | | | | | | | |
| | | | | 2008 | | 2007 |
| Beginning balance | | $ | 53,596 | | $ | 17,888 | | | $ | 141,416 | | | $ | 136,171 | |
| Accretion | | 3,060 | | 1,258 | | | 41,196 | | 10,151 | |
| New obligations | | — | | 2,969 | | | 5,022 | | 2,651 | |
| Changes in estimates of existing obligations | | | 80,713 | (1) | | 23,662 | | | 47,447 | | | (5,544 | ) |
| Property dispositions | | | (1,198 | ) | | | (979 | ) | | | (5,721 | ) | | | (2,013 | ) |
| Adoption of FIN 47 | | — | | 8,798 | | |
| | | | | | | | | | |
| Ending balance | | $ | 136,171 | | $ | 53,596 | | | $ | 229,360 | | $ | 141,416 | |
| | | | | | | | | | |
| | |
(1) | | Includes $6 million related to assets inadvertently omitted in the 2005 ARO calculation. Management believes this omission is not material to the financial statements for any period presented. |
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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.
Pursuant to the terms of the Agreement (see Note 3 of Notes to Financial Statements), we are entitled to collect in rates the amounts necessary to fund our ARO. All funds received for such retirements shall be deposited into an external trust account dedicated to funding our ARO. Effective June 1, 2008, the effective date of the Agreement, we were required to initially fund the ARO Trust account. On June 30, 2008, we paid the initial funding of $11.2 million, which included an adjustment for the total spending on ARO requirements as of May 31, 2008. Subsequent to the initial funding, we will have an annual funding obligation through the effective period of the Agreement of approximately $16.7 million, with installments to be paid monthly.
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10.11. REGULATORY ASSETS AND LIABILITIES
The regulatory assets and regulatory liabilities resulting from our application of the provisions of SFAS No. 71 included in the accompanying Consolidated Balance Sheet at December 31, 20062008 and December 31, 20052007 are as follows (in millions):
| | | | | | | | | | |
| | | 2006 | | 2005 | | | | | | | | | |
| Regulatory Assets | | | 2008 | | 2007 | |
| | | |
| Grossed-up deferred taxes on equity funds used during construction | | $ | 87.7 | | $ | 81.7 | | | $ | 92.0 | | $ | 91.5 | |
| Asset retirement obligations | | 87.6 | | 22.3 | | |
| Asset retirement obligations (1) | | | 85.9 | | 47.3 | |
| Deferred taxes | | 15.5 | | 6.9 | | | 13.5 | | 14.5 | |
| Deferred gas costs | | 8.6 | | 10.5 | | | 4.2 | | - | |
| Environmental costs | | 5.7 | | 8.4 | | | 1.8 | | 4.0 | |
| Postretirement benefits other than pension | | 9.4 | | 25.3 | | | 31.9 | | 9.9 | |
| Fuel cost | | 9.5 | | 1.0 | | | 74.0 | | 11.9 | |
| Other | | — | | 2.3 | | |
| Electric power cost | | | 2.5 | | - | |
| | | | | | |
| | | | | | | |
| Total Regulatory Assets | | $ | 224.0 | | $ | 158.4 | | | $ | 305.8 | | | $ | 179.1 | |
| | | | | | | | | | |
| | | |
| Regulatory Liabilities | | |
| | | |
Negative salvage | | $ | 40.1 | | $ | 38.5 | | | $ | 47.1 | | $ | 17.4 | |
| Deferred cash out | | 15.8 | | 39.8 | | | 9.8 | | 7.6 | |
| Electric power cost | | 4.2 | | 6.8 | | | - | | 1.4 | |
| Other | | 0.9 | | 3.0 | | |
| Deferred gas costs | | | - | | 1.2 | |
| Postretirement benefits other than pension | | | 2.7 | | 19.9 | |
| | | | | | |
| | | | | | | |
| Total Regulatory Liabilities | | $ | 61.0 | | $ | 88.1 | | | $ | 59.6 | | $ | 47.5 | |
| | | | | | | | | | |
(1) $40 million of negative salvage liability was reclassified to ARO asset in 2007.
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1211.. QUARTERLY INFORMATION (UNAUDITED)
The following summarizes selected quarterly financial data for 20062008 and 20052007 (in thousands):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2006 | | First (1) | | Second | | Third | | Fourth (2) | | |
| 2008 | | | First (1) | | Second (2) | | Third (3) | | Fourth (4) |
| | | | (Restated) | | (Restated) | | (Restated) | |
| Operating revenues | | | $ | 306,626 | | $ | 299,593 | | $ | 299,434 | | $ | 295,559 | |
| Operating expenses | | | 196,155 | | 194,682 | | 201,957 | | 214,821 | |
| | | | | | | | | | |
| Operating income | | | 110,471 | | 104,911 | | 97,477 | | 80,738 | |
| Interest expense | | | 24,327 | | 24,495 | | 23,811 | | 23,606 | |
| Other (income) and deductions, net | | | | (8,545 | ) | | | (9,600 | ) | | | (8,533 | ) | | | (8,152 | ) |
| | | | | | | | | | |
| Income before income taxes | | | 94,689 | | 90,016 | | 82,199 | | 65,284 | |
| (Benefit) Provision for income taxes | | | 35,966 | | 34,211 | | 30,843 | | | (1,049,800 | ) |
| | | | | | | | | | |
| | | |
| Net income | | | $ | 58,723 | | $ | 55,805 | | $ | 51,356 | | $ | 1,115,084 | |
| | | | | | | | | | |
| | |
| 2007 | | | First | | Second | | Third | | Fourth (5) |
| | | | (Restated) | | (Restated) | | (Restated) | | (Restated) |
| Operating revenues | | $ | 259,591 | | $ | 260,812 | | $ | 261,816 | | $ | 266,172 | | | $ | 272,967 | | $ | 315,119 | | $ | 288,688 | | $ | 323,827 | |
| Operating expenses | | 179,736 | | 192,913 | | 209,971 | | 215,738 | | | 198,792 | | 230,612 | | 205,000 | | 238,545 | |
| | | | | | | | | | | | | | | | | | |
| Operating income | | 79,855 | | 67,899 | | 51,845 | | 50,434 | | | 74,175 | | 84,507 | | 83,688 | | 85,282 | |
| Interest expense | | 15,073 | | 22,941 | | 23,489 | | 24,503 | | | 23,193 | | 23,431 | | 24,097 | | 24,383 | |
| Other (income) and deductions, net | | | (8,515 | ) | | | (10,271 | ) | | | (11,313 | ) | | | (11,001 | ) | | | (7,760 | ) | | | (8,981 | ) | | | (12,024 | ) | | | (7,889 | ) |
| | | | | | | | | | | | | | | | | | |
| Income before income taxes | | 73,297 | | 55,229 | | 39,669 | | 36,932 | | | 58,742 | | 70,057 | | 71,615 | | 68,788 | |
| Provision for income taxes | | 27,585 | | 21,104 | | 15,320 | | 23,867 | | | 22,187 | | 27,073 | | 27,188 | | 24,668 | |
| | | | | | | | | | | | | | | | | | |
| | | |
| Net income | | $ | 45,712 | | $ | 34,125 | | $ | 24,349 | | $ | 13,065 | | | $ | 36,555 | | $ | 42,984 | | $ | 44,427 | | $ | 44,120 | |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| 2005 | | First | | | Second | | | Third (3) | | | Fourth | |
| Operating revenues | | $ | 348,945 | | | $ | 263,802 | | | $ | 270,891 | | | $ | 302,775 | |
| Operating expenses | | | 260,044 | | | | 176,553 | | | | 178,404 | | | | 229,327 | |
| | | | | | | | | | | | | |
| Operating income | | | 88,901 | | | | 87,249 | | | | 92,487 | | | | 73,448 | |
| Interest expense | | | 20,120 | | | | 19,672 | | | | 19,782 | | | | 20,087 | |
| Other (income) and deductions, net | | | (6,818 | ) | | | (8,394 | ) | | | (9,227 | ) | | | (8,391 | ) |
| | | | | | | | | | | | | |
| Income before income taxes | | | 75,599 | | | | 75,971 | | | | 81,932 | | | | 61,752 | |
| Provision for income taxes | | | 28,459 | | | | 28,682 | | | | 31,357 | | | | 21,441 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Net income | | $ | 47,140 | | | $ | 47,289 | | | $ | 50,575 | | | $ | 40,311 | |
| | | | | | | | | | | | | |
(2) Includes a $9.5 million decrease to operating expenses resulting from a gain on the sale of top gas from the Eminence storage facility and a $3.4 million decrease to operating expenses resulting from recording the difference between amounts accrued and amounts collected in rates for Asset Retirements Obligations.
(3) Includes a $10.4 million decrease to operating expenses resulting from a gain on the sale of South Texas assets and a $4.0 million increase to operating expenses resulting from an accrual for a pipeline rupture near Appomattox, Virginia. The accrual was subsequently increased to $4.5 million in the fourth quarter.
(4) Includes a $2.1 million decrease to operating expenses resulting from the reversal of a liability associated with unidentified transportation and exchange gas for a prior year.
| | |
(1) | | Includes a $2.0 million decrease to operating expenses and a $5.0 million decrease to interest expense resulting from a reversal of excess royalties reserve. |
|
(2) | | Includes a $9.3 million increase to operating revenue resulting from a change in the effective state income tax rate. This is more than offset by $15.9 million net increase in tax expense included in provision for income taxes. |
|
(3) | | Includes a $14.2 million decrease to operating expenses resulting from a reversal of a liability related to the 1999 Fuel Tracker. |
(5) Includes a $2.2 million decrease to operating expenses resulting from a reversal of a reserve related to prior cashout periods and a $2.0 million decrease to operating expenses resulting from the reversal of a liability associated with unidentified transportation and exchange gas for prior years.
5768
TRANSCONTINENTAL GAS PIPE LINE CORPORATION
COMPANY, LLC
SCHEDULE II —– VALUATION AND QUALIFYING ACCOUNTS
(ThousandsIn thousands)
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | ADDITIONS | | | | | | | |
| | | | | | | Charged to | | | | | | | | | | | |
| | | Beginning | | Costs and | | | | | | | | | | Ending |
| Description | | Balance | | Expenses | | Other | | Deductions | | Balances |
| Year ended December 31, 2008: | | | | | | | | | | | | | | | | | | | | |
| Reserve for rate refunds | | $ | 98,035 | | | $ | - | | | $ | 61,387 | | | $ | (145,060 | )(1) | | $ | 14,362 | |
| Reserve for doubtful receivables | | | 462 | | | | - | | | | - | | | | (38 | ) | | | 424 | |
| Year ended December 31, 2007: | | | | | | | | | | | | | | | | | | | | |
| Reserve for rate refunds | | | 2,232 | | | | - | | | $ | 106,163 | (2) | | | (10,360 | ) | | | 98,035 | |
| Reserve for doubtful receivables | | | 503 | | | | - | | | | - | | | | (41 | ) | | | 462 | |
| Year ended December 31, 2006: | | | | | | | | | | | | | | | | | | | | |
| Reserve for rate refunds | | | 3,763 | | | | 1,542 | | | | - | | | | (3,073 | ) | | | 2,232 | |
| Reserve for doubtful receivables | | | 509 | | | | 154 | | | | - | | | | (160 | ) | | | 503 | |
(1) Rate refunds were paid in the Third Quarter of Dollars)
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | ADDITIONS | | | | | | | | |
| | | | | | | Charged to | | | | | | | | | | | | |
| | | Beginning | | | Costs and | | | | | | | | | | | Ending | |
| Description | | Balance | | | Expenses | | | Other | | | Deductions | | | Balances | |
| Year ended December 31, 2006: | | | | | | | | | | | | | | | | | | | | |
| Reserve for rate refunds | | $ | 3,763 | | | $ | 1,542 | | | $ | — | | | $ | (3,073 | ) | | $ | 2,232 | |
| Reserve for doubtful receivables | | | 509 | | | | 154 | | | | — | | | | (160 | ) | | | 503 | |
| Year ended December 31, 2005: | | | | | | | | | | | | | | | | | | | | |
| Reserve for rate refunds | | | 8,919 | | | | 8,194 | | | | | | | | (13,350 | ) | | | 3,763 | |
| Reserve for doubtful receivables | | | 778 | | | | — | | | | — | | | | (269 | ) | | | 509 | |
| Year ended December 31, 2004: | | | | | | | | | | | | | | | | | | | | |
| Reserve for rate refunds | | | 10,610 | | | | 7,417 | | | | (7,637 | ) | | | (1,471 | ) | | | 8,919 | |
| Reserve for doubtful receivables | | | 2,470 | | | | 490 | | | | — | | | | (2,182 | ) | | | 778 | |
ITEM 9. Changes In and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
ITEM 9A.9A(T). Controls and Procedures
Evaluation of Disclosure Controls and Procedures
An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) and 15d-15(e) of the Securities Exchange Act) (Disclosure Controls) was performed as of the end of the period covered by this report. This evaluation was performed under the supervision and with the participation of our management, including our Senior Vice President and our Vice President and Treasurer. Based upon that evaluation, our Senior Vice President and our Vice President and Treasurer have concluded that our Disclosure Controls and procedures were effective at a reasonable assurance level.
Our management, including our Senior Vice President and our Vice President and Treasurer, does not expect that our Disclosure Controls or our internaldisclosure controls over financial reporting (Internaland 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 companyTransco 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
58
Disclosure Controls and Internal Controls and make modifications as necessary; our intent in this regard is that the Disclosure Controls and the Internal Controls will be modified as systems change and conditions warrant.
A material weakness is a control deficiency, or combination of control deficiencies, that results in more than a remote likelihood that a material misstatementAn evaluation of the annual or interim financial statements will not be prevented or detected.
Duringeffectiveness of the fourth quarterdesign and operation of 2005our Disclosure Controls was performed as of the end of the period covered by this report. This evaluation was performed under the supervision and as reported inwith the participation of our 2005management, including our Senior Vice President and our Vice President and Treasurer. Based upon that evaluation, our Senior Vice President and our Vice President and Treasurer concluded that these Disclosure Controls are effective at a reasonable assurance level.
69
Management’s Annual Report on Form 10-K, we identified a material weaknessInternal Control over Financial Reporting
See report set forth above in internal control over financial reporting associated with the absence of an effective control to identify to specific customers a material amount of transportationItem 8, “Financial Statements and exchange imbalance volumes, primarily for the period April 2003 to December 2004. These natural gas volumes represent gas received in excess of amounts delivered on our pipeline systems that had not been associated with specific transportation contracts and related customers, and were recorded within Transportation and Exchange Gas Payables in our consolidated balance sheet at December 31, 2005.
In 2005, we implemented controls designed to prevent the repetition of this failure of identification in future periods. In 2006 we reconciled the vast majority of the unidentified volumes for each month retroactive to April 2003. At December 31, 2006, the reconciliation process had been completed for the 2003 to 2004 period. The resulting adjustments were recorded and did not have a material effect on our 2006 financial statements. We now consider this material weakness to be remediated.Supplementary Data.”
Changes in Internal Control overControls Over Financial Reporting
There have been no changes during the fourth quarter of 20062008 that have materially affected, or are reasonably likely to materially affect, our internal controlsInternal Controls over financial reporting.
ITEM 9B. Other Information
None
59
PART III
Since we meet the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K, the information required by Items 10, 11, 12, and 13 is omitted.
ITEM 14. Principal Accountant Fees and Services
Fees for professional services provided by our independent registered public accounting firm in each of the last two fiscal years in each of the following categories are (in thousands):
| | | | | | | | | | | | | | | | | |
| | | 2006 | | 2005 | | | 2008 | | 2007 |
| Audit Fees | | $ | 2,463 | | $ | 1,941 | | | $ | 2,086 | | $ | 2,240 | |
| Audit-Related Fees | | 203 | | 87 | | | - | | 142 | |
| Tax Fees | | — | | — | | | - | | - | |
| All Other Fees | | — | | — | | | - | | - | |
| | | | | | | | | | |
| | | |
| Total Fees | | $ | 2,666 | | $ | 2,028 | | | $ | 2,086 | | $ | 2,382 | |
| | | | | | | | | | |
Fees for audit services include fees associated with the annual audit, the reviews for our quarterly reports on Form 10-Q, the reviews for other SEC filings and accounting consultation. Audit-related fees include other attestattestation services.
As a wholly-owned subsidiary of Williams, we do not have a separate audit committee.Audit Committee. The Williams audit committeeAudit Committee policies and procedures for pre-approving audit and non-audit services will be filed withset forth in the proxy statement for Williams’ 2009 annual meeting of stockholders which will be available upon its filing on the SEC’s website at http://www.sec.gov and on the Williams Proxy Statement to be filed withwebsite at http://www.williams.com under the Securities and Exchange Commission on or before April 9, 2007.heading “Investors-SEC Filings”.
6070
PART IV
ITEM 15. Exhibits and Financial Statement Schedules.
| | | | |
| | Page | |
| | Reference to | |
| | 2006 10-K | |
A. Index
| | | | |
| | | | |
1. Financial Statements:
| | | | |
| | | | |
Report of Independent Registered Public Accounting Firm - Ernst &Young LLP | | | 28 | |
| | | | |
Consolidated Statement of Income for the Years Ended December 31, 2006, 2005 and 2004 | | | 29 | |
| | | | |
Consolidated Balance Sheet as of December 31, 2006 and 2005 | | | 30-31 | |
| | | | |
Consolidated Statement of Common Stockholder’s Equity for the Years Ended December 31, 2006, 2005 and 2004 | | | 32 | |
| | | | |
Consolidated Statement of Comprehensive Income for the Years Ended December 31, 2006, 2005 and 2004 | | | 33 | |
| | | | |
Consolidated Statement of Cash Flows for the Years Ended December 31, 2006, 2005 and 2004 | | | 34-35 | |
| | | | |
Notes to Consolidated Financial Statements | | | 36-57 | |
| | | | |
2. Financial Statement Schedules:
| | | | |
| | | | |
Schedule II — Valuation and Qualifying Accounts for the Years ended December 31, 2006, 2005 and 2004 | | | 58 | |
| | | | |
The following schedules are omitted because of the absence of the conditions under which they are required: |
| | | | |
I, III, IV, and V. | | | | |
| | | | |
61
3. Exhibits:
The following instruments are included as exhibits to this report. Those exhibits below incorporated by reference herein are indicated as such by the information supplied in the parenthetical thereafter. If no parenthetical appears after an exhibit, copies of the instrument have been included herewith.
(2) Plan of acquisition, reorganization arrangement, liquidation or succession
| | | | |
- | | Stock | | Option Agreement dated as of December 12, 1994 by and between The Williams Companies, Inc. and Transco Energy Company. (Exhibit 3 to Transco Energy Company Schedule 14D-9 Commission File Number 005-19963) |
(3) Articles of incorporation and by-laws
| | | | | | | | |
- | | | 1 | | | Second Restated Certificate of Incorporation, as amended, of Transco. (Exhibit 3.1 to Transco Form 8-K dated January 23, 1987 Commission File Number 1-7584) |
| | | | | | | | | |
| | | | | | | a)Page | |
| | Certificate of Amendment, dated August 4, 1992, of the Second Restated Certificate of Incorporation (Exhibit (10)-17(a) | | | | Reference to Transco Energy Company Form | |
| | | | | | 2008 10-K for 1993 Commission File Number 1-7513)
| |
A. | | Index | | | | | | |
| | | | | | | | |
| | 1. | | Financial Statements: | | | | |
| | | | | | | | | |
| | | | | Management’s Report on Internal Control over Financial Reporting | | b) | 37 | | Certificate of Amendment, dated December 23, 1986, of the Second Restated Certificate of Incorporation (Exhibit (10)-17(b) to Transco Energy Company Form 10-K for 1993 Commission File Number 1-7513) |
| | | | | | | | | |
| | | | | Report of Independent Registered Public Accounting Firm - Ernst & Young LLP | | c) | 38 | | Certificate of Amendment, dated August 12, 1987, of the Second Restated Certificate of Incorporation (Exhibit (10)-17(c) to Transco Energy Company Form 10-K for 1993 Commission File Number 1-7513) |
| | | | | | | | | |
- | | | 2 | Statement of Income for the Years Ended December 31, 2008, 2007 and 2006 | | | By-Laws of Transco, as Amended and Restated April 1, 2003 (filed as Exhibit 3.2 to Transco Form 10-K filed March 30, 2005)39 | |
(4) Instruments defining the rights of security holders, including indentures
| | | | | | | | |
- | | | 1 | Balance Sheet as of December 31, 2008 and 2007 | | | 40-41 | |
| | | | | | | | |
| | | | Statement of Owner’s Equity for the Years Ended December 31, 2008, 2007 and 2006 | | | 42 | |
| | | | | | | | |
| | | | Statement of Comprehensive Income for the Years Ended December 31, 2008, 2007 and 2006 | | | 43 | |
| | | | | | | | |
| | | | Statement of Cash Flows for the Years Ended December 31, 2008, 2007 and 2006 | | | 44-45 | |
| | | | | | | | |
| | | | Notes to Financial Statements | | | 46-68 | |
| | | | | | | | |
| | 2. | | Financial Statement Schedules: | | | | |
| | | | | | | | |
| | | | Schedule II – Valuation and Qualifying Accounts for the Years ended December 31, 2008, 2007 and 2006 | | | 69 | |
| | | | | | | | |
| | | | The following schedules are omitted because of the absence of the conditions under which they are required: | | | | |
| | | | | | | | |
| | | | I, III, IV, and V. | | | | |
71
| 3. | | Exhibits: |
|
| | The following instruments are included as exhibits to this report. Those exhibits below incorporated by reference herein are indicated as such by the information supplied in the parenthetical thereafter. If no parenthetical appears after an exhibit, copies of the instrument have been included herewith. |
(3) Articles of incorporation and by-laws
| | – | 1 | Certificate of Conversion and Certificate of Formation, dated December 24, 2008 and effective on December 31, 2008. |
| |
| | – | 2 | Operating Agreement of Transco dated December 31, 2008. |
(4) Instruments defining the rights of security holders, including indentures
| | – | 1 | Indenture dated July 15, 1996 between Transco and Citibank, N.A., as Trustee (filed as Exhibit 4.1 to Transco Form S-3 dated April 2, 1996 Transco Registration Statement No. 333-2155) |
| |
| | – | 2 | Indenture dated January 16, 1998 between Transco and Citibank, N.A., as Trustee (filed as Exhibit 4.1 to Transco Form S-3 dated September 8, 1997 Transco Registration Statement No. 333-27311) |
| |
| | – | 3 | Indenture dated August 27, 2001 between Transco and Citibank, N.A., as Trustee (filed as Exhibit 4.1 to Transco Form S-4 dated November 8, 2001 Transco Registration Statement No. 333-72982) |
| |
| | – | 4 | Indenture dated July 3, 2002 between Transco and Citibank, N.A., as Trustee (filed as Exhibit 4.1 to The Williams Companies, Inc. Form 10-Q for the quarterly period ended June 30, 2002 Commission File Number 1-4174) |
| |
| | – | 5 | Indenture dated December 17, 2004 between Transco and JPMorgan Chase, N.A., as trustee (filed as Exhibit 4.1 to Transco Form 8-K filed December 21, 2004) |
| |
| | – | 6 | Indenture dated April 11, 2006 between Transco and JP Morgan Chase Bank, N.A., as trustee (filed as Exhibit 4.1 to Transco Form 8-K filed April 11, 2006). |
| |
| | – | 7 | Indenture, dated as of May 22, 2008 between Transco and The Bank of New York Trust Company, N.A. (filed as Exhibit 4.1 to our form 8-K filed May 23, 2008). |
(10) Material contracts
| – | 1 | Lease Agreement, dated October 23, 2003, between Transco and Transco Tower Limited, a Texas limited partnership as amended March 10, 2004, March 11, 2004, May 10, 2004, and June 25, 2004 (filed as Exhibit 10.2 to Transco Form 10-K filed March 30, 2005). |
72
| | – | 2 | Credit Agreement, dated May 1, 2006, among The Williams Companies, Inc., Northwest Pipeline Corporation, Transcontinental Gas Pipe Line Corporation, and Williams Partners L.P., as Borrowers, and Citibank, N.A., as Administrative Agent (filed as Exhibit 10.1 to The Williams Companies, Inc. Form 8-K filed May 1, 2006 Commission File Number 1-4174). |
| |
| | – | 3 | Amendment Agreement, dated May 9, 2007, among The Williams Companies, Inc., Williams Partners L.P., Northwest Pipeline Corporation, Transcontinental Gas Pipe Line Corporation, certain banks, financial institutions and other institutional lenders and Citibank, N.A., as administrative agent (filed as Exhibit 10.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) filed with the SEC on May 15, 2007 and incorporated by reference as Exhibit 10.1 to our Form 8-K filed May 15, 2007). |
| |
| | – | 4 | Amendment Agreement, dated November 21, 2007, among The Williams Companies, Inc., Williams Partners L.P., Northwest Pipeline Corporation, Transcontinental Gas Pipe Line Corporation, certain banks, financial institutions and other institutional lenders and Citibank, N.A., as administrative agent (filed as Exhibit 10.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) filed with the SEC on November 28, 2007 and incorporated by reference as Exhibit 10.1 to our Form 8-K filed November 28, 2007). |
| |
| | – | 5 | Registration Rights Agreement, dated as of May 22, 2008 between Transco and Banc of America Securities LLC, Greenwich Capital Markets, Inc., and J.P. Morgan Securities Inc., acting on behalf of themselves and the several initial purchasers listed on Schedule 1 thereto (filed as Exhibit 10.1 to our Form 8-K filed May 23, 2008). |
(23) Consent of Independent Registered Public Accounting Firm
(24) Power of attorney
(31) Section 302 Certifications
| | – | 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. |
| |
| | – | 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) | | Section 906 Certification |
| – | | 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. |
73
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, on this 26th day of February 2009.
| | | | |
| TRANSCONTINENTAL GAS PIPE
LINE COMPANY, LLC
(Registrant)
| |
| By: | /s/ Jeffrey P. Heinrichs | |
| | Jeffrey P. Heinrichs | |
| | Controller and Assistant Treasurer | |
|
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below on this 26th day of February 2009, by the following persons on behalf of the registrant and in the capacities indicated.
| | | | |
| Signature | | | | Title |
| | | | |
| /s/ PHILLIP D. WRIGHT * | | | | Management Committee Member and Senior Vice President |
| | | | |
| Phillip D. Wright | | | | (Principal Executive Officer) |
| | | | |
| /s/ RICHARD D. RODEKOHR* | | | | Vice President and Treasurer (Principal Financial |
| | | | |
| Richard D. Rodekohr | | | | Officer) |
| | | | |
| /s/ JEFFREY P. HEINRICHS * | | | | Controller and Assistant Treasurer (Principal Accounting Officer) |
| | | | |
| Jeffrey P. Heinrichs | | | | |
| | | | |
| /s/ STEVEN J. MALCOLM* | | | | Management Committee Member |
| | | | |
| Steven J. Malcolm | | | | |
| | | | |
| /s/ FRANK J. FERAZZI * | | | | Management Committee Member and Vice President |
| | | | |
| Frank J. Ferazzi | | | | |
| | | |
| |
| By /s/ JEFFREY P. HEINRICHS | |
| Jeffrey P. Heinrichs | |
| Attorney-in-fact | |
|
74
INDEX OF EXHIBITS
| 3.1* | | Certificate of Conversion and Certificate of Formation, dated December 24, 2008 and effective on December 31, 2008. |
|
| 3.2* | | Operating Agreement of Transco dated December 31, 2008. |
|
| 4.1 | | Indenture dated July 15, 1996 between Transco and Citibank, N.A., as Trustee (filed as Exhibit 4.1 to Transco Form S-3 dated April 2, 1996 Transco Registration Statement No. 333-2155) |
| |
| | | | | | |
- | | | 2 | 4.2 | | Indenture dated January 16, 1998 between Transco and Citibank, N.A., as Trustee (filed as Exhibit 4.1 to Transco Form S-3 dated September 8, 1997 Transco Registration Statement No. 333-27311) |
| |
| | | | | | |
- | | | 3 | 4.3 | | Indenture dated August 27, 2001 between Transco and Citibank, N.A., as Trustee (filed as Exhibit 4.1 to Transco Form S-4 dated November 8, 2001 Transco Registration Statement No. 333-72982) |
62
| | | | | | |
- | | | 4 | 4.4 | | Indenture dated July 3, 2002 between Transco and Citibank, N.A., as Trustee (filed as Exhibit 4.1 to The Williams Companies, Inc. Form 10-Q for the quarterly period ended June 30, 2002 Commission File Number 1-4174) |
| |
| | | | | | |
- | | | 5 | 4.5 | | Indenture dated December 17, 2004 between Transco and JPMorgan Chase, N.A., as trustee (filed as Exhibit 4.1 to Transco Form 8-K filed December 21, 2004) |
| |
| | | | | | |
- | | | 6 | 4.6 | | Indenture dated April 11, 2006 between Transco and JP Morgan Chase Bank, N.A., as trustee (filed as Exhibit 4.1 to Transco Form 8-K filed April 11, 2006). |
(10) Material contracts
| | | | | | | |
- | | | 1 | | | Transco Energy Company Tran$tock Employee Stock Ownership Plan (Transco Energy Company Registration Statement No. 33-11721) |
| | 4.7 | | Indenture, dated as of May 22, 2008 between Transco and The Bank of New York Trust Company, N.A. (filed as Exhibit 4.1 to our form 8-K filed May 23, 2008). | | |
| |
- | | | 2 | 10.1 | | Lease Agreement, dated October 23, 2003, between Transco and Transco Tower Limited, a Texas limited partnership as amended March 10, 2004, March 11, 2004, May 10, 2004, and June 25, 2004 (filed as Exhibit 10.2 to Transco Form 10-K filed March 30, 2005). |
| | | | | | | |
- | | | 3 | | | U.S. $1,275,000,000 Amended and Restated Credit Agreement dated as of May 20, 2005 among The Williams Companies, Inc., Northwest Pipeline Corporation, Transcontinental Gas Pipe Line Corporation, Williams Partner L.P., as Borrowers, Citicorp USA, Inc. as Administrative Agent and Collateral Agent, Citibank, N.A. and Bank of America, N.A. as Issuing Banks and The Banks Named Herein as Banks (filed as Exhibit 1.1 to the Transco Form 8-K filed May 26, 2005) |
| | | | | | | |
- | | | 4 | | | Registration Rights Agreement dated April 11, 2006 between Transco, Banc of America Securities LLC, Greenwich Capital Markets, Inc. and other parties listed therein, as Initial Purchasers (filed as Exhibit 10.1 to Transco Form 8-K filed April 11, 2006). |
| | | | | | |
- | | | 5 | 10.2 | | Credit Agreement, dated May 1, 2006, among The Williams Companies, Inc., Northwest Pipeline Corporation, Transcontinental Gas Pipe Line Corporation, and Williams Partners L.P., as Borrowers, and Citibank, N.A., as Administrative Agent (filed as Exhibit 10.1 to The Williams Companies, Inc. Form 8-K filed May 1, 2006 Commission File Number 1-4174). |
(23) Consent of Independent Registered Public Accounting Firm
(24) Power of attorney with certified resolution
63
(31) Section 302 Certifications
| | 10.3 | | Amendment Agreement, dated May 9, 2007, among The Williams Companies, Inc., Williams Partners L.P., Northwest Pipeline Corporation, Transcontinental Gas Pipe Line Corporation, certain banks, financial institutions and other institutional lenders and Citibank, N.A., as administrative agent (filed as Exhibit 10.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) filed with the SEC on May 15, 2007 and incorporated by reference as Exhibit 10.1 to our Form 8-K filed May 15, 2007). | | |
| |
- | 10.4 | | Amendment Agreement, dated November 21, 2007, among The Williams Companies, Inc., Williams Partners L.P., Northwest Pipeline Corporation, Transcontinental Gas Pipe Line Corporation, certain banks, financial institutions and other institutional lenders and Citibank, N.A., as administrative agent (filed as Exhibit 10.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) filed with the SEC on November 28, 2007 and incorporated by reference as Exhibit 10.1 to our Form 8-K filed November 28, 2007). |
|
| | 110.5 | | Registration Rights Agreement, dated as of May 22, 2008 between Transco and Banc of America Securities LLC, Greenwich Capital Markets, Inc., and J.P. Morgan Securities Inc., acting on behalf of themselves and the several initial purchasers listed on Schedule 1 thereto (filed as Exhibit 10.1 to our Form 8-K filed May 23, 2008). |
|
| 23* | | Consent of Independent Registered Public Accounting Firm |
|
| 24* | | Power of attorney |
|
| 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. |
| |
| | | | | | |
- | | | 2 | 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) Section 906 Certification
| | | | |
- | | 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. |
64
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, on this 2nd day of March 2007.
| | | | |
| TRANSCONTINENTAL GAS PIPE
LINE CORPORATION
(Registrant)
| |
| By: | /s/ Jeffrey P. Heinrichs | |
| | Jeffrey P. Heinrichs | |
| | Controller | |
|
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below on this 2nd day of March 2007, by the following persons on behalf of the registrant and in the capacities indicated.
| | |
Signature | | Title |
| | |
/s/ STEVEN J. MALCOLM* | | Chairman of the Board |
| | |
Steven J. Malcolm | | |
| | |
/s/ PHILLIP D. WRIGHT * | | Director and Senior Vice President |
| | |
Phillip D.Wright | | (Principal Executive Officer) |
| | |
/s/ FRANK J. FERAZZI * | | Director and Vice President |
| | |
Frank J. Ferazzi | | |
| | |
/s/ RICHARD D. RODEKOHR* | | Vice President and Treasurer (Principal Financial Officer) |
| | |
Richard D. Rodekohr | | |
| | |
/s/ JEFFREY P. HEINRICHS * | | Controller (Principal Accounting Officer) |
| | |
Jeffrey P. Heinrichs | | |
| | |
By /s/ JEFFREY P. HEINRICHS * | | |
| | |
Jeffrey P. Heinrichs | | |
Attorney-in-fact
| | Filed herewith |
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