UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
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| þ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
20132015OR |
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| ¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Commission file number 1-7584
TRANSCONTINENTAL GAS PIPE LINE COMPANY, 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)
| | (I.R.S. Employer Identification No.)
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2800 Post Oak Boulevard, Houston, Texas
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| (Address of Principal Executive Offices) | | (Zip Code) |
713-215-2000
(Registrant’s Telephone Number, Including Area Code)
Securities registered pursuant to Section 12(b) of the Act:
None
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No þ
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
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| Large accelerated filer | ¨ | Accelerated filer | ¨ | Non-accelerated filer | þ | Smaller reporting company | ¨ |
(Do not check if a smaller reporting company)
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No þ
DOCUMENTS INCORPORATED BY REFERENCE
None
REGISTRANT MEETS THE CONDITIONS SET FORTH IN GENERAL INSTRUCTIONS (I) (1)(a) AND (b) OF FORM 10-K AND IS THEREFORE FILING THIS FORM 10-K WITH THE REDUCED DISCLOSURE FORMAT.
TRANSCONTINTENTAL GAS PIPE LINE COMPANY, LLC
FORM 10-K
TABLE OF CONTENTS
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| Item 9A. | | | |
| Item 9B. | | | |
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| Item 10. | Directors, Executive Officers and Corporate Governance (Omitted) | | |
| Item 11. | Executive Compensation (Omitted) | | |
| Item 12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters (Omitted) | | |
| Item 13. | Certain Relationships and Related Transactions, and Director Independence (Omitted) | | |
| Item 14. | | | |
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| Item 15. | | | |
DEFINITIONS
We use the following gas measurements in this report:
Bcf – means billion cubic feet.
Mdth – means thousand dekatherms.
Mdth/d – means thousand dekatherms per day.
MMdth – means million dekatherms.
PART 1
Item 1. Business.Business
In this report, Transcontinental Gas Pipe Line Company, LLC (Transco) is at times referred to in the first person as “we”, “us” or “our”.
Transco is indirectly owned through Williams Partners Operating LLC (WPO), by Williams Partners L.P. (WPZ), a publicly traded Delaware limited partnership, which is consolidated by The Williams Companies, Inc. (Williams). On February 2, 2015, WPZ was merged into Access Midstream Partners, L.P. (ACMP), another publicly traded limited partnership consolidated by Williams. ACMP was the surviving partnership and was subsequently renamed Williams Partners L.P. At December 31, 2013,2015, Williams holds an approximate 6460 percent interest in WPZ, comprised of an approximate 6258 percent limited partner interest and all of WPZ’sthe 2 percent general partner interest.
On September 28, 2015, Williams publicly announced in a press release that it had entered into an Agreement and Plan of Merger (Merger Agreement) with Energy Transfer Equity, L.P. (Energy Transfer) and certain of its affiliates. The Merger Agreement provides that, subject to the satisfaction of customary closing conditions, Williams will be merged with and into the newly formed Energy Transfer Corp LP (ETC) (ETC Merger) with ETC surviving the ETC Merger. Energy Transfer formed ETC as a limited partnership that will be treated as a corporation for U.S. federal income tax purposes. Immediately following the completion of the ETC Merger, ETC will contribute to Energy Transfer all of the assets and liabilities of Williams in exchange for the issuance by Energy Transfer to ETC of a number of Energy Transfer Class E common units equal to the number of ETC common shares issued to Williams stockholders in the ETC Merger (ETC Exchange). WPZ expects to retain its current name and remain a publicly traded limited partnership following the ETC Merger.
GENERAL
We are an interstate natural gas transmission company that owns a natural gas pipeline system extending from Texas, Louisiana, Mississippi and the Gulf of Mexico through Alabama, Georgia, South Carolina, North Carolina, Virginia, Maryland, Delaware, Pennsylvania and New Jersey to the New York City metropolitan area. We also hold a minority interest in Cardinal Pipeline Company, LLC (Cardinal), an intrastate natural gas pipeline located in North Carolina. Our principal business is the interstate transportation of natural gas which is regulated by the Federal Energy Regulatory Commission (FERC).
At December 31, 2013,2015, our system had a mainline delivery capacity of approximately 5.96.4 MMdth of gas per day from production areas to our primary markets including delivery capacity from the mainline to locations on our Mobile Bay Lateral. Using our Leidy Line along with market-area storage and transportation capacity, we can deliver an additional 4.35.1 MMdth of gas per day for a system-wide delivery capacity total of approximately 10.211.5 MMdth of gas per day. The system is comprised of approximately 9,700 miles of mainline and branch transmission pipelines, 45 compressor stations, four underground storage fields and one liquefied natural gas (LNG) storage facility. Compression facilities at sea level rated capacity total approximately 1.71.8 million horsepower.
We have natural gas storage capacity in four underground storage fields located on or near our pipeline system and/or market areas, and we operate two of these storage fields. We also have storage capacity in an LNG storage facility that we own and operate. The total usable gas storage capacity available to us and our customers in such underground storage fields and LNG storage facility and through storage service contracts is approximately 200 Bcf of gas. At December 31, 2013,2015, our customers had stored in our facilities approximately 143161 Bcf of gas. In addition, through wholly-owned subsidiaries we operate and own a 35 percent interest in Pine Needle LNG Company, LLC (Pine Needle), an LNG storage facility with 4 Bcf of storage capacity. Storage capacity permits our customers to inject gas into storage during the summer and off-peak periods for delivery during peak winter demand periods.
MARKETS AND TRANSPORTATION
Our natural gas pipeline system serves customers in Texas and 12 southeast and Atlantic seaboard states including major metropolitan areas in Georgia, North Carolina, Washington, D.C., Maryland, New York, New Jersey and Pennsylvania.
Our major customers are public utilities and municipalities that provide service to residential, commercial, industrial and electric generation end users. Shippers on our pipeline system include public utilities, municipalities, intrastate pipelines, direct industrial users, electrical generators, gas marketers and producers. Our two largest customers in 20132015 were National Grid and Public Service Enterprise Group, and National Grid, which accounted for approximately 9.78.1 percent and 6.66.9 percent, respectively, of our total operating revenues. Our firm transportation agreements are generally long-term agreements with various expiration dates and account for the major portion of our business. Additionally, we offer interruptible transportation services under shorter-term agreements.
Our facilities are divided into eight rate zones. Five are located in the production area and three are located in the market area. Long-haul transportation is gas that is received in one of the production-area zones and delivered in
a market-area zone. Market-area transportation is gas that is both received and delivered within market-area zones. Production–area transportation is gas that is both received and delivered within production–area zones.
PIPELINE PROJECTS
The pipeline projects listed below were either completed during 20132015 or are significant future pipeline projects for which we have customer commitments. In 2014,2016, we expect to invest capital of approximately $660 million$1.1 billion in pipeline expansion projects.
Mid-South
The Mid-South Expansion Project involves an expansion of our mainline from Station 85 in Choctaw County, Alabama to markets as far downstream as North Carolina. In August 2011, we received approval from the FERC for the project. The capital cost of the project was approximately $202 million. We placed the first phase of the project into service in September 2012 which increased capacity by 95 Mdth/d. We placed the second phase of the project into service in June 2013 which increased capacity by an additional 130 Mdth/d.
Mid-Atlantic Connector
The Mid-Atlantic Connector Project involves an expansion of our mainline from an existing interconnection with East Tennessee Natural Gas in North Carolina to markets as far downstream as Maryland. In July 2011, we received approval from the FERC for the project. The capital cost of the project was approximately $60 million. We placed the project into service in the first quarter of 2013, and it increased capacity by 142 Mdth/d.
Northeast Supply Link
The Northeast Supply Link Project involves an expansion of our existing natural gas transmission system from the Marcellus Shale production region on the Leidy Line to various delivery points in Zone 6. In November 2012, we received approval from the FERC for the project. The capital cost of the project is estimated to be approximately $390 million. We placed a portion of the project into service in the third quarter of 2013 increasing capacity by 125 Mdth/d. We placed the remaining portion into service in November 2013, and it increased capacity by an additional 125 Mdth/d.
Rockaway Delivery Lateral
The Rockaway Delivery Lateral Project involves the construction of a three-mile offshore lateral to National Grid’s distribution system in New York. We filed an application withIn May 2014, we received approval from the FERC in January 2013 for approval of the project. We plan to placeplaced the project into service during the second halfquarter of 2014, and2015, which enabled us to begin providing 647 Mdth/d of firm service to National Grid through the capacity of the lateral is expected to be 647 Mdth/d.Rockaway Delivery Lateral.
Northeast Connector Project
The Northeast Connector Project involves an expansion of our existing natural gas transmission system from southeastern Pennsylvania to the proposed Rockaway Delivery Lateral. We filed an application with the FERC in April 2013 for approval of the project. We plan to place the project into service during the second half ofIn May 2014, and it is expected to increase capacity by 100 Mdth/d.
Virginia Southside
The Virginia Southside Project involves an expansion of our existing natural gas transmission system from the Zone 6 Station 210 Pooling Point in New Jersey to Dominion Virginia Power’s proposed power station in Brunswick County, Virginia, and both our Cascade Creek interconnect with East Tennessee Natural Gas and our Pleasant Hill delivery point to Piedmont Natural Gas Company, Inc. in North Carolina. In November 2013, we received approval from the FERC for the project. On December 1, 2014, we placed a portion of the project into service, which enabled us to begin providing 65 Mdth/d of additional firm transportation service from Station 195 in Pennsylvania to the Rockaway Delivery Lateral junction. We plan to placeplaced the remainder of the project into service during the thirdsecond quarter of 2015, and it is expected to increase2015. In total, the project increased capacity by 270 Mdth/d.
Leidy Southeast
The Leidy Southeast Project involves an expansion of our existing natural gas transmission system from the Marcellus Shale production region on the Leidy Line in Pennsylvania to the Station 85 pooling point in Alabama. We filed an application with the FERC in September 2013 for approval of the project. We plan to place the project into service during the fourth quarter of 2015, and it is expected to increase capacity by 525100 Mdth/d.
Mobile Bay South III
The Mobile Bay South III Project involves an expansion of the Mobile Bay line south from Station 85 in west central Alabama to delivery points along the line. We filed an application withIn April 2014, we received approval from the FERC for the project. On April 1, 2015, the project was placed into service, which enabled us to begin providing 225 Mdth/d of additional firm transportation service through the Mobile Bay Lateral.
Virginia Southside
The Virginia Southside Project involves an expansion of our existing mainline natural gas transmission system together with a new lateral to provide incremental firm transportation capacity from the Zone 6 Station 210 Pooling Point in JulyNew Jersey to Dominion Virginia Power’s power station under construction in Brunswick County, Virginia, and to both our Cascade Creek interconnection with East Tennessee Natural Gas and our Pleasant Hill delivery point to Piedmont Natural Gas Company, Inc. in North Carolina. In November 2013, we received approval from the FERC for approvalthe project. On December 1, 2014, we placed a portion of the project.project into service, which enabled us to begin providing 250 Mdth/d of additional firm transportation service through the mainline portion of the project on an interim basis, until the in-service date of the project as a whole. We plan to placeplaced the remainder of the project into service during the secondthird quarter of 2015. In total, the project increased capacity by 270 Mdth/d.
Leidy Southeast
The Leidy Southeast Project involves an expansion of our existing natural gas transmission system from the Marcellus Shale production region on the Leidy Line in Pennsylvania to the Station 85 Pooling Point in Choctaw County, Alabama. In December 2014, we received approval from the FERC for the project. On March 1, 2015, we began providing firm transportation service through the mainline portion of the project (from the Station 210 Pooling Point in New Jersey to the Station 85 Pooling Point in Alabama) on an interim basis, until the in-service date of the project as a whole. We placed 130 Mdth/d of full project capacity into service on December 1, 2015 and it is expectedincreased that amount to increase290 Mdth/d on December 30, 2015. We placed the remainder of the project into service during January 2016. In total, the project increased capacity on the line by 225525 Mdth/d.
Rock Springs Expansion
The Rock Springs Expansion Project involves an expansion of our existing natural gas transmission system southbound from the Zone 6 Station 210 Pooling Point in New Jersey along with a new, eleven mileeleven-mile lateral to Old Dominion Electric Cooperative's proposed Wildcat Point generation facility in Cecil County, Maryland. We plan to file an application with theIn March 2015, we received approval from FERC in the second quarter of 2014 for approval of the project. We plan to place the project into service during the third quarter of 2016, and it2016. The project is expected to increase capacity by 192 Mdth/d.
Gulf Trace
The Gulf Trace Expansion Project involves an expansion of our existing natural gas transmission system together with greenfield facilities to provide incremental firm transportation capacity from Station 65 in St. Helena Parish, Louisiana westward to a new interconnection with Sabine Pass Liquefaction in Cameron Parish, Louisiana. In October 2015, we received approval from the FERC for the project. We plan to place the project into service during the first quarter of 2017, assuming timely receipt of all necessary regulatory approvals, and it is expected to increase capacity by 1,200 Mdth/d.
Hillabee Expansion
The Hillabee Expansion Project involves an expansion of our existing natural gas transmission system from Transco'sour Station 85 pooling pointPooling Point in Choctaw County, Alabama to a proposed new interconnection with Sabal Trail Transmission's system in Tallapoosa County, Alabama. The project will be constructed in phases, and all of the project expansion capacity will be leased to Sabal Trail Transmission. We plan to file an application withIn February 2016, the FERC in the fourth quarter of 2014issued a certificate order for approval of the initial phases of the project. We may seek rehearing of certain aspects of the FERC order. We plan to place the initial phases of the project into service during the second quarterquarters of 2017 and 2020, assuming timely receipt of all necessary regulatory approvals, and together they are expected to increase capacity by 1,025 Mdth/d.
Atlantic Sunrise ExpansionDalton
The Atlantic SunriseDalton Expansion Project involves an expansion of our existing natural gas transmission system alongtogether with greenfield facilities to provide incremental firm transportation capacity from the Zone 6 Station 210 Pooling Point in New Jersey to markets in northwest Georgia. We filed an application with the FERC in March 2015 for approval of the project. We plan to place the project into service in 2017, assuming timely receipt of all necessary regulatory approvals, and it is expected to increase capacity by 448 Mdth/d.
Atlantic Sunrise
The Atlantic Sunrise Project involves an expansion of our existing natural gas transmission system together with greenfield facilities to provide incremental firm transportation capacity from the northeastern Marcellus producing area to markets along Transco'sour mainline as far south as Station 85 in Alabama. We plan to filefiled an application with the FERC in the second quarter ofMarch 2015 for approval of the project. We plan to place the project into service during the second half of 2017, assuming timely receipt of all necessary regulatory approvals, and it is expected to increase capacity by 1,700 Mdth/d.
Garden State
The Garden State Expansion Project involves an expansion of our existing natural gas transmission system to provide incremental firm transportation capacity from our Zone 6 Station 210 Pooling Point in New Jersey to a new interconnection on our Trenton Woodbury Lateral in Burlington County, New Jersey. The project will be constructed in phases. We filed an application with the FERC in February 2015 for approval of the project. We plan to place the initial phase of the project into service during the fourth quarter of 2016 and the remaining portion of the project into
service during the third quarter of 2017, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 180 Mdth/d.
Virginia Southside II
The Virginia Southside II Expansion Project involves an expansion of our existing natural gas transmission system together with greenfield facilities to provide incremental firm transportation capacity from the Zone 6 Station 210 Pooling Point in New Jersey and the Zone 5 Station 165 Pooling Point in Virginia to a proposed delivery point on a new lateral off of our Brunswick Lateral in Virginia. We filed an application with the FERC in March 2015 for approval of the project. We plan to place the project into service during the fourth quarter of 2017, assuming timely receipt of all necessary regulatory approvals, and it is expected to increase capacity by 250 Mdth/d.
New York Bay
The New York Bay Expansion Project involves an expansion of our existing natural gas transmission system to provide incremental firm transportation capacity from Station 195 in Pennsylvania to the Rockaway Delivery Lateral transfer point and the Narrows meter station in Richmond County, New York. We filed an application with the FERC in July 2015 for approval of the project. We plan to place the project into service during the fourth quarter of 2017, assuming timely receipt of all necessary regulatory approvals, and it is expected to increase capacity by 115 Mdth/d.
Gulf Connector
The Gulf Connector Expansion Project involves an expansion of our existing natural gas transmission system to provide incremental firm transportation capacity from Station 65 in Louisiana to delivery points in Wharton and San Patricio Counties, Texas. The project will be constructed in phases. We intend to file an application with the FERC in the third quarter of 2016. We plan to place the initial phase of the project into service during the second half of 2018 and the remaining phase in 2019, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 475 Mdth/d.
RATE MATTERS
Our transportation rates are established through the FERC ratemaking process. Key determinants in the ratemaking process are (1) costs of providing service, including depreciation expense, (2) allowed rate of return, including the equity component of the capital structure and related income taxes, and (3) contract and volume throughput assumptions. The allowed rate of return is determined in each rate case. Rate design and the allocation of costs between the reservation and commodity rates also impact profitability. As a result of these proceedings, certain revenues may be collected subject to refund. We record estimates of rate refund liabilities considering our and third-party regulatory proceedings, advice of counsel and other risks.
Since September 1, 1992, we have designed our rates using the straight fixed-variable (SFV) method of rate design. Under the SFV method of rate design, substantially all fixed costs, including return on equity and income taxes, are included in a reservation charge to customers and all variable costs are recovered through a commodity charge to customers. While the use of SFV rate design limits our opportunity to earn incremental revenues through increased throughput, it also limits our risk associated with fluctuations in throughput.
General rate case (Docket No. RP12-993) On August 31, 2012, we submitted to the FERC a general rate filing principally designed to recover increased costs and to comply with the terms of the settlement in our Docket No.
RP06-569 rate proceeding (see below) which required us to file a rate case no later than August 31, 2012. On September 28, 2012, the FERC issued an order accepting our filing subject to the outcome of a hearing. The rates for certain services that were proposed as overall rate decreases became effective October 1, 2012, without suspension. The increase rates became effective March 1, 2013, subject to refund and the outcome of the hearing. On August 27, 2013, after reaching an agreement in principle with the participants, we filed a stipulation and agreement (Agreement) proposing to resolve all issues in this proceeding without the need for a hearing. On December 6, 2013, the FERC issued an order approving the Agreement without modifications. Pursuant to its terms, the Agreement will become effective March 1, 2014. We have provided a reserve for rate refunds which we believe is adequate for required refunds as of December 31, 2013, under the Agreement. Refunds will be made on or before April 30, 2014.
General rate case (Docket No. RP06-569) On August 31, 2006, we submitted to the FERC a general rate filing principally designed to recover increased costs. The rates became effective March 1, 2007, subject to refund and the outcome of a hearing. All issues in this proceeding except one have been resolved by settlement.
The one issue reserved for litigation or further settlement relates to our proposal to change the design of the rates for service under one of our storage rate schedules, which was implemented subject to refund on March 1, 2007. A hearing on that issue was held before a FERC Administrative Law Judge (ALJ) in July 2008. In November 2008, the ALJ issued an initial decision in which he determined that our proposed incremental rate design is unjust and unreasonable. On January 21, 2010, the FERC reversed the ALJ’s initial decision and approved our proposed incremental rate design. Certain parties sought rehearing of the FERC’s order and, on April 2, 2012, the FERC denied the rehearing request. On June 1, 2012, one of the parties filed an appeal in the U.S. Court of Appeals for the D.C. Circuit (D.C. Circuit). On February 21, 2014, the D.C. Circuit issued an opinion that vacated and remanded the FERC's order because
the FERC did not adequately support its conclusions. On October 16, 2014, the FERC issued an order establishing a "paper hearing" and requesting briefs on certain questions raised by the D.C. Circuit's opinion. Parties to the proceeding filed initial and reply briefs on February 6, 2015 and March 6, 2015, respectively. We intend to continue to pursue approval of our proposed rate design. If we are unsuccessful, we believe anyit is reasonably possible that refunds would notcould be material to our results of operations.as much as $17.8 million at December 31, 2015.
REGULATION
FERC Regulation.
Our interstate transmission and storage activities are subject to regulation by the FERC under the Natural Gas Act of 1938, as amended (NGA), and under the Natural Gas Policy Act of 1978, as amended (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. The FERC’s Standards of Conduct govern the relationship between natural gas transmission providers and marketing function employees as defined by the rule. The standards of conduct are intended to prevent natural gas transmission providers from preferentially benefiting gas marketing functions by requiring the employees of a transmission provider that perform transmission functions to function independently from gas marketing employees and by restricting the information that transmission providers may provide to gas marketing employees. Under the Energy Policy Act of 2005, the FERC is authorized to impose civil penalties of up to $1 million per day for each violation of its rules.
Environmental Matters.
Our operations are subject to federal environmental laws and regulations as well as the state and local laws and regulations adopted by the jurisdictions in which we operate. We could incur liability to governments or third parties for any unlawful discharge of pollutants into the air, soil, or water, as well as liability for cleanup costs. Materials could be released into the environment in several ways including, but not limited to:
Leakage from gathering systems, underground gas storage caverns, pipelines, transportation facilities and storage tanks;
Damage to facilities resulting from accidents during normal operations;
Damages to onshore and offshore equipment and facilities resulting from storm events or natural disasters; and
Blowouts, cratering and explosions.
In addition, we may be liable for environmental damage caused by former operators of our properties.
We believe compliance with current environmental laws and regulations will not have a material adverse effect on our capital expenditures, earnings or competitive position. However, environmental laws and regulations could affect our business in various ways from time to time, including incurring capital and maintenance expenditures, fines and penalties, and creating the need to seek relief from the FERC for rate increases to recover the costs of certain capital expenditures and operation and maintenance expenses.
For additional information regarding the potential impact of federal, state or local regulatory measures on our business and specific environmental issues, please refer to “Risk Factors – Our operations are subject to environmental laws and regulations, including laws and regulations relating to climate change and greenhouse gas emissions, which may expose us to significant costs, liabilities and expenditures and could exceed current expectations,” and “Environmental Matters” in Note 2 of our Notes to Consolidated Financial Statements.
Safety and Maintenance.
Our operations are subject to the Natural Gas Pipeline Safety Act of 1968, as amended, the Pipeline Safety Improvement Act of 2002, and the Pipeline Safety, Regulatory Certainty, and Jobs Creation Act of 2011 (Pipeline Safety
Act), which regulatesregulate safety requirements in the design, construction, operation and maintenance of interstate natural gas transmission facilities. The U.S. Department of Transportation (USDOT) administers federal pipeline safety laws.
Federal pipeline safety laws authorize USDOT to establish minimum safety standards for pipeline facilities and persons engaged in the transportation of gas or hazardous liquids by pipeline. These safety standards apply to the design, construction, testing, operation, and maintenance of gas and hazardous liquids pipeline facilities affecting interstate or foreign commerce. USDOT has also established reporting requirements for operators of gas and hazardous liquid pipeline facilities, as well as provisions for establishing the qualification of pipeline personnel and requirements for managing the integrity of gas transmission and distribution lines and certain hazardous liquid pipelines. To ensure compliance with these provisions, USDOT performs pipeline safety inspections and has the authority to initiate enforcement actions.
On January 3, 2012, the Pipeline Safety Act was enacted. The Pipeline Safety Act requires USDOT to complete a number of reports in preparation for potential rulemakings. The issues addressed in these rulemaking provisions include, but are not limited to, the use of automatic or remotely-controlled shut-off valves on new or replaced transmission line facilities, modifying the requirements for pipeline leak detection systems, and expanding the scope of the pipeline integrity management requirements. USDOT is considering these and other provisions in the Pipeline Safety Act and has sought public comment on changes to the standards in its pipeline safety regulations.currently pending rulemaking proceedings.
Pipeline Integrity Regulations We have developed an Integrity Management Plan that we believe compliesin compliance with the United States Department of TransportationUSDOT Pipeline and Hazardous Materials Safety Administration (PHMSA) final rule that was issued pursuant to the requirements of the Pipeline Safety Improvement Act of 2002. The rule requires gas pipeline operators to develop an integrity management program for transmission pipelines that could affect high consequence areas in the event of pipeline failure. The Integrity Management programPlan includes a baseline assessment plan that was completed in 2012 along with periodic reassessments to be completed within required timeframes. In meeting the integrity regulations, we have identified high consequence areas and developed our baseline assessment plan. The required pipeline segments originally identified for assessment were completed withinas defined by the required timeframe, with one exception which was reported to PHMSA.rule. Ongoing periodic reassessments and initial assessments of any new high consequence areas will be completed within the timeframes required by the rule. We estimate that the cost to be incurred in 20142016 associated with this program towill be approximately $34 million, most of which we expect to be capital expenditures.$30 million. 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.
EMPLOYEES
Transco has no employees. Operations, management and certain administrative services are provided by Williams and its affiliates.
TRANSACTIONS WITH AFFILIATES
We engage in transactions with WPZ, Williams and other Williams’ subsidiaries. (See Note 1 and Note 7 of Notes to Consolidated Financial Statements.)
Item 1A. RISK FACTORSRisk Factors
FORWARD-LOOKING STATEMENTS AND CAUTIONARY STATEMENT FOR PURPOSES OF
THE “SAFE HARBOR” PROVISIONS OF
THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
Certain matters contained in this report includeThe reports, filings, and other public announcements of Transcontinental Gas Pipe Line Company, LLC may contain or incorporate by reference statements that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (Securities Act), and Section 21E of the Securities Exchange Act of 1934, as amended.amended (Exchange Act). These forward-looking statements relate to anticipated financial performance, management’s plans and objectives for future operations, business prospects, outcome of regulatory proceedings, market conditions and other matters. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995.
All statements, other than statements of historical facts, included in this report that address activities, events or developments that we expect, believe or anticipate will exist or may occur in the future are forward-looking statements. Forward-looking statements can be identified by various forms of words or phrases such as “anticipates,” “believes,” “seeks,” “could,” “may,” “should,” “continues,” “estimates,” “expects,” “assumes,” “forecasts,” “intends,” “might,” “goals,” “objectives,” “targets,” “planned,” “potential,” “projects,” “scheduled,” “will,” “guidance,” “outlook,” “in service date” or other similar expressions. These forward-looking statements are based on management’s beliefs and assumptions and on information currently available to management and include, among others, statements regarding:
The status, expected timing and expected outcome of the proposed ETC Merger;
Events which may occur subsequent to the proposed ETC Merger including events which directly impact our business;
Amounts and nature of future capital expenditures;
Expansion and growth of our business and operations;
Financial condition and liquidity;
Business strategy;
Cash flow from operations or results of operations;
Rate case filings;
Natural gas prices, supply and demand; and
Demand for our services.
Forward-looking statements are based on numerous assumptions, uncertainties, and risks that could cause future events or results to be materially different from those stated or implied in this report. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors that could cause actual results to differ from results contemplated by the forward-looking statements include, among others, the following:
The timing and likelihood of completion of the proposed ETC Merger, including the satisfaction of conditions to the completion of the proposed ETC Merger;
Energy Transfer's plans for us, following the completion of the proposed ETC Merger;
Disruption from the proposed ETC Merger making it more difficult to maintain business and operational relationships;
Availability of supplies, market demand, and volatility of prices;
Inflation, interest rates, and general economic conditions (including future disruptions and volatility in the global credit markets and the impact of these events on our customers and suppliers);
The strength and financial resources of our competitors and the effects of competition;
Whether we are able to successfully identify, evaluate and execute investment opportunities;
Development of alternative energy sources;
The impact of operational and development hazards and unforeseen interruptions;
Costs of, changes in, or the results of laws, government regulations (including safety and environmental regulations), environmental liabilities, litigation, and rate proceedings;
Our allocated costs for defined benefit pension plans and other postretirement benefit plans sponsored by our affiliates;
Changes in maintenance and construction costs;
Changes in the current geopolitical situation;
Our exposure to the credit risks of our customers and counterparties;
Risks related to financing, including restrictions stemming from our debt agreements, future changes in our credit ratings and the availability and cost of capital;
Risks associated with weather and natural phenomena including climate conditions;
Acts of terrorism, including cybersecurity threats and related disruptions; and
Additional risks described in our filings with the Securities and Exchange Commission (SEC).
Given the uncertainties and risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement, we caution investors not to unduly rely on our forward-looking statements. We disclaim any obligations to and do not intend to update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments.
In addition to causing our actual results to differ, the factors listed above and referred to below may cause our intentions to change from those statements of intention set forth in this report. Such changes in our intentions may also cause our results to differ. We may change our intentions, at any time and without notice, based upon changes in such factors, our assumptions, or otherwise.
Because forward-looking statements involve risks and uncertainties, we caution that there are important factors, in addition to those listed above, that may cause actual results to differ materially from those contained in the forward-looking statements. These factors are described in the following section.
RISK FACTORS
You should carefully consider the following risk factors in addition to the other information in this report. If any of the risks discussed below occur, our business, prospects, financial condition, results of operations, cash flows and, in some cases our reputation, could be materially adversely affected. 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.
Throughout these risk factors reference is made to Williams and the potential impact Williams may have on our business, financial condition and operating results. As noted above, Williams has entered into the Energy Transfer Merger Agreement with Energy Transfer and certain of its affiliates. Should the ETC Merger and the ETC Exchange each be consummated, references throughout these risk factors to Williams would instead refer to Energy Transfer or ETC, as applicable.
Risks Inherent to Our Industry and Business
Our natural gas transportation and storage activities involve numerous risks and hazards that might result in accidents and other operating risks and hazards.unforeseen interruptions.
Our operations are subject to all the risks and hazards typically associated with the transportation and storage of natural gas. These operating risks include,gas including, but are not limited to:
fires, blowouts, cratering, and explosions;
uncontrolled releases of natural gas;
pollution and other environmental risks;
aging infrastructure and mechanical problems;
damages to pipelines and pipeline blockages or other pipeline interruptions;
operator error; and
damage caused by third party activity, such as operation of construction equipment.
TheseAny of these risks could result in loss of human life, personal injuries, significant damage to property, environmental pollution, impairment of our operations, loss of services to our customers, reputational damage and substantial losses to us. 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. An event such as those described above could cause considerable harm and have a material adverse effect on our financial condition and results of operations, particularly if the event is not fully covered by insurance.
Certain of our services are subject to long-term, fixed-price contracts that are not subject to adjustment, even if our cost to perform such services exceeds the revenues received from such contracts.
We provide some services pursuant to long-term, fixed-price contracts. It is possible that costs to perform services under such contracts will exceed the revenues we collect for our services. Although most of the services are priced at
cost-based rates that are subject to adjustment in rate cases, under the FERC policy, a regulated service provider and a customer may mutually agree to sign a contract for service at a “negotiated rate” that may be above or below the FERC regulated cost-based rate for that service. These “negotiated rate” contracts are not generally subject to adjustment for increased costs that could be produced by inflation or other factors relating to the specific facilities being used to perform the services.
We may not be able to extend or replace expiring natural gas transportation and storage contracts at favorable rates, on a long-term basis or at all.
Our primary exposure to market risk occurs at the time the terms of existing transportation and storage contracts expire andor are subject to termination. Upon expiration or termination of the terms,our existing contracts, we may not be able to extend such contracts with existing customers or obtain replacement contracts at favorable rates, on a long-term basis or at all. 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. Our ability to extend or replace existing customer contracts on favorable terms is subject to a number of factors, some of which are beyond our control, including:
the level of existing and new competition to deliver natural gas to our markets and competition from alternative fuel sources such as electricity, coal, fuel oils or nuclear energy;
Pricing,pricing, demand, availability and margins for natural gas in our markets;
whether the market will continue to support long-term firm contractscontracts;
the effects of regulation on us, our customers and our contracting practices; and
the ability to understand our customers'customers’ expectations, efficiently and reliably deliver high quality services and effectively manage customer relationships. The results of these efforts will impact our reputation and positioning in the market.
Competitive pressures could lead to decreases in the volume of natural gas contracted for or transported through our pipeline system.
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. Although most of our pipeline system’s current capacity is fully contracted, the FERC has taken certain actions to strengthen market forces in the interstate natural gas pipeline industry that have led to increased competition throughout the industry. Similarly, a highly-liquidhighly liquid competitive commodity market in natural gas and increasingly competitive markets for natural gas services, including competitive secondary markets in pipeline capacity, have developed. As a result, pipeline capacity is being used more efficiently, and peaking and storage services are increasingly effective substitutes for annual pipeline capacity. As a result, we could experience some "turnback" “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.
We compete primarily with other interstate pipelines and storage facilities in the transportation and storage of natural gas. Some of our competitors may have greater financial resources and access to greater supplies of natural gas than we do. Some of these competitors may expand or construct transportation and storage systems that would create additional competition for natural gas supplies or the services we provide to our customers. Moreover, WPZ and its other affiliates, including Williams, may not be limited in their ability to compete with us. In a number of key markets, interstate pipelines are now facing competitive pressure from other major pipeline systems, enabling local distribution companies and end users to choose a transmission provider based on considerations other than location. Other entities could construct new pipelines or expand existing pipelines that could potentially serve the same markets as our pipeline system. Any such new pipelines could offer transportation services that are more desirable to shippers because of locations, facilities, or other factors. These new pipelines could charge rates or provide service to locations that would result in greater net profit for shippers and producers and thereby force us to lower the rates charged for service on our pipeline in order to extend our existing transportation service agreements or to attract new customers. We are aware of proposals by competitors to expand pipeline capacity in certain markets we also serve which, if the proposed projects proceed, could increase the competitive pressure upon us. Further, natural gas also competes with
other forms of energy available to our customers, including electricity, coal, fuel oils, and other alternative energy
sources. We may not be able to successfully compete against current and future competitors and any failure to do so could have a material adverse effect on our business, cash flows and results of operations.
Any significant decrease in supplies of natural gas in the supply basins we access or in demand for those supplies in our traditional markets could adversely affect our business and operating results.
Our ability to maintain and expand our business depends on the level of drilling and production by third parties in our supply basins. 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 existing wells may also be less than anticipated, and the rate at which production from these reserves declines may be greater than anticipated. We do not obtain independent evaluations of natural gas reserves underlying such wells and supply basins with access to our pipeline. Accordingly, we do not have independent estimates of total reserves dedicated to our pipeline or the anticipated life of such reserves. In addition, low prices for natural gas, regulatory limitations, including environmental regulations, or the lack of available capital for these projects could adversely affect the development and production of additional reserves, as well as gathering, storage, pipeline transportation, and import and export of natural gas supplies. The competition for natural gas supplies to serve other markets could also reduce the amount of natural gas supply for our customers.
Demand for our transportation services depends on the ability and willingness of shippers with access to our facilities to satisfy demand in the markets we serve 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, orand technological advances in fuel economy and energy generation devices, all of which are matters beyond our control.
A failure to obtain sufficient natural gas supplies or a reduction in demand for our services in the markets we serve could have a material adverse effect on our business, financial condition and results of operations.
Significant prolonged changes in natural gas prices could affect supply and demand and cause a reduction in or termination of our long-term transportation and storage contracts or throughput on our system.
Higher natural gas prices over the long term could result in a decline in the demand for natural gas and, therefore, in our long-term transportation and storage contracts or throughput on our system. Also, lower natural gas prices over the long term could result in a decline in the production of natural gas resulting in reduced contracts or throughput on our system. As a result, significant prolonged changes in natural gas prices could have a material adverse effect on our business, financial condition, results of operations, and cash flows.
Our costs of testing, maintaining or repairing our facilities may exceed our expectations, and the FERC may not allow, or competition in our markets may not allow us to recoverprevent our recovery of such costs in the rates we charge for our services.
We have experienced and could experience in the future unexpected leaks or ruptures on our gas pipeline system. Either as a preventative measure or in response to a leak or another issue, we could be required by regulatory authorities to test or undertake modifications to our systems. If the cost of testing, maintaining or repairing our facilities exceed expectations and the FERC does not allow us to recover, or competition in our markets do not allowprevents us to recoverfrom recovering such costs in the rates that we charge for our services, such costs could have a material adverse impact on our business, financial condition and results of operations.
Legal and regulatory proceedings and investigations relating to the energy industry have adversely affected our business and may continue to do so. The operation of our businesses might also be adversely affected by changes in government regulations or in their interpretation or implementation, or the introduction of new laws or regulations applicable to our businesses or our customers.
Public and regulatory scrutiny of the energy industry has resulted in the proposal and/or implementation of increased regulations. Such scrutiny has also resulted in various inquiries, investigations and court proceedings, including litigation of energy industry matters. Both the shippers on our pipeline and regulators have rights to challenge the rates we charge under certain circumstances. Any successful challenge could materially affect our results of operations.
Certain inquiries, investigations and court proceedings are ongoing. Adverse effects may continue as a result of the uncertainty of these ongoing inquiries, investigations and court proceedings, or additional inquiries and proceedings
by federal or state regulatory agencies or private plaintiffs. In addition, we cannot predict the outcome of any of these inquiries or whether these inquiries will lead to additional legal proceedings against us, civil or criminal fines and/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 including environmental matters, suits, regulatory appeals and similar matters might result in adverse decisions against us which, among other outcomes, could result in the imposition of substantial penalties and fines and could damage our reputation. The result of such adverse decisions, either individually or in the aggregate, could be material and may not be covered fully or at all by insurance.
In addition, existing regulations might be revised or reinterpreted and new laws and regulations might be adopted or become applicable to us, our facilitiescustomers or our customers.business activities. If new laws or regulations are imposed relating to oil and gas extraction, or if additional levels of reporting, regulation or permitting moratoria are required or imposed, including those related to hydraulic fracturing, the volumes of natural gas that we transport could decline and our results of operations could be adversely affected.
Our operations are subject to environmental laws and regulations, including laws and regulations relating to climate change and greenhouse gas emissions, which may expose us to significant costs, liabilities and expenditures that could exceed our expectations.
Our operations are subject to extensive federal, state and local laws and regulations governing environmental protection, endangered and threatened species, the discharge of materials into the environment and the security of chemical and industrial facilities. Substantial costs, liabilities, delays and other significant issues related to environmental laws and regulations are inherent in the gathering, transportation, and storage of natural gas as well as waste disposal practices.practices and construction activities. New or amended environmental laws and regulations can also result in significant increases in capital costs we incur to comply with such laws and regulations.
Failure to comply with laws, regulations and permits may result in the assessment of administrative, civil and/or criminal penalties, the imposition of remedial obligations, the imposition of stricter conditions on or revocation of permits, the issuance of injunctions limiting or preventing some or all of our operations and delays in granting permits.
Joint and several, strict liability may be incurred without regard to fault under certain environmental laws and regulations for the remediation of contaminated areas and in connection with spills or releases of materials associated with natural gas, oil and wastes on, under or from our properties and facilities. Private parties, including the owners of properties through which our pipeline system passes and facilities where our wastes are taken for reclamation or disposal, may have the right to pursue legal actions to enforce compliance as well as to seek damages for noncompliance with environmental laws and regulations or for personal injury or property damage arising from our operations. Some sites at which we operate are located near current or former third-partythird party hydrocarbon storage and processing or oil and natural gas operations or facilities, and there is a risk that contamination has migrated from those sites to ours.
We are generally responsible for all liabilities associated with the environmental condition of our facilities and assets, whether acquired or developed, regardless of when the liabilities arose and whether they are known or
unknown. In connection with certain acquisitions and divestitures, we could acquire, or be required to provide indemnification against, environmental liabilities that could expose us to material losses, which may not be covered by insurance. In addition, the steps we could be required to take to bring certain facilities into compliance could be prohibitively expensive, and we might be required to shut down, divest or alter the operation of those facilities, which might cause us to incur losses.
In addition, climate change and the costs that may be associated with its impacts and with the regulation of emissions of greenhouse gases (GHG) have the potential to affect our business. Regulatory actions by the EPAU.S. Environmental Protection Agency (EPA) or the passage of new climate change laws or regulations could result in increased costs to (i) operate and maintain our facilities, (ii) install new emissions controls on our facilities and (iii) administer and manage any GHG emissions program. If we are unable to recover or pass through a significant level of our costs related to complying with climate change regulatory requirements imposed on us, it could have a material
adverse effect on our results of operations and financial condition. To the extent financial markets view climate change and GHG emissions as a financial risk, this could negatively impact our cost of and access to capital. Climate change and GHG regulation could also reduce demand for our 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. Although some of these customers are subject to long-term contracts, we may be unable to negotiate extensions or replacements of these contracts on favorable terms, or at all. For the year ended December 31, 2013,2015, our two largest customers were Public Service Enterprise Group andcustomer was National Grid. These customersGrid, which accounted for approximately 9.78.1 percent and 6.6 percent, respectively, of our operating revenues for the year ended December 31, 2013.revenues. The loss of all, or even a portion of, the revenues from contracted volumes supplied by 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, results of operations, financial condition, and cash flows, unless we are able to acquire comparable volumes from other sources.
We are exposed to the credit risk of our customers and counterparties and our credit risk management maywill not be adequateable to protect againstcompletely eliminate such risk.
We are subject to the risk of loss resulting from nonpayment and/or nonperformance by our customers and counterparties in the ordinary course of our business. Generally, our customers are rated investment grade, are otherwise considered creditworthy, or are required to make pre-payments or provide security to satisfy credit concerns. However, our credit procedures and policies maywill not be adequate to fullycompletely eliminate customer credit risk. Our customers and counterparties include industrial customers, local distribution companies, natural gas producers and marketers whose creditworthiness may be suddenly and disparately impacted by, among other factors, commodity price volatility, deteriorating energy market conditions, and public and regulatory opposition to energy producing activities. The current low commodity price environment has, in particular, negatively impacted natural gas producers causing them significant economic stress including, in some cases, to file for bankruptcy protection or to renegotiate contracts. To the extent one or more of our key customers commences bankruptcy proceedings, our contracts with the customers may be subject to rejection under applicable provisions of the United States Bankruptcy Code, or may be renegotiated. Further, during any such bankruptcy proceeding, prior to assumption, rejection or renegotiation of such contracts, the bankruptcy court may temporarily authorize the payment of value for our services less than contractually required, which cold have a material adverse effect on our business, results of operations, cash flows and financial condition. If we fail to adequately assess the creditworthiness of existing or future customers and counterparties, unanticipatedor otherwise do not take sufficient mitigating actions, including obtaining sufficient collateral, deterioration in their creditworthiness and any resulting increase in nonpayment and/or nonperformance by them could cause us to write down or write off doubtful accounts.accounts receivable. Such write-downs or write-offs could negatively affect our operating results for the period in which they occur, and, if significant, could have a material adverse effect on our business, results of operations, cash flows, and financial condition.
If third-party pipelines and other facilities interconnected to our pipeline and facilities become unavailable to transport natural gas, our revenues could be adversely affected.
We depend upon third-party pipelines and other facilities that provide delivery options to and from our pipeline and storage facilities for the benefit of our customers. Because we do not own these third-party pipelines or facilities, their continuing operation is not within our control. If these pipelines or other facilities were to become temporarily or permanently unavailable for any reason, or if throughput were reduced because of testing, line repair, damage to pipelines or facilities, reduced operating pressures, lack of capacity, increased credit requirements or rates charged by such pipelines or facilities or other causes, we and our customers would have reduced capacity to transport, store or deliver natural gas to end use markets, thereby reducing our revenues. Any temporary or permanent interruption at any key pipeline interconnectinterconnection causing a material reduction in volumes transported on our pipeline or stored at our facilities could have a material adverse effect on our business, financial condition, results of operations and cash flows.
We do not own all of the land on which our pipeline and facilities are located, which could disrupt our operations.
We do not own all of the land on which our pipeline and facilities have been constructed. As such, we are subject to the possibility of increased costs to retain necessary land use. In those instances in which we do not own the land on which our facilities are located, we obtain the rights to construct and operate our pipeline on land owned by third parties and governmental agencies for a specific period of time. Our loss of any of these rights, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations, financial condition, and cash flows.
We do not insure against all potential risks and losses and could be seriously harmed by unexpected liabilities or by the inability of our insurers to satisfy our claims.
In accordance with customary industry practice, we maintain insurance against some but not all risks and losses, and only at levels we believe to be appropriate.
Williams currently maintains excess liability insurance with limits of $610$820 million per occurrence and in the annual aggregate with a $2 million per occurrence deductible. This insurance covers Williams, its subsidiaries, and certain of its affiliates, including us, for legal and contractual liabilities arising out of bodily injury or property damage, including resulting loss of use to third parties. This excess liability insurance includes coverage for sudden and accidental pollution liability for full limits, with the first $135 million of insurance also providing gradual pollution liability coverage for natural gas and natural gas liquids operations.
Although we maintain property insurance on certain physical assets that we own, lease, or are responsible to insure, the policy may not cover the full replacement cost of all damaged assets or the entire amount of business interruption loss we may experience. In addition, certain perils may be excluded from coverage or sub-limited. We may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. We may elect to selfself- insure a portion of our risks. We do not insure our onshore underground pipelines for physical damage, except at certain locations such as river crossings and compressor stations. Offshore assets are covered for property damage when loss is due to a named windstorm event and coverage for loss caused by a named windstorm is significantly sub-limited and subject to a large deductible. All of our insurance is subject to deductibles.
In addition to the insurance coverage described above, Williams is a member of Oil Insurance Limited (OIL), an energy industry mutual insurance company, which provides coverage for damage to our property. As an insured member of OIL, Williams shares in the losses among other OIL members even if our property is not damaged. As a result, we may share in any losses incurred by Williams.
The occurrence of any risks not fully covered by insurance could have a material adverse effect on our business, financial condition, results of operations and cash flows, and our ability to repay our debt.
We may not be able to grow or effectively manage our growth.
As part of our growth strategy, we consider acquisition opportunities and engage in significant capital projects. We recently implemented ourhave a project lifecycle process and refocused ouran investment evaluation process. These are processes we use to identify, evaluate and execute on acquisition opportunities and capital projects. We may not always have sufficient and accurate information to identify and value potential opportunities and risks or our investment evaluation process may be incomplete or flawed. Regarding potential acquisitions, suitable acquisition candidates may not be available on terms and conditions we find acceptable or, where multiple parties are trying to acquire an acquisition candidate, we may not be chosen as the acquirer. If we are able to acquire a targeted business, we may not be able to successfully integrate the acquired businesses and realize anticipated benefits in a timely manner. Our growth may also be dependent upon the construction of new natural gas gathering, transportation, compression, processing or treating pipelines and facilities, NGL transportation, fractionation or storage facilities or olefins processing facilities, as well as the expansion of existing facilities. We also face all the risks associated with construction. These risks include the inability to obtain skilled labor, equipment, materials, permits, rights-of-way and other required inputs in a timely manner such that projects are completed on time and the risk that construction cost overruns could cause total project costs to exceed budgeted costs. Additional risks associated with growing our business include, among others, that:
changing circumstances and deviations in variables could negatively impact our investment analysis, including our projections of revenues, earnings and cash flow relating to potential investment targets, resulting in outcomes which are materially different than anticipated;
Wewe could be required to contribute additional capital to support acquired businesses or assets. We may assume liabilities that were not disclosed to us, that exceed our estimates and for which contractual protections are either unavailable or prove inadequate;
Acquisitionsacquisitions could disrupt our ongoing business, distract management, divert financial and operational resources from existing operations and make it difficult to maintain our current business standards, controls and procedures; and
Acquisitionsacquisitions and capital projects may require substantial new capital, either by the issuance of debt or equity, and we may not be able to access credit or capital markets or obtain acceptable terms.
If realized, any of these risks, including impairments, could have an adverse impact on our results of operations, financial position or cash flows.
Failure of our service providers or disruptions to outsourcing relationships might negatively impact our ability to conduct our business.
We rely on Williams and other third parties for certain services necessary for us to be able to conduct our business. We have a limited ability to control these operations and the associated costs. Certain of Williams’ accounting and information technology functions that we rely on are currently provided by third party vendors, and sometimes from service centers outside of the United States. Services provided pursuant to these agreements could be disrupted. Similarly, the expiration of such agreements or the transition of services between providers could lead
to loss of institutional knowledge or service disruptions. Our reliance on Williams and others as service providers and on Williams’ outsourcing relationships, and our limited ability to control certain costs, could have a material adverse effect on our business, results of operations and financial condition.
The pendency of the proposed ETC Merger between Energy Transfer and Williams could adversely affect our business and operations.
The proposed ETC Merger between Energy Transfer and Williams may create a significant distraction for the management team and board of directors of Williams and require Williams to expend significant time and resources. As certain members of Williams’ management team also serve on our management team we may encounter the same management distraction and constraints. In connection with the proposed ETC Merger some of our customers or vendors may delay or defer decisions, which could negatively impact our revenues, earnings, cash flows and expenses regardless of whether the proposed ETC Merger is completed. Similarly, current and prospective employees of Williams and its affiliates that provide services to us may experience uncertainty about their future roles following the proposed ETC Merger, which may materially adversely affect Williams’ ability to attract and retain such key personnel during the pendency of the proposed ETC Merger. If Energy Transfer and Williams fail to complete the proposed ETC Merger, it may be difficult and expensive for Williams to recruit and hire replacements for departed employees. The proposed ETC Merger, its effects and related matters may also distract the Williams employees that provide services to us from day-to-day operations and require substantial commitments of time and resources. Moreover, the proposed ETC Merger may disrupt our business by causing uncertainty among our suppliers, customers and investors. In addition, due to operating covenants in the Merger Agreement, we may be unable, during the pendency of the proposed ETC Merger, to pursue certain strategic transactions, undertake certain significant capital projects, undertake certain significant financing transactions and otherwise pursue other actions that are not in the ordinary course of business. Such risks relating to vendors, customers, employees and those risks arising from operating covenants in the Merger Agreement will also apply to varying degrees our affiliates thereby have a corresponding impact on us.
Risks Related to Strategy and Financing
Restrictions in our debt agreements and the amount of our indebtedness may affect our future financial and operating flexibility.
Our total outstanding long-term debt (including current portion) as of December 31, 2013,2015, was $1,428.4$1,419.6 million.
The agreements governing our indebtedness contain covenants that restrict our ability to incur certain liens to support indebtedness and our ability to merge or consolidate or sell all or substantially all of our assets. In addition, certain of our debt agreements contain various covenants that restrict or limit, among other things, our ability to make certain distributions during the continuation of an event of default and our ability to enter into certain affiliate transactions and certain restrictive agreements and to change the nature of our business. Certain of our debt agreements also contain, and those we enter into in the future may contain, financial covenants and other limitations with which we will need to comply. Williams’ and WPZ’s debt agreements contain similar covenants with respect to such entities and their respective subsidiaries, including us.
Our debt service obligations and the covenants described above could have important consequences. For example, they could:could, among other things:
Makemake it more difficult for us to satisfy our obligations with respect to our indebtedness, which could in turn result in an event of default on such indebtedness;
Impairimpair our ability to obtain additional financing in the future for working capital, capital expenditures, general limited liability company purposes or other purposes;
Diminishdiminish our ability to withstand a continued or future downturn in our business or the economy generally;
Requirerequire us to dedicate a substantial portion of our cash flow from operations to debt service payments, thereby reducing the availability of cash for working capital, capital expenditures, general limited liability company purposes or other purposes; and
Limitlimit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate, including by limiting our ability to expand or pursue our business activities and by preventing us from engaging in certain transactions that might otherwise be considered beneficial to us.
Our ability to comply with our debt covenants, to repay, extend or refinance our existing debt obligations and to obtain future credit will depend primarily on our operating performance. Our ability to refinance existing debt obligations or obtain future credit will also depend upon the current conditions in the credit markets and the availability of credit generally. If we are unable to comply with these covenants, meet our debt service obligations or obtain future credit on favorable terms, or at all, we could be forced to restructure or refinance our indebtedness, seek additional equity capital or sell assets. We may be unable to obtain financing or sell assets on satisfactory terms, or at all.
Our failure to comply with the covenants in the documents governing our indebtedness could result in events of default, which could render such indebtedness due and payable. We may not have sufficient liquidity to repay our indebtedness in such circumstances. In addition, cross-default or cross-acceleration provisions in our debt agreements
could cause a default or acceleration to have a wider impact on our liquidity than might otherwise arise from a default or acceleration of a single debt instrument. For more information regarding our debt agreements, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity”.
Our ability to obtain credit in the future could be affected by Williams’ and WPZ’s credit ratings.
Substantially all of Williams’ and WPZ’s operations are conducted through their respective subsidiaries. Each of Williams’ and WPZ’s cash flows are substantially derived from loans, dividends and distributions paid to them by their subsidiaries. Their cash flows are typically utilized to service debt and pay dividends or distributions on their equity, with the balance, if any, reinvested in their respective subsidiaries as loans or contributions to capital. Due to our relationshipsrelationship with each of Williams and WPZ, our ability to obtain credit will be affected by Williams’ and WPZ’s credit ratings. Both Williams and WPZ have recently been downgraded. If Williams or WPZ were to experience a further deterioration in theirits respective credit standing or financial condition, our access to creditcapital and our ratings could be adversely affected. Any futurefurther downgrading of a Williams or WPZ credit rating could result in a downgrading of our credit rating. A downgrading of a Williams or WPZ credit rating could limit our ability to obtain financing in the future upon favorable terms, if at all.
Difficult conditions in the global financial markets and the economy in general could negatively affect our business and results of operations.
Our business may be negatively impacted by adverse economic conditions or future disruptions in the global financial markets. Included among these potential negative impacts are industrial or economic contraction leading to reduced energy demand and lower prices for our products and services and increased difficulty in collecting amounts owed to us by our customers. We have availability under the credit facility, but our ability to borrow under that facility could be impaired if one or more of our lenders fails to honor its contractual obligation to lend to us. If financing is not available when needed, or is available only on unfavorable terms, we may be unable to implement our business plans or otherwise take advantage of business opportunities or respond to competitive pressures. In addition, financial markets have recentlyperiodically been affected by concerns over U.S. fiscal policy, including uncertainty regarding federal spending and tax policy, as well as the U.S. federal government’s debt ceiling and the federal deficit.monetary policies. These concerns, as well as actions taken by the U.S. federal government in response to these concerns, could significantly and adversely impact the global and U.S. economies and financial markets, which could negatively impact us in the mannersmanner described above.
A downgrade of our credit ratings, which are determined outside of our control by independent third parties, could impact our liquidity, access to capital and our costs of doing business.
AOur credit ratings have recently been downgraded. Any further downgrade of our credit ratings might increase our cost of borrowing and could require us to provide collateral to our counterparties, negatively impacting our available liquidity. In addition, our ability to access capital markets could be limited by a downgrade of our credit ratings as well as by economic, market or other disruptions.ratings. Credit rating agencies perform independent analysis when assigning credit ratings. The analysis includes a number of criteria such as business composition, market and operational risks, as well as various financial tests. Credit rating agencies continue to review the criteria for industry sectors and various debt ratings and may make changes to those criteria from time to time. Credit ratings are subject to revision or withdrawal at any time by the ratings agencies.
WPZ can exercise substantial control over our distribution policy and our business and operations and may do so in a manner that is adverse to our interests.
Because we are an indirect wholly-owned subsidiary of WPZ, WPZ exercises substantial control over our business and operations and makes determinations with respect to, among other things, the following:
payment of distributions and repayment of advances;
decisions on financings and our capital raising activities;
mergers or other business combinations; and
acquisition or disposition of assets.
WPZ could decide to increase distributions or advances to our member consistent with existing debt covenants. This could adversely affect our liquidity.
Risks Related to Regulations That Affect Our Industry
Our natural gas transportation and storage operations are subject to regulation by the FERC, which could have an adverse impact on our ability to establish transportation and storage rates that would allow us to recover the full cost of operating our pipeline, including a reasonable rate of return.
In addition to regulation by other federal, state, and local regulatory authorities, under the Natural Gas Act of 1938,NGA, our interstate pipeline transportation and storage services and related assets are subject to regulation by the FERC. Federal regulation extends to such matters as:
transportation of natural gas in interstate commerce;
rates, operating terms, types of services offered to customers and conditions of service;
the types of services we may offer to our customers;
certification and construction of new interstate pipelinespipeline and storage facilities;
acquisition, extension, disposition, or abandonment of existing interstate pipelines and storage facilities;
accounts and records;
depreciation and amortization policies;
relationships with affiliated companies who are involved in marketing functions of the natural gas business; and
market manipulation in connection with interstate sales, purchases, or transportation of natural gas.
Regulatory or administrative actions in these areas, including successful complaints or protests against our rates, can affect our business in many ways, including by decreasing existing tariff rates or setting future tariff rates to levels such that revenues are inadequate to recover increases in operating costs or to sustain an adequate return on capital investments, decreasing volumes in our pipelines, increasing our costs and otherwise altering the profitability of our business.
Unlike other interstate pipelines that own facilities in the offshore Gulf of Mexico, we charge our transportation customers a separate fee to access our offshore facilities. The separate charge is referred to as an “IT feeder” charge. The “IT feeder” rate is charged only when gas is actually transported on the facilities and typically it is paid by producers or marketers. Because the “IT feeder” rate is typically paid by producers and marketers, it generally results in netback prices to producers that are slightly lower than the netbacks realized by producers transporting on other interstate pipelines. This rate design disparity can result in producers bypassing our offshore facilities in favor of alternative transportation facilities.
The outcome of future rate cases will determine the amount of income taxes that we will be allowed to recover.
In May 2005, the FERC issued a statement of general policy permitting a pipeline to include in its cost-of-service computations an income tax allowance provided that an entity or individual has an actual or potential income tax liability on income from the pipeline’s public utility assets. The extent to which owners of pipelines have such actual or potential income tax liability will be reviewed by the FERC on a case-by-case basis in rate cases where the amounts of the allowances will be established.
Risks Related to Employees, Outsourcing of Non-Core Support Activities, and Technology.Technology
Institutional knowledge residing with current Williams' employees nearing retirement eligibility or, with former Williams' employees might not be adequately preserved.
We expect that a significant percentage of Williams' employees will become eligible for retirement over the next threeseveral years. In our business, institutional knowledge resides with employees who have many years of service. As these employees reach retirement age, or their service is no longer available, Williams may not be able to replace them with employees of comparable knowledge and experience. In addition, Williams may not be able to retain or recruit other qualified individuals, and Williams’ efforts at knowledge transfer could be inadequate. If knowledge transfer, recruiting and retention efforts are inadequate, access to significant amounts of internal historical knowledge and expertise could become unavailable to us.
Our allocation from Williams for costs for its defined benefit pension plans and other postretirement benefit plans are affected by factors beyond our and Williams’ control.
As we have no employees, employees of Williams and its affiliates provide services to us. As a result, we are allocated a portion of Williams’ costs in defined benefit pension plans covering substantially all of Williams’ or its affiliates’ employees providing services to us, as well as a portion of the costs of other postretirement benefit plans covering certain eligible participants providing services to us. The timing and amount of our allocations under the defined benefit pension plans depend upon a number of factors that Williams controls, including changes to pension plan benefits, as well as factors outside of Williams’ control, such as asset returns, interest rates and changes in pension laws. Changes to these and other factors that can significantly increase our allocations could have a significant adverse effect on our financial condition and results of operations.
Risks Related to Weather, Other Natural Phenomena and Business Disruption
Our assets and operations, as well as our customers' customers’ assets and operations, can be affected by weather and other natural phenomena.
Our assets and operations, especially those located offshore, and our customers' assets and operations can be adversely affected by hurricanes, floods, earthquakes, landslides, tornadoes and other natural phenomena and weather conditions, including extreme or unseasonable temperatures, making it more difficult for us to realize the historic rates of return associated with our assets and operations. A significant disruption in our or our customers' operations or the occurrence of a significant liability for which we were not fully insured could have a material adverse effect on our business, results of operations, and financial condition.
Acts of terrorism could have a material adverse effect on our financial condition, results of operations and cash flows.
Given the volatile nature of the commodities we transport and store, our assets and the assets of our customers and others in our industry may be targets of terrorist activities. A terrorist attack could create significant price volatility, disrupt our business, limit our access to capital markets or cause significant harm to our operations, such as full or partial disruption to our ability to transport natural gas. Acts of terrorism, as well as events occurring in response to or in connection with acts of terrorism, could cause environmental repercussions that could result in a significant decrease in revenues or significant reconstruction or remediation costs, which could have a material adverse effect on our financial condition, results of operations, and cash flows.
Our business could be negatively impacted by security threats, including cybersecurity threats, and related disruptions.
We rely on our information technology infrastructure to process, transmit and store electronic information, including information we use to safely operate our assets. While we believe that we maintain appropriate information security policies and protocols, we face cybersecurity and other security threats to our information technology infrastructure, which could include threats to our operational industrial control systems and safety systems that operate our pipelines, plants and assets. We could face unlawful attempts to gain access to our information technology infrastructure, including coordinated attacks from hackers, whether state-sponsored groups, “hacktivists,” or private individuals. The age, operating systems or condition of our current information technology infrastructure and software assets and our ability to maintain and upgrade such assets could affect our ability to resist cybersecurity threats. We could also face attempts to gain access to information related to our assets through attempts to obtain unauthorized access by targeting acts of deception against individuals with legitimate access to physical locations, or information.
Breaches in our information technology infrastructure or physical facilities, or other disruptions including those arising from theft, vandalism, fraud or unethical conduct, could result in damage to our assets, unnecessary waste, safety incidents, damage to the environment, reputational damage, potential liability or the loss of contracts, and have a material adverse effect on our operations, financial position and results of operations.
Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
Our gas pipeline facilities are generally owned in fee. However, a substantial portion of such facilities are constructed and maintained pursuant to rights-of-way, easements, permits, licenses or consents on and across real property owned by others. Compressor stations, with appurtenant facilities, are located in whole or in part either on lands owned or on sites held under leases or permits issued or approved by public authorities. Our storage facilities are either owned or contracted for under long-term leases or easements. We lease our company offices in Houston, Texas.
Item 3. Legal Proceedings
The information called for by this item is provided in “Item 8. Financial Statements and Supplementary Data – Notes to Consolidated Financial Statements – Note 2. Contingent Liabilities and Commitments”.
Item 4. Mine Safety Disclosures
Not applicable.
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
At December 31, 2013,2015, we are owned through WPO,indirectly by WPZ,Williams Partners L.P., and Williams holds an approximate 6460 percent interest in WPZ,Williams Partners, L.P., comprised of an approximate 6258 percent limited partner interest and all of WPZ’sWilliams Partners L.P.’s 2 percent general partner interest.
Distributions totaling $250$536 million were declared and paid by us to our parent during the year ended December 31, 2013.2015. An additional distribution of $112$175 million was declared and paid by us to our parent in January 2014.2016. Distributions totaling $246$411 million were declared and paid by us to our parent during the year ended December 31, 2012.2014.
In the year ended December 31, 2013, WPO2015, our parent made contributions totaling $264$652 million to us to fund a portion of our expenditures for additions to property, plant and equipment. In January 2014, WPO2016, our parent made an additional $54$112 million contribution to us. In the year ended December 31, 2012, WPO2014, our parent made contributions to us totaling $150$267 million. In 2012, we received a non-cash contribution of approximately $1.5 million related to the transfer of certain property, plant and equipment and other assets.
Item 6. Selected Financial Data
Since we meet the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K, this information is omitted.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
General
The following discussion and analysis of critical accounting estimates, results of operations and capital resources and liquidity should be read in conjunction with the financial statements and notes thereto included within Item 8.
Critical Accounting Estimates
Our financial statements reflect the selection and application of accounting policies that require management to make significant estimates and assumptions. We believe that the following are the most critical judgment areas in the application of accounting policies that currently affect our financial condition and results of operations.
Regulatory Accounting
We are regulated by the FERC. The Accounting Standards Codification (ASC) Topic 980, Regulated Operations (Topic 980) provides that rate-regulated public utilities account for and report regulatory assets and liabilities consistent with the economic effect of the way in which regulators establish rates if the rates established are designed to recover the costs of providing the regulated service and if the competitive environment makes it probable that such rates can be charged and collected. Accounting for businesses that are regulated and apply the provisions of Topic 980 can differ from the accounting requirements for non-regulated businesses. Transactions that are recorded differently as a result of regulatory accounting requirements include the capitalization of an equity return component on regulated capital projects, capitalization of other project costs, retirements of general plant assets, employee related benefits, environmental costs, negative salvage, asset retirement obligations and other costs and taxes included in, or expected to be included in, future rates. As a rate-regulated entity, our management has determined that it is appropriate to apply the accounting prescribed by Topic 980 and, accordingly, the accompanying consolidated financial statements include
the effects of the types of transactions described above that result from regulatory accounting requirements. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities requires judgment and interpretation of laws and regulatory commission orders. If, for any reason, we cease to meet the criteria for application of regulatory accounting treatment for all or part of our operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the Consolidated Balance Sheet and included in the Consolidated Statement of Comprehensive Income for the period in which the discontinuance of regulatory accounting treatment occurs, unless otherwise required to be recorded under other provisions of U.S. GAAP.generally accepted accounting principles. The aggregate amount of regulatory assets reflected in the Consolidated Balance Sheet is $294.1$343.3 million at December 31, 2013.2015. The aggregate amount of regulatory liabilities reflected in the Consolidated Balance Sheet is $287.6$385.9 million at December 31, 2013.2015. A summary of regulatory assets and liabilities is included in Note 9 of Notes to Consolidated Financial Statements.
Revenue SubjectImpairment of Long-lived Assets
We evaluate our long lived assets for impairment when events or changes in circumstances indicate, in our management's judgment, that the carrying value of such assets may not be recoverable. When an indicator of a potential impairment has occurred, we compare our management's estimate of undiscounted future cash flows attributable to Refundthe assets to the carrying value of the assets to determine whether an impairment has occurred.
FERC regulations promulgate policies and procedures which governIn December 2010 we detected a process to establishleak in one of the rates that we are permitted to charge customers forseven underground natural gas salesstorage caverns at our Eminence Storage Field in Covington County, Mississippi. Due to the leak at this cavern, damage to the well at an adjacent cavern, and services, includingoperating problems at two other caverns constructed at about the transportation and storage of natural gas. Key determinantssame time, we determined that the four caverns should be retired, which was completed in 2014. In addition, further studies have indicated the ratemaking process are (i) costs of providing service, including depreciation expense, (ii) allowed rate of return, includingneed for capital improvements over the equity componentnext several years of the capital structure and related taxes, and (iii) volume throughput assumptions.
remaining three caverns. As a result, we performed an assessment of our Eminence storage field for impairment as of December 31, 2015. The carrying value at that date was $86 million. These events have not affected the performance of our obligations under our service agreements with our customers. However, judgments and assumptions are inherent in our estimate of future cash flows used to evaluate Eminence. In our evaluation, our estimate of the ratemaking process, certain revenues collected by us may be subject to possible refunds upon the issuanceundiscounted cash flows of final orders by the FERCEminence exceeded its carrying value, and thus no impairment loss was recognized in pending rate proceedings. We record2015. If our estimates of rate refund liabilities considering our and third-party regulatory proceedings, advicerevenues were to significantly decrease, it could result in an impairment of counsel and other risk. 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, 2013, we had accrued approximately $98 million for potential amounts to be refunded.this asset.
Results of Operations
Analysis of Financial Results
This analysis discusses financial results of our operations for the years 20132015 and 2012.2014. Variances due to changes in natural gas prices and transportation volumes have little impact on revenues, because under our rate design methodology, the majority of overall cost of service is recovered through firm capacity reservation charges in our transportation rates.
20132015 COMPARED TO 20122014
Operating Income and Net Income Operating Income for 20132015 was $429.1$587.2 million compared to $330.1$472.8 million for 2012.2014. Net Income for 20132015 was $374.0$575.5 million compared to $272.5$422.9 million for 2012.2014. The increase in Operating Income of $99.0$114.4 million (30.0(24.2 percent) was primarily due to higher Natural gas transportation revenues, and a decreasepartly offset by an increase in certain Operating Costs and Expenses in 20132015 compared to 2012,2014, as discussed below. The increase in Net Income of $101.5$152.6 million (37.2(36.1 percent) was mostly attributable to the increase in Operating Income, and a favorable change in net expenses in Other (Income) and Other Expenses, as discussed below.
Sales Revenues We have cash out sales, which settle gas imbalances with shippers. In the course of providing transportation services to customers, we may receive different quantities of gas from shippers than the quantities delivered on behalf of those shippers. Additionally, we transport gas on various pipeline systems, which may deliver different quantities of gas on our behalf than the quantities of gas received from us. These transactions result in gas transportation and exchange imbalance receivables and payables. Our tariff includes a method whereby the majority of transportation imbalances are settled on a monthly basis through cash out sales or purchases. The cash out sales have no impact on our operating income or results of operations.
Operating Revenues: Revenues Natural gas sales increased $48.4$4.4 million (74.3(3.6 percent) to $113.5$125.8 million for 20132015 when compared to 2012.2014. The increase was primarily due to higher cash-out sales. Cash-out sales are offset in our costs of natural gas sold and therefore had no impact on our operating income or results of operations.
TransportationOperating RevenuesOperating Revenues: Natural gas transportation for 20132015 was $1,094.8$1,318.7 million compared to $1,023.0$1,166.2 million for 2012.2014. The $71.8$152.5 million (7.0(13.1 percent) increase was partlyprimarily due to the implementation of new rates in March 2013 which were higher as compared to the rates provided in the settlement of the prior rate proceedings. Also contributing to the positive variance were higher transportation reservation revenues related to new incremental projects of $58.6$165.9 million, ($30.8(primarily due to $65.6 million from our Mid-South project Phase 1 placed in service in September 2012 and Phase 2 placed in service in June 2013, $14.3 million from our Northeast Supply LinkLeidy Southeast project placed in partial service in third quarter 2013, with full service in November 2013 and $13.5March 2015, $51.6 million from our Mid-Atlantic ConnectorRockaway project placed in service in January 2013)May 2015 and $28.3 million from our Virginia Southside project placed into partial service in December 2014 and fully placed in service in September 2015), higher transportation revenue of $3.5 million related to re-marketing of previously turned back capacity on Mobile Bay, partially offset by $6.6$10.0 million lower transportationcommodity revenues, due to a firm contract termination on the Mobile Bay lateral, $6.3$3.4 million lower recovery of electric power costs,FT backhaul revenues and $2.2$2.5 million lower revenues due to one less billable day, as of result of leap year in 2012.which recover electric power costs. Electric power costs are recovered from customers through transportation rates resulting in no net impact on our operating income or results of operations.
Operating RevenuesNatural gas storage for 2015 was $138.0 million compared to $140.3 million for 2014. The $2.3 million (1.6 percent) decrease was primarily due to lower commodity revenues in 2015.
Operating Revenues Other for 2015 was $10.1 million compared to $5.2 million for 2014. The $4.9 million (94.2 percent) increase was primarily due to higher Park and Loan volumes in 2015.
Operating Costs and Expenses Excluding the Cost of natural gas sales, which is directly offset in revenues, our operating expenses decreasedincreased approximately $25.2$40.7 million (3.0(4.9 percent) from the comparable period in 2012.2014. This decreaseincrease was primarily attributable to:
A $35.1$16.8 million (11.7(6.2 percent) decreaseincrease in Operation and maintenance costs primarily resulting from a $16.1$13.1 million decreaseincrease in miscellaneous contractual services costs primarily due to general maintenance, hydrostatic and other testing on our pipeline and an $8.2 million increase resulting from higher employee labor and related benefit costs, andpartly offset by a $19.0$4.4 million decrease in other materials and supplies primarily relateddue to compressorhigher general repairs and pipeline operation, maintenance and repairs;in 2014;
A $6.9$7.7 million (21.7(2.8 percent) increase in Depreciation and amortization costs primarily due to additional assets placed into service in 2015;
A $5.1 million (11.5 percent) increase in Taxes - other than income taxes primarily due to additional assets placed into service in 2015;
A $20.6 million (55.4 percent) increase in Other expense, net primarily due to an $8.0 million of expense to establish a regulatory liability associated with rate collections in excess of our pension funding obligation, a $6.2 million increase in reserve for litigations due to the absence of favorable adjustments recorded in 2014 for certain litigation and regulatory matters which have been settled, a $4.6 million increase in project development costs partly due to the capitalization in 2014 of $3.5 million of feasibility costs, and a $3.6 million unfavorable change in the deferral of ARO-related depreciation to a regulatory asset;
Partially offset by a $5.1 million (16.1 percent) decrease in Cost of natural gas transportation primarily resulting from a $2.7 million lower fuel costs and a $2.5 million lower electric power costs. Electric power costs are recovered from customers through transportation rates resulting in no net impact on our operating income or results of operations;
Partially offset by $11.4 million (53.8 percent) unfavorable change in Other expense, net primarily due to a $23.4 million increase due to the amortization of regulatory assets resulting from ARO cost incurred prior to the Docket No. RP12-993 rate case,operations.; and a $11.5 million expense in 2013 related to a charge for the portion of the Eminence regulatory asset that will not be recovered in rates associated with Eminence abandonment discussed below, partially offset by a $16.1 million gain recognized in 2013 related to insurance recoveries associated with Eminence abandonment discussed below, a $2.3 million decrease in expense for a certain litigation matter and a $2.3 million decrease of loss on disposal of property, plant and equipment.
A $7.8$4.3 million (4.5(2.3 percent) increasedecrease in Administrative and general costs primarily resulting from employeea $12.9 million lower allocated corporate expenses, partly offset by a $6.6 million increase in labor and related benefit costs.
Other (Income) and Other Deductions Other (income) and other expenses in 20132015 had a favorable change of $2.5$38.3 million (4.3(76.6 percent) over 20122014 primarily due to lower interest expensea $38.1 million increase in Allowance for equity and borrowed funds used during construction (AFUDC) due to the July 2012 refinancing of debt at lower interest rates.increased spending on various expansion projects.
Eminence Storage Field Leak
On December 28, 2010, we detected a leak in one of the seven underground natural gas storage caverns at our Eminence Storage Field in Covington County, Mississippi. We initially reduced the pressure in the cavern by safely venting and flaring gas, and began the process of flowing all remaining gas into our pipeline. Due to the leak at this cavern and damage to the well at an adjacent cavern, both caverns were taken out of service. In addition, two other
cavernsStation 62 Incident
On October 8, 2015, an explosion and fire occurred at our Compressor Station No. 62 in Gibson, Louisiana. At the time of the incident, planned facility maintenance was being performed at the field, whichstation and the facility was not operational. The incident was related to maintenance work being performed on the slug catcher at the station. Four contractors were constructed at or aboutfatally injured as a result of the same time as those caverns, experienced operating problems,incident.
We are cooperating with local, state and federal authorities, including the Louisiana State Police, Terrebonne Parish, the Louisiana Department of Environmental Quality, the U.S. Environmental Protection Agency (Region 6), the Occupational Safety and Health Administration, and the U.S. Department of Transportation's Pipeline and Hazardous Materials Safety Administration, and we determined that they shouldare investigating to determine the cause of the incident. We have not received any formal enforcement actions from the agencies involved, but the agencies could issue penalties pertaining to final determinations. Any potential fines and penalties from these agencies would not be retired. covered by our insurance policy. Both on-site and off-site air monitoring was conducted from shortly after the incident until approximately one week following the incident.
The eventincident did not affect the performance of our obligations under our service agreements with our customers.
In September 2011, we filed an application with the FERC seeking authorization to abandon these four caverns. In February 2013, the FERC issued an order approving the abandonment. We estimate the remaining cost to complete the abandonmentcause any rupture of the caverns will be approximately $7 million, and is expectedgas pipeline or any damage to be spent through the first half of 2014.
As of December 31, 2013, we have incurred approximately $93.2 million of these abandonment costs. Consistent withbuilding containing the termscompressor engines. In anticipation of the Agreement inplanned maintenance, our Southeast Louisiana Lateral was taken out of service on October 4, 2015, which affected approximately 200 MMcf/d of natural gas production. The lateral currently remains out of service while we assess the Docket No. RP12-993 rate case, forcondition of facilities potentially impacted by the year ended December 31, 2013, we expensed $11.5 million, related to the Eminence abandonment regulatory asset that will not be recovered in rates.incident.
We have reached settlement agreementsbeen served with insurance counterparties relateda civil lawsuit in connection with the incident, which includes claims for wrongful death and personal injury. However, due to this event. A portionthe ongoing investigation into the cause of the proceeds from these settlements has been creditedincident, our potential defenses to liability and limited information as to the Eminence regulatory asset pursuant to the termsnature and extent of the Agreement inplaintiffs' damages, and the Docket No. RP12-993 rate case. The remaining balance of the proceeds are allocated to us to offset the expenselimited information available associated with the write offany potential agency actions, we cannot reasonably estimate a range of the uncollectible portion of the Eminence regulatory asset and a portion of our costs incurred to ensure the safety of the surrounding area. For the year ended December 31, 2013, we have recognized $16.1 millionpotential loss related to these insurance recoveries.
During 2013, 2012 and 2011, we incurred $4.3 million, $2.5 million and $14.6 million, respectively, of expense, related primarily to costs to ensure the safety of the surrounding area. We anticipate incurring additional expense of approximately $2.6 million during 2014.contingencies at this time.
Filing of Rate Case.Case
On August 31, 2012, we filed a general rate case with the FERC for an overall increase in rates. In September 2012, with the exception of certain rates that reflected a rate decrease, the FERC accepted and suspendedissued an order accepting our general rate filing to be effective March 1, 2013, subject to refund and the outcome of a hearing. The specific rates for certain services that reflected awere proposed as overall rate decrease were accepted, without suspension, to bedecreases became effective October 1, 2012, and will not be subject to refund. On August 27, 2013, after reaching an agreementthe increased rates became effective March 1, 2013. All issues in principle with the participants, we filedthis proceeding have been resolved by a stipulation and agreement (Agreement) proposing to resolve all issues in this proceeding withoutapproved by the need for a hearing. On December 6, 2013, the FERC issued an order approving the Agreement without modifications.FERC. Pursuant to its terms, the Agreement will becomebecame effective March 1, 2014. We have provided a reserve for rate2014 and refunds which we believe is adequate for required refunds as of December 31, 2013, under the Agreement.approximately $118 million were issued on April 18, 2014.
Effects of Inflation
We have generally experienced increased costs due to the effect of inflation on the cost of labor, materials and supplies, and property, plant and equipment. A portion of the increased labor and materials and supplies cost can directly affect income through increased operation and maintenance expenses. The cumulative impact of inflation over a number of years has resulted in increased costs for current replacement of productive facilities. The majority of our property, plant and equipment and material and supplies inventory is subject to ratemaking treatment, and under current FERC practices, recovery is limited to historical costs. We believe that we will be allowed to recover and earn a return based on increased actual costs incurred when existing facilities are replaced. Cost based regulation along with competition and other market factors limit our ability to price services or products based upon inflation’s effect on costs.
CAPITAL RESOURCES AND LIQUIDITY
Method of Financing
We fund our capital requirements with cash flows from operating activities, equity contributions from WPZ, collection of advances to WPZ, accessing capital markets, and, if required, borrowings under the credit facility described below and advances from WPZ.
We may raise capital through private debt offerings, as well as offerings registered pursuant to offering-specific registration statements. Interest rates, market conditions, and industry conditions will affect amounts raised, if any, in the capital markets. On January 22, 2016, we completed a private placement of $1 billion in aggregate principal amount
of 7.85 percent senior unsecured notes due 2026. We intend to use the net proceeds from the offering to repay indebtedness, including our $200 million of 6.4 percent notes due upon their maturity on April 15, 2016, and to fund capital markets. expenditures.
We, anticipate that we will be able to access publicalong with WPZ and private markets on terms commensurate with ourNorthwest Pipeline LLC, are co-borrowers under a $3.5 billion unsecured credit ratings to finance our capital requirements.
On July 31, 2013, WPZ amended the $2.4 billion credit facility to increase the aggregate commitments to $2.5 billion and extend the maturity date to July 31, 2018. The amended credit facility may also, under certain conditions, be increased up to an additional $500 million.facility. Total letter of credit capacity available to WPZ under the credit facility is $1.3$1.125 billion. We may borrow up to $500 million under the amended credit facility to the extent not otherwise utilized by WPZ and Northwest Pipeline LLC. See Note 3 of Notes to Consolidated Financial Statements for further discussion of the credit facility.
We are a participant in WPZ's cash management program, and we make advances to and receive advances from WPZ. At December 31, 2013,2015, our advances to WPZ totaled approximately $526.4$64.6 million. These advances are represented by demand notes. The decrease in 2015 of these advances primarily resulted from the use of funds for capital expenditures. In April 2014, we expectutilized repayment of a portion of these advances in order to pay rate refunds to our customers under the Agreement in Docket No. RP12-993. The net proceeds of the January 2016 financing were advanced to WPZ.
Through wholly-owned subsidiaries, we hold a 35 percent interest in Pine Needle and approximately a 45 percent interest in Cardinal, which have interest rate swap agreements that qualify as cash flow hedge transactions under the accounting and reporting standards established by ASC Topic 815, Derivatives and Hedging. As such, our equity interest in the changes in fair value of Pine Needle’s hedge and Cardinal’s hedge are recognized in other comprehensive income.
Capital Expenditures
We categorize our capital expenditures as either maintenance capital expenditures or expansion capital expenditures. Maintenance capital expenditures are those expenditures required to maintain the existing operating capacity and service capability of our assets, including replacement of system components and equipment that are worn, obsolete, completing their useful life, or necessary to remain in compliance with environmental laws and regulations. Expansion capital expenditures improve the service capability of existing assets, extend useful lives, increase transmission or storage capacities from existing levels, reduce costs or enhance revenues. We anticipate 20142016 capital expenditures will be approximately $830 million.$1.3 billion. Of this total, approximately $750 million$1.2 billion is considered nondiscretionary due to legal, regulatory, and/or contractual requirements, primarily due to expansion projects.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
At December 31, 2013,2015, our debt portfolio included only fixed rate issues. The following table provides information about our long-term debt, including current maturities, as of December 31, 2013.2015. The table presents principal cash flows and weighted-average interest rates by expected maturity dates.
| | | December 31, 2013 | Expected Maturity Date | |
| December 31, 2015 | | Expected Maturity Date |
| | 2014 | | 2015 | | 2016 | | 2017 | 2016 | | 2017 | | 2018 | | 2019 |
| | (Dollars in millions) | (Dollars in millions) |
| Long-term debt: | | | | | | | | | | | | | | |
| Fixed rate | $ | — |
| | $ | — |
| | $ | 200 |
| | $ | — |
| $ | 200 |
| | $ | — |
| | $ | 250 |
| | $ | — |
|
| Interest rate | 5.65 | % | | 5.65 | % | | 5.57 | % | | 5.53 | % | 5.57 | % | | 5.53 | % | | 5.47 | % | | 5.40 | % |
| | | | | | | | | | | | | | | |
| December 31, 2013 | Expected Maturity Date | |
| December 31, 2015 | | Expected Maturity Date |
| | 2018 | | Thereafter | | Total | | Fair Value | 2020 | | Thereafter | | Total | | Fair Value |
| | (Dollars in millions) | (Dollars in millions) |
| Long-term debt: | | | | | | | | | | | | | | |
| Fixed rate | $ | 250 |
| | $ | 983 |
| | $ | 1,433 |
| | $ | 1,513 |
| $ | — |
| | $ | 983 |
| | $ | 1,433 |
| | $ | 1,244 |
|
| Interest rate | 5.47 | % | | 5.10 | % | | | | | 5.40 | % | | 5.06 | % | | | | |
Item 8. Financial Statements and Supplementary Data
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Management Committee of Transcontinental Gas Pipe Line Company, LLC
We have audited the accompanying consolidated balance sheetssheet of Transcontinental Gas Pipe Line Company, LLC as of December 31, 20132015 and 2012,2014, and the related consolidated statements of comprehensive income, owner’s equity, and cash flows for each of the three years in the period ended December 31, 2013.2015. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Transcontinental Gas Pipe Line Company, LLC at December 31, 20132015 and 2012,2014, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2013,2015, in conformity with U.S. generally accepted accounting principles.
/S/ ERNST & YOUNG LLP
Houston, Texas
February 26, 201424, 2016
TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
(Thousands of Dollars)
| | | | | Years Ended December 31, | | Years Ended December 31, |
| | | 2013 | | 2012 | | 2011 | | 2015 | | 2014 | | 2013 |
| Operating Revenues: | | | | | | | | | | | | |
| Natural gas sales | | $ | 113,488 |
| | $ | 65,120 |
| | $ | 108,359 |
| | $ | 125,774 |
| | $ | 121,397 |
| | $ | 113,488 |
|
| Natural gas transportation | | 1,094,807 |
| | 1,022,990 |
| | 983,554 |
| | 1,318,656 |
| | 1,166,244 |
| | 1,094,807 |
|
| Natural gas storage | | 143,047 |
| | 140,390 |
| | 142,556 |
| | 137,983 |
| | 140,344 |
| | 143,047 |
|
| Other | | 4,990 |
| | 5,601 |
| | 8,045 |
| | 10,106 |
| | 5,152 |
| | 4,990 |
|
| Total operating revenues | | 1,356,332 |
| | 1,234,101 |
| | 1,242,514 |
| | 1,592,519 |
| | 1,433,137 |
| | 1,356,332 |
|
| | | | | | | | | | | | | |
| Operating Costs and Expenses: | | | | | | | | | | | | |
| Cost of natural gas sales | | 113,488 |
| | 65,120 |
| | 108,359 |
| | 125,774 |
| | 121,397 |
| | 113,488 |
|
| Cost of natural gas transportation | | 24,936 |
| | 31,815 |
| | 35,674 |
| | 26,501 |
| | 31,629 |
| | 24,936 |
|
| Operation and maintenance | | 264,631 |
| | 299,734 |
| | 281,496 |
| | 288,386 |
| | 271,603 |
| | 264,631 |
|
| Administrative and general | | 182,352 |
| | 174,610 |
| | 148,113 |
| | 179,489 |
| | 183,760 |
| | 182,352 |
|
| Depreciation and amortization | | 265,273 |
| | 266,445 |
| | 259,660 |
| | 277,850 |
| | 270,181 |
| | 265,273 |
|
| Taxes — other than income taxes | | 43,898 |
| | 45,086 |
| | 41,673 |
| | 49,567 |
| | 44,521 |
| | 43,898 |
|
| Other expense, net | | 32,606 |
| | 21,230 |
| | 12,988 |
| | 57,800 |
| | 37,208 |
| | 32,606 |
|
| Total operating costs and expenses | | 927,184 |
| | 904,040 |
| | 887,963 |
| | 1,005,367 |
| | 960,299 |
| | 927,184 |
|
| | | | | | | | | | | | | |
| Operating Income | | 429,148 |
| | 330,061 |
| | 354,551 |
| | 587,152 |
| | 472,838 |
| | 429,148 |
|
| | | | | | | | | | | | | |
| Other (Income) and Other Expenses: | | | | | | | | | | | | |
| Interest expense - affiliate | | 190 |
| | 309 |
| | 262 |
| | 64 |
| | 70 |
| | 190 |
|
| - other | | 84,000 |
| | 88,766 |
| | 94,920 |
| | 82,774 |
| | 84,917 |
| | 84,000 |
|
| Interest income - affiliate | | (45 | ) | | (35 | ) | | (29 | ) | | (28 | ) | | (49 | ) | | (45 | ) |
| - other | | (2,068 | ) | | (2,351 | ) | | (2,119 | ) | | (1,933 | ) | | (1,782 | ) | | (2,068 | ) |
| Allowance for equity and borrowed funds used during construction (AFUDC) | | (18,595 | ) | | (19,257 | ) | | (15,339 | ) | | (63,072 | ) | | (25,046 | ) | | (18,595 | ) |
| Equity in earnings of unconsolidated affiliates | | (5,678 | ) | | (7,458 | ) | | (5,164 | ) | | (5,593 | ) | | (5,783 | ) | | (5,678 | ) |
| Miscellaneous other (income) expenses, net | | (2,682 | ) | | (2,379 | ) | | 2,362 |
| | (517 | ) | | (2,373 | ) | | (2,682 | ) |
| Total other (income) and other expenses | | 55,122 |
| | 57,595 |
| | 74,893 |
| | 11,695 |
| | 49,954 |
| | 55,122 |
|
| | | | | | | | | | | | | |
| Net Income | | 374,026 |
| | 272,466 |
| | 279,658 |
| | 575,457 |
| | 422,884 |
| | 374,026 |
|
| | | | | | | | | | | | | |
| Other comprehensive income (loss): | | | | | | | |
| Equity interest in unrealized gain (loss) on interest rate hedges (includes $330, $220, and $170 for the years ended December 31, 2013, 2012, and 2011, respectively, of accumulated other comprehensive income reclassification for realized losses on interest rate hedges) | | 464 |
| | (376 | ) | | (519 | ) | |
| Other comprehensive income: | | | | | | | |
| Equity interest in unrealized gain on interest rate hedges (includes $316, $344, and $330 for the years ended December 31, 2015, 2014, and 2013, respectively, of accumulated other comprehensive income reclassification for equity interest in realized losses on interest rate hedges) | | | 84 |
| | 143 |
| | 464 |
|
| | | | | | | | | | | | | |
| Comprehensive Income | | $ | 374,490 |
| | $ | 272,090 |
| | $ | 279,139 |
| | $ | 575,541 |
| | $ | 423,027 |
| | $ | 374,490 |
|
See accompanying notes.
TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
|
| | | | | | | | |
| | | December 31, |
| | | 2013 | | 2012 |
| ASSETS | | | | |
| | | | | |
| Current Assets: | | | | |
| Cash | | $ | 113 |
| | $ | 185 |
|
| Receivables: | | | | |
| Trade | | 137,808 |
| | 116,847 |
|
| Affiliates | | 2,601 |
| | 2,656 |
|
| Advances to affiliate | | 526,380 |
| | 312,165 |
|
| Other | | 10,364 |
| | 8,928 |
|
| Transportation and exchange gas receivables | | 6,757 |
| | 2,876 |
|
| Inventories: | | | | |
| Gas in storage, at original cost | | 790 |
| | 812 |
|
| Gas in storage, LIFO | | 1,056 |
| | — |
|
| Gas available for customer nomination, at average cost | | 8,553 |
| | 8,600 |
|
| Material and supplies, at lower of average cost or market | | 37,133 |
| | 36,506 |
|
| Regulatory assets | | 37,520 |
| | 36,706 |
|
| Other | | 13,451 |
| | 14,342 |
|
| Total current assets | | 782,526 |
| | 540,623 |
|
| | | | | |
| Investments, at cost plus equity in undistributed earnings | | 50,262 |
| | 55,603 |
|
| | | | | |
| Property, Plant and Equipment: | | | | |
| Natural gas transmission plant | | 8,867,626 |
| | 8,506,189 |
|
| Less-Accumulated depreciation and amortization | | 3,090,234 |
| | 2,954,276 |
|
| Total property, plant and equipment, net | | 5,777,392 |
| | 5,551,913 |
|
| | | | | |
| Other Assets: | | | | |
| Regulatory assets | | 256,612 |
| | 214,912 |
|
| Other | | 57,785 |
| | 47,764 |
|
| Total other assets | | 314,397 |
| | 262,676 |
|
| | | | | |
| Total assets | | $ | 6,924,577 |
| | $ | 6,410,815 |
|
(continued)
See accompanying notes.
TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
|
| | | | | | | | |
| | | December 31, |
| | | 2013 | | 2012 |
| LIABILITIES AND OWNER’S EQUITY | | |
| | | | | |
| Current Liabilities: | | | | |
| Payables: | | | | |
| Trade | | $ | 106,096 |
| | $ | 107,795 |
|
| Affiliates | | 28,268 |
| | 32,006 |
|
| Cash overdrafts | | 8,539 |
| | 11,512 |
|
| Transportation and exchange gas payables | | 3,599 |
| | 3,513 |
|
| Reserve for rate refunds | | 98,217 |
| | — |
|
| Accrued liabilities: | | | | |
| Property and other taxes | | 14,180 |
| | 13,326 |
|
| Interest | | 19,894 |
| | 20,784 |
|
| Regulatory liabilities | | 18,014 |
| | 14,624 |
|
| Customer advances | | 17,811 |
| | 11,020 |
|
| Asset retirement obligations | | 35,902 |
| | 43,472 |
|
| Other | | 47,462 |
| | 36,107 |
|
| Total current liabilities | | 397,982 |
| | 294,159 |
|
| | | | | |
| Long-Term Debt | | 1,428,355 |
| | 1,428,323 |
|
| | | | | |
| Other Long-Term Liabilities: | | | | |
| Asset retirement obligations | | 238,085 |
| | 253,398 |
|
| Regulatory liabilities | | 269,563 |
| | 232,888 |
|
| Other | | 5,307 |
| | 5,339 |
|
| Total other long-term liabilities | | 512,955 |
| | 491,625 |
|
| | | | | |
| Contingent Liabilities and Commitments (Note 2) | |
| |
|
| | | | | |
| Owner’s Equity: | | | | |
| Member’s capital | | 2,257,499 |
| | 1,993,412 |
|
| Retained earnings | | 2,328,044 |
| | 2,204,018 |
|
| Accumulated other comprehensive income (loss) | | (258 | ) | | (722 | ) |
| Total owner’s equity | | 4,585,285 |
| | 4,196,708 |
|
| | | | | |
| Total liabilities and owner’s equity | | $ | 6,924,577 |
| | $ | 6,410,815 |
|
|
| | | | | | | | |
| | | December 31, |
| | | 2015 | | 2014 |
| ASSETS | | | | |
| | | | | |
| Current Assets: | | | | |
| Cash | | $ | — |
| | $ | 173 |
|
| Receivables: | | | | |
| Trade, less allowance of $13 ($0 in 2014) | | 134,834 |
| | 127,141 |
|
| Affiliates | | 1,084 |
| | 654 |
|
| Advances to affiliate | | 64,608 |
| | 306,910 |
|
| Other | | 15,422 |
| | 3,594 |
|
| Transportation and exchange gas receivables | | 2,427 |
| | 3,485 |
|
| Inventories: | | | | |
| Gas in storage, at original cost | | 780 |
| | 715 |
|
| Gas in storage, LIFO | | — |
| | 497 |
|
| Gas available for customer nomination, at average cost | | 19,838 |
| | 28,464 |
|
| Material and supplies, at lower of average cost or market | | 36,223 |
| | 37,023 |
|
| Regulatory assets | | 79,575 |
| | 77,810 |
|
| Other | | 15,297 |
| | 14,683 |
|
| Total current assets | | 370,088 |
| | 601,149 |
|
| | | | | |
| Investments, at cost plus equity in undistributed earnings | | 45,078 |
| | 47,050 |
|
| | | | | |
| Property, Plant and Equipment: | | | | |
| Natural gas transmission plant | | 10,863,944 |
| | 9,645,382 |
|
| Less-Accumulated depreciation and amortization | | 3,471,775 |
| | 3,257,844 |
|
| Total property, plant and equipment, net | | 7,392,169 |
| | 6,387,538 |
|
| | | | | |
| Other Assets: | | | | |
| Regulatory assets | | 263,730 |
| | 239,080 |
|
| Other | | 73,814 |
| | 65,263 |
|
| Total other assets | | 337,544 |
| | 304,343 |
|
| | | | | |
| Total assets | | $ | 8,144,879 |
| | $ | 7,340,080 |
|
(continued)
See accompanying notes.
TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
CONSOLIDATED STATEMENT OF OWNER’S EQUITYBALANCE SHEET
(Thousands of Dollars)
|
| | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2013 | | 2012 | | 2011 |
| Member's Capital: | | | | | | |
| Balance at beginning of period | | $ | 1,993,412 |
| | $ | 1,841,888 |
| | $ | 1,727,434 |
|
| Cash contributions from parent | | 264,000 |
| | 150,000 |
| | 115,000 |
|
| Non-cash contributions from parent | | 87 |
| | 1,524 |
| | — |
|
| Non-cash return of capital | | — |
| | — |
| | (546 | ) |
| Balance at end of period | | 2,257,499 |
| | 1,993,412 |
| | 1,841,888 |
|
| Retained Earnings: | | | | | | |
| Balance at beginning of period | | 2,204,018 |
| | 2,177,811 |
| | 2,117,153 |
|
| Net income | | 374,026 |
| | 272,466 |
| | 279,658 |
|
| Cash distributions to parent | | (250,000 | ) | | (246,259 | ) | | (219,000 | ) |
| Balance at end of period | | 2,328,044 |
| | 2,204,018 |
| | 2,177,811 |
|
| Accumulated Other Comprehensive Income (Loss): | | | | | | |
| Balance at beginning of period | | (722 | ) | | (346 | ) | | 173 |
|
| Equity interest in unrealized gain (loss) on interest rate hedge | | 464 |
| | (376 | ) | | (519 | ) |
| Balance at end of period | | (258 | ) | | (722 | ) | | (346 | ) |
| | | | | | | |
| Total Owner's Equity | | $ | 4,585,285 |
| | $ | 4,196,708 |
| | $ | 4,019,353 |
|
|
| | | | | | | | |
| | | December 31, |
| | | 2015 | | 2014 |
| LIABILITIES AND OWNER’S EQUITY | | |
| | | | | |
| Current Liabilities: | | | | |
| Payables: | | | | |
| Trade | | $ | 194,081 |
| | $ | 237,873 |
|
| Affiliates | | 38,243 |
| | 37,688 |
|
| Cash overdrafts | | 28,969 |
| | 30,867 |
|
| Transportation and exchange gas payables | | 1,355 |
| | 4,701 |
|
| Accrued liabilities: | | | | |
| Property and other taxes | | 12,661 |
| | 13,723 |
|
| Interest | | 19,894 |
| | 19,894 |
|
| Regulatory liabilities | | 3,536 |
| | 7,054 |
|
| Customer advances | | 20,999 |
| | 9,205 |
|
| Asset retirement obligations | | 23,192 |
| | 16,444 |
|
| Other | | 28,948 |
| | 37,785 |
|
| Total current liabilities | | 371,878 |
| | 415,234 |
|
| | | | | |
| Long-Term Debt | | 1,419,574 |
| | 1,418,692 |
|
| | | | | |
| Other Long-Term Liabilities: | | | | |
| Asset retirement obligations | | 299,834 |
| | 280,031 |
|
| Regulatory liabilities | | 382,325 |
| | 326,083 |
|
| Advances for construction costs | | 97,790 |
| | 30,456 |
|
| Transportation prepayments | | 12,806 |
| | — |
|
| Other | | 4,819 |
| | 5,272 |
|
| Total other long-term liabilities | | 797,574 |
| | 641,842 |
|
| | | | | |
| Contingent Liabilities and Commitments (Note 2) | |
| |
|
| | | | | |
| Owner’s Equity: | | | | |
| Member’s capital | | 3,176,499 |
| | 2,524,499 |
|
| Retained earnings | | 2,379,385 |
| | 2,339,928 |
|
| Accumulated other comprehensive loss | | (31 | ) | | (115 | ) |
| Total owner’s equity | | 5,555,853 |
| | 4,864,312 |
|
| | | | | |
| Total liabilities and owner’s equity | | $ | 8,144,879 |
| | $ | 7,340,080 |
|
See accompanying notes.
TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
CONSOLIDATED STATEMENT OF CASH FLOWSOWNER’S EQUITY
(Thousands of Dollars)
|
| | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2013 | | 2012 | | 2011 |
| Cash flows from operating activities: | | | | | | |
| Net income | | $ | 374,026 |
| | $ | 272,466 |
| | $ | 279,658 |
|
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | | | |
| Depreciation and amortization | | 263,949 |
| | 266,981 |
| | 260,069 |
|
| Allowance for equity funds used during construction (equity AFUDC) | | (13,299 | ) | | (13,222 | ) | | (10,588 | ) |
| Changes in operating assets and liabilities: | | | | | | |
| Receivables — affiliates | | 55 |
| | 3,247 |
| | (982 | ) |
| — trade and other | | (21,772 | ) | | (4,186 | ) | | (11,155 | ) |
| Transportation and exchange gas receivable | | (3,881 | ) | | 2,038 |
| | (2,497 | ) |
| Regulatory assets - current | | 28,536 |
| | 1,171 |
| | 10,567 |
|
| Regulatory assets - non-current | | 21,910 |
| | (5,980 | ) | | (8,698 | ) |
| Inventories | | 232 |
| | 673 |
| | 50,295 |
|
| Payables — affiliates | | (3,738 | ) | | 15,069 |
| | (1,832 | ) |
| — trade | | (26,463 | ) | | 3,727 |
| | 14,577 |
|
| Accrued liabilities | | 28,322 |
| | 8,256 |
| | 27,775 |
|
| Asset retirement obligations | | 13,105 |
| | 35,195 |
| | (6,964 | ) |
| Asset retirement obligation - removal costs | | (26,919 | ) | | (41,052 | ) | | (43,666 | ) |
| Reserve for rate refunds | | 98,217 |
| | — |
| | — |
|
| Other, net | | 10,731 |
| | (2,934 | ) | | 15,085 |
|
| Net cash provided by operating activities | | 743,011 |
| | 541,449 |
| | 571,644 |
|
| | | | | | | |
| Cash flows from financing activities: | | | | | | |
| Additions to long-term debt | | — |
| | 398,804 |
| | 372,518 |
|
| Retirement of long-term debt | | — |
| | (325,000 | ) | | (300,000 | ) |
| Debt issue costs | | — |
| | (4,403 | ) | | (3,846 | ) |
| Cash distributions to parent | | (250,000 | ) | | (246,259 | ) | | (219,000 | ) |
| Cash contributions from parent | | 264,000 |
| | 150,000 |
| | 115,000 |
|
| Other, net | | (3,034 | ) | | (3,333 | ) | | (4,681 | ) |
| Net cash provided by (used in) financing activities | | 10,966 |
| | (30,191 | ) | | (40,009 | ) |
|
| | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2015 | | 2014 | | 2013 |
| Member's Capital: | | | | | | |
| Balance at beginning of period | | $ | 2,524,499 |
| | $ | 2,257,499 |
| | $ | 1,993,412 |
|
| Cash contributions from parent | | 652,000 |
| | 267,000 |
| | 264,000 |
|
| Non-cash contributions from parent | | — |
| | — |
| | 87 |
|
| Balance at end of period | | 3,176,499 |
| | 2,524,499 |
| | 2,257,499 |
|
| Retained Earnings: | | | | | | |
| Balance at beginning of period | | 2,339,928 |
| | 2,328,044 |
| | 2,204,018 |
|
| Net income | | 575,457 |
| | 422,884 |
| | 374,026 |
|
| Cash distributions to parent | | (536,000 | ) | | (411,000 | ) | | (250,000 | ) |
| Balance at end of period | | 2,379,385 |
| | 2,339,928 |
| | 2,328,044 |
|
| Accumulated Other Comprehensive Income (Loss): | | | | | | |
| Balance at beginning of period | | (115 | ) | | (258 | ) | | (722 | ) |
| Equity interest in unrealized gain (loss) on interest rate hedge | | 84 |
| | 143 |
| | 464 |
|
| Balance at end of period | | (31 | ) | | (115 | ) | | (258 | ) |
| | | | | | | |
| Total Owner's Equity | | $ | 5,555,853 |
| | $ | 4,864,312 |
| | $ | 4,585,285 |
|
(continued)
See accompanying notes.
TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
CONSOLIDATED STATEMENT OF CASH FLOWS
(Thousands of Dollars)
|
| | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2013 | | 2012 | | 2011 |
| Cash flows from investing activities: | | | | | | |
| Property, plant and equipment additions, net of equity AFUDC* | | $ | (526,916 | ) | | $ | (475,450 | ) | | $ | (385,671 | ) |
| Disposal of property, plant and equipment, net | | (3,621 | ) | | 7,157 |
| | 2,698 |
|
| Advances to affiliate, net | | (214,215 | ) | | (58,554 | ) | | (144,773 | ) |
| Return of capital from unconsolidated affiliates | | 1,438 |
| | 11,327 |
| | 1,925 |
|
| Contributions to unconsolidated affiliates | | — |
| | (5,806 | ) | | (14,834 | ) |
| Purchase of ARO Trust investments | | (58,242 | ) | | (34,430 | ) | | (41,310 | ) |
| Proceeds from sale of ARO Trust investments | | 45,607 |
| | 43,205 |
| | 56,576 |
|
| Other, net | | 1,900 |
| | 1,314 |
| | (6,230 | ) |
| Net cash used in investing activities | | (754,049 | ) | | (511,237 | ) | | (531,619 | ) |
| | | | | | | |
| Increase (decrease) in cash | | (72 | ) | | 21 |
| | 16 |
|
| Cash at beginning of period | | 185 |
| | 164 |
| | 148 |
|
| Cash at end of period | | $ | 113 |
| | $ | 185 |
| | $ | 164 |
|
| | | | | | | |
| ____________________________ | | | | | | |
| * Increase to property, plant and equipment | | $ | (558,201 | ) | | $ | (466,115 | ) | | $ | (386,462 | ) |
| Changes in related accounts payable and accrued liabilities | | 31,285 |
| | (9,335 | ) | | 791 |
|
| Property, plant and equipment additions, net of equity AFUDC | | $ | (526,916 | ) | | $ | (475,450 | ) | | $ | (385,671 | ) |
| | | | | | | |
| Supplemental disclosures of cash flow information: | | | | | | |
| Cash paid during the year for: | | | | | | |
| Interest (exclusive of amount capitalized) | | $ | 76,803 |
| | $ | 86,586 |
| | $ | 88,357 |
|
| Income taxes | | 116 |
| | 254 |
| | 728 |
|
|
| | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2015 | | 2014 | | 2013 |
| Cash flows from operating activities: | | | | | | |
| Net income | | $ | 575,457 |
| | $ | 422,884 |
| | $ | 374,026 |
|
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | | | |
| Depreciation and amortization | | 277,850 |
| | 269,395 |
| | 263,949 |
|
| Allowance for equity funds used during construction (equity AFUDC) | | (48,435 | ) | | (18,701 | ) | | (13,299 | ) |
| Changes in operating assets and liabilities: | | | | | | |
| Receivables — affiliates | | (430 | ) | | 1,947 |
| | 55 |
|
| — trade and other | | (19,521 | ) | | 17,437 |
| | (21,772 | ) |
| Transportation and exchange gas receivable | | 1,058 |
| | 3,272 |
| | (3,881 | ) |
| Regulatory assets - current | | (1,765 | ) | | (40,290 | ) | | 28,536 |
|
| Regulatory assets - non-current | | (24,650 | ) | | 17,532 |
| | 21,910 |
|
| Inventories | | 9,858 |
| | (19,167 | ) | | 232 |
|
| Payables — affiliates | | 2,676 |
| | 9,420 |
| | (3,738 | ) |
| — trade | | (2,077 | ) | | 32,618 |
| | (26,463 | ) |
| Accrued liabilities | | (10,015 | ) | | (39,450 | ) | | 28,322 |
|
| Asset retirement obligations - non-current | | 19,022 |
| | 30,840 |
| | 13,105 |
|
| Asset retirement obligation - removal costs | | (3,097 | ) | | (12,824 | ) | | (26,919 | ) |
| Reserve for rate refunds | | — |
| | (98,217 | ) | | 98,217 |
|
| Other, net | | 45,007 |
| | 7,954 |
| | 10,731 |
|
| Net cash provided by operating activities | | 820,938 |
| | 584,650 |
| | 743,011 |
|
| | | | | | | |
| Cash flows from financing activities: | | | | | | |
| Cash distributions to parent | | (536,000 | ) | | (411,000 | ) | | (250,000 | ) |
| Cash contributions from parent | | 652,000 |
| | 267,000 |
| | 264,000 |
|
| Other, net | | — |
| | 22,329 |
| | (3,034 | ) |
| Net cash provided by (used in) financing activities | | 116,000 |
| | (121,671 | ) | | 10,966 |
|
(continued)
See accompanying notes.
TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
CONSOLIDATED STATEMENT OF CASH FLOWS
(Thousands of Dollars)
|
| | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2015 | | 2014 | | 2013 |
| Cash flows from investing activities: | | | | | | |
| Property, plant and equipment additions, net of equity AFUDC* | | $ | (1,270,860 | ) | | $ | (724,163 | ) | | $ | (557,366 | ) |
| Contributions and advances for construction costs | | 85,901 |
| | 57,817 |
| | 30,450 |
|
| Disposal of property, plant and equipment, net | | (12,358 | ) | | (7,532 | ) | | (3,621 | ) |
| Advances to affiliate, net | | 242,302 |
| | 219,470 |
| | (214,215 | ) |
| Return of capital from unconsolidated affiliates | | 2,015 |
| | 2,333 |
| | 1,438 |
|
| Purchase of ARO Trust investments | | (64,087 | ) | | (52,038 | ) | | (58,242 | ) |
| Proceeds from sale of ARO Trust investments | | 43,284 |
| | 38,691 |
| | 45,607 |
|
| Proceeds from insurance | | 35,132 |
| | — |
| | — |
|
| Other, net | | 1,560 |
| | 2,503 |
| | 1,900 |
|
| Net cash used in investing activities | | (937,111 | ) | | (462,919 | ) | | (754,049 | ) |
| | | | | | | |
| Increase (decrease) in cash | | (173 | ) | | 60 |
| | (72 | ) |
| Cash at beginning of period | | 173 |
| | 113 |
| | 185 |
|
| Cash at end of period | | $ | — |
| | $ | 173 |
| | $ | 113 |
|
| | | | | | | |
| ____________________________ | | | | | | |
| * Increase to property, plant and equipment, net of equity AFUDC | | $ | (1,222,292 | ) | | $ | (807,232 | ) | | $ | (572,956 | ) |
| Changes in related accounts payable and accrued liabilities | | (48,568 | ) | | 83,069 |
| | 15,590 |
|
| Property, plant and equipment additions, net of equity AFUDC | | $ | (1,270,860 | ) | | $ | (724,163 | ) | | $ | (557,366 | ) |
| | | | | | | |
| Supplemental disclosures of cash flow information: | | | | | | |
| Cash paid during the year for: | | | | | | |
| Interest (exclusive of amount capitalized) | | $ | 66,489 |
| | $ | 77,304 |
| | $ | 76,803 |
|
| Income taxes | | 1,161 |
| | 864 |
| | 116 |
|
See accompanying notes.
TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES.POLICIES
Corporate Structure and Control.Control
In this report, Transco (which includes Transcontinental Gas Pipe Line Company, LLC and, unless the context otherwise requires, all of our majority-owned subsidiaries) is at times referred to in the first person as “we,” “us” or “our.”
Transco is indirectly owned through Williams Partners Operating LLC (WPO), by Williams Partners L.P. (WPZ), a publicly traded Delaware limited partnership, which is consolidated by The Williams Companies, Inc. (Williams). On February 2, 2015, WPZ was merged into Access Midstream Partners, L.P. (ACMP), another publicly traded limited partnership consolidated by Williams. ACMP was the surviving partnership and was subsequently renamed Williams Partners, L.P. At December 31, 2013,2015, Williams holds an approximate 6460 percent interest in WPZ, comprised of an approximate 6258 percent limited partner interest and all of WPZ’sthe 2 percent general partner interest.
Transco is a single member limited liability company, and as such, single member losses are limited to the amount of theirits investment.
On September 28, 2015, Williams publicly announced in a press release that it had entered into an Agreement and Plan of Merger (Merger Agreement) with Energy Transfer Equity, L.P. (Energy Transfer) and certain of its affiliates. The Merger Agreement provides that, subject to the satisfaction of customary closing conditions, Williams will be merged with and into the newly formed Energy Transfer Corp LP (ETC) (ETC Merger) with ETC surviving the ETC Merger. Energy Transfer formed ETC as a limited partnership that will be treated as a corporation for U.S. federal income tax purposes. Immediately following the completion of the ETC Merger, ETC will contribute to Energy Transfer all of the assets and liabilities of Williams in exchange for the issuance by Energy Transfer to ETC of a number of Energy Transfer Class E common units equal to the number of ETC common shares issued to Williams stockholders in the ETC Merger (ETC Exchange). WPZ expects to retain its current name and remain a publicly traded limited partnership following the ETC Merger.
Related Party Transaction.Transaction
A member of Williams' Board of Directors, who was elected in 2013, is also the current chairman, president, and chief executive officer of Public Service Enterprise Group, an energy services company that is a customer of ours. We recorded $130.7 million in operating revenues in the Consolidated Statement of Comprehensive Income from this company for transportation and storage of natural gas for the year ended December 31, 2013. This board member does not have any material interest in any transactions between the energy services company and us and he had no role in any such transactions. (See Note 7.)
Nature of Operations.Operations
We are an interstate natural gas transmission company that owns a natural gas pipeline system extending from Texas, Louisiana, Mississippi and the Gulf of Mexico through Alabama, Georgia, South Carolina, North Carolina, Virginia, Maryland, Delaware, Pennsylvania and New Jersey to the New York City metropolitan area. The system serves customers in Texas and the 12 southeast and Atlantic seaboard states mentioned above, including major metropolitan areas in Georgia, Washington D.C., Maryland, North Carolina, New York, New Jersey and Pennsylvania.
Regulatory Accounting.
We are regulated by the Federal Energy Regulatory Commission (FERC). The Accounting Standards Codification (ASC) Regulated Operations (Topic 980), provides that rate-regulated public utilities account for and report regulatory assets and liabilities consistent with the economic effect of the way in which regulators establish rates if the rates established are designed to recover the costs of providing the regulated service and if the competitive environment makes it probable that such rates can be charged and collected. Accounting for businesses that are regulated and apply the provisions of Topic 980 can differ from the accounting requirements for non-regulated businesses. Transactions
that are recorded differently as a result of regulatory accounting requirements include the capitalization of an equity return component on regulated capital projects, capitalization of other project costs, retirements of general plant assets, employee related benefits, environmental costs, negative salvage, asset retirement obligations, and other costs and taxes included in, or expected to be included in, future rates. As a rate-regulated entity, our management has determined that it is appropriate to apply the accounting prescribed by Topic 980 and, accordingly, the accompanying consolidated financial statements include the effects of the types of transactions described above that result from regulatory accounting requirements.
Basis of Presentation.Presentation
Williams’ acquisition of Transco Energy Company and its subsidiaries, including us, in 1995 was accounted for using the purchase method of accounting. Accordingly, an allocation of the purchase price was assigned to our assets
and liabilities based on their estimated fair values. The purchase price allocation to us primarily consisted of a $1.5 billion allocation to property, plant and equipment and adjustments to deferred taxes based upon the book basis of the net assets recorded as a result of the acquisition. The amount allocated to property, plant and equipment is being depreciated on a straight-line basis over 40 years, the estimated useful lives of these assets at the date of acquisition, at approximately $35 million per year. At December 31, 2013,2015, the remaining property, plant and equipment allocation was approximately $0.7 billion. Current FERC policy does not permit us to recover through rates amounts in excess of original cost.
We are a participant in WPZ’s cash management program. We make advances to and receive advances from WPZ. The advances are represented by demand notes. The interest rate on these intercompany demand notes is based upon the daily overnight investment rate paid on WPZ’s excess cash at the end of each month.
Certain prior period amounts reported within Total operating costs and expenses in the Consolidated Statement of Comprehensive Income have been reclassified to conform to the current presentation. The effect of the correction increased Operation and maintenance costs $7.1 million and $6.8 million for the years ended December 31, 2012 and 2011, respectively, for the reclassification from Taxes-other than income taxes with no net impact on Total operating costs and expenses, Operating Income and Net Income.
Principles of Consolidation.Consolidation
The consolidated financial statements include our accounts and the accounts of the subsidiaries we control. Companies in which we and our subsidiaries own 20 percent to 50 percent of the voting common stock or otherwise exercise significant influence over operating and financial policies of the company are accounted for under the equity method. The equity method investments as of December 31, 20132015 and December 31, 20122014 consist of Cardinal Pipeline Company, LLC (Cardinal) with ownership interest of approximately 45 percent and Pine Needle LNG Company, LLC (Pine Needle) with ownership interest of 35 percent. We received distributions associated with our equity method investments totaling $7.6 million, $9.1 million, and $11.5 million $14.3 million,in 2015, 2014 and $6.2 million in 2013, 2012 and 2011, respectively. Included in the distributions are $2.0 million, $2.3 million and $1.4 million return of capital from Pine Needle in 2015, 2014 and 2013, and $11.3 million return of capital from Cardinal in 2012. We made capital contributions to Cardinal related to Cardinal’s expansion project totaling $5.8 million in 2012.respectively.
Use of Estimates.
The preparation of financial statements in conformity with U.S. generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Estimates and assumptions which, in the opinion of management, are significant to the underlying amounts included in the financial statements and for which it would be reasonably possible that future events or information could change those estimates include: 1) revenues subject to refund; 2) litigation-related contingencies; 3) environmental remediation obligations; 4) impairment assessments of long-lived assets; 5) depreciation; and 6) asset retirement obligations.
Revenue Recognition.Recognition
Revenues for transportation of gas under long-term firm agreements are recognized considering separately the reservation and commodity charges. Reservation revenues are recognized monthly over the term of the agreement regardless of the volume of natural gas transported. Commodity revenues from both firm and interruptible transportation are recognized in the period transportation services are provided based on volumes of natural gas physically delivered at the agreed upon delivery point. Revenues for the storage of gas under firm agreements are recognized considering separately the reservation, capacity, and injection and withdrawal charges. Reservation and capacity revenues are recognized monthly over the term of the agreement regardless of the volume of storage service actually utilized. Injection and withdrawal revenues are recognized in the period when volumes of natural gas are physically injected into or withdrawn from storage.
In the course of providing transportation services to customers, we may receive different quantities of gas from shippers than the quantities delivered on behalf of those shippers. The resulting imbalances are primarily settled through
the purchase and sale of gas with our customers under terms provided for in our FERC tariff. Revenue is recognized from the sale of gas upon settlement of the transportation and exchange imbalances (See Gas Imbalances in this Note).
As a result of the ratemaking process, certain revenues collected by us may be subject to refunds upon the issuance of final orders by the FERC in pending rate proceedings. We record estimates of rate refund liabilities considering our and other third-party regulatory proceedings, advice of counsel and other risks.
Environmental Matters.Matters
We are subject to federal, state, and local environmental laws and regulations. Environmental expenditures are expensed or capitalized depending on their economic benefit and potential for rate recovery. We believe that any expenditures required to meet applicable environmental laws and regulations are prudently incurred in the ordinary course of business and such expenditures would be permitted to be recovered through rates.
Property, Plant and Equipment.
Property, plant and equipment is recorded at cost. The carrying values of these assets are also based on estimates, assumptions and judgments relative to capitalized costs, useful lives and salvage values. These estimates, assumptions and judgments reflect FERC regulations, as well as historical experience and expectations regarding future industry conditions and operations. We account for repair and maintenance costs under the guidance of FERC regulations. The FERC identifies installation, construction and replacement costs that are to be capitalized. All other costs are expensed as incurred. Gains or losses from the ordinary sale or retirement of property, plant and equipment are credited or charged to accumulated depreciation; certain other gains or losses are recorded in operating income.
We provide for depreciation under the composite (group) method at straight-line FERC prescribed rates that are applied to the cost of the group for transmission facilities, production and gathering facilities and storage facilities. Under this method, assets with similar lives and characteristics are grouped and depreciated as one asset. Included in our depreciation rates is a negative salvage component (net cost of removal) that we currently collect in rates. Our depreciation rates are subject to change each time we file a general rate case with the FERC. Depreciation rates used for major regulated gas plant facilities at December 31, 2013, 20122015, 2014 and 20112013 are as follows:
|
| | | | |
| Category of Property | | 2013 (1) | | 2012-20112015-2013 |
| | | | |
| Gathering facilities | | 1.35% - 2.50% | | 0.18% - 1.66% |
| Storage facilities | | 2.10% - 2.25% | | 2.10% - 3.70% |
| Onshore transmission facilities | | 2.61% - 5.00% | | 2.79% - 5.71% |
| Offshore transmission facilities | | 1.20% - 1.20% | | 1.01% - 1.01% |
(1) Changes in depreciation rates in 2013 due to placing into effect, subject to refund, the rates in Docket No. RP12-993 on March 1, 2013.
We record a liability and increase the basis in the underlying asset for the present value of each expected future asset retirement obligation (ARO) at the time the liability is initially incurred, typically when the asset is acquired or constructed. Measurements of AROs include, as a component of future expected costs, an estimate of the price that a third party would demand, and could expect to receive, for bearing the uncertainties inherent in the obligations, sometimes referred to as a market-risk premium. The ARO asset is depreciated in a manner consistent with the expected timing of the future abandonment of the underlying physical assets. We measure changes in the liability due to passage of time by applying an interest method of allocation. The depreciation of the ARO asset and accretion of the ARO liability are recognized as an increase to a regulatory asset, as management expects to recover such amounts in future rates. The regulatory asset is amortized commensurate with our collection of these costs in rates.
Impairment of Long-lived Assets.Assets
We evaluate the long lived assets of identifiable business activities for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable.
When an indicator of a potential impairment has occurred we compare our management’s estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has
occurred. We apply a probability-weighted approach to consider the likelihood of different cash flow assumptions and possible outcomes including selling in the near term or holding for the remaining estimated useful life. If an impairment of the carrying value has occurred, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value.
For assets identified to be disposed of in the future and considered held for sale in accordance with the ASC Property, Plant, and Equipment (Topic 360), we compare the carrying value to the estimated fair value less the cost to sell to determine if recognition of an impairment is required. Until the assets are disposed of, the estimated fair value, which includes estimated cash flows from operations until the assumed date of sale, is recalculated when related events or circumstances change.
Judgments and assumptions are inherent in our management’s estimate of undiscounted future cash flows used to determine recoverability of an asset and the estimate of an asset’s fair value used to calculate the amount of impairment to recognize. The use of alternate judgments and/or assumptions could result in the recognition of different levels of impairment charges in the financial statements.
Allowance for Funds Used During Construction.Construction
Allowance for funds used during construction (AFUDC) represents the estimated cost of borrowed and equity funds applicable to utility plant in process of construction and are included as a cost of property, plant and equipment because it constitutes an actual cost of construction under established regulatory practices. The FERC has prescribed a formula to be used in computing separate allowances for borrowed and equity AFUDC. The allowance for borrowed funds used during construction was $14.6 million, $6.3 million and $5.3 million, $6.0 millionfor 2015, 2014 and $4.7 million, for 2013, 2012 and 2011, respectively. The allowance for equity funds was $48.4 million, $18.7 million, and $13.3 million, $13.2 million,for 2015, 2014 and $10.6 million, for 2013, 2012 and 2011, respectively.
Income Taxes.
We generally are not a taxable entity for federal or state and local income tax purposes. The tax on net income is generally borne by unitholders of our ultimate parent, WPZ. Net income for financial statement purposes may differ significantly from taxable income of WPZ’s unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under the WPZ partnership agreement. The aggregated difference in the basis of our assets for financial and tax reporting purposes cannot be readily determined because information regarding each of WPZ’s unitholder’s tax attributes in WPZ is not available to us.
Accounts Receivable and Allowance for Doubtful Receivables.Receivables
Accounts receivable are stated at the historical carrying amount net of reserves or write-offs. Our credit risk exposure in the event of nonperformance by the other parties is limited to the face value of the receivables. We perform ongoing credit evaluations of our customers’ financial condition and require collateral from our customers, if necessary. Due to our customer base, we have not historically experienced recurring credit losses in connection with our receivables. Receivables determined to be uncollectible are reserved or written off in the period of determination.
Gas Imbalances.
In the course of providing transportation services to customers, we may receive different quantities of gas from shippers than the quantities delivered on behalf of those shippers. Additionally, we transport gas on various pipeline systems which may deliver different quantities of gas on behalf of us than the quantities of gas received from us. These transactions result in gas transportation and exchange imbalance receivables and payables which are recovered or repaid in cash or through the receipt or delivery of gas in the future and are recorded in the accompanying Consolidated Balance Sheet. Settlement of imbalances requires agreement between the pipelines and shippers as to allocations of volumes to specific transportation contracts and timing of delivery of gas based on operational conditions. Our tariff includes a method whereby most transportation imbalances are settled on a monthly basis. Each month a portion of the
imbalances are not identified to specific parties and remain unsettled. These are generally identified to specific parties and settled in subsequent periods. We believe that amounts that remain unidentified to specific parties and unsettled at year end are valid balances that will be settled with no material adverse effect upon our financial position, results of
operations or cash flows. Management has implemented a policy of continuing to carry any unidentified transportation and exchange imbalances on the books for a three-year period. At the end of the three year period a final assessment will be made of their continued validity. Absent a valid reason for maintaining the imbalance, any remaining balance will be recognized in income. Certain imbalances are being recovered or repaid in cash or through the receipt or delivery of gas upon agreement of the parties as to the allocation of the gas volumes, and as permitted by pipeline operating conditions. These imbalances have been classified as current assets and current liabilities at December 31, 20132015 and 2012.2014. We utilize the average cost method of accounting for gas imbalances.
Deferred Cash Out.Out
Most transportation imbalances are settled in cash on a monthly basis (cash out). We are required by our tariff to refund revenues received from the cash out of transportation imbalances in excess of costs incurred during the annual August through July reporting period. Revenues received in excess of costs incurred are deferred until refunded in accordance with the tariff.
Gas Inventory.Inventory
We utilize the last-in, first-out (LIFO) method of accounting for inventory gas in storage. At December 31, 2015, Gas in Storage, at LIFO, was zero. If inventories valued using theGas in Storage, at LIFO, cost method werewas valued at current replacement cost,costs, the amountsamount at December 31, 2014 would increase by $1.3 million at December 31, 2013. At December 31, 2012, physical withdrawals from the Eminence Storage facility exceeded the customer nominations for withdrawals, resulting in a liability.$0.1 million. The basis for determining current cost at the end of each year is the December monthly average gas price delivered to pipelines in Texas and Louisiana. We utilize the average cost method of accounting for gas available for customer nomination. Liquefied natural gas in storage is valued at original cost.
Materials and Supplies Inventory.Inventory
All inventories are stated at lower of average cost or market. We perform an annual review of Materials and Supplies inventories, including a quarterly analysis of parts that may no longer be useful due to planned replacements of compressor engines and other components on our system. Based on this assessment, we record a reserve for the value of the inventory which can no longer be used for maintenance and repairs on our pipeline. There was a minimal reserve at December 31, 20132015 and at December 31, 2012.2014.
Contingent Liabilities.Liabilities
We record liabilities for estimated loss contingencies, including environmental matters, when we assess that a loss is probable and the amount of the loss can be reasonably estimated. These liabilities are calculated based upon our assumptions and estimates with respect to the likelihood or amount of loss and upon advice of legal counsel, engineers, or other third parties regarding the probable outcomes of the matters. These calculations are made without consideration of any potential recovery from third-parties. We recognize insurance recoveries or reimbursements from others when realizable. Revisions to these liabilities are generally reflected in income when new or different facts or information become known or circumstances change that affect the previous assumptions or estimates.
Pension and Other Postretirement Benefits.Benefits
We do not have employees. Certain of the costs charged to us by Williams associated with employees who directly support us include costs related to Williams’ pension and other postretirement benefit plans. (See Note 6.) Although the underlying benefit plans of Williams are single-employer plans, we follow multiemployer plan accounting whereby the amount charged to us and thus paid by us, is based on our share of net periodic benefit cost.
Cash Flows from Operating Activities and Cash Equivalents.
We use the indirect method to report cash flows from operating activities, which requires adjustments to net income to reconcile to net cash flows provided by operating activities. We include short-term, highly-liquid investments that have an original maturity of three months or less as cash equivalents.
Accounting Standards Issued But Not Yet Adopted
In January 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2016-01 “Financial Instruments - Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities” (ASU 2016-01). ASU 2016-01 addresses certain aspects of recognition, measurement, presentation, and disclosure of financial instruments. The new standard is effective for interim and annual periods beginning after December 15, 2017. Early adoption is only permitted for certain applications. We are evaluating the impact of the new standard on our consolidated financial statements and our timing for adoption.
In July 2015, the FASB issued ASU 2015-11 “Simplifying the Measurement of Inventory” (ASU 2015-11). ASU 2015-11 simplifies the guidance on the subsequent measurement of inventory, excluding inventory measured using last-in, first out or the retail inventory method. Under the new standard, in scope inventory should be measured at the lower of cost and net realizable value. The new standard is effective for interim and annual periods beginning after December 15, 2016, with early adoption permitted. We measure inventory at the lower of cost or market; upon adoption, we will measure inventory at the lower of cost and net realizable value. We do not expect the new standard will have a material impact on the value of inventory reported in our consolidated financial statements.
In February 2015, the FASB issued ASU 2015-02 “Amendments to the Consolidation Analysis” (ASU 2015-02). ASU 2015-02 alters the models used to determine consolidation conclusions for certain entities, including limited partnerships, and may require additional disclosures. The standard is effective for financial statements issued for interim and annual reporting periods beginning after December 15, 2015, with either retrospective or modified retrospective presentation allowed. We do not expect the new standard will have a significant impact on our consolidated financial statements.
In May 2014, the FASB issued ASU 2014-09 establishing ASC Topic 606, “Revenue from Contracts with Customers” (ASC 606). ASC 606 establishes a comprehensive new revenue recognition model designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to be entitled to receive in exchange for those goods or services and requires significantly enhanced revenue disclosures. In August 2015, the FASB issued ASU 2015-14 “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date” (ASU 2015-14). Per ASU 2015-14, the standard is effective for interim and annual reporting periods beginning after December 15, 2017. ASC 606 allows either full retrospective or modified retrospective transition and early adoption is permitted for annual periods beginning after December 15, 2016. We continue to evaluate both the impact of this new standard on our consolidated financial statements and the transition method we will utilize for adoption.
2. CONTINGENT LIABILITIES AND COMMITMENTS.COMMITMENTS
Rate Matters.
General rate case (Docket No. RP12-993) On August 31, 2012, we submitted to the FERC a general rate filing principally designed to recover increased costs and to comply with the terms of the settlement in our Docket No. RP06-569 rate proceeding (see below) which required us to file a rate case no later than August 31, 2012. On September 28, 2012, the FERC issued an order accepting our filing subject to the outcome of a hearing. The rates for certain services that were proposed as overall rate decreases became effective October 1, 2012, without suspension. The increased rates became effective March 1, 2013, subject to refund and the outcome of the hearing. On August 27, 2013, after reaching an agreement in principle with the participants, we filed a stipulation and agreement (Agreement) proposing to resolve all issues in this proceeding without the need for a hearing. On December 6, 2013, the FERC issued an order approving the Agreement without modifications. Pursuant to its terms, the Agreement will become effective March 1, 2014. We have provided a reserve for rate refunds which we believe is adequate for required refunds as of December 31, 2013, under the Agreement. Refunds will be made on or before April 30, 2014.Matters
General rate case (Docket No. RP06-569) On August 31, 2006, we submitted to the FERC a general rate filing principally designed to recover increased costs. The rates became effective March 1, 2007, subject to refund and the outcome of a hearing. All issues in this proceeding except one have been resolved by settlement.
The one issue reserved for litigation or further settlement relates to our proposal to change the design of the rates for service under one of our storage rate schedules, which was implemented subject to refund on March 1, 2007. A hearing on that issue was held before a FERC Administrative Law Judge (ALJ) in July 2008. In November 2008, the ALJ issued an initial decision in which he determined that our proposed incremental rate design is unjust and unreasonable. On January 21, 2010, the FERC reversed the ALJ’s initial decision, and approved our proposed incremental rate design. Certain parties sought rehearing of the FERC’s order and, on April 2, 2012, the FERC denied the rehearing request. On June 1, 2012, one of the parties filed an appeal in the U.S. Court of Appeals for the D.C. Circuit (D.C. Circuit). On February 21, 2014, the D.C. Circuit issued an opinion that vacated and remanded the FERC's order because the FERC did not adequately support its conclusions. On October 16, 2014, the FERC issued an order establishing a "paper hearing" and requesting briefs on certain questions raised by the D.C. Circuit's opinion. Parties to the proceeding filed initial and reply briefs on February 6, 2015 and March 6, 2015. We intend to continue to pursue approval of our proposed rate design. If we are unsuccessful, we believe anyit is reasonably possible that refunds would notcould be material to our resultsas much as $17.8 million at December 31, 2015.
Environmental Matters.Matters
We have had studies underway for many years to test some of our facilities for the presence of toxic and hazardous substances such as polychlorinated biphenyls (PCBs) and mercury to determine to what extent, if any, remediation may be necessary. We have also similarly evaluated past on-site disposal of hydrocarbons at a number of our facilities. We have worked closely with and responded to data requests from the U.S. Environmental Protection Agency (EPA) and state agencies regarding such potential contamination of certain of our sites. On the basis of the findings to date, we estimate that environmental assessment and remediation costs under various federal and state statutes will total approximately $6$4 million to $8$6 million (including both expense and capital expenditures), measured on an undiscounted basis, and will substantially be spent over the next three to fivefour years. This estimate depends on a number of assumptions concerning the scope of remediation that will be required at certain locations and the cost of the remedial measures. We are conducting environmental assessments and implementing a variety of remedial measures that may result in increases or decreases in the total estimated costs. At December 31, 2013,2015, we had a balance of approximately $4.1$2.9 million for the expense portion of these estimated costs recorded in current liabilities ($2.31.4 million) and other long-term liabilities ($1.81.5 million) in the accompanying Consolidated Balance Sheet. At December 31, 2012,2014, we had a balance of approximately $3.3$2.7 million for the expense portion of these estimated costs recorded in current liabilities ($1.10.8 million) and other long-term liabilities ($2.21.9 million) in the accompanying Consolidated Balance Sheet.
Although we discontinued the use of lubricating oils containing polychlorinated biphenyls (PCBs) in the 1970s, we have discovered residual PCB contamination in equipment and soils at certain gas compressor station sites. We have worked closely with the EPA and state regulatory authorities regarding PCB issues, and we have a program to assess and remediate such conditions where they exist. In addition, we commenced negotiations with certain
environmental authorities and other parties concerning investigative and remedial actions relative to potential mercury contamination at certain gas metering sites. All such costs are included in the $6 million to $8 million range discussed above.
We have been identified as a potentially responsible party (PRP) at various Superfund and state waste disposal sites. Based on present volumetric estimates and other factors, our estimated aggregate exposure for remediation of these sites is less than $0.5 million. The estimated remediation costs for all of these sites are included in the $6$4 million to $8$6 million range discussed above. Liability under the Comprehensive Environmental Response, Compensation and Liability Act and applicable state law can be joint and several with other PRPs. Although volumetric allocation is a factor in assessing liability, it is not necessarily determinative; thus, the ultimate liability could be substantially greater than the amounts described above.
In March 2008, the EPA promulgated a new, lower National Ambient Air Quality Standard (NAAQS) for ground-level ozone. However, in September 2009,In May 2012, the EPA announced it would reconsider the 2008 NAAQS for ground level ozone to ensure that the standards were clearly grounded in science, and were protective of both public health and the environment. As a result, the EPA delayedcompleted designation of new eight-hour ozone non-attainment areas underareas. Several of our facilities are located in 2008 ozone non-attainment areas. To date, no federal actions have been proposed to mandate additional emission controls at these facilities. Pursuant to pending state regulatory actions associated with implementation of the 2008 standards untilozone standard, we anticipate that some facilities may be subject to increased controls within five years. As a result, the reconsiderationcost of additions to property, plant, and equipment is complete. expected to increase. We are unable at this time to estimate with any certainty the cost of additions that may be required to meet the proposed regulations.
In January 2010,December 2014, the EPA proposed to further reduce the ground-level ozone NAAQS from the March 2008 levels. In September 2011,levels and subsequently finalized a rule on October 1, 2015. We are monitoring the EPA announced that it was proceeding with required actions to implementrule's implementation as the 2008 ozone standardreduction will trigger additional federal and area designations. In May 2012, the EPA completed designation of new eight-hour ozone non-attainment areas. Several Transco facilities are located in 2008 ozone non-attainment areas; however, each facility has been previously subjected to federal and/or state emission control requirements implemented to address preceding ozone standards. To date, no new federal or state actions have been proposed to mandate additional emission controls at these facilities. At this time, it is unknown whether future federal or state regulatory actions associated with implementation of the 2008 ozone standard willthat may impact our operations and increaseoperations. As a result, the cost of additions to property, plant and equipment. Until any additional federal or state regulatory actions are proposed, weequipment is expected to increase. We are unable at this time to estimate with any certainty the cost of additions that may be required to meet this new regulation.
Additionally, in August 2010, the EPA promulgated National Emission Standards for Hazardous Air Pollutants (NESHAP) regulations that will impact our operations. All capital expenditures related to compliance with these hazardous air pollutant regulations were completed, and affected facilities were in compliance by the October 2013 regulatory deadline.regulations.
On January 22, 2010, the EPA set a new one-hour nitrogen dioxide (NO2) NAAQS. The effective date of the new NO2 standard was April 12, 2010. On January 20, 2012, the EPA determined pursuant to available information that no area in the country is violating the 2010 NO2 NAAQS and thus designated all areas of the country as “unclassifiable/attainment.” Also, at that time, the EPA noted its plan to deploy an expanded NO2 monitoring network beginning in 2013. However, on October 5, 2012, the EPA proposed a graduated implementation of the monitoring network between January 1, 2014 and January 1, 2017. Once three years of data is collected from the new monitoring network, the EPA will reassess attainment status with the one-hour NO2 NAAQS. Until that time, the EPA or states may require ambient air quality modeling on a case by case basis to demonstrate compliance with the NO2 standard. Because we are unable to predict the outcome of the EPA’s or states’ future assessment using the new monitoring network, we are unable to estimate the cost of additions that may be required to meet this regulation.
We consider prudently incurred environmental assessment and remediation costs and the costs associated with compliance with environmental standards to be recoverable through rates. To date, we have been permitted recovery of environmental costs, and it is our intent to continue seeking recovery of such costs through future rate filings. As a result, as estimated costs of environmental assessment and remediation are incurred, they are recorded as regulatory
assets in the Consolidated Balance Sheet until collected through rates. At December 31, 2013,2015, we had a balance of approximately $1.8$1.6 million of uncollected environmental related regulatory assets recorded in current assets ($1.2 million) and other assets ($0.60.4 million) in the accompanying Consolidated Balance Sheet. WeAt December 31, 2014, we had noa balance of approximately $1.7 million of uncollected environmental related regulatory assets at December 31, 2012.
By letter dated September 20, 2007, the EPA required us to provide information regarding natural gas compressor stationsrecorded in current assets ($1.2 million) and other assets ($0.5 million) in the states of Mississippi and Alabama as part of the EPA’s investigation of our compliance with the Federal Clean Air Act (Act). By January 2008, we responded with the requested information. By Notices of Violation (NOVs)
dated March 28, 2008, the EPA found us to be in violation of the requirements of the Act with respect to these compressor stations. We met with the EPA in May 2008 to discuss the allegations contained in the NOVs; in June 2008, we submitted to the EPA a written response denying the allegations. The EPA has requested additional information pertaining to these compressor stations and in May 2011, we submitted information in response to the EPA’s latest request. In August, 2010, the EPA requested, and we provided, similar information for a compressor station in Maryland. Since 2011, we have not received any additional requests from the EPA for information related to these facilities.accompanying Consolidated Balance Sheet.
Other Matters.Matters
Various other proceedings are pending against us and are considered incidental to our operations.
Summary.Summary
We estimate that for all matters for which we are able to reasonably estimate a range of loss, including those noted above and others that are not individually significant, our aggregate reasonably possible losses beyond amounts accrued for all of our contingent liabilities are immaterial to our expected future annual results of operations, liquidity and financial position. These calculations have been made without consideration of any potential recovery from third parties. We have disclosed all significant matters for which we are unable to reasonably estimate a range of possible loss.
Other Commitments.Commitments
Commitments for construction We have commitments for construction and acquisition of property, plant and equipment of approximately $368$417 million at December 31, 2013.2015.
3. DEBT, FINANCING ARRANGEMENTS AND LEASES.LEASES
Long-Term Debt.Debt
At December 31, 20132015 and 2012,2014, long-term debt issues were outstanding as follows (in thousands):
| | | | | 2013 | | 2012 | | 2015 | | 2014 |
| 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: | | | | | | | | |
| 6.4% due 2016 | | 200,000 |
| | 200,000 |
| | 200,000 |
| | 200,000 |
|
| 6.05% due 2018 | | 250,000 |
| | 250,000 |
| | 250,000 |
| | 250,000 |
|
| 5.4% due 2041 | | 375,000 |
| | 375,000 |
| | 375,000 |
| | 375,000 |
|
| 4.45% due 2042 | | 400,000 |
| | 400,000 |
| | 400,000 |
| | 400,000 |
|
| Total notes | | 1,225,000 |
| | 1,225,000 |
| | 1,225,000 |
| | 1,225,000 |
|
| | | | | | | | | |
| Total long-term debt issues | | 1,432,500 |
| | 1,432,500 |
| | 1,432,500 |
| | 1,432,500 |
|
| Unamortized debt premium and discount | | (4,145 | ) | | (4,177 | ) | |
| Unamortized debt issuance costs | | | (9,069 | ) | | (9,803 | ) |
| Unamortized debt premium and discount, net | | | (3,857 | ) | | (4,005 | ) |
| | | | | | | | | |
| Total long-term debt, less current maturities | | $ | 1,428,355 |
| | $ | 1,428,323 |
| |
| Total long-term debt | | | $ | 1,419,574 |
| | $ | 1,418,692 |
|
Aggregate minimum maturities (face value) applicable to long-term debt outstanding at December 31, 2013,2015, for the next five years, are as follows (in thousands):
|
| | |
| 2016: 6.4% Notes | | $200,000 |
| 2018: 6.05% Notes | | $250,000 |
There are no maturities applicable to long-term debt outstanding for the years 2014, 2015,2017, 2019, and 2017.2020.
No property is pledged as collateral under any of our long-term debt issues.
Restrictive Debt Covenants.Covenants
At December 31, 2013,2015, none of our debt instruments restrict the amount of distributions to our parent. Our debt agreements contain restrictions on our ability to incur secured debt beyond certain levels.
Issuance
On January 22, 2016, we issued $1 billion of 7.85 percent senior unsecured notes due 2026 to investors in a private debt placement. We intend to use the net proceeds to repay debt and to fund capital expenditures. Accordingly, the $200 million of 6.4 percent notes due 2016 are classified as non-current in the accompanying Consolidated Balance Sheet.
Credit Facility.Facility
On July 31, 2013,February 2, 2015, we along with WPZ, amended its $2.4 billion credit facility to increaseNorthwest, the lenders named therein and an administrative agent entered into the Second Amended and Restated Credit Agreement with aggregate commitments to $2.5available of $3.5 billion, and extend the maturity date to July 31, 2018. The amended credit facility may also, under certain conditions, be increasedwith up to an additional $500 million. Total lettermillion increase in aggregate commitments available under certain circumstances. The maturity date of creditthe facility is February 2, 2020. However, the co-borrowers may request up to two extensions of the maturity date each for an additional one year period to allow a maturity date as late as February 2, 2022, under certain circumstances. The agreement allows for swing line loans up to aggregate amount of $150 million, subject to available capacity available to WPZ under the credit facility, is $1.3 billion. At December 31, 2013, noand letters of credit have been issued and no loanscommitments available to WPZ of $1.125 billion. We are outstanding under our credit facility. We mayable to borrow up to $500 million under the amendedthis credit facility to the extent not otherwise utilized by WPZ and Northwest Pipeline LLC.the other co-borrowers. At December 31, 2013, the full $500 million2015, no letters of credit have been issued and $1.31 billion of loans to WPZ are outstanding under the credit facility was availablefacility. On December 18, 2015, we along with WPZ, Northwest, the lenders named therein and an administrative agent entered into the Amendment No. 1 to us.Second Amended & Restated Credit Agreement modifying the thresholds specified in the covenant related to the maximum ratio of WPZ's consolidated indebtedness to consolidated EBITDA.
Under the credit facility, WPZ is required to maintain a ratio of debt to EBITDA (each as defined in the credit facility) that must be no greater than 5.75 to 1.0 for the quarters ending December 31, 2015, March 31, 2016 and June 30, 2016. The ratio must be no greater than 5.5 to 1.0 for the quarters ending September 30, 2016 and December 31, 2016. The ratio must be no greater than 5.0 to 1.0. For1.0 for the quarter ending March 31, 2017 and each subsequent fiscal quarter, except for the fiscal quarter and the two following fiscal quarters in which one or more acquisitions for a total aggregate purchase price equal to or greater than $50 million has been executed, WPZ is required to maintain ain which case the ratio of debt to EBITDA ofmust be no greater than 5.55.50 to 1.00. In addition,1.0. For us, the ratio of debt to capitalization (defined as net worth plus debt) must be no greater than 65 percent for us and our consolidated subsidiaries. Atpercent. Measured as of December 31, 2013,2015, we are in compliance with thesethis financial covenants.covenant.
Each time funds are borrowed, the applicable borrowerVarious covenants may choose from two methods of calculating interest: a fluctuating base rate equal to Citibank N.A.’s alternate base rate plus an applicable margin, or a periodic fixed rate equal to London Interbank Offered Rate (LIBOR) plus an applicable margin. The applicable borrower is required to pay a commitment fee (currently 0.20 percent) based on the unused portion of the credit facility. The applicable margin and the commitment fee are determined for each borrower by reference to a pricing schedule based on such borrower’s senior unsecured long-term debt ratings. The credit facility contains various covenants that limit, among other things, a borrower’sborrower's and its respective material subsidiaries’subsidiaries' ability to grant certain liens supporting indebtedness, a borrower’sborrower's ability to merge or consolidate, sell all or substantially all of its assets, enter into certain affiliate transactions, make certain distributions during an event of default, make investments,enter into certain restrictive agreements, and allow any material change in the nature of its business.
If an event of default with respect to a borrower occurs under the credit facility, the lenders will be able to terminate the commitments for allthe respective borrowers and accelerate the maturity of any loans of the defaulting borrower under the credit facility agreement and exercise other rights and remedies.
Other than swingline loans, each time funds are borrowed, the borrower must choose whether such borrowing will be an alternate base rate borrowing or a Eurodollar borrowing. If such borrowing is an alternate base rate borrowing, interest is calculated on the basis of the greater of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus 1/2 of 1 percent and (c) a periodic fixed rate equal to the London Interbank Offered Rate (LIBOR) plus 1 percent, plus, in the case of each of (a), (b) and (c), an applicable margin. If the borrowing is a Eurodollar borrowing, interest is calculated on the basis of LIBOR for the relevant period plus an applicable margin. Interest on swingline loans is calculated as the sum of the alternate base rate plus an applicable margin. The borrower is required to pay a commitment fee based on the unused portion of the credit facility. The applicable margin and the commitment fee are determined for each borrower by reference to a pricing schedule based on such borrower's senior unsecured long-term debt ratings.
WPZ participates in a commercial paper program and WPZ management considers amounts outstanding under this program to be a reduction of available capacity under the credit facility. TheOn February 2, 2015, WPZ amended and restated the commercial paper program allowsfor the WPZ/ACMP merger and to allow a maximum outstanding amount at any time of $2 billion of unsecured commercial paper notes.$3 billion. At December 31, 2013,2015, WPZ had $225$499 million in outstanding commercial paper.
Accounting Standards Issued and Adopted
In April 2015, the FASB issued ASU 2015-03 “Interest - Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs” (ASU 2015-03). ASU 2015-03 simplifies the presentation of debt issuance costs by requiring such costs be presented as a deduction from the corresponding debt liability. Subsequently, in August 2015, the FASB issued ASU 2015-15 “Interest - Imputation of Interest (Subtopic 835-30): Presentation and RetirementSubsequent Measurement of Long-Term Debt.
On July 13, 2012, weDebt Issuance Costs Associated with Line-of-Credit Arrangement-Amendments to SEC Paragraphs Pursuant to Staff Announcement at June 18, 2015 EITF Meeting” (ASU 2015-15). In ASU 2015-15 the FASB stated that the guidance in ASU 2015-03 did not address the presentation or subsequent measurement of debt issuance costs related to line-of-credit arrangements, and entities are permitted to defer and present debt issuance costs related to line-of-credit arrangements as assets The standards are effective for financial statements issued $400for interim and annual reporting periods beginning after December 15, 2015, and require retrospective presentation. Early adoption is permitted. We elected to early adopt these standards for the periods presented. Accordingly, $9.1 million aggregate principal amountand $9.8 million of 4.45 percent senior unsecured notes due 2042 (4.45 percent Notes) to certain institutional investors pursuant to certain exemptions from registration under the Securities Actdebt issuance costs as of 1933,December 31, 2015 and 2014, respectively, are now reflected as amended. Interest is payable on February 1 and August 1a direct reduction of each year, beginning February 1, 2013. A portion of these proceeds was used to repaydebt in our $325 million 8.875 percent notes that matured on July 15, 2012. We used the remainder for general corporate purposes, including the funding of capital expenditures.
As part of the new issuance, we entered into a registration rights agreement with the initial purchasers of the 4.45 percent Notes. An offer to exchange these unregistered notes for substantially identical new notes that are registered under the Securities Act of 1933, as amended, was commenced in November 2012 and completed in December 2012.Consolidated Balance Sheet.
Lease Obligations.Obligations
The future minimum lease payments under our various operating leases are as follows (in thousands):
| | | 2014 | | $ | 10,154 |
| |
| 2015 | | 10,025 |
| |
| 2016 | | 10,025 |
| | $ | 13,552 |
|
| 2017 | | 9,971 |
| | 13,485 |
|
| 2018 | | 9,956 |
| | 13,480 |
|
| 2019 | | | 11,074 |
|
| 2020 | | | 11,093 |
|
| Thereafter | | 22,401 |
| | 5,037 |
|
| Total net minimum obligations | | $ | 72,532 |
| | $ | 67,721 |
|
Our lease expense was $10.7 million in 2015, $11.1 million in 2014, and $11.4 million in 2013, $10.9 million in 2012, and $9.1 million in 2011.2013.
4. INVESTMENTS.ARO TRUST
Available-for-Sale Investments.Investments
We are entitled to collect in rates the amounts necessary to fund our asset retirement obligations (ARO). We deposit monthly, into an external trust account (ARO Trust), the revenues specifically designated for ARO. We established the ARO trust account (ARO Trust) on June 30, 2008. The ARO Trust carries a moderate risk portfolio. We measure the financial instruments held in our ARO Trust at fair value. However, in accordance with the ASC Topic 980, Regulated Operations, both realized and unrealized gains and losses of the ARO Trust are recorded as regulatory assets or liabilities.
Effective March 1, 2013, based on the Agreement in Docket No. RP12-993, the annual funding obligation is approximately $36.4 million, with installments paiddeposits made monthly.
Investments in available-for-sale securities within the ARO Trust at fair value were as follows (in millions):
| | | | | December 31, 2013 | | December 31, 2012 | | December 31, 2015 | | December 31, 2014 |
| | | Amortized Cost Basis | | Fair Value | | Amortized Cost Basis | | Fair Value | | Amortized Cost Basis | | Fair Value | | Amortized Cost Basis | | Fair Value |
| Cash and Money Market Funds | | $ | 6.5 |
| | $ | 6.5 |
| | $ | 1.3 |
| | $ | 1.3 |
| | $ | 3.2 |
| | $ | 3.2 |
| | $ | 2.1 |
| | $ | 2.1 |
|
| U.S. Equity Funds | | 8.0 |
| | 11.1 |
| | 5.4 |
| | 7.4 |
| | 19.2 |
| | 22.9 |
| | 15.0 |
| | 19.0 |
|
| International Equity Funds | | 4.2 |
| | 4.9 |
| | 3.4 |
| | 3.8 |
| | 16.1 |
| | 15.0 |
| | 8.0 |
| | 8.2 |
|
| Municipal Bond Funds | | 10.2 |
| | 10.2 |
| | 4.9 |
| | 5.3 |
| | 25.1 |
| | 25.6 |
| | 17.7 |
| | 18.2 |
|
| Total | | $ | 28.9 |
| | $ | 32.7 |
| | $ | 15.0 |
| | $ | 17.8 |
| | $ | 63.6 |
| | $ | 66.7 |
| | $ | 42.8 |
| | $ | 47.5 |
|
5. FAIR VALUE MEASUREMENTS.MEASUREMENTS
The following table presents, by level within the fair value hierarchy, certain of our financial assets and liabilities. The carrying values of cash, short-term financial assets (advances to affiliate) that have variable interest rates, accounts receivable and accounts payable approximate fair value because of the short-term nature of these instruments. Therefore, these assets and liabilities are not presented in the following table.
| | | | | | | | | Fair Value Measurements Using | | | | | | Fair Value Measurements Using |
| | | Carrying Amount | | Fair Value | | Quoted Prices In Active Markets for Identical Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | | Carrying Amount | | Fair Value | | Quoted Prices In Active Markets for Identical Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) |
| | | | | | | (Millions) | | | | | | | | | | (Millions) | | | | |
| Assets (liabilities) at December 31, 2013: | | | | | | | | | | | |
| Assets (liabilities) at December 31, 2015: | | | | | | | | | | | |
| Measured on a recurring basis: | | | | | | | | | | | | | | | | | | | | |
| ARO Trust investments | | $ | 32.7 |
| | $ | 32.7 |
| | $ | 32.7 |
| | $ | — |
| | $ | — |
| | $ | 66.7 |
| | $ | 66.7 |
| | $ | 66.7 |
| | $ | — |
| | $ | — |
|
| | | | | | | | | | | | | | | | | | | | | |
| Additional disclosures: | | | | | | | | | | | | | | | | | | | | |
| Notes receivable | | 6.3 |
| | 6.3 |
| | — |
| | 6.3 |
| | — |
| | 1.1 |
| | 1.1 |
| | — |
| | 1.1 |
| | — |
|
| Long-term debt | | (1,428.4 | ) | | (1,512.9 | ) | | — |
| | (1,512.9 | ) | | — |
| | (1,419.6 | ) | | (1,244.1 | ) | | — |
| | (1,244.1 | ) | | — |
|
| | | | | | | | | | | | | | | | | | | | | |
| Assets (liabilities) at December 31, 2012: | | | | | | | | | | | |
| Assets (liabilities) at December 31, 2014: | | | | | | | | | | | |
| Measured on a recurring basis: | | | | | | | | | | | | | | | | | | | | |
| ARO Trust investments | | $ | 17.8 |
| | $ | 17.8 |
| | $ | 17.8 |
| | $ | — |
| | $ | — |
| | $ | 47.5 |
| | $ | 47.5 |
| | $ | 47.5 |
| | $ | — |
| | $ | — |
|
| | | | | | | | | | | | | | | | | | | | | |
| Additional disclosures: | | | | | | | | | | | | | | | | | | | | |
| Notes receivable | | 8.2 |
| | 8.2 |
| | — |
| | 8.2 |
| | — |
| | 3.8 |
| | 3.8 |
| | — |
| | 3.8 |
| | — |
|
| Long-term debt, including current portion | | (1,428.3 | ) | | (1,704.5 | ) | | — |
| | (1,704.5 | ) | | — |
| |
| Long-term debt | | | (1,418.7 | ) | | (1,506.4 | ) | | — |
| | (1,506.4 | ) | | — |
|
Fair Value of Methods.Methods
The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value:
Cash and short-term financial assets (advances to affiliates) that have variable interest rates - The carrying amount is a reasonable estimate of fair value due to the short maturity of those instruments.
ARO Trust investments - We deposit a portion of our collected rates, pursuant to the terms of the Docket No. RP06-569RP12-993 rate case settlement, into the ARO Trust which is specifically designated to fund future asset retirement obligations. The ARO Trust invests in a portfolio of actively traded mutual funds that are measured at fair value on a recurring basis based on quoted prices in an active market, are classified as available-for-sale and are reported in Other Assets-Other in the Consolidated Balance Sheet. However, both realized and unrealized gains and losses are ultimately recorded as regulatory assets or liabilities. See Note 4 for more information regarding the ARO Trust.
Notes receivable - The disclosed fair value of our notes receivable is determined by an income approach, which considers the underlying contract amounts and our assessment of our ability to recover these amounts. The current portionbalance in notes receivables is reported in Trade and other receivables and the noncurrent portion is reported in Other Assets-Other in the Consolidated Balance Sheet.
Long-term debt - The disclosed fair value of our long-term debt is determined by a market approach using broker quoted indicative period-end bond prices. The quoted prices are based on observable transactions in less active markets for our debt or similar instruments.
Reclassifications of fair value between Level 1, Level 2, and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. No transfers between Level 1 and Level 2 occurred during the year ended December 31, 20132015 or 2012.
6. BENEFIT PLANS.2014.
6. BENEFIT PLANS
Certain of the benefit costs charged to us by Williams associated with employees who directly support us are described below. Additionally, allocated corporate expenses from Williams to us also include amounts related to these same employee benefits, which are not included in the amounts presented below.
Pension and Other Postretirement Benefit Plans.Plans
Williams has noncontributory defined benefit pension plans (Williams Pension Plan, Williams Inactive Employees Pension Plan and The Williams Companies Retirement Restoration Plan) that provide pension benefits for its eligible employees. Pension cost charged to us by Williams was $13.5 million, $11.9 million and $22.3 million $20.3 millionfor 2015, 2014, and $16.4 million for 2013, 2012,respectively.
Williams makes annual cash contributions to the pension plans, based on annual actuarial estimates, which Transco recovers through rates that are set through periodic general rate filings. Effective with the RP12-993 Settlement, any amounts of annual contributions that exceed an upper threshold or fall below a lower threshold are recorded as adjustments to income and 2011, respectively.collected or refunded through future rate adjustments. The amount of deferred pension collections recorded as a regulatory liability at December 31, 2015 is $8.0 million. There were no deferred pension collections recorded as a regulatory liability or a regulatory asset at December 31, 2014.
Williams provides certain retiree health care and life insurance benefits for eligible participants that generally were employed by Williams on or before December 31, 1991 or December 31, 1995, if they were employees or retirees of Transco Energy Company and its subsidiaries. We recognized other postretirement benefit income of $11.9 million, $13.7 million, and $4.2 million for 2015, 2014 and $3.0 million for 2013, and 2011, respectively, and cost of $2.5 million for 2012.respectively.
We have been allowed by rate case settlements to collect or refund in future rates any differences between the actuarially determined costs and amounts currently being recovered in rates related to other postretirement benefits. Any differences between the annual actuarially determined cost and amounts currently being recovered in rates are recorded as an adjustment to expense and collected or refunded through future rate adjustments. The amountsamount of other postretirement benefits costs deferred as a regulatory liability at December 31, 2013 is $25.32015 and 2014 are $51.0 million and is$39.1 million, respectively. These amounts are comprised of $6.6 millionamounts being deferred for future rate treatment of $37.4 million and $18.7$23.0 million at December 31, 2015 and 2014, respectively, and amounts of $13.6 million and $16.1 million being amortized over a period of approximately an 8 year periodyears per Docket No. RP12-993. AtRP12-993 at December 31, 2012, the amount of other postretirement benefit costs deferred consisted of a regulatory liability of $24.7 million deferred for future rate treatment,2015 and a regulatory asset of $4.6 million which was being amortized over a 10 year period per Docket No. RP06-569.2014, respectively. Effective March 1, 2013, the residual regulatory asset balance from the prior rate filing was netted against the accumulated regulatory liability.
Defined Contribution Plan.Plan
Williams charged us compensation expense of $6.6 million in 2015, $6.4 million in 2014 and $6.0 million in 2013 $7.2 million in 2012, and $6.9 million in 2011 for Williams’ company matching contributions to this plan.
Employee Stock-Based Compensation Plan Information.Information
The Williams Companies, Inc. 2007 Incentive Plan, as amended and restated on February 23, 2010, (Plan) was approved by stockholders on May 20, 2010. The Plan provides for Williams’ common stock based awards to both employees and non-management directors. The Plan permits the granting of various types of awards including, but not limited to, restricted stock units and stock options. Awards may be granted for no consideration other than prior and future services or based on certain financial performance targets achieved.
Williams currently bills us directly for compensation expense related to stock-based compensation awards based on the fair value of the awards. We are also billed for our proportionate share of Williams’ and other affiliates’ stock-based compensation expense through various allocation processes.
Total stock-based compensation expense for the years ended December 31, 2015, 2014 and 2013 2012 and 2011 was $4.0 million, $3.0 million $2.8 million and $2.4$3.0 million, respectively, excluding amounts allocated from WPZ and Williams.
7. TRANSACTIONS WITH MAJOR CUSTOMERS AND AFFILIATES.AFFILIATES
Major Customers.
Operating revenues received from two of our two major customers in 2013, 20122015, 2014 and 20112013 are as follows (in millions):
| | | | 2013 | | 2012 | | 2011 | 2015 | | 2014 | | 2013 |
| National Grid | | $ | 129.6 |
| | $ | 91.2 |
| | $ | 88.5 |
|
| Public Service Enterprise Group | $ | 130.7 |
| | $ | 127.4 |
| | $ | 136.7 |
| 110.2 |
|
| 115.3 |
|
| 130.7 |
|
| National Grid | 88.5 |
| | 93.5 |
| | 98.2 |
| |
Affiliates.
We are a participant in WPZ’s cash management program, and we make advances to and receive advances from WPZ. At December 31, 20132015 and 2012,2014, our advances to WPZ totaled approximately $526.4$64.6 million and $312.2$306.9 million, respectively. These advances are represented by demand notes and are classified as Current Assets in the accompanying Consolidated Balance Sheet. Advances are stated at the historical carrying amounts. Interest income is recognized when chargeable and collectability is reasonably assured. The interest rate on these intercompany demand notes is based upon the daily overnight investment rate paid on WPZ’s excess cash at the end of each month. At December 31, 2013,2015, the interest rate was 0.010.12 percent.
On December 31, 2011, Williams completed the spin-off of its former exploration and production business, WPX, by means of a special stock dividend to its shareholders. Included in our operating revenues and cost of sales listed below for the year 2011 are amounts related to activity with WPX.
Included in Operating Revenuesin the accompanying Consolidated Statement of Comprehensive Income for 2013, 20122015, 2014 and 20112013 are revenues received from affiliates of $16.3$4.6 million, $17.0$8.3 million, and $18.5$16.3 million, respectively. The rates charged to provide sales and services to affiliates are the same as those that are charged to similarly-situated nonaffiliated customers.
Included in Cost of natural gas sales in the accompanying Consolidated Statement of Comprehensive Income for 2013, 20122015, 2014 and 20112013 is purchased gas cost from affiliates of $6.9$6.0 million, $3.9$10.5 million, and $8.8$6.9 million, respectively. All gas purchases are made at market or contract prices.
We have no employees. Services necessary to operate our business are provided to us by Williams and certain affiliates of Williams. We reimburse Williams and its affiliates for all direct and indirect expenses incurred or payments made (including salary, bonus, incentive compensation and benefits) in connection with these services. Employees of Williams also provide general, administrative and management services to us, and we are charged for certain administrative expenses incurred by Williams. These charges are either directly identifiable or allocated to our assets. Direct charges are for goods and services provided by Williams at our request. Allocated charges are based on a three-factor formula, which considers revenues; property, plant and equipment; and payroll. In management’s estimation, the allocation methodologies used are reasonable and result in a reasonable allocation to us of our costs of doing business incurred by Williams. We were billed $327.1 million, $310.1 million, and $310.3 million $320.1 million,during 2015, 2014 and $278.6 million during 2013, 2012 and 2011, respectively, for these services. Such expenses are primarily included in Administrative and general and Operation and maintenance expenses in the accompanying Consolidated Statement of Comprehensive Income.
PursuantWe provide services to an operating agreement, we serve as contract operator on certain Williams Field Services (WFS) facilities.of our affiliates. We recorded reductions in operating expenses for services provided to and reimbursed by WFSour affiliates of $2.3$5.7 million, $4.5$6.6 million, and $6.4$7.1 million in 2015, 2014 and 2013, 2012 and 2011, respectively, under terms of the operating agreement.respectively. In 2013, we received $3.6 million of reimbursements from WFS,Williams Field Services Group, LLC (WFS), related to a capital project. Pursuant to construction agreements, we received pre-payments from WFS of $2.3 million and $4.5$5.0 million during 2012 and 2011, respectively,2014 associated with capital projects. We received reimbursements totaling $3.1 millionIn 2015, we acquired certain assets from Williams Gas Processing – Gulf Coast Company, L.P. in 2012 associated with costs related to a transfer and assignment agreement.WFS for $1.9 million.
We made equity distributions of $536 million, $411 million and $250 million $246 millionduring 2015, 2014 and $219 million during 2013, 2012 and 2011, respectively. In January 2014,2016, an additional distribution of $112$175 million was declared and paid.
During 2015, 2014 and 2013, 2012 and 2011, WPOour parent made contributions totaling $264$652 million, $150$267 million and $115$264 million, respectively, to us to fund a portion of our expenditures for additions to property, plant and equipment. In January 2014, WPO2016, our parent made an additional $54$112 million contribution. During 2012, we received a non-cash contribution
8. ASSET RETIREMENT OBLIGATIONS.OBLIGATIONS
TheThese accrued obligations relate to underground storage caverns, offshore platforms, pipelines, and gas transmission facilities. At the end of the useful life of each respective asset, we are legally obligated to plug storage caverns and remove any related surface equipment, to dismantle offshore platforms, to cap certain gathering pipelines at the wellhead
connection and remove any related surface equipment, and to remove certain components of gas transmission facilities from the ground.
During 20132015 and 2012,2014, our overall asset retirement obligation changed as follows (in thousands):
| | | | | 2013 | | 2012 | | 2015 | | 2014 |
| Beginning balance | | $ | 296,870 |
| | $ | 302,768 |
| | $ | 296,475 |
| | $ | 273,987 |
|
| Accretion | | 31,461 |
| | 23,052 |
| | 25,178 |
| | 17,962 |
|
| New obligations | | 2,225 |
| | 2,556 |
| | 256 |
| | 1,346 |
|
| Changes in estimates of existing obligations (1) | | (27,628 | ) | | 10,895 |
| | 3,691 |
| | 23,031 |
|
| Property dispositions/obligations settled | | (28,941 | ) | | (42,401 | ) | | (2,574 | ) | | (19,851 | ) |
| Ending balance | | $ | 273,987 |
| | $ | 296,870 |
| | $ | 323,026 |
| | $ | 296,475 |
|
| |
| (1) | The 2013 changesChanges in estimates of existing obligations reflects decreases of $36 million,are primarily due to a revision in the estimated remaining life of the assets, which is among several factors considered in the annual review process, which considers various factors including inflation rates, current estimates for removal cost, discount rates, and discount rates. These decreases are partially offset by an increasethe estimated remaining life of $9 million related to changes in the timing and method of abandonment of our Eminence natural gas storage caverns that were associated with a leak in 2010.assets. The 2012 changes in estimates of existing obligations is primarily due toreflect an increase of $13$4 million relatedand $23 million for 2015 and 2014, respectively, due to changesrevisions in the timingestimated remaining life of assets, inflation rates, discount rates, and method of abandonment of our Eminence natural gas storage caverns that were associated with a leak in 2010.current estimates for removal costs. |
We are entitled to collect in rates the amounts necessary to fund our ARO. All funds received for such retirements are deposited into an external trust account dedicated to funding our ARO. Under our current rate settlement our annual funding obligation is approximately $36.4 million, with installments to be deposited monthly.
9. REGULATORY ASSETS AND LIABILITIES.LIABILITIES
The regulatory assets and regulatory liabilities resulting from our application of the provisions of ASC Topic 980, Regulated Operations, included in the accompanying Consolidated Balance Sheet at December 31, 20132015 and December 31, 20122014 are as follows (in millions):
| | | Regulatory Assets | | 2013 | | 2012 | | 2015 | | 2014 |
| Grossed-up deferred taxes on equity funds used during construction | | $ | 80.6 |
| | $ | 83.5 |
| | $ | 75.8 |
| | $ | 78.4 |
|
| Asset retirement obligations | | 128.5 |
| | 125.1 |
| | 113.5 |
| | 115.9 |
|
| Asset retirement costs - Eminence | | 68.2 |
| | — |
| | 58.8 |
| | 63.2 |
|
| Deferred taxes | | 8.1 |
| | 9.1 |
| | 5.9 |
| | 7.0 |
|
| Postretirement benefits other than pension | | — |
| | 4.6 |
| |
| Deferred cash out | | | 43.9 |
| | 12.9 |
|
| Deferred gas costs | | | — |
| | 8.7 |
|
| Fuel cost | | 0.7 |
| | 29.3 |
| | 43.8 |
| | 29.2 |
|
| Other | | 8.0 |
| | — |
| | 1.6 |
| | 1.6 |
|
| Total Regulatory Assets | | $ | 294.1 |
| | $ | 251.6 |
| | $ | 343.3 |
| | $ | 316.9 |
|
| | | Regulatory Liabilities | | 2013 | | 2012 | | 2015 | | 2014 |
| Negative salvage | | $ | 241.7 |
| | $ | 203.8 |
| | $ | 318.3 |
| | $ | 283.8 |
|
| Deferred cash out | | 1.6 |
| | 6.2 |
| |
| Sentinel meter station depreciation | | 5.0 |
| | 3.9 |
| | 6.0 |
| | 5.8 |
|
| Postretirement benefits other than pension | | 25.3 |
| | 24.7 |
| | 51.0 |
| | 39.1 |
|
| Electric power cost | | 13.8 |
| | 7.7 |
| | 0.8 |
| | 4.4 |
|
| Pension - deferred collections | | | 8.0 |
| | — |
|
| Other | | 0.2 |
| | 1.2 |
| | 1.8 |
| | — |
|
| Total Regulatory Liabilities | | $ | 287.6 |
| | $ | 247.5 |
| | $ | 385.9 |
| | $ | 333.1 |
|
The significant regulatory assets and liabilities include:
Grossed-up deferred taxes on equity funds used during construction: Regulatory asset balance established to offset the deferred tax for the equity component of the allowance for funds used during the construction of long-lived assets. All amounts were generated during the period that we were a taxable entity. Taxes on capitalized funds used during construction and the offsetting deferred income taxes are included in the rate base and are recovered over the depreciable lives of the long-lived asset to which they relate.
Asset retirement obligations: Regulatory asset balance established to offset depreciation of the ARO asset and changes in the ARO liability due to the passage of time. The regulatory asset is being recovered through our rates, and is being amortized to expense consistent with the amounts collected in rates.
Asset retirement costs - Eminence: Regulatory asset balance associated with the Eminence Storage Field retirement costs. The regulatory asset is being recovered through our rates, and is being amortized to expense consistent with the amounts collected in rates (See Note 10).
Deferred taxes:taxes: Regulatory asset balance was established as a result of an increase to rate base deferred taxes due to an increase to the effective state income tax rate. The regulatory asset is being collected from rate payers over the remaining depreciable lives of the long-lived asset to which they relate.
Postretirement benefits:Deferred cash out We recover: This amount represents the actuarially determined costdeferral of postretirement benefits through rates that are set through periodic general rate filings. Any difference betweengains or losses on the annual actuarially determined costpurchases and the amount recovered in rates is recorded as a regulatory asset or liability to be collected or refunded through future rate adjustments.sales of gas imbalances with shippers. These amounts are not included in the rate base.base but are expected to be recovered/refunded in subsequent annual cash out filing periods.
Deferred gas costs: This amount arises from the movement of gas volumes between gas inventory accounts that have different valuations. These amounts are expected to be recovered/refunded in subsequent periods.
Fuel cost: This amount represents the difference between the gas retained from our customers and the gas consumed in operations. These amounts are not included in the rate base but are expected to be recovered/refunded in subsequent annual fuel tracker filing periods.
Electric power cost: This amount represents the difference between the electric power costs recovered from our customers and the electric power costs incurred in operations. These amounts are not included in the rate base but are expected to be recovered/refunded in subsequent annual electric power tracker filing periods.
Negative salvage: Our rates include a component designed to recover certain future retirement costs for which we are not required to record an asset retirement obligation. We record a regulatory liability representing the cumulative residual amount of recoveries through rates, net of expenditures associated with these retirement costs.
Deferred cash out: This amount represents the deferral of gains or losses on the purchases and sales of gas imbalances with shippers. These amounts are not included in the rate base but are expected to be recovered/refunded in subsequent annual cash out filing periods.
Sentinel meter station depreciation: This amount reflects the incremental depreciation being recorded related to the meter station modifications made for three of the Sentinel shippers. These modifications will be recovered through a surcharge over a defined period of time as stated in the Sentinel FERC order. The incremental depreciation represents the difference between the FERC granted depreciation rate for such facilities in the last rate case as compared to the
depreciation rates in the Sentinel order which are based on the contractual terms in the surcharge agreements. The incremental depreciation will be recorded through the end of the contractual term and then will be amortized.
Postretirement benefits: We recover the actuarially determined cost of postretirement benefits through rates that are set through periodic general rate filings. Any difference between the annual actuarially determined cost and the amount recovered in rates is recorded as a regulatory asset or liability to be collected or refunded through future rate adjustments. These amounts are not included in the rate base.
Electric power cost: This amount represents the difference between the electric power costs recovered from our customers and the electric power costs incurred in operations. These amounts are not included in the rate base but are expected to be recovered/refunded in subsequent annual electric power tracker filing periods.
Pension - deferred collections: We recover the actuarially determined pension cash contributions through rates that are set through periodic general rate filings. Effective with the RP12-993 Settlement, any amounts of annual contributions that exceed an upper threshold or fall below a lower threshold are recorded as adjustments to income and collected or refunded through future rate adjustments.
10. OTHER.OTHER
During 2012,2014, we capitalized $8.7$3.5 million and $2.4 million, respectively, of project feasibility costs associated with the Rockaway Delivery Lateral Project and the Northeast Connector Project,various projects, which had been expensed in prior periods in Other expense, net, upon determining that the projects were probable of development. During 2011, we capitalized $10.1 million of project feasibility costs associated with the Northeast Supply Link Expansion Project, which had been expensed in prior periods in Other expense, net, upon determining that the project was probable of development. These costs will be included in the capital costs of the projects, which we believe are probable of recovery through the projects’ rates.
We detected a leak in an underground cavern at our Eminence Storage Field in Mississippi on December 28, 2010. During 2013, 20122014 and 2011,2013, we recorded $4.3 million, $2.5$0.8 million and $14.6$4.3 million, respectively, of charges to Operation and maintenance expenses primarily related to costs to ensure the safety of the surrounding area.
Due to the abandonment and retirement of four of the seven caverns at our Eminence Storage Field in 2013 and the expected recovery of such costs in our rates, we have reclassified $92 million of costs related to the Eminence ARO from Total property, plant and equipment, net to Regulatory assets (Eminence abandonment regulatory asset). Included in Other expense, net, for the year 2013, consistent with the Agreementstipulation and agreement in our Docket No. RP12-993 general rate case proceeding, iswas a charge of $11.5 million, related to the estimated portion of the Eminence abandonment regulatory asset that will not be recovered in rates.rates; which was reduced by $2.9 million in 2014 upon completion of the abandonment. We have also recognized income during 2013 of $16.1 million, related to insurance recoveries associated with this event.
TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
QUARTERLY FINANCIAL DATA (UNAUDITED)
Summarized quarterly financial data are as follows (in thousands):
| | | 2013 | | First | | Second (1) | | Third (2) | | Fourth (3) | |
| 2015 | | | First (1) | | Second (2) | | Third (3) | | Fourth (4) |
| Operating revenues | | $ | 331,062 |
| | $ | 342,879 |
| | $ | 332,255 |
| | $ | 350,136 |
| | $ | 380,023 |
| | $ | 390,921 |
| | $ | 414,568 |
| | $ | 407,007 |
|
| Operating expenses | | 229,301 |
| | 231,922 |
| | 235,248 |
| | 230,713 |
| | 246,205 |
| | 243,859 |
| | 257,480 |
| | 257,823 |
|
| Operating income | | 101,761 |
| | 110,957 |
| | 97,007 |
| | 119,423 |
| | 133,818 |
| | 147,062 |
| | 157,088 |
| | 149,184 |
|
| Interest expense | | 20,554 |
| | 20,746 |
| | 21,416 |
| | 21,474 |
| | 20,807 |
| | 20,656 |
| | 20,675 |
| | 20,700 |
|
| Other (income) and deductions, net | | (7,768 | ) | | (7,838 | ) | | (8,127 | ) | | (5,335 | ) | | (15,807 | ) | | (16,391 | ) | | (19,094 | ) | | (19,851 | ) |
| Net income | | 88,975 |
| | 98,049 |
| | 83,718 |
| | 103,284 |
| | 128,818 |
| | 142,797 |
| | 155,507 |
| | 148,335 |
|
| Equity interest in unrealized gain (loss) on interest rate hedge | | 102 |
| | 404 |
| | (102 | ) | | 60 |
| | (53 | ) | | 50 |
| | (167 | ) | | 254 |
|
| Comprehensive income | | $ | 89,077 |
| | $ | 98,453 |
| | $ | 83,616 |
| | $ | 103,344 |
| | $ | 128,765 |
| | $ | 142,847 |
| | $ | 155,340 |
| | $ | 148,589 |
|
| | | 2012 | | First | | Second | | Third | | Fourth (4) | |
| 2014 | | | First | | Second | | Third | | Fourth (5) |
| Operating revenues | | $ | 309,879 |
| | $ | 293,764 |
| | $ | 302,957 |
| | $ | 327,501 |
| | $ | 365,662 |
| | $ | 338,454 |
| | $ | 352,799 |
| | $ | 376,222 |
|
| Operating expenses | | 216,421 |
| | 230,274 |
| | 231,945 |
| | 225,400 |
| | 235,980 |
| | 218,711 |
| | 240,481 |
| | 265,127 |
|
| Operating income | | 93,458 |
| | 63,490 |
| | 71,012 |
| | 102,101 |
| | 129,682 |
| | 119,743 |
| | 112,318 |
| | 111,095 |
|
| Interest expense | | 23,718 |
| | 23,668 |
| | 21,132 |
| | 20,557 |
| | 21,959 |
| | 21,197 |
| | 20,954 |
| | 20,877 |
|
| Other (income) and deductions, net | | (5,043 | ) | | (8,859 | ) | | (10,082 | ) | | (7,496 | ) | | (4,057 | ) | | (6,943 | ) | | (11,378 | ) | | (12,655 | ) |
| Net income | | 74,783 |
| | 48,681 |
| | 59,962 |
| | 89,040 |
| | 111,780 |
| | 105,489 |
| | 102,742 |
| | 102,873 |
|
| Equity interest in unrealized gain (loss) on interest rate hedge | | (25 | ) | | (133 | ) | | (283 | ) | | 65 |
| | 38 |
| | (41 | ) | | 159 |
| | (13 | ) |
| Comprehensive income | | $ | 74,758 |
| | $ | 48,548 |
| | $ | 59,679 |
| | $ | 89,105 |
| | $ | 111,818 |
| | $ | 105,448 |
| | $ | 102,901 |
| | $ | 102,860 |
|
| |
| (1) | Includes a $6.4$3.0 million increase to operating expenses related to the portionestablish a regulatory liability associated with rate collections in excess of the Eminence abandonment regulatory asset that will not be recovered in rates and a $12.1 million decrease for related insurance recoveries.our pension funding obligation. |
| |
| (2) | Includes a $8.1$1.0 million increase to operating expenses related to the portionestablish a regulatory liability associated with rate collections in excess of the Eminence abandonment regulatory asset that will not be recovered in rates and a $3.3 million decrease for related insurance recoveries.our pension funding obligation. |
| |
| (3) | Includes a $3.0$2.0 million increase to operating expenses to establish a regulatory liability associated with rate collections in excess of our pension funding obligation. |
| |
| (4) | Includes a $2.0 million increase to operating expenses to establish a regulatory liability associated with rate collections in excess of our pension funding obligation. |
| |
| (5) | Includes a $3.1 million increase to operating expenses related to a measurement adjustment and a $2.9 million decrease to operating expenses related to Eminence abandonment costs reduction. |
| |
(4) | Includes a $15.9 million decrease to operating expenses resulting from the reversal of project feasibility costs from expense to capital associated with Leidy Southeast, Rockaway Lateral and Northeast Connector Expansion projects. Of this amount, $4.8 million was expensed in the first three quarters of 2012. |
Item 9. Changes In and Disagreements With Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
Disclosure Controls and Procedures
Our management, including our Senior Vice President – Atlantic-Gulf and our Vice President and Chief Accounting Officer, does not expect that our disclosure controls and procedures (as defined in Rules 13a—15(e) and 15d—15(e) of the Securities Exchange Act) (Disclosure Controls) will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our Disclosure Controls and make modifications as necessary; our intent in this regard is that the Disclosure Controls will be modified as systems change and conditions warrant.
Evaluation of Disclosure Controls and Procedures
An evaluation of the effectiveness of the design and operation of our Disclosure Controls was performed as of the end of the period covered by this report. This evaluation was performed under the supervision and with the participation of our management, including our Senior Vice President – Atlantic-Gulf and our Vice President and Chief Accounting Officer. Based upon that evaluation, our Senior Vice President – Atlantic-Gulf and our Vice President and Chief Accounting Officer concluded that these Disclosure Controls are effective at a reasonable assurance level.
Fourth Quarter 2013 Changes in Internal ControlsControl over Financial Reporting
Except as described below, thereThere have been no changes during the fourth quarter of 20132015 that have materially affected, or are reasonably likely to materially affect, our Internal ControlsControl over financial reporting.Financial Reporting.
Management’s Annual Report on Internal Control over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a – 15(f) and 15d – 15(f) under the Securities Exchange Act of 1934). Our internal controlscontrol over financial reporting areis designed to provide reasonable assurance to our management regarding the preparation and fair presentation of financial statements in accordance with accounting principles generally accepted in the United States. Our internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorization of our management; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.
All internal control systems, no matter how well designed, have inherent limitations including the possibility of human error and the circumvention or overriding of controls. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
Under the supervision and with the participation of our management, including our Senior Vice President – Atlantic-Gulf and our Vice President and Chief Accounting Officer, we assessed the effectiveness of our internal control over financial reporting as of December 31, 2013,2015, based on the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework (1992)(2013). Based on our assessment, we concluded that, as of December 31, 2013,2015, our internal control over financial reporting was effective.
This annual report does not include a report of the company’s registered public accounting firm regarding internal control over financial reporting. A report by the company’s registered public accounting firm is not required pursuant to rules of the Securities and Exchange Commission that permit the companyus to provide only management’s report in this annual report.
Item 9B. Other information
None.
PART III
Since we meet the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K, the information required by Items 10, 11, 12, and 13, is omitted.
Items 14. Principal Accounting Fees and Services
Fees for professional services provided by our independent registered public accounting firm in each of the last two fiscal years in each of the following categories are (in thousands):
| | | | | 2013 | | 2012 | | 2015 | | 2014 |
| Audit fees | | $ | 1,678 |
| | $ | 1,879 |
| | $ | 1,460 |
| | $ | 1,499 |
|
| Audit-related fees | | — |
| | — |
| | — |
| | — |
|
| Tax fees | | — |
| | — |
| | — |
| | — |
|
| All other fees | | — |
| | — |
| | 78 |
| | — |
|
| Total fees | | $ | 1,678 |
| | $ | 1,879 |
| | $ | 1,538 |
| | $ | 1,499 |
|
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 and FERC filings, and accounting consultation.
As a wholly owned subsidiary of WPZ, we do not have a separate audit committee. The policies and procedures for pre-approving audit and non-audit services of the Audit Committee of the Board of Directors of WPZ’s general partner have been set forth in WPZ’s 20132015 annual report on Form 10-K, which is available on the SEC’s website at http://www.sec.gov and on WPZ’s website at http://www.williamslp.com under the heading “Investors-SEC Filings”.investor.williams.com.
PART IV
Item 15. Exhibits and Financial Statement Schedules
|
| |
| | Page Reference to 20132015 10-K |
| A. 1 and 2. Transcontinental Gas Pipe Line Company, LLC financials | |
| | |
| Index | |
| | |
| Covered by Report of Independent Registered Public Accounting Firm: | |
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| |
| | |
| |
| | |
| |
| | |
| |
| | |
| |
| | |
Not covered by Report of Independent Registered Public Accounting Firm: | |
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| | |
| The following schedules are omitted because of the absence of the conditions under which they are required: I, II, III, IV, and V. | |
3. Exhibits:
|
| | |
| Exhibit Number | | Description |
| | | |
2.12 | | Certificate of Conversion dated December 22, 2008 and effective December 31, 2008 (filed on February 24, 2011 as Exhibit 2.1 to our annual report on Form 10-K (File No. 001-07584) and incorporated herein by reference). |
| | | |
| 3.1 | | Certificate of Formation dated December 22, 2008 and effective December 31, 2008 (filed on February 24, 2011 as Exhibit 3.1 to our annual report on Form 10-K (File No. 001-07584) and incorporated herein by reference).
|
| | | |
| 3.2 | | Amended and Restated Operating Agreement of Transcontinental Gas Pipe Line Company, LLC dated February 17, 2010 (filed on October 28, 2010 as Exhibit 3.2 to our quarterly report on Form 10-Q (File No. 001-07584) and incorporated herein by reference). |
| | | |
| 4.1 | | Senior Indenture dated July 15, 1996 between Transco and Citibank, N.A., as Trustee (filed on April 2, 1996 as Exhibit 4.1 to our registration statement Form S-3 (File No. 333-02155) and incorporated herein by reference). |
| | | |
| 4.2 | | Indenture dated April 11, 2006 between Transco and JP Morgan Chase Bank, N.A., as Trustee (filed on April 11, 2006 as Exhibit 4.1 to our current report on Form 8-K (File No. 001-07584) and incorporated herein by reference). |
| | | |
| 4.3 | | Indenture, dated as of May 22, 2008 between Transco and The Bank of New York Trust Company, N.A., as Trustee (filed on May 23, 2008 as Exhibit 4.1 to our current report on Form 8-K (File No. 001-07584) and incorporated herein by reference). |
| | | |
| 4.4 | | Indenture, dated as of August 12, 2011 between Transco and The Bank of New York Mellon Trust Company, N.A., as Trustee (filed on August 12, 2011 as Exhibit 4.1 to our current report on Form 8-K (File No. 001-07584) and incorporated herein by reference). |
| | | |
| 4.5 | | Indenture, dated as of July 13, 2012, between Transco and The Bank of New York Mellon Trust Company, N.A., as Trustee (filed on July 16, 2012 as Exhibit 4.1 to our current report Form 8-K (File No. 001-07584) and incorporated herein by reference). |
| | |
| 4.6 | | Indenture, dated as of January 22, 2016, between Transcontinental Gas Pipe Line Company, LLC and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on January 22, 2016 as Exhibit 4.1 to our current report on Form 8-K (File No. 001-07584) and incorporated herein by reference). |
| | | |
| 10.1 | | Administrative Services Agreement, dated as of February 17, 2010, by and between Transco Pipeline Services LLC and Transco (filed on February 22, 2010 as Exhibit 10.3 to Williams Partners L.P.’s, Form 8-K (File No. 001-32599) and incorporated herein by reference). |
| | | |
| 10.2 | | Assignment Agreement dated February 13, 2013 by and between Transco Pipeline Services LLC and Williams WPC-I, LLC, effective January 1, 2013 (filed on February 27, 2013 as Exhibit 10.2 to our annual report on Form 10-K and incorporated herein by reference). |
| | | |
| 10.3 | | FirstSecond Amended and Restated Credit Agreement dated as of February 2, 2015, between Williams Partners L.P. (formerly known as Access Midstream Partners, L.P.), Northwest Pipeline LLC, Transcontinental Gas Pipeline Company, LLC, as co-borrowers, the lenders named therein, and Citibank, N.A. as Administrative Agent (filed on February 3, 2015 as Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
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| 10.4 | | Amendment No. 1 to Second Amended & Restated Credit Agreement dated as of July 31, 2013, by and amongDecember 18, 2015, between Williams Partners L.P., Northwest Pipeline LLC, and Transcontinental Gas Pipe Line Company, LLC, as co-borrowers, the lenders named therein, and Citibank, N.A., as Administrative Agent (filed on July 31, 2013December 23, 2015 as Exhibit 1010.1 to Williams Partners L.P.'s Quarterly Report onour Form 10-Q8-K (File No. 001-07584) and incorporated herein by reference). |
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| 10.5 | | Registration Rights Agreement, dated January 22, 2016, between Transcontinental Gas Pipe Line Company, LLC and the initial purchasers listed therein (filed on January 22, 2016 as Exhibit 10.1 to our current report on Form 8-K (File No. 001-07584) and incorporated herein by reference) |
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| 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. |
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| 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. |
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32**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. |
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101.INS** 101.I SCH *** 101.CAL** 101.DEF** 101.LAB** | | XBRL Instance Document. XBRL Taxonomy Extension Schema. XBRL Taxonomy Extension Calculation Linkbase. XBRL Taxonomy Extension Definition Linkbase. XBRL Taxonomy Extension Label Linkbase. |
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101.PRE** | | XBRL Taxonomy Extension Presentation Linkbase. |
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* Filed herewith. ** Furnished herewith. | | |
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.
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TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC (Registrant) |
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| By: | | /s/ Jeffrey P. Heinrichs |
| | | Jeffrey P. Heinrichs |
| | | Controller |
Date: February 26, 201424, 2016
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated:
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| Signature | | Title |
| /s/ Rory L. Miller | | Management Committee Member and Senior Vice President – Atlantic-Gulf (Principal Executive Officer) |
| Rory L. Miller | |
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| /s/ Ted T. Timmermans | | Vice President and Chief Accounting Officer (Principal Financial Officer) |
| Ted T. Timmermans | |
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| /s/ Jeffrey P. Heinrichs | | Controller (Principal Accounting Officer) |
| Jeffrey P. Heinrichs | |
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| /s/ Frank J. Ferazzi | | Management Committee Member and Vice President |
| Frank J. Ferazzi | |
Date: February 26, 201424, 2016
INDEX OF EXHIBITS
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| Exhibit Number | | Description |
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2.12 | | Certificate of Conversion dated December 22, 2008 and effective December 31, 2008 (filed on February 24, 2011 as Exhibit 2.1 to our annual report on Form 10-K (File No. 001-07584) and incorporated herein by reference). |
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| 3.1 | | Certificate of Formation dated December 22, 2008 and effective December 31, 2008 (filed on February 24, 2011 as Exhibit 3.1 to our annual report on Form 10-K (File No. 001-07584) and incorporated herein by reference).
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| 3.2 | | Amended and Restated Operating Agreement of Transcontinental Gas Pipe Line Company, LLC dated February 17, 2010 (filed on October 28, 2010 as Exhibit 3.2 to our quarterly report on Form 10-Q (File No. 001-07584) and incorporated herein by reference). |
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| 4.1 | | Senior Indenture dated July 15, 1996 between Transco and Citibank, N.A., as Trustee (filed on April 2, 1996 as Exhibit 4.1 to our registration statement Form S-3 (File No. 333-02155) and incorporated herein by reference). |
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| 4.2 | | Indenture dated April 11, 2006 between Transco and JP Morgan Chase Bank, N.A., as Trustee (filed on April 11, 2006 as Exhibit 4.1 to our current report on Form 8-K (File No. 001-07584) and incorporated herein by reference). |
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| 4.3 | | Indenture, dated as of May 22, 2008 between Transco and The Bank of New York Trust Company, N.A., as Trustee (filed on May 23, 2008 as Exhibit 4.1 to our current report on Form 8-K (File No. 001-07584) and incorporated herein by reference). |
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| 4.4 | | Indenture, dated as of August 12, 2011 between Transco and The Bank of New York Mellon Trust Company, N.A., as Trustee (filed on August 12, 2011 as Exhibit 4.1 to our current report on Form 8-K (File No. 001-07584) and incorporated herein by reference). |
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| 4.5 | | Indenture, dated as of July 13, 2012, between Transco and The Bank of New York Mellon Trust Company, N.A., as Trustee (filed on July 16, 2012 as Exhibit 4.1 to our current report on Form 8-K (File No. 001-07584) and incorporated herein by reference). |
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| 4.6 | | Indenture, dated as of January 22, 2016, between Transcontinental Gas Pipe Line Company, LLC and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on January 22, 2016 as Exhibit 4.1 to our current report on Form 8-K (File No. 001-07584) and incorporated herein by reference). |
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| 10.1 | | Administrative Services Agreement, dated as of February 17, 2010, by and between Transco Pipeline Services LLC and Transco (filed on February 22, 2010 as Exhibit 10.3 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599) and incorporated herein by reference). |
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| 10.2 | | Assignment Agreement dated February 13, 2013 by and between Transco Pipeline Services LLC and Williams WPC-I, LLC, effective January 1, 2013 (filed on February 27, 2013 as Exhibit 10.2 to our annual report on Form 10-K and incorporated herein by reference). |
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| 10.3 | | FirstSecond Amended and Restated Credit Agreement dated as of February 2, 2015, between Williams Partners L.P. (formerly known as Access Midstream Partners, L.P.), Northwest Pipeline LLC, Transcontinental Gas Pipeline Company, LLC, as co-borrowers, the lenders named therein, and Citibank, N.A. as Administrative Agent (filed on February 3, 2015 as Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
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| 10.4 | | Amendment No. 1 to Second Amended & Restated Credit Agreement dated as of July 31, 2013, by and amongDecember 18, 2015, between Williams Partners L.P., Northwest Pipeline LLC, and Transcontinental Gas Pipe Line Company, LLC, as co-borrowers, the lenders named therein, and Citibank, N.A., as Administrative Agent (filed on July 31, 2013December 23, 2015 as Exhibit 1010.1 to Williams Partners L.P.'s Quarterly Report onour Form 10-Q8-K (File No. 001-07584) and incorporated herein by reference). |
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| 10.5 | | Registration Rights Agreement, dated January 22, 2016, between Transcontinental Gas Pipe Line Company, LLC and the initial purchasers listed therein (filed on January 22, 2016 as Exhibit 10.1 to our current report on Form 8-K (File No. 001-07584) and incorporated herein by reference) |
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| 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. |
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| 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. |
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| 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. |
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101.INS** | | XBRL Instance Document. |
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101.I SCH *** | | XBRL Taxonomy Extension Schema. |
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101.CAL** | | XBRL Taxonomy Extension Calculation Linkbase. |
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101.DEF** | | XBRL Taxonomy Extension Definition Linkbase. |
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101.LAB** | | XBRL Taxonomy Extension Label Linkbase. |
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101.PRE** | | XBRL Taxonomy Extension Presentation Linkbase. |
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* Filed herewith. ** Furnished herewith. | | |